☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number | Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address; and Telephone Number | IRS Employer Identification No. | ||
1-8962 | PINNACLE WEST CAPITAL CORPORATION (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000 | 86-0512431 | ||
1-4473 | ARIZONA PUBLIC SERVICE COMPANY (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000 | 86-0011170 |
PINNACLE WEST CAPITAL CORPORATION | Yes ☒ No ☐ |
ARIZONA PUBLIC SERVICE COMPANY | Yes ☒ No ☐ |
PINNACLE WEST CAPITAL CORPORATION | Yes ☒ No ☐ |
ARIZONA PUBLIC SERVICE COMPANY | Yes ☒ No ☐ |
Large accelerated filer ☒ | Accelerated filer ☐ | Non-accelerated filer ☐ | Smaller reporting company ☐ |
Emerging growth company ☐ |
Large accelerated filer ☐ | Accelerated filer ☐ | Non-accelerated filer ☒ | Smaller reporting company ☐ |
Emerging growth company ☐ |
PINNACLE WEST CAPITAL CORPORATION | Yes ☐ No ☒ |
ARIZONA PUBLIC SERVICE COMPANY | Yes ☐ No ☒ |
PINNACLE WEST CAPITAL CORPORATION | Number of shares of common stock, no par value, outstanding as of July 26, 2017: 111,624,528 |
ARIZONA PUBLIC SERVICE COMPANY | Number of shares of common stock, $2.50 par value, outstanding as of July 26, 2017: 71,264,947 |
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• | our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels; |
• | variations in demand for electricity, including those due to weather, seasonality, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation; |
• | power plant and transmission system performance and outages; |
• | competition in retail and wholesale power markets; |
• | regulatory and judicial decisions, developments and proceedings; |
• | new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, nuclear plant operations and potential deregulation of retail electric markets; |
• | fuel and water supply availability; |
• | our ability to achieve timely and adequate rate recovery of our costs, including returns on and of debt and equity capital investment; |
• | our ability to meet renewable energy and energy efficiency mandates and recover related costs; |
• | risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; |
• | current and future economic conditions in Arizona, including in real estate markets; |
• | the development of new technologies which may affect electric sales or delivery; |
• | the cost of debt and equity capital and the ability to access capital markets when required; |
• | environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions; |
• | volatile fuel and purchased power costs; |
• | the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements; |
• | the liquidity of wholesale power markets and the use of derivative contracts in our business; |
• | potential shortfalls in insurance coverage; |
• | new accounting requirements or new interpretations of existing requirements; |
• | generation, transmission and distribution facility and system conditions and operating costs; |
• | the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region; |
• | the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; and |
• | restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission ("ACC") orders. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
OPERATING REVENUES | $ | 944,587 | $ | 915,394 | $ | 1,622,315 | $ | 1,592,561 | ||||||||
OPERATING EXPENSES | ||||||||||||||||
Fuel and purchased power | 254,611 | 274,848 | 467,006 | 496,133 | ||||||||||||
Operations and maintenance | 214,013 | 242,279 | 433,989 | 485,474 | ||||||||||||
Depreciation and amortization | 125,739 | 123,073 | 253,366 | 242,549 | ||||||||||||
Taxes other than income taxes | 44,289 | 42,117 | 88,125 | 84,618 | ||||||||||||
Other expenses | 1,706 | 1,329 | 2,094 | 1,877 | ||||||||||||
Total | 640,358 | 683,646 | 1,244,580 | 1,310,651 | ||||||||||||
OPERATING INCOME | 304,229 | 231,748 | 377,735 | 281,910 | ||||||||||||
OTHER INCOME (DEDUCTIONS) | ||||||||||||||||
Allowance for equity funds used during construction | 10,456 | 10,369 | 19,938 | 20,885 | ||||||||||||
Other income (Note 8) | 484 | 197 | 964 | 314 | ||||||||||||
Other expense (Note 8) | (3,822 | ) | (2,842 | ) | (7,502 | ) | (6,880 | ) | ||||||||
Total | 7,118 | 7,724 | 13,400 | 14,319 | ||||||||||||
INTEREST EXPENSE | ||||||||||||||||
Interest charges | 54,969 | 52,849 | 106,833 | 103,593 | ||||||||||||
Allowance for borrowed funds used during construction | (4,906 | ) | (5,301 | ) | (9,378 | ) | (10,528 | ) | ||||||||
Total | 50,063 | 47,548 | 97,455 | 93,065 | ||||||||||||
INCOME BEFORE INCOME TAXES | 261,284 | 191,924 | 293,680 | 203,164 | ||||||||||||
INCOME TAXES | 88,967 | 65,742 | 93,178 | 67,656 | ||||||||||||
NET INCOME | 172,317 | 126,182 | 200,502 | 135,508 | ||||||||||||
Less: Net income attributable to noncontrolling interests (Note 5) | 4,874 | 4,874 | 9,747 | 9,747 | ||||||||||||
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 167,443 | $ | 121,308 | $ | 190,755 | $ | 125,761 | ||||||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC | 111,797 | 111,368 | 111,763 | 111,336 | ||||||||||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED | 112,345 | 112,004 | 112,270 | 111,930 | ||||||||||||
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||||||||||||||
Net income attributable to common shareholders — basic | $ | 1.50 | $ | 1.09 | $ | 1.71 | $ | 1.13 | ||||||||
Net income attributable to common shareholders — diluted | $ | 1.49 | $ | 1.08 | $ | 1.70 | $ | 1.12 | ||||||||
DIVIDENDS DECLARED PER SHARE | $ | 1.31 | $ | 1.25 | $ | 1.31 | $ | 1.25 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
NET INCOME | $ | 172,317 | $ | 126,182 | $ | 200,502 | $ | 135,508 | |||||||
OTHER COMPREHENSIVE INCOME, NET OF TAX | |||||||||||||||
Derivative instruments: | |||||||||||||||
Net unrealized gain (loss), net of tax expense of $4, $80, $679 and $626 for the respective periods | 7 | 128 | (763 | ) | (566 | ) | |||||||||
Reclassification of net realized loss, net of tax (benefit) expense of ($348), ($392), $8 and ($191) for the respective periods | 564 | 624 | 1,771 | 1,766 | |||||||||||
Pension and other postretirement benefits activity, net of tax benefit (expense) of $823, $439, $119 and ($206) for the respective periods | (1,334 | ) | (701 | ) | (812 | ) | (171 | ) | |||||||
Total other comprehensive income (loss) | (763 | ) | 51 | 196 | 1,029 | ||||||||||
COMPREHENSIVE INCOME | 171,554 | 126,233 | 200,698 | 136,537 | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests | 4,874 | 4,874 | 9,747 | 9,747 | |||||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 166,680 | $ | 121,359 | $ | 190,951 | $ | 126,790 |
June 30, 2017 | December 31, 2016 | ||||||
ASSETS | |||||||
CURRENT ASSETS | |||||||
Cash and cash equivalents | $ | 4,953 | $ | 8,881 | |||
Customer and other receivables | 293,266 | 250,491 | |||||
Accrued unbilled revenues | 213,703 | 107,949 | |||||
Allowance for doubtful accounts | (2,151 | ) | (3,037 | ) | |||
Materials and supplies (at average cost) | 258,134 | 253,979 | |||||
Fossil fuel (at average cost) | 29,890 | 28,608 | |||||
Income tax receivable | 4,073 | 3,751 | |||||
Assets from risk management activities (Note 6) | 307 | 19,694 | |||||
Deferred fuel and purchased power regulatory asset (Note 3) | 48,122 | 12,465 | |||||
Other regulatory assets (Note 3) | 172,606 | 94,410 | |||||
Other current assets | 45,301 | 45,028 | |||||
Total current assets | 1,068,204 | 822,219 | |||||
INVESTMENTS AND OTHER ASSETS | |||||||
Assets from risk management activities (Note 6) | 55 | 1 | |||||
Nuclear decommissioning trust (Note 11) | 822,244 | 779,586 | |||||
Other assets | 71,121 | 69,063 | |||||
Total investments and other assets | 893,420 | 848,650 | |||||
PROPERTY, PLANT AND EQUIPMENT | |||||||
Plant in service and held for future use | 17,227,444 | 17,341,888 | |||||
Accumulated depreciation and amortization | (5,951,653 | ) | (5,970,100 | ) | |||
Net | 11,275,791 | 11,371,788 | |||||
Construction work in progress | 1,195,076 | 1,019,947 | |||||
Palo Verde sale leaseback, net of accumulated depreciation (Note 5) | 111,580 | 113,515 | |||||
Intangible assets, net of accumulated amortization | 265,926 | 90,022 | |||||
Nuclear fuel, net of accumulated amortization | 118,909 | 119,004 | |||||
Total property, plant and equipment | 12,967,282 | 12,714,276 | |||||
DEFERRED DEBITS | |||||||
Regulatory assets (Note 3) | 1,415,091 | 1,313,428 | |||||
Assets for other postretirement benefits (Note 4) | 184,629 | 166,206 | |||||
Other | 141,101 | 139,474 | |||||
Total deferred debits | 1,740,821 | 1,619,108 | |||||
TOTAL ASSETS | $ | 16,669,727 | $ | 16,004,253 |
June 30, 2017 | December 31, 2016 | ||||||
LIABILITIES AND EQUITY | |||||||
CURRENT LIABILITIES | |||||||
Accounts payable | $ | 270,262 | $ | 264,631 | |||
Accrued taxes | 150,709 | 138,964 | |||||
Accrued interest | 53,046 | 52,835 | |||||
Common dividends payable | 73,113 | 72,926 | |||||
Short-term borrowings (Note 2) | 482,000 | 177,200 | |||||
Current maturities of long-term debt (Note 2) | 207,000 | 125,000 | |||||
Customer deposits | 72,585 | 82,520 | |||||
Liabilities from risk management activities (Note 6) | 48,613 | 25,836 | |||||
Liabilities for asset retirements | 8,960 | 9,135 | |||||
Regulatory liabilities (Note 3) | 91,173 | 99,899 | |||||
Other current liabilities | 181,133 | 244,000 | |||||
Total current liabilities | 1,638,594 | 1,292,946 | |||||
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2) | 4,192,520 | 4,021,785 | |||||
DEFERRED CREDITS AND OTHER | |||||||
Deferred income taxes | 3,048,007 | 2,945,232 | |||||
Regulatory liabilities (Note 3) | 940,106 | 948,916 | |||||
Liabilities for asset retirements | 631,657 | 615,340 | |||||
Liabilities for pension benefits (Note 4) | 460,368 | 509,310 | |||||
Liabilities from risk management activities (Note 6) | 46,586 | 47,238 | |||||
Customer advances | 98,795 | 88,672 | |||||
Coal mine reclamation | 236,811 | 221,910 | |||||
Deferred investment tax credit | 206,969 | 210,162 | |||||
Unrecognized tax benefits | 10,307 | 10,046 | |||||
Other | 168,930 | 156,784 | |||||
Total deferred credits and other | 5,848,536 | 5,753,610 | |||||
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7) | |||||||
EQUITY | |||||||
Common stock, no par value; authorized 150,000,000 shares, 111,642,680 and 111,392,053 issued at respective dates | 2,604,482 | 2,596,030 | |||||
Treasury stock at cost; 19,298 and 55,317 shares at respective dates | (1,553 | ) | (4,133 | ) | |||
Total common stock | 2,602,929 | 2,591,897 | |||||
Retained earnings | 2,300,109 | 2,255,547 | |||||
Accumulated other comprehensive loss: | |||||||
Pension and other postretirement benefits | (39,882 | ) | (39,070 | ) | |||
Derivative instruments | (3,744 | ) | (4,752 | ) | |||
Total accumulated other comprehensive loss | (43,626 | ) | (43,822 | ) | |||
Total shareholders’ equity | 4,859,412 | 4,803,622 | |||||
Noncontrolling interests (Note 5) | 130,665 | 132,290 | |||||
Total equity | 4,990,077 | 4,935,912 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 16,669,727 | $ | 16,004,253 |
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||
Net income | $ | 200,502 | $ | 135,508 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization including nuclear fuel | 291,285 | 282,291 | |||||
Deferred fuel and purchased power | (21,993 | ) | (21,026 | ) | |||
Deferred fuel and purchased power amortization | (13,663 | ) | 13,778 | ||||
Allowance for equity funds used during construction | (19,938 | ) | (20,885 | ) | |||
Deferred income taxes | 94,365 | 65,881 | |||||
Deferred investment tax credit | (3,194 | ) | (2,083 | ) | |||
Change in derivative instruments fair value | (222 | ) | (237 | ) | |||
Stock compensation | 12,891 | 25,048 | |||||
Changes in current assets and liabilities: | |||||||
Customer and other receivables | (62,624 | ) | (19,898 | ) | |||
Accrued unbilled revenues | (105,754 | ) | (101,331 | ) | |||
Materials, supplies and fossil fuel | (5,437 | ) | 1,551 | ||||
Income tax receivable | (322 | ) | 589 | ||||
Other current assets | (23,418 | ) | (5,649 | ) | |||
Accounts payable | 21,771 | 47,621 | |||||
Accrued taxes | 11,745 | 6,567 | |||||
Other current liabilities | (44,778 | ) | 53,912 | ||||
Change in margin and collateral accounts — assets | (71 | ) | (34 | ) | |||
Change in margin and collateral accounts — liabilities | (4,700 | ) | 18,010 | ||||
Change in other long-term assets | (49,162 | ) | (41,101 | ) | |||
Change in other long-term liabilities | 13,279 | (16,037 | ) | ||||
Net cash flow provided by operating activities | 290,562 | 422,475 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||
Capital expenditures | (693,626 | ) | (731,609 | ) | |||
Contributions in aid of construction | 18,032 | 29,127 | |||||
Allowance for borrowed funds used during construction | (9,378 | ) | (10,528 | ) | |||
Proceeds from nuclear decommissioning trust sales | 275,364 | 290,594 | |||||
Investment in nuclear decommissioning trust | (276,505 | ) | (291,734 | ) | |||
Other | (2,127 | ) | (1,307 | ) | |||
Net cash flow used for investing activities | (688,240 | ) | (715,457 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||
Issuance of long-term debt | 251,635 | 445,933 | |||||
Repayment of long-term debt | — | (76,850 | ) | ||||
Short-term borrowing and payments — net | 287,800 | 64,140 | |||||
Short-term debt borrowings under revolving credit facility | 17,000 | — | |||||
Dividends paid on common stock | (142,520 | ) | (135,335 | ) | |||
Common stock equity issuance - net of purchases | (8,792 | ) | 10,017 | ||||
Distributions to noncontrolling interests | (11,372 | ) | (11,372 | ) | |||
Other | (1 | ) | 1 | ||||
Net cash flow provided by financing activities | 393,750 | 296,534 | |||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (3,928 | ) | 3,552 | ||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,881 | 39,488 | |||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 4,953 | $ | 43,040 |
Common Stock | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||||||||||
Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||
Balance, January 1, 2016 | 111,095,402 | $ | 2,541,668 | (115,030 | ) | $ | (5,806 | ) | $ | 2,092,803 | $ | (44,748 | ) | $ | 135,540 | $ | 4,719,457 | ||||||||||||
Net income | — | — | 125,761 | — | 9,747 | 135,508 | |||||||||||||||||||||||
Other comprehensive income | — | — | — | 1,029 | — | 1,029 | |||||||||||||||||||||||
Dividends on common stock | — | — | (138,947 | ) | — | — | (138,947 | ) | |||||||||||||||||||||
Issuance of common stock | 80,098 | 7,830 | — | — | — | — | 7,830 | ||||||||||||||||||||||
Purchase of treasury stock (a) | — | (71,962 | ) | (4,880 | ) | — | — | — | (4,880 | ) | |||||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | — | 185,092 | 10,556 | 2 | — | — | 10,558 | ||||||||||||||||||||||
Capital activities by noncontrolling interests | — | — | — | — | (11,372 | ) | (11,372 | ) | |||||||||||||||||||||
Balance, June 30, 2016 | 111,175,500 | $ | 2,549,498 | (1,900 | ) | $ | (130 | ) | $ | 2,079,619 | $ | (43,719 | ) | $ | 133,915 | $ | 4,719,183 | ||||||||||||
Balance, January 1, 2017 | 111,392,053 | $ | 2,596,030 | (55,317 | ) | $ | (4,133 | ) | $ | 2,255,547 | $ | (43,822 | ) | $ | 132,290 | $ | 4,935,912 | ||||||||||||
Net income | — | — | 190,755 | — | 9,747 | 200,502 | |||||||||||||||||||||||
Other comprehensive income | — | — | — | 196 | — | 196 | |||||||||||||||||||||||
Dividends on common stock | — | — | (146,204 | ) | — | — | (146,204 | ) | |||||||||||||||||||||
Issuance of common stock | 250,627 | 8,452 | — | — | — | — | 8,452 | ||||||||||||||||||||||
Purchase of treasury stock (a) | — | (156,172 | ) | (12,430 | ) | — | — | — | (12,430 | ) | |||||||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | — | 192,191 | 15,010 | 11 | — | — | 15,021 | ||||||||||||||||||||||
Capital activities by noncontrolling interests | — | — | — | — | (11,372 | ) | (11,372 | ) | |||||||||||||||||||||
Balance, June 30, 2017 | 111,642,680 | $ | 2,604,482 | (19,298 | ) | $ | (1,553 | ) | $ | 2,300,109 | $ | (43,626 | ) | $ | 130,665 | $ | 4,990,077 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
ELECTRIC OPERATING REVENUES | $ | 942,615 | $ | 909,757 | $ | 1,619,485 | $ | 1,586,389 | ||||||||
OPERATING EXPENSES | ||||||||||||||||
Fuel and purchased power | 259,892 | 274,848 | 476,995 | 496,133 | ||||||||||||
Operations and maintenance | 208,286 | 233,712 | 420,505 | 472,423 | ||||||||||||
Depreciation and amortization | 125,317 | 123,033 | 252,524 | 242,479 | ||||||||||||
Income taxes | 92,381 | 70,444 | 103,754 | 76,294 | ||||||||||||
Taxes other than income taxes | 43,949 | 42,036 | 87,447 | 84,446 | ||||||||||||
Total | 729,825 | 744,073 | 1,341,225 | 1,371,775 | ||||||||||||
OPERATING INCOME | 212,790 | 165,684 | 278,260 | 214,614 | ||||||||||||
OTHER INCOME (DEDUCTIONS) | ||||||||||||||||
Income taxes | 3,856 | 1,721 | 6,579 | 3,536 | ||||||||||||
Allowance for equity funds used during construction | 10,456 | 10,369 | 19,938 | 20,885 | ||||||||||||
Other income (Note 8) | 1,142 | 5,747 | 2,204 | 6,357 | ||||||||||||
Other expense (Note 8) | (5,651 | ) | (4,430 | ) | (10,029 | ) | (9,180 | ) | ||||||||
Total | 9,803 | 13,407 | 18,692 | 21,598 | ||||||||||||
INTEREST EXPENSE | ||||||||||||||||
Interest on long-term debt | 49,989 | 48,903 | 97,480 | 95,722 | ||||||||||||
Interest on short-term borrowings | 2,331 | 1,930 | 4,459 | 4,007 | ||||||||||||
Debt discount, premium and expense | 1,197 | 1,195 | 2,374 | 2,334 | ||||||||||||
Allowance for borrowed funds used during construction | (4,906 | ) | (4,999 | ) | (9,378 | ) | (10,039 | ) | ||||||||
Total | 48,611 | 47,029 | 94,935 | 92,024 | ||||||||||||
NET INCOME | 173,982 | 132,062 | 202,017 | 144,188 | ||||||||||||
Less: Net income attributable to noncontrolling interests (Note 5) | 4,874 | 4,874 | 9,747 | 9,747 | ||||||||||||
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 169,108 | $ | 127,188 | $ | 192,270 | $ | 134,441 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
NET INCOME | $ | 173,982 | $ | 132,062 | $ | 202,017 | $ | 144,188 | |||||||
OTHER COMPREHENSIVE INCOME, NET OF TAX | |||||||||||||||
Derivative instruments: | |||||||||||||||
Net unrealized gain (loss), net of tax expense of $4, $80, $679 and $626 for the respective periods | 7 | 128 | (763 | ) | (566 | ) | |||||||||
Reclassification of net realized loss, net of tax (benefit) expense of ($348), ($392), $8 and ($191) for the respective periods | 564 | 624 | 1,771 | 1,766 | |||||||||||
Pension and other postretirement benefits activity, net of tax benefit (expense) of $808, $403, $218 and ($156) for the respective periods | (1,308 | ) | (642 | ) | (697 | ) | (31 | ) | |||||||
Total other comprehensive income (loss) | (737 | ) | 110 | 311 | 1,169 | ||||||||||
COMPREHENSIVE INCOME | 173,245 | 132,172 | 202,328 | 145,357 | |||||||||||
Less: Comprehensive income attributable to noncontrolling interests | 4,874 | 4,874 | 9,747 | 9,747 | |||||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 168,371 | $ | 127,298 | $ | 192,581 | $ | 135,610 |
June 30, 2017 | December 31, 2016 | ||||||
ASSETS | |||||||
PROPERTY, PLANT AND EQUIPMENT | |||||||
Plant in service and held for future use | $ | 17,112,413 | $ | 17,228,787 | |||
Accumulated depreciation and amortization | (5,865,446 | ) | (5,881,941 | ) | |||
Net | 11,246,967 | 11,346,846 | |||||
Construction work in progress | 1,157,017 | 989,497 | |||||
Palo Verde sale leaseback, net of accumulated depreciation (Note 5) | 111,580 | 113,515 | |||||
Intangible assets, net of accumulated amortization | 265,764 | 89,868 | |||||
Nuclear fuel, net of accumulated amortization | 118,909 | 119,004 | |||||
Total property, plant and equipment | 12,900,237 | 12,658,730 | |||||
INVESTMENTS AND OTHER ASSETS | |||||||
Nuclear decommissioning trust (Note 11) | 822,244 | 779,586 | |||||
Assets from risk management activities (Note 6) | 55 | 1 | |||||
Other assets | 49,798 | 48,320 | |||||
Total investments and other assets | 872,097 | 827,907 | |||||
CURRENT ASSETS | |||||||
Cash and cash equivalents | 4,851 | 8,840 | |||||
Customer and other receivables | 285,482 | 262,611 | |||||
Accrued unbilled revenues | 213,703 | 107,949 | |||||
Allowance for doubtful accounts | (2,151 | ) | (3,037 | ) | |||
Materials and supplies (at average cost) | 256,828 | 252,777 | |||||
Fossil fuel (at average cost) | 29,890 | 28,608 | |||||
Income tax receivable | — | 11,174 | |||||
Assets from risk management activities (Note 6) | 307 | 19,694 | |||||
Deferred fuel and purchased power regulatory asset (Note 3) | 48,122 | 12,465 | |||||
Other regulatory assets (Note 3) | 172,606 | 94,410 | |||||
Other current assets | 38,743 | 41,849 | |||||
Total current assets | 1,048,381 | 837,340 | |||||
DEFERRED DEBITS | |||||||
Regulatory assets (Note 3) | 1,415,091 | 1,313,428 | |||||
Assets for other postretirement benefits (Note 4) | 181,237 | 162,911 | |||||
Other | 129,423 | 130,859 | |||||
Total deferred debits | 1,725,751 | 1,607,198 | |||||
TOTAL ASSETS | $ | 16,546,466 | $ | 15,931,175 |
June 30, 2017 | December 31, 2016 | ||||||
LIABILITIES AND EQUITY | |||||||
CAPITALIZATION | |||||||
Common stock | $ | 178,162 | $ | 178,162 | |||
Additional paid-in capital | 2,421,696 | 2,421,696 | |||||
Retained earnings | 2,377,315 | 2,331,245 | |||||
Accumulated other comprehensive loss: | |||||||
Pension and other postretirement benefits | (21,368 | ) | (20,671 | ) | |||
Derivative instruments | (3,744 | ) | (4,752 | ) | |||
Total accumulated other comprehensive loss | (25,112 | ) | (25,423 | ) | |||
Total shareholder equity | 4,952,061 | 4,905,680 | |||||
Noncontrolling interests (Note 5) | 130,665 | 132,290 | |||||
Total equity | 5,082,726 | 5,037,970 | |||||
Long-term debt less current maturities (Note 2) | 4,192,520 | 4,021,785 | |||||
Total capitalization | 9,275,246 | 9,059,755 | |||||
CURRENT LIABILITIES | |||||||
Short-term borrowings (Note 2) | 385,700 | 135,500 | |||||
Current maturities of long-term debt (Note 2) | 82,000 | — | |||||
Accounts payable | 265,291 | 259,161 | |||||
Accrued taxes | 147,335 | 130,576 | |||||
Accrued interest | 52,752 | 52,525 | |||||
Common dividends payable | 73,100 | 72,900 | |||||
Customer deposits | 72,585 | 82,520 | |||||
Liabilities from risk management activities (Note 6) | 48,613 | 25,836 | |||||
Liabilities for asset retirements | 8,499 | 8,703 | |||||
Regulatory liabilities (Note 3) | 91,173 | 99,899 | |||||
Other current liabilities | 180,095 | 226,417 | |||||
Total current liabilities | 1,407,143 | 1,094,037 | |||||
DEFERRED CREDITS AND OTHER | |||||||
Deferred income taxes | 3,095,019 | 2,999,295 | |||||
Regulatory liabilities (Note 3) | 940,106 | 948,916 | |||||
Liabilities for asset retirements | 623,437 | 607,234 | |||||
Liabilities for pension benefits (Note 4) | 440,016 | 488,253 | |||||
Liabilities from risk management activities (Note 6) | 46,586 | 47,238 | |||||
Customer advances | 98,795 | 88,672 | |||||
Coal mine reclamation | 221,295 | 206,645 | |||||
Deferred investment tax credit | 206,969 | 210,162 | |||||
Unrecognized tax benefits | 37,669 | 37,408 | |||||
Other | 154,185 | 143,560 | |||||
Total deferred credits and other | 5,864,077 | 5,777,383 | |||||
COMMITMENTS AND CONTINGENCIES (SEE NOTE 7) | |||||||
TOTAL LIABILITIES AND EQUITY | $ | 16,546,466 | $ | 15,931,175 |
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||
Net income | $ | 202,017 | $ | 144,188 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization including nuclear fuel | 290,444 | 282,221 | |||||
Deferred fuel and purchased power | (21,994 | ) | (21,026 | ) | |||
Deferred fuel and purchased power amortization | (13,663 | ) | 13,778 | ||||
Allowance for equity funds used during construction | (19,938 | ) | (20,885 | ) | |||
Deferred income taxes | 87,412 | 60,131 | |||||
Deferred investment tax credit | (3,194 | ) | (2,083 | ) | |||
Change in derivative instruments fair value | (222 | ) | (237 | ) | |||
Changes in current assets and liabilities: | |||||||
Customer and other receivables | (41,422 | ) | (19,809 | ) | |||
Accrued unbilled revenues | (105,754 | ) | (101,331 | ) | |||
Materials, supplies and fossil fuel | (5,333 | ) | 1,551 | ||||
Income tax receivable | 11,174 | — | |||||
Other current assets | (20,039 | ) | (3,749 | ) | |||
Accounts payable | 20,147 | 48,593 | |||||
Accrued taxes | 16,759 | 17,141 | |||||
Other current liabilities | (33,408 | ) | 44,711 | ||||
Change in margin and collateral accounts — assets | (71 | ) | (34 | ) | |||
Change in margin and collateral accounts — liabilities | (4,700 | ) | 18,010 | ||||
Change in other long-term assets | (45,420 | ) | (38,780 | ) | |||
Change in other long-term liabilities | 13,061 | 3,979 | |||||
Net cash flow provided by operating activities | 325,856 | 426,369 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||
Capital expenditures | (680,343 | ) | (717,729 | ) | |||
Contributions in aid of construction | 18,032 | 29,127 | |||||
Allowance for borrowed funds used during construction | (9,378 | ) | (10,039 | ) | |||
Proceeds from nuclear decommissioning trust sales | 275,364 | 290,594 | |||||
Investment in nuclear decommissioning trust | (276,505 | ) | (291,734 | ) | |||
Other | (1,478 | ) | (388 | ) | |||
Net cash flow used for investing activities | (674,308 | ) | (700,169 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||
Issuance of long-term debt | 251,635 | 445,933 | |||||
Short-term borrowings and payments — net | 250,200 | 64,140 | |||||
Repayment of long-term debt | — | (76,850 | ) | ||||
Dividends paid on common stock | (146,000 | ) | (138,900 | ) | |||
Distributions to noncontrolling interests | (11,372 | ) | (11,372 | ) | |||
Net cash flow provided by financing activities | 344,463 | 282,951 | |||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (3,989 | ) | 9,151 | ||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 8,840 | 22,056 | |||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 4,851 | $ | 31,207 | |||
Supplemental disclosure of cash flow information | |||||||
Cash paid during the period for: | |||||||
Income taxes, net of refunds | $ | 1 | $ | 8,772 | |||
Interest, net of amounts capitalized | $ | 92,334 | $ | 88,066 | |||
Significant non-cash investing and financing activities: | |||||||
Accrued capital expenditures | $ | 82,621 | $ | 55,286 | |||
Dividends declared but not yet paid | $ | 73,100 | $ | 69,500 |
Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | |||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||||
Balance, January 1, 2016 | 71,264,947 | $ | 178,162 | $ | 2,379,696 | $ | 2,148,493 | $ | (27,097 | ) | $ | 135,540 | $ | 4,814,794 | ||||||||||||
Net income | — | — | 134,441 | — | 9,747 | 144,188 | ||||||||||||||||||||
Other comprehensive income | — | — | — | 1,169 | — | 1,169 | ||||||||||||||||||||
Dividends on common stock | — | — | (139,000 | ) | — | — | (139,000 | ) | ||||||||||||||||||
Net capital activities by noncontrolling interests | — | — | — | — | (11,372 | ) | (11,372 | ) | ||||||||||||||||||
Balance, June 30, 2016 | 71,264,947 | $ | 178,162 | $ | 2,379,696 | $ | 2,143,934 | $ | (25,928 | ) | $ | 133,915 | $ | 4,809,779 | ||||||||||||
Balance, January 1, 2017 | 71,264,947 | $ | 178,162 | $ | 2,421,696 | $ | 2,331,245 | $ | (25,423 | ) | $ | 132,290 | $ | 5,037,970 | ||||||||||||
Net income | — | — | 192,270 | — | 9,747 | 202,017 | ||||||||||||||||||||
Other comprehensive income | — | — | — | 311 | — | 311 | ||||||||||||||||||||
Dividends on common stock | (146,200 | ) | (146,200 | ) | ||||||||||||||||||||||
Net capital activities by noncontrolling interests | — | — | — | — | (11,372 | ) | (11,372 | ) | ||||||||||||||||||
Balance, June 30, 2017 | 71,264,947 | $ | 178,162 | $ | 2,421,696 | $ | 2,377,315 | $ | (25,112 | ) | $ | 130,665 | $ | 5,082,726 |
1. | Consolidation and Nature of Operations |
Statements of Cash Flows for the Six Months Ended June 30, 2016 | As previously reported | Reclassifications to conform to current year presentation | Amount reported after reclassification to conform to current year presentation | ||||||||
Cash Flows from Operating Activities | |||||||||||
Stock compensation | $ | — | $ | 25,048 | $ | 25,048 | |||||
Change in other long-term liabilities | 9,011 | (25,048 | ) | (16,037 | ) |
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
Cash paid during the period for: | |||||||
Income taxes, net of refunds | $ | 2,062 | $ | 2,503 | |||
Interest, net of amounts capitalized | 94,870 | 89,109 | |||||
Significant non-cash investing and financing activities: | |||||||
Accrued capital expenditures | $ | 80,517 | $ | 55,286 | |||
Dividends accrued but not yet paid | 73,113 | 69,484 |
2. | Long-Term Debt and Liquidity Matters |
As of June 30, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Pinnacle West | $ | 125,000 | $ | 125,000 | $ | 125,000 | $ | 125,000 | |||||||
APS | 4,274,520 | 4,645,844 | 4,021,785 | 4,300,789 | |||||||||||
Total | $ | 4,399,520 | $ | 4,770,844 | $ | 4,146,785 | $ | 4,425,789 |
3. | Regulatory Matters |
• | an agreement by APS not to file another general 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 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 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 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 environmental improvement surcharge cumulative per kilowatt-hour (“kWh”) cap rate increase from $0.00016 to a new rate of $0.00050, which includes 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 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. |
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
Beginning balance | $ | 12,465 | $ | (9,688 | ) | ||
Deferred fuel and purchased power costs — current period | 21,994 | 21,027 | |||||
Amounts refunded/(charged) to customers | 13,663 | (13,778 | ) | ||||
Ending balance | $ | 48,122 | $ | (2,439 | ) |
• | Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS's pending rate case will be grandfathered for a period of 20 years from the date of interconnection; |
• | 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. |
Amortization Through | June 30, 2017 | December 31, 2016 | |||||||||||||||
Current | Non-Current | Current | Non-Current | ||||||||||||||
Pension | (a) | $ | — | $ | 697,184 | $ | — | $ | 711,059 | ||||||||
Retired power plant costs | Various | 19,083 | 205,418 | 9,913 | 117,591 | ||||||||||||
Income taxes — allowance for funds used during construction ("AFUDC") equity | 2047 | 6,202 | 158,356 | 6,305 | 152,118 | ||||||||||||
Deferred fuel and purchased power — mark-to-market (Note 6) | 2020 | 45,993 | 43,354 | — | 42,963 | ||||||||||||
Deferred fuel and purchased power (b) (e) | 2018 | 48,122 | — | 12,465 | — | ||||||||||||
Four Corners cost deferral | 2024 | 6,689 | 53,549 | 6,689 | 56,894 | ||||||||||||
Income taxes — investment tax credit basis adjustment | 2046 | 2,120 | 53,509 | 2,120 | 54,356 | ||||||||||||
Lost fixed cost recovery (b) | 2018 | 75,070 | — | 61,307 | — | ||||||||||||
Palo Verde VIEs (Note 5) | 2046 | — | 19,085 | — | 18,775 | ||||||||||||
Deferred compensation | 2036 | — | 37,161 | — | 35,595 | ||||||||||||
Deferred property taxes | (c) | — | 85,694 | — | 73,200 | ||||||||||||
Loss on reacquired debt | 2038 | 1,637 | 16,124 | 1,637 | 16,942 | ||||||||||||
Tax expense of Medicare subsidy | 2024 | 1,503 | 9,922 | 1,513 | 10,589 | ||||||||||||
Demand Side Management | 2018 | 5,122 | — | 3,744 | — | ||||||||||||
AG-1 deferral | (f) | — | 10,058 | — | 5,868 | ||||||||||||
Mead-Phoenix transmission line CIAC | 2050 | 332 | 10,542 | 332 | 10,708 | ||||||||||||
Transmission cost adjustor (b) | 2018 | 8,115 | — | — | 1,588 | ||||||||||||
Coal reclamation | 2026 | 418 | 15,135 | 418 | 5,182 | ||||||||||||
Other | Various | 322 | — | 432 | — | ||||||||||||
Total regulatory assets (d) | $ | 220,728 | $ | 1,415,091 | $ | 106,875 | $ | 1,313,428 |
(a) | See Note 4 for further discussion. |
(b) | See "Cost Recovery Mechanisms" discussion above. |
(c) | Per the provision of the 2012 Settlement Agreement. |
(d) | There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters." |
(e) | Subject to a carrying charge. |
(f) | Amortization is expected through 2022, but the balance is classified as non-current since the related 2017 Settlement Agreement was not approved as of June 30, 2017. |
Amortization Through | June 30, 2017 | December 31, 2016 | |||||||||||||||
Current | Non-Current | Current | Non-Current | ||||||||||||||
Asset retirement obligations | 2057 | $ | — | $ | 321,732 | $ | — | $ | 279,976 | ||||||||
Removal costs | (a) | 37,943 | 189,959 | 29,899 | 223,145 | ||||||||||||
Other postretirement benefits | (b) | 32,725 | 107,764 | 32,662 | 123,913 | ||||||||||||
Income taxes — deferred investment tax credit | 2046 | 4,315 | 107,153 | 4,368 | 108,827 | ||||||||||||
Income taxes — change in rates | 2046 | 2,565 | 68,583 | 1,771 | 70,898 | ||||||||||||
Spent nuclear fuel | 2047 | — | 71,996 | — | 71,726 | ||||||||||||
Renewable energy standard (c) | 2018 | 11,519 | — | 26,809 | — | ||||||||||||
Demand side management (c) | 2019 | — | 19,921 | — | 20,472 | ||||||||||||
Sundance maintenance | 2030 | — | 16,092 | — | 15,287 | ||||||||||||
Deferred gains on utility property | 2019 | 2,063 | 7,851 | 2,063 | 8,895 | ||||||||||||
Four Corners coal reclamation | 2031 | — | 20,894 | — | 18,248 | ||||||||||||
Other | Various | 43 | 8,161 | 2,327 | 7,529 | ||||||||||||
Total regulatory liabilities | $ | 91,173 | $ | 940,106 | $ | 99,899 | $ | 948,916 |
(a) | In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal. |
(b) | See Note 4 for further discussion. |
(c) | See "Cost Recovery Mechanisms" discussion above. |
4. | Retirement Plans and Other Postretirement Benefits |
Pension Benefits | Other Benefits | ||||||||||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||
2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||
Service cost — benefits earned during the period | $ | 13,669 | $ | 12,630 | $ | 27,429 | $ | 26,896 | $ | 4,201 | $ | 3,560 | $ | 8,559 | $ | 7,497 | |||||||||||||||
Interest cost on benefit obligation | 32,177 | 32,878 | 64,878 | 65,823 | 7,415 | 7,519 | 14,980 | 14,860 | |||||||||||||||||||||||
Expected return on plan assets | (43,425 | ) | (43,161 | ) | (87,135 | ) | (86,953 | ) | (13,350 | ) | (9,125 | ) | (26,701 | ) | (18,247 | ) | |||||||||||||||
Amortization of: | |||||||||||||||||||||||||||||||
Prior service cost (credit) | 20 | 132 | 41 | 263 | (9,461 | ) | (9,471 | ) | (18,921 | ) | (18,942 | ) | |||||||||||||||||||
Net actuarial loss | 11,460 | 10,627 | 23,950 | 20,358 | 1,104 | 1,349 | 2,559 | 2,295 | |||||||||||||||||||||||
Net periodic benefit cost | $ | 13,901 | $ | 13,106 | $ | 29,163 | $ | 26,387 | $ | (10,091 | ) | $ | (6,168 | ) | $ | (19,524 | ) | $ | (12,537 | ) | |||||||||||
Portion of cost charged to expense | $ | 6,894 | $ | 6,433 | $ | 14,461 | $ | 12,951 | $ | (5,004 | ) | $ | (3,027 | ) | $ | (9,682 | ) | $ | (6,153 | ) |
5. | Palo Verde Sale Leaseback Variable Interest Entities |
June 30, 2017 | December 31, 2016 | ||||||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ | 111,580 | $ | 113,515 | |||
Equity — Noncontrolling interests | 130,665 | 132,290 |
6. | Derivative Accounting |
Commodity | Quantity | ||||
Power | 908 | GWh | |||
Gas | 247 | Billion cubic feet |
Financial Statement Location | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
Commodity Contracts | 2017 | 2016 | 2017 | 2016 | ||||||||||||||
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion) | OCI — derivative instruments | $ | 11 | $ | 208 | $ | (84 | ) | $ | 60 | ||||||||
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) | Fuel and purchased power (b) | (912 | ) | (1,016 | ) | (1,763 | ) | (1,957 | ) |
(a) | During the three and six months ended June 30, 2017 and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. |
(b) | Amounts are before the effect of PSA deferrals. |
Financial Statement Location | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
Commodity Contracts | 2017 | 2016 | 2017 | 2016 | ||||||||||||||
Net Gain (Loss) Recognized in Income | Operating revenues | $ | (58 | ) | $ | 585 | $ | (346 | ) | $ | 483 | |||||||
Net Gain (Loss) Recognized in Income | Fuel and purchased power (a) | (5,416 | ) | 60,894 | (58,043 | ) | 29,958 | |||||||||||
Total | $ | (5,474 | ) | $ | 61,479 | $ | (58,389 | ) | $ | 30,441 |
(a) | Amounts are before the effect of PSA deferrals. |
As of June 30, 2017: (dollars in thousands) | Gross Recognized Derivatives (a) | Amounts Offset (b) | Net Recognized Derivatives | Other (c) | Amount Reported on Balance Sheet | |||||||||||||||
Current assets | $ | 15,624 | $ | (15,387 | ) | $ | 237 | $ | 70 | $ | 307 | |||||||||
Investments and other assets | 1,620 | (1,565 | ) | 55 | — | 55 | ||||||||||||||
Total assets | 17,244 | (16,952 | ) | 292 | 70 | 362 | ||||||||||||||
Current liabilities | (64,646 | ) | 18,587 | (46,059 | ) | (2,554 | ) | (48,613 | ) | |||||||||||
Deferred credits and other | (48,151 | ) | 1,565 | (46,586 | ) | — | (46,586 | ) | ||||||||||||
Total liabilities | (112,797 | ) | 20,152 | (92,645 | ) | (2,554 | ) | (95,199 | ) | |||||||||||
Total | $ | (95,553 | ) | $ | 3,200 | $ | (92,353 | ) | $ | (2,484 | ) | $ | (94,837 | ) |
(a) | All of our gross recognized derivative instruments were subject to master netting arrangements. |
(b) | Includes cash collateral provided to counterparties of $3,200. |
(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. Includes cash collateral received from counterparties of $2,554, and cash margin provided to counterparties of $70. |
As of December 31, 2016: (dollars in thousands) | Gross Recognized Derivatives (a) | Amounts Offset (b) | Net Recognized Derivatives | Other (c) | Amount Reported on Balance Sheet | |||||||||||||||
Current assets | $ | 48,094 | $ | (28,400 | ) | $ | 19,694 | $ | — | $ | 19,694 | |||||||||
Investments and other assets | 6,704 | (6,703 | ) | 1 | — | 1 | ||||||||||||||
Total assets | 54,798 | (35,103 | ) | 19,695 | — | 19,695 | ||||||||||||||
Current liabilities | (50,182 | ) | 28,400 | (21,782 | ) | (4,054 | ) | (25,836 | ) | |||||||||||
Deferred credits and other | (53,941 | ) | 6,703 | (47,238 | ) | — | (47,238 | ) | ||||||||||||
Total liabilities | (104,123 | ) | 35,103 | (69,020 | ) | (4,054 | ) | (73,074 | ) | |||||||||||
Total | $ | (49,325 | ) | $ | — | $ | (49,325 | ) | $ | (4,054 | ) | $ | (53,379 | ) |
(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. Includes cash collateral received from counterparties of $4,054. |
June 30, 2017 | |||
Aggregate fair value of derivative instruments in a net liability position | $ | 112,797 | |
Cash collateral posted | 3,200 | ||
Additional cash collateral in the event credit-risk-related contingent features were fully triggered (a) | 89,336 |
(a) | This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above. |
7. | Commitments and Contingencies |
8. | Other Income and Other Expense |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Other income: | |||||||||||||||
Interest income | $ | 387 | $ | 184 | $ | 864 | $ | 302 | |||||||
Investment gains — net | — | 13 | — | 13 | |||||||||||
Miscellaneous | 97 | — | 100 | (1 | ) | ||||||||||
Total other income | $ | 484 | $ | 197 | $ | 964 | $ | 314 | |||||||
Other expense: | |||||||||||||||
Non-operating costs | $ | (3,401 | ) | $ | (2,085 | ) | $ | (5,360 | ) | $ | (4,133 | ) | |||
Investment losses — net | (227 | ) | (539 | ) | (528 | ) | (1,058 | ) | |||||||
Miscellaneous | (194 | ) | (218 | ) | (1,614 | ) | (1,689 | ) | |||||||
Total other expense | $ | (3,822 | ) | $ | (2,842 | ) | $ | (7,502 | ) | $ | (6,880 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Other income: | |||||||||||||||
Interest income | $ | 257 | $ | 109 | $ | 596 | $ | 181 | |||||||
Gain on disposition of property | 260 | 4,989 | 567 | 5,321 | |||||||||||
Miscellaneous | 625 | 649 | 1,041 | 855 | |||||||||||
Total other income | $ | 1,142 | $ | 5,747 | $ | 2,204 | $ | 6,357 | |||||||
Other expense: | |||||||||||||||
Non-operating costs (a) | $ | (3,753 | ) | $ | (2,719 | ) | $ | (5,918 | ) | $ | (4,685 | ) | |||
Loss on disposition of property | (1,169 | ) | (657 | ) | (1,257 | ) | (1,083 | ) | |||||||
Miscellaneous | (729 | ) | (1,054 | ) | (2,854 | ) | (3,412 | ) | |||||||
Total other expense | $ | (5,651 | ) | $ | (4,430 | ) | $ | (10,029 | ) | $ | (9,180 | ) |
9. | Earnings Per Share |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Net income attributable to common shareholders | $ | 167,443 | $ | 121,308 | $ | 190,755 | $ | 125,761 | |||||||
Weighted average common shares outstanding — basic | 111,797 | 111,368 | 111,763 | 111,336 | |||||||||||
Net effect of dilutive securities: | |||||||||||||||
Contingently issuable performance shares and restricted stock units | 548 | 636 | 507 | 594 | |||||||||||
Weighted average common shares outstanding — diluted | 112,345 | 112,004 | 112,270 | 111,930 | |||||||||||
Earnings per weighted-average common share outstanding | |||||||||||||||
Net income attributable to common shareholders — basic | $ | 1.50 | $ | 1.09 | $ | 1.71 | $ | 1.13 | |||||||
Net income attributable to common shareholders — diluted | $ | 1.49 | $ | 1.08 | $ | 1.70 | $ | 1.12 |
10. | Fair Value Measurements |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (a) (Level 3) | Other | Balance at June 30, 2017 | |||||||||||||||||
Assets | |||||||||||||||||||||
Coal reclamation escrow account (b); | |||||||||||||||||||||
Municipal bonds | $ | — | $ | 14,839 | $ | — | $ | — | $ | 14,839 | |||||||||||
Risk management activities — derivative instruments: | |||||||||||||||||||||
Commodity contracts | — | 10,804 | 6,440 | (16,882 | ) | (c) | 362 | ||||||||||||||
Nuclear decommissioning trust: | |||||||||||||||||||||
U.S. commingled equity funds | — | — | — | 384,999 | (d) | 384,999 | |||||||||||||||
Fixed income securities: | |||||||||||||||||||||
Cash and cash equivalent funds | — | — | — | 1,833 | (e) | 1,833 | |||||||||||||||
U.S. Treasury | 101,337 | — | — | — | 101,337 | ||||||||||||||||
Corporate debt | — | 120,288 | — | — | 120,288 | ||||||||||||||||
Mortgage-backed securities | — | 113,950 | — | — | 113,950 | ||||||||||||||||
Municipal bonds | — | 80,659 | — | — | 80,659 | ||||||||||||||||
Other | — | 19,178 | — | — | 19,178 | ||||||||||||||||
Subtotal nuclear decommissioning trust | 101,337 | 334,075 | — | 386,832 | 822,244 | ||||||||||||||||
Total | $ | 101,337 | $ | 359,718 | $ | 6,440 | $ | 369,950 | $ | 837,445 | |||||||||||
Liabilities | |||||||||||||||||||||
Risk management activities — derivative instruments: | |||||||||||||||||||||
Commodity contracts | $ | — | $ | (70,112 | ) | $ | (42,685 | ) | $ | 17,598 | (c) | $ | (95,199 | ) |
(a) | Primarily consists of long-dated electricity contracts. |
(b) | Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. |
(c) | Represents counterparty netting, margin and collateral. See Note 6. |
(d) | Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. |
(e) | Represents nuclear decommissioning trust net pending securities sales and purchases. |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (a) (Level 3) | Other | Balance at December 31, 2016 | |||||||||||||||||
Assets | |||||||||||||||||||||
Coal reclamation trust - cash equivalents (b) | $ | 14,521 | $ | — | $ | — | $ | — | $ | 14,521 | |||||||||||
Risk management activities — derivative instruments: | |||||||||||||||||||||
Commodity contracts | — | 43,722 | 11,076 | (35,103 | ) | (c) | 19,695 | ||||||||||||||
Nuclear decommissioning trust: | |||||||||||||||||||||
U.S. commingled equity funds | — | — | — | 353,261 | (d) | 353,261 | |||||||||||||||
Fixed income securities: | |||||||||||||||||||||
Cash and cash equivalent funds | — | — | — | 795 | (e) | 795 | |||||||||||||||
U.S. Treasury | 95,441 | — | — | — | 95,441 | ||||||||||||||||
Corporate debt | — | 111,623 | — | — | 111,623 | ||||||||||||||||
Mortgage-backed securities | — | 115,337 | — | — | 115,337 | ||||||||||||||||
Municipal bonds | — | 80,997 | — | — | 80,997 | ||||||||||||||||
Other | — | 22,132 | — | — | 22,132 | ||||||||||||||||
Subtotal nuclear decommissioning trust | 95,441 | 330,089 | — | 354,056 | 779,586 | ||||||||||||||||
Total | $ | 109,962 | $ | 373,811 | $ | 11,076 | $ | 318,953 | $ | 813,802 | |||||||||||
Liabilities | |||||||||||||||||||||
Risk management activities — derivative instruments: | |||||||||||||||||||||
Commodity contracts | $ | — | $ | (45,641 | ) | $ | (58,482 | ) | $ | 31,049 | (c) | $ | (73,074 | ) |
(a) | Primarily consists of long-dated electricity contracts. |
(b) | Represents investments restricted for coal mine reclamation funding related to Four Corners. These assets are included in the Other Assets line item, reported under the Investments and Other Assets section of our Condensed Consolidated Balance Sheets. |
(c) | Represents counterparty netting, margin and collateral. See Note 6. |
(d) | Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy. |
(e) | Represents nuclear decommissioning trust net pending securities sales and purchases. |
June 30, 2017 Fair Value (thousands) | Valuation Technique | Significant Unobservable Input | Weighted-Average | ||||||||||||||
Commodity Contracts | Assets | Liabilities | Range | ||||||||||||||
Electricity: | |||||||||||||||||
Forward Contracts (a) | $ | 5,996 | $ | 25,514 | Discounted cash flows | Electricity forward price (per MWh) | $18.46 - $38.43 | $ | 28.48 | ||||||||
Natural Gas: | |||||||||||||||||
Forward Contracts (a) | 444 | 17,171 | Discounted cash flows | Natural gas forward price (per MMBtu) | $2.16 - $2.81 | $ | 2.50 | ||||||||||
Total | $ | 6,440 | $ | 42,685 |
(a) | Includes swaps and physical and financial contracts. |
December 31, 2016 Fair Value (thousands) | Valuation Technique | Significant Unobservable Input | Weighted-Average | ||||||||||||||
Commodity Contracts | Assets | Liabilities | Range | ||||||||||||||
Electricity: | |||||||||||||||||
Forward Contracts (a) | $ | 10,648 | $ | 32,042 | Discounted cash flows | Electricity forward price (per MWh) | $16.43 - $41.07 | $ | 29.86 | ||||||||
Natural Gas: | |||||||||||||||||
Forward Contracts (a) | 428 | 26,440 | Discounted cash flows | Natural gas forward price (per MMBtu) | $2.32 - $3.60 | $ | 2.81 | ||||||||||
Total | $ | 11,076 | $ | 58,482 |
(a) | Includes swaps and physical and financial contracts. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Commodity Contracts | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Net derivative balance at beginning of period | $ | (41,685 | ) | $ | (39,507 | ) | $ | (47,406 | ) | $ | (32,979 | ) | ||||
Total net gains (losses) realized/unrealized: | ||||||||||||||||
Included in OCI | (6 | ) | 104 | (6 | ) | 104 | ||||||||||
Deferred as a regulatory asset or liability | 4,252 | 1,499 | (7,503 | ) | (7,604 | ) | ||||||||||
Settlements | 1,699 | 4,502 | 3,122 | 6,267 | ||||||||||||
Transfers into Level 3 from Level 2 | (4,350 | ) | 120 | (4,388 | ) | 382 | ||||||||||
Transfers from Level 3 into Level 2 | 3,845 | 902 | 19,936 | 1,450 | ||||||||||||
Net derivative balance at end of period | $ | (36,245 | ) | $ | (32,380 | ) | $ | (36,245 | ) | $ | (32,380 | ) | ||||
Net unrealized gains included in earnings related to instruments still held at end of period | $ | — | $ | — | $ | — | $ | — |
11. | Nuclear Decommissioning Trusts |
Fair Value | Total Unrealized Gains | Total Unrealized Losses | |||||||||
June 30, 2017 | |||||||||||
Equity securities | $ | 384,999 | $ | 217,288 | $ | — | |||||
Fixed income securities | 435,412 | 12,224 | (2,630 | ) | |||||||
Net receivables (a) | 1,833 | — | — | ||||||||
Total | $ | 822,244 | $ | 229,512 | $ | (2,630 | ) |
(a) | Net receivables/payables relate to pending purchases and sales of securities. |
Fair Value | Total Unrealized Gains | Total Unrealized Losses | |||||||||
December 31, 2016 | |||||||||||
Equity securities | $ | 353,261 | $ | 188,091 | $ | — | |||||
Fixed income securities | 425,530 | 9,820 | (4,962 | ) | |||||||
Net receivables (a) | 795 | — | — | ||||||||
Total | $ | 779,586 | $ | 197,911 | $ | (4,962 | ) |
(a) | Net receivables/payables relate to pending purchases and sales of securities. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Realized gains | $ | 939 | $ | 2,282 | $ | 3,306 | $ | 4,720 | |||||||
Realized losses | (1,159 | ) | (1,350 | ) | (3,612 | ) | (3,136 | ) | |||||||
Proceeds from the sale of securities (a) | 124,238 | 148,785 | 275,364 | 290,594 |
(a) | Proceeds are reinvested in the trust. |
Fair Value | |||
Less than one year | $ | 14,979 | |
1 year – 5 years | 123,392 | ||
5 years – 10 years | 107,622 | ||
Greater than 10 years | 189,419 | ||
Total | $ | 435,412 |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
Balance at beginning of period | $ | (42,863 | ) | $ | (43,770 | ) | $ | (43,822 | ) | $ | (44,748 | ) | |||
Derivative Instruments | |||||||||||||||
OCI (loss) before reclassifications | 7 | 128 | (763 | ) | (566 | ) | |||||||||
Amounts reclassified from accumulated other comprehensive loss (a) | 564 | 624 | 1,771 | 1,766 | |||||||||||
Net current period OCI (loss) | 571 | 752 | 1,008 | 1,200 | |||||||||||
Pension and Other Postretirement Benefits | |||||||||||||||
OCI (loss) before reclassifications | (2,157 | ) | (1,585 | ) | (2,157 | ) | (1,585 | ) | |||||||
Amounts reclassified from accumulated other comprehensive loss (b) | 823 | 884 | 1,345 | 1,414 | |||||||||||
Net current period OCI (loss) | (1,334 | ) | (701 | ) | (812 | ) | (171 | ) | |||||||
Balance at end of period | $ | (43,626 | ) | $ | (43,719 | ) | $ | (43,626 | ) | $ | (43,719 | ) |
(a) | These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 6. |
(b) | These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 4. |
Three Months Ended | Six Months Ended | |||||||||||||
June 30, | June 30, | |||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||
Balance at beginning of period | $ | (24,375 | ) | $ | (26,038 | ) | $ | (25,423 | ) | $ | (27,097 | ) | ||
Derivative Instruments | ||||||||||||||
OCI (loss) before reclassifications | 7 | 128 | (763 | ) | (566 | ) | ||||||||
Amounts reclassified from accumulated other comprehensive loss (a) | 564 | 624 | 1,771 | 1,766 | ||||||||||
Net current period OCI (loss) | 571 | 752 | 1,008 | 1,200 | ||||||||||
Pension and Other Postretirement Benefits | ||||||||||||||
OCI (loss) before reclassifications | (2,121 | ) | (1,521 | ) | (2,121 | ) | (1,521 | ) | ||||||
Amounts reclassified from accumulated other comprehensive loss (b) | 813 | 879 | 1,424 | 1,490 | ||||||||||
Net current period OCI (loss) | (1,308 | ) | (642 | ) | (697 | ) | (31 | ) | ||||||
Balance at end of period | $ | (25,112 | ) | $ | (25,928 | ) | $ | (25,112 | ) | $ | (25,928 | ) |
(a) | These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA. See Note 6. |
(b) | These amounts primarily represent amortization of actuarial loss and are included in the computation of net periodic pension cost. See Note 4. |
Net Capacity in Operation (MW) | Net Capacity Planned / Under Development (MW) | ||||
Total APS Owned: Solar (a) | 239 | — | |||
Purchased Power Agreements: | |||||
Solar | 310 | — | |||
Wind | 289 | — | |||
Geothermal | 10 | — | |||
Biomass | 14 | — | |||
Biogas | 6 | — | |||
Total Purchased Power Agreements | 629 | — | |||
Total Distributed Energy: Solar (b) | 648 | 67 (c) | |||
Total Renewable Portfolio | 1,516 | 67 |
(c) | Applications received by APS that are not yet installed and online. |
• | Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS's pending rate case will be grandfathered for a period of 20 years from the date of interconnection; |
• | 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. |
Three Months Ended June 30, | |||||||||||
2017 | 2016 | Net Change | |||||||||
(dollars in millions) | |||||||||||
Regulated Electricity Segment: | |||||||||||
Operating revenues less fuel and purchased power expenses | $ | 683 | $ | 635 | $ | 48 | |||||
Operations and maintenance | (211 | ) | (242 | ) | 31 | ||||||
Depreciation and amortization | (125 | ) | (123 | ) | (2 | ) | |||||
Taxes other than income taxes | (44 | ) | (42 | ) | (2 | ) | |||||
All other income and expenses, net | 6 | 12 | (6 | ) | |||||||
Interest charges, net of allowance for borrowed funds used during construction | (50 | ) | (48 | ) | (2 | ) | |||||
Income taxes | (88 | ) | (66 | ) | (22 | ) | |||||
Less income related to noncontrolling interests (Note 5) | (5 | ) | (5 | ) | — | ||||||
Regulated electricity segment income | 166 | 121 | 45 | ||||||||
All other | 1 | — | 1 | ||||||||
Net Income Attributable to Common Shareholders | $ | 167 | $ | 121 | $ | 46 |
Increase (Decrease) | |||||||||||
Operating revenues | Fuel and purchased power expenses | Net change | |||||||||
(dollars in millions) | |||||||||||
Transmission revenues (Note 3): | |||||||||||
Higher transmission revenues | $ | 10 | $ | — | $ | 10 | |||||
Absence of 2016 FERC disallowance | 12 | — | 12 | ||||||||
Higher retail sales due to customer growth and changes in usage patterns | 25 | 7 | 18 | ||||||||
Lost fixed cost recovery | 7 | — | 7 | ||||||||
Effects of weather | 4 | 1 | 3 | ||||||||
Higher demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power, partially offset in operations and maintenance costs | 3 | 2 | 1 | ||||||||
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (25 | ) | (25 | ) | — | ||||||
Miscellaneous items, net | (3 | ) | — | (3 | ) | ||||||
Total | $ | 33 | $ | (15 | ) | $ | 48 |
• | A decrease of $15 million in fossil generation costs primarily due to less planned outage activity in the current year period; |
• | A decrease of $6 million for employee benefit costs primarily related to the adoption of new stock compensation guidance in the fourth quarter of 2016; |
• | A decrease of $6 million for Palo Verde costs; |
• | A decrease of $6 million primarily due to the absence of 2016 costs to support the Company's positions on a solar net metering ballot initiative in Arizona; |
• | A decrease of $2 million related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; |
• | An increase of $5 million related to the Navajo Plant canceled capital projects due to the expected plant retirement which were deferred for regulatory recovery in depreciation; and |
• | A decrease of $1 million related to miscellaneous other factors. |
Six Months Ended June 30, | |||||||||||
2017 | 2016 | Net Change | |||||||||
(dollars in millions) | |||||||||||
Regulated Electricity Segment: | |||||||||||
Operating revenues less fuel and purchased power expenses | $ | 1,142 | $ | 1,090 | $ | 52 | |||||
Operations and maintenance | (428 | ) | (485 | ) | 57 | ||||||
Depreciation and amortization | (253 | ) | (243 | ) | (10 | ) | |||||
Taxes other than income taxes | (88 | ) | (84 | ) | (4 | ) | |||||
All other income and expenses, net | 14 | 20 | (6 | ) | |||||||
Interest charges, net of allowance for borrowed funds used during construction | (97 | ) | (93 | ) | (4 | ) | |||||
Income taxes | (92 | ) | (68 | ) | (24 | ) | |||||
Less income related to noncontrolling interests (Note 5) | (10 | ) | (10 | ) | — | ||||||
Regulated electricity segment income | 188 | 127 | 61 | ||||||||
All other | 3 | (1 | ) | 4 | |||||||
Net Income Attributable to Common Shareholders | $ | 191 | $ | 126 | $ | 65 |
Increase (Decrease) | |||||||||||
Operating revenues | Fuel and purchased power expenses | Net change | |||||||||
(dollars in millions) | |||||||||||
Transmission revenues (Note 3): | |||||||||||
Higher transmission revenues | $ | 9 | $ | — | $ | 9 | |||||
Absence of 2016 FERC disallowance | 12 | — | 12 | ||||||||
Lost fixed cost recovery | 15 | — | 15 | ||||||||
Higher retail sales due to customer growth and changes in usage patterns | 11 | 1 | 10 | ||||||||
Effects of weather | 13 | 4 | 9 | ||||||||
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (27 | ) | (30 | ) | 3 | ||||||
Lower demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power, partially offset in operations and maintenance costs | 2 | 3 | (1 | ) | |||||||
Miscellaneous items, net | (2 | ) | 3 | (5 | ) | ||||||
Total | $ | 33 | $ | (19 | ) | $ | 52 |
• | A decrease of $33 million in fossil generation costs primarily due to less planned outage activity and lower Navajo Generating Station plant costs in the current year period; |
• | A decrease of $13 million for employee benefit costs primarily related to the adoption of new stock compensation guidance in the fourth quarter of 2016; |
• | A decrease of $7 million for Palo Verde costs; |
• | A decrease of $4 million for transmission, distribution, and customer service costs primarily due to decreased maintenance costs, partially offset by costs related to the implementation of new systems; |
• | A decrease of $6 million primarily due to the absence of 2016 costs to support the Company's positions on a solar net metering ballot initiative in Arizona; |
• | A decrease of $4 million related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; |
• | An increase of $7 million for costs primarily related to information technology and other corporate support; |
• | An increase of $5 million related to the Navajo Plant canceled capital projects due to the expected plant retirement which were deferred for regulatory recovery in depreciation; and |
• | A decrease of $2 million related to miscellaneous other factors. |
Six Months Ended June 30, | Net | ||||||||||
2017 | 2016 | Change | |||||||||
Net cash flow provided by operating activities | $ | 290 | $ | 422 | $ | (132 | ) | ||||
Net cash flow used for investing activities | (688 | ) | (715 | ) | 27 | ||||||
Net cash flow provided by financing activities | 394 | 297 | 97 | ||||||||
Net decrease in cash and cash equivalents | $ | (4 | ) | $ | 4 | $ | (8 | ) |
Six Months Ended June 30, | Net | ||||||||||
2017 | 2016 | Change | |||||||||
Net cash flow provided by operating activities | $ | 326 | $ | 426 | $ | (100 | ) | ||||
Net cash flow used for investing activities | (674 | ) | (700 | ) | 26 | ||||||
Net cash flow provided by financing activities | 344 | 283 | 61 | ||||||||
Net decrease in cash and cash equivalents | $ | (4 | ) | $ | 9 | $ | (13 | ) |
Estimated for the Year Ended December 31, | |||||||||||
2017 | 2018 | 2019 | |||||||||
APS | |||||||||||
Generation: | |||||||||||
Nuclear Fuel | $ | 70 | $ | 71 | $ | 65 | |||||
Renewables | 3 | 17 | 16 | ||||||||
Environmental | 198 | 106 | 48 | ||||||||
New Gas Generation | 237 | 119 | 8 | ||||||||
Other Generation | 147 | 175 | 168 | ||||||||
Distribution | 402 | 409 | 412 | ||||||||
Transmission | 203 | 170 | 190 | ||||||||
Other (a) | 77 | 72 | 102 | ||||||||
Total APS | $ | 1,337 | $ | 1,139 | $ | 1,009 |
Moody’s | Standard & Poor’s | Fitch | |||
Pinnacle West | |||||
Corporate credit rating | A3 | A- | A- | ||
Commercial paper | P-2 | A-2 | F2 | ||
Outlook | Stable | Stable | Stable | ||
APS | |||||
Corporate credit rating | A2 | A- | A- | ||
Senior unsecured | A2 | A- | A | ||
Commercial paper | P-1 | A-2 | F2 | ||
Outlook | Stable | Stable | Stable |
• | ASU 2014-09: Revenue recognition guidance, and related amendments, effective for us on January 1, 2018 |
• | ASU 2016-01: Financial instrument recognition and measurement guidance, effective for us on January 1, 2018 |
• | ASU 2017-07: Presentation of net periodic pension costs and net periodic postretirement benefit costs, effective for us on January 1, 2018 |
• | ASU 2017-01: Business combination guidance, clarifying the definition of a business, effective for us on January 1, 2018 |
• | ASU 2017-05: Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, effective for us on January 1, 2018 |
• | ASU 2016-02: Lease accounting guidance, effective for us on January 1, 2019 |
• | ASU 2016-13: Measurement of credit losses on financial instruments, effective for us on January 1, 2020 |
Six Months Ended June 30, | |||||||
2017 | 2016 | ||||||
Mark-to-market of net positions at beginning of year | $ | (49 | ) | $ | (154 | ) | |
Decrease (Increase) in regulatory asset/liability | (48 | ) | 70 | ||||
Recognized in OCI: | |||||||
Mark-to-market losses realized during the period | 1 | 2 | |||||
Change in valuation techniques | — | — | |||||
Mark-to-market of net positions at end of period | $ | (96 | ) | $ | (82 | ) |
Source of Fair Value | 2017 | 2018 | 2019 | 2020 | Total fair value | |||||||||||||||
Observable prices provided by other external sources | $ | (26 | ) | $ | (28 | ) | $ | (4 | ) | $ | (1 | ) | $ | (59 | ) | |||||
Prices based on unobservable inputs | (4 | ) | (10 | ) | (19 | ) | (4 | ) | (37 | ) | ||||||||||
Total by maturity | $ | (30 | ) | $ | (38 | ) | $ | (23 | ) | $ | (5 | ) | $ | (96 | ) |
June 30, 2017 | December 31, 2016 | ||||||||||||||
Gain (Loss) | Gain (Loss) | ||||||||||||||
Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||
Mark-to-market changes reported in: | |||||||||||||||
Regulatory asset (liability) or OCI (a) | |||||||||||||||
Electricity | $ | 2 | $ | (2 | ) | $ | 2 | $ | (2 | ) | |||||
Natural gas | 39 | (39 | ) | 46 | (46 | ) | |||||||||
Total | $ | 41 | $ | (41 | ) | $ | 48 | $ | (48 | ) |
(a) | These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability. |
Exhibit No. | Registrant(s) | Description | ||
10.1 | Pinnacle West | Performance Cash Award Agreement, dated May 10, 2017, between Pinnacle West and Donald E. Brandt | ||
10.2 | Pinnacle West APS | Five-Year Credit Agreement dated as of June 29, 2017, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto | ||
10.11.2a | Pinnacle West | Amendment No. 1 to Five-Year Credit Agreement dated as of May 13, 2016, among Pinnacle West, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto | ||
10.11.3a | Pinnacle West | Amendment No. 1 to 364-day Credit Agreement dated as of August 31, 2016, among Pinnacle West, as Borrower, The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Agent and Issuing Bank, and the lenders and other parties thereto | ||
10.11.7a | Pinnacle West APS | Amendment No. 1 to Five-Year Credit Agreement dated as of May 13, 2016, among APS, as Borrower, Barclays Bank PLC, as Agent and Issuing Bank, and the lenders and other parties thereto | ||
12.1 | Pinnacle West | Ratio of Earnings to Fixed Charges | ||
12.2 | APS | Ratio of Earnings to Fixed Charges | ||
12.3 | Pinnacle West | Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements | ||
31.1 | Pinnacle West | Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | ||
31.2 | Pinnacle West | Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | ||
31.3 | APS | Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | ||
31.4 | APS | Certificate of James R. Hatfield, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended | ||
32.1* | Pinnacle West | Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||
32.2* | APS | Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||
101.INS | Pinnacle West APS | XBRL Instance Document | ||
101.SCH | Pinnacle West APS | XBRL Taxonomy Extension Schema Document | ||
101.CAL | Pinnacle West APS | XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB | Pinnacle West APS | XBRL Taxonomy Extension Label Linkbase Document | ||
101.PRE | Pinnacle West APS | XBRL Taxonomy Extension Presentation Linkbase Document | ||
101.DEF | Pinnacle West APS | XBRL Taxonomy Definition Linkbase Document |
Exhibit No. | Registrant(s) | Description | Previously Filed as Exhibit(1) | Date Filed | |||||
3.1 | Pinnacle West | Pinnacle West Capital Corporation Bylaws, amended as of February 22, 2017 | 3.1 to Pinnacle West/APS February 28, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473 | 2/28/2017 | |||||
3.2 | Pinnacle West | Articles of Incorporation, restated as of May 21, 2008 | 3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | 8/7/2008 | |||||
3.3 | APS | Articles of Incorporation, restated as of May 25, 1988 | 4.2 to APS’s Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473 | 9/29/1993 | |||||
3.4 | APS | Amendment to the Articles of Incorporation of Arizona Public Service Company, amended May 16, 2012 | 3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473 | 5/22/2012 | |||||
3.5 | APS | Arizona Public Service Company Bylaws, amended as of December 16, 2008 | 3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File Nos. 1-8962 and 1-4473 | 2/20/2009 | |||||
4.1 | Pinnacle West | Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value | 4.1 to Pinnacle West June 20, 2017 Form 8-K Report, File No. 1-8962 | 6/20/2017 | |||||
10.6.6j | Pinnacle West | First Amendment to the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan | Appendix A to the Proxy Statement for Pinnacle West’s 2017 Annual Meeting of Shareholders, File No. 1-8962 | 3/31/2017 |
PINNACLE WEST CAPITAL CORPORATION | |||
(Registrant) | |||
Dated: | August 3, 2017 | By: | /s/ James R. Hatfield |
James R. Hatfield | |||
Executive Vice President and | |||
Chief Financial Officer | |||
(Principal Financial Officer and | |||
Officer Duly Authorized to sign this Report) | |||
ARIZONA PUBLIC SERVICE COMPANY | |||
(Registrant) | |||
Dated: | August 3, 2017 | By: | /s/ James R. Hatfield |
James R. Hatfield | |||
Executive Vice President and | |||
Chief Financial Officer | |||
(Principal Financial Officer and | |||
Officer Duly Authorized to sign this Report) |
A. | The Board of Directors of the Company (the “Board of Directors”) has adopted, and the Company’s shareholders have approved, the Pinnacle West Capital Corporation 2012 Long-Term Incentive Plan (the “Plan”), pursuant to which Performance Cash Awards may be granted to employees of the Company and its subsidiaries. |
B. | The Company desires to grant to Employee a Performance Cash Award under the terms of the Plan. |
C. | Pursuant to the Plan, the Company and Employee agree as follows: |
1. | Grant of Award. Pursuant to action of the Human Resources Committee of the Board (the “HRC”), on March 29, 2017, the Company grants to Employee a maximum Performance Cash Award of $4,000,000 (the “Performance Cash Award Maximum”), with the specific amount of the Award that will be earned to be determined in accordance with the terms set forth hereunder and in Attachment A attached hereto (such earned amount, the “Performance Cash Award”). |
2. | Award Subject to Plan. This Performance Cash Award is granted under and is expressly subject to all of the terms and provisions of the Plan, which terms are incorporated herein by reference, and this Award Agreement. In the event of any conflict between the terms and conditions of this Award Agreement and the Plan, the provisions of the Plan shall control. Capitalized terms shall have the meanings ascribed to them herein, in Attachment A or in the Plan. |
3. | Performance Period and Performance Criteria. |
(a) | Performance Period. The Performance Period for this Award began on January 1, 2017 and ends on February 28, 2019. |
(b) | Performance Criteria. No portion of the Performance Cash Award will be payable unless the Company’s average return on equity for the period beginning January 1, 2017 and ending December 31, 2017 is at least 8.00% (the “ROE Condition”) (except as set forth in Section 5(b) below). If the ROE condition is achieved, all, none or a portion of the Performance Cash Award Maximum may become payable, as described below. The Performance Cash Award Maximum is comprised of two tranches. Tranche 1 of the Performance Cash Award Maximum will be determined by the HRC based upon (i) the Company meeting the 2017 Earnings Threshold (as defined in Attachment A) and (ii) the satisfaction, by the ROE Determination Date, of Year 1 Milestones (as defined in Attachment A) towards the achievement of the S/D Goals (as defined in Attachment A). Tranche 2 of the Performance Cash Award Maximum will be based upon (i) the Company meeting the 2018 Earnings Threshold (as defined in Attachment A), and (ii) the |
(c) | Award Determination Dates. The HRC shall determine at the February 2018 HRC meeting (the “ROE Determination Date”) whether (i) the ROE Condition has been met, (ii) the 2017 Earnings Threshold has been met and (iii) the Year 1 Milestones have been met. The HRC shall determine at the February 2019 HRC meeting (the “Award Determination Date”) whether (i) the 2018 Earnings Threshold has been met and (ii) the S/D Goals have been met. The HRC’s determination at the ROE Determination Date whether the Year 1 Milestones have been met may not be revisited by the HRC for purposes of the determination of any subsequent Performance Cash Award, but such finding shall not prevent the HRC from determining at the Award Determination Date that the S/D Goals have been met. |
(d) | Award Conditions Adjustments. The ROE Condition, the 2017 Earnings Threshold and the 2018 Earnings Threshold shall be adjusted to exclude (i) the impact of rate adjustments related to actions of the Arizona Corporation Commission (other than the rate case of the Company that is pending as of the date of this Award Agreement), and (ii) the effects of any retirement, or other adjustments to the carrying value, of the Company’s coal plants. Any adjustments shall be confirmed by the Chief Financial Officer of the Company and communicated to the HRC with appropriate supporting calculations. |
4. | Vesting. If Employee remains employed by the Company for the entire Performance Period, or terminates employment earlier but nonetheless is potentially entitled to a payment pursuant to Section 5 below, all, none or a portion of the Performance Cash Award Target will vest based on satisfaction of the Award Conditions and the other terms set forth hereunder and in Attachment A to this Award Agreement as determined by the HRC in accordance with this Agreement. |
5. | Forfeiture. |
(a) | Failure to Meet Award Conditions. |
(i) | If the HRC determines on the ROE Determination Date that the ROE Condition has not been met, no portion of the Performance Cash Award Maximum shall be payable under this Award Agreement and the Employee shall forfeit the right to receive any Performance Cash Award hereunder and shall have no further rights with respect to such Performance Cash Award. |
(ii) | If at the Award Determination Date, the ROE Condition has been met but the HRC determines that neither the 2017 Earnings Threshold nor the 2018 Earnings Threshold has been met, no portion of the Performance Cash Award Maximum shall be payable under this Award Agreement and the Employee shall forfeit the right to receive any Performance Cash Award hereunder and shall have no further rights with respect to such Performance Cash Award. |
(iii) | If at the Award Determination Date, the ROE Condition has been met but the HRC determines that only one of either the 2017 Earnings Threshold or the 2018 Earnings Threshold has been met, in no event shall the Performance Cash Award be less than |
(b) | Death or Disability. Prior to March 1, 2018, if the Employee’s employment by the Company terminates by reason of death or if the HRC determines that Employee is suffering from a Disability, the Employee (or the Employee’s estate or permitted beneficiary(ies) in the event of the Employee’s death) will be eligible to receive all or a portion of the Performance Cash Award Maximum as the HRC shall determine in its discretion with due regard to the progress of the Employee toward meeting the applicable Award Conditions had the Employee otherwise remained employed through the Award Determination Date; provided, however, that in no event shall the Performance Cash Award be less than $2,000,000. Between March 1, 2018 and the Award Payment Date, if the Employee’s employment by the Company terminates by reason of death or if the HRC determines that Employee is suffering from a Disability, the Employee (or the Employee’s estate or permitted beneficiary(ies) in the event of the Employee’s death) will receive the entire Performance Cash Award Maximum. For purposes of this Award Agreement, Employee shall be considered to be suffering from a “Disability” if Employee is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the Company. |
(c) | Retirement. Prior to March 1, 2018, if the Employee’s employment by the Company terminates by reason of Normal Retirement (as defined in the Pinnacle West Capital Corporation Retirement Plan), then Employee shall forfeit the right to receive any Performance Cash Award hereunder and the Employee shall have no further rights with respect to such Performance Cash Award. Between March 1, 2018 and the Award Payment Date, if the Employee’s employment by the Company terminates by reason of Normal Retirement, then the Employee shall receive (i) a Performance Cash Award of $2,000,000 subject to a determination by the HRC that the (A) ROE Condition, (B) 2017 Earnings Threshold, and (C) Year 1 Milestones each have been met, plus (ii) up to an additional $2,000,000 Performance Cash Award as the HRC may determine if at the time of the Employee’s Normal Retirement, the Board has selected and elected the Employee’s successor. |
(d) | Termination For Cause. In the event Employee is terminated by the Board for Cause during the Performance Period, Employee shall forfeit the right to receive any Performance Cash Award hereunder and the Employee shall have no further rights with respect to such Performance Cash Award. For purposes only of this Section 5(d), “Cause” means (A) embezzlement, theft, fraud, deceit and/or dishonesty by the Employee involving the property, business or affairs of the Company or any of its subsidiaries, or (B) an act of moral turpitude which in the sole judgment of the Board reflects adversely on the business or reputation of the Company or any of its subsidiaries or negatively affects any of the Company’s or any of its subsidiaries’ employees or customers. |
(e) | Termination Without Cause. Prior to March 1, 2018, if the Employee’s employment as Chief Executive Officer of the Company is terminated by the Board without Cause, then |
6. | Payment. Except as otherwise provided below in this Section 6, the portion of the Performance Cash Award Maximum that vests hereunder shall be paid in cash to the Employee (or to the Employee’s estate or permitted beneficiary(ies)) on February 28, 2019 (the “Award Payment Date”). |
(a) | Death or Disability. If any payment is owed to Employee pursuant to Section 5(b) of this Award Agreement, the portion of the Performance Cash Award Maximum that vests in accordance with that provision shall be paid in cash to the Employee (or to the Employee’s estate or permitted beneficiary(ies)) within 30 days following the Employee’s death or within 30 days following the HRC’s determination that Employee is suffering from a Disability, as applicable. |
(b) | Retirement. If any payment is owed to Employee pursuant to Section 5(c) of this Award Agreement, the portion of the Performance Cash Award Maximum that vests in accordance with that provision shall be paid in cash to the Employee within 30 days following the later of (i) the Employee’s Termination of Employment or (ii) the HRC’s determination of the amount of the Award payable to the Employee pursuant to the terms of Section 5(c), but in no event later than March 15, 2019. |
(c) | Termination Without Cause. If any payment is owed to Employee pursuant to Section 5(e), the amount of the Award that vests in accordance with those provisions shall be paid in cash to the Employee within thirty (30) days of the later of (A) the ROE Determination Date or (B) the Employee’s date of Termination of Employment. Any payment made pursuant to this Section 6(c) of the Award Agreement shall be payable only upon the execution by the Employee of an appropriate release of claims against the Company and any such payment shall be in addition to all other compensation that may be owed to the Employee pursuant to any other Company benefit plans, agreements or compensatory arrangements. The release shall be provided to Employee on the date of his Termination of Employment. Employee will then have 21 days within which to consider signing the release. After signing the release, the Employee shall have seven days within which to revoke the release. If the Employee fails to sign the release, or if the Employee revokes the release, within the above-described time periods, Employee shall not be entitled to any payment pursuant to this Award Agreement. If the release consideration period and the release revocation period span two calendar years, no payment will be made until the second calendar year. |
(d) | Delay in Commencement of Payment. Notwithstanding anything herein to the contrary, if at the time of Employee’s Termination of Employment, the Employee is a "specified employee" as defined in Section 409A of the Code, and the deferral of the commencement of any payments or benefits otherwise payable hereunder as a result of such Termination of Employment is necessary in order to comply with Section 409A of the Code and to avoid the imposition of taxes or penalties thereunder, then the Company will defer the |
(e) | Impact on Retirement Plans. Any Performance Cash Award paid to Employee will be disregarded for purposes of calculating the amount of Employee’s benefit under any Company retirement plans. |
7. | Tax Withholding; Limited Acceleration of Payment. Employee is responsible for any and all federal, state, and local income, payroll or other tax obligations or withholdings (collectively, the “Taxes”) arising out of this Award. Employee shall pay any and all Taxes due in connection with a payout hereunder by check or by having the Company withhold cash from any payout of the Award. No later than June 1, 2017, Employee must elect, on the election form attached hereto, how Employee will satisfy the tax obligations upon a payout. In the absence of a timely election by Employee, Employee’s tax withholding obligation will be satisfied through the Company’s withholding cash from any payout of the Award as set forth above. |
8. | Continued Employment. Nothing in the Plan or this Award Agreement shall be interpreted to interfere with or limit in any way the right of the Company or its subsidiaries to terminate Employee’s employment or services at any time. In addition, nothing in the Plan or this Award Agreement shall be interpreted to confer upon Employee the right to continue in the employ or service of the Company or its subsidiaries. |
9. | Confidentiality. During Employee’s employment and after termination thereof, for any reason, Employee agrees that Employee will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than the Company or any of its Affiliates any Confidential Information (as hereinafter defined), whether prepared by Employee or not; provided, however, that during the term of Employee’s employment, any Confidential Information may be disclosed (i) to officers, representatives, employees and agents of the Company and its Affiliates who need to know such Confidential Information in order to perform the services or conduct the operations required or expected of them in the business, and (ii) in good faith by Employee in connection with the performance of Employee’s job duties to persons who are authorized to receive such information by the Company or its Affiliates. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is required by |
10. | Restrictive Covenants. |
(a) | Non-Competition. Employee agrees that for a period of 12 months following any Termination of Employment voluntarily by Employee (other than due to Disability), Employee shall not, without the prior written consent of the Company’s General Counsel, participate, whether as a consultant, employee, contractor, partner, owner (ownership of less than 5% of the outstanding stock of a publicly traded company will not be considered ownership under this provision), co-owner, or otherwise, with any business, corporation, group, entity or individual that is or intends to be engaged in the business activity of supplying electricity in any area of Arizona for which the Company or its Affiliates is authorized to supply electricity. |
(b) | Employee Non-Solicitation. Employee agrees that for a period of 12 months following Employee’s Termination of Employment for any reason, Employee will not encourage, induce, or otherwise solicit, or actively assist any other person or organization to encourage, induce or otherwise solicit, directly or indirectly, any employee of the Company or any of its Affiliates to terminate his or her employment with the Company or its Affiliates, or otherwise interfere with the advantageous business relationship of the Company and its Affiliates with their employees. |
(c) | Remedies. If Employee fails to comply with Sections 9, 10(a), or 10(b) in a material respect, the Company may (i) cause any of Employee’s unvested Performance Cash Award to be forfeited, (ii) refuse to deliver any cash owed hereunder, and/or (iii) pursue any other rights and remedies the Company may have pursuant to this Award Agreement or the Plan at law or in equity including, specifically, injunctive relief. If Employee is in breach of any of the provisions of this Section 10, then the time periods set forth in Sections 10(a) and (b) will be extended by the length of time during which Employee is in breach of such provisions. |
11. | Cooperation with Government Agencies. Employee shall have no obligation to keep confidential any Confidential Information, if and to the extent disclosure of any such information is specifically permitted by law, because Employee is providing information to government |
12. | Section 409A Compliance. If the Company concludes, in the exercise of its discretion, that this Award is subject to Section 409A of the Code, the Plan and this Award Agreement shall be administered in compliance with Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with Section 409A. If the Company concludes, in the exercise of its discretion, that this Award is not subject to Section 409A, but, instead, is eligible for the short-term deferral exception to the requirements of Section 409A, the Plan and this Award Agreement shall be administered to comply with the requirements of the short-term deferral exception to the requirements of Section 409A and each provision of this Award Agreement and the Plan shall be interpreted to comply with the requirements of such exception. In either event, Employee does not have any right to make any election regarding the time or form of any payment due under this Award Agreement other than the tax withholding election described in Section 7. |
13. | Clawback. The portion of this Award, if any, that is earned based on the Company’s return on equity, the 2017 Earnings Threshold or the 2018 Earnings Threshold will be subject to potential forfeiture or recovery to the extent called for by the Company’s Clawback Policy, which is intended to be responsive to the final rules to be issued by the Securities and Exchange Commission and the listing standards to be adopted by the New York Stock Exchange pursuant to Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act. The Clawback Policy may include such other provisions as the HRC determines to be necessary or appropriate either to comply with any applicable law or listing standard or in light of Company ethics or other policies and practices. Specific requirements of the Clawback Policy may be adopted and amended at such times as the HRC determines in its discretion. By accepting this Award, Employee consents and agrees to abide by such Clawback Policy. |
14. | Non-Transferability. Neither this Award nor any rights under this Award Agreement may be assigned, transferred, or in any manner encumbered except as provided in the Plan. |
15. | Definitions: Copy of Plan and Plan Prospectus. To the extent not specifically defined in this Award Agreement, all capitalized terms used in this Award Agreement will have the same meanings ascribed to them in the Plan. By signing this Award Agreement, Employee acknowledges receipt of a copy of the Plan and the related Plan prospectus. |
16. | Amendment. Except as provided below, any amendments to this Award Agreement must be made by a written agreement executed by the Company and Employee. The Company may amend this Award Agreement unilaterally, without the consent of Employee, if the change (i) is required by law or regulation, (ii) does not adversely affect in any material way the rights of Employee, or (iii) is required to cause the benefits under the Plan to qualify as performance-based compensation within the meaning of Section 162(m) of the Code or to comply with the provisions of Section 409A of the Code and applicable regulations or other interpretive authority. Additional rules relating to amendments to the Plan or any Award Agreement to assure compliance with Section 409A of the Code are set forth in Section 17.15 of the Plan. |
17. | Performance-Based Award. This Award is intended to be a Performance-Based Award if Employee is considered to be a Covered Employee for the tax year of the Company for which the Company claims a related tax deduction. |
PINNACLE WEST CAPITAL CORPORATION | |
By: /s/ Lee R. Nickloy | |
Its: Vice President and Treasurer | |
Date: May 10, 2017 | |
EMPLOYEE | |
By: /s/ Donald E. Brandt | |
Date: May 10, 2017 |
Public Debt Rating S&P/Moody’s | Eurodollar Rate Advances | Base Rate Advances | Commitment Fee |
Level 1 | |||
AA-/Aa3 or above | 0.750% | 0.000% | 0.060% |
Level 2 | |||
< Level 1 but ≥ | |||
A+/A1 | 0.875% | 0.000% | 0.075% |
Level 3 | |||
< Level 2 but ≥ | |||
A/A2 | 1.000% | 0.000% | 0.100% |
Level 4 | |||
< Level 3 but ≥ | |||
A-/A3 | 1.125% | 0.125% | 0.125% |
Level 5 | |||
< Level 4 | 1.250% | 0.250% | 0.175% |
ARIZONA PUBLIC SERVICE COMPANY | |
By: /s/ Lee R. Nickloy | |
Name: Lee R. Nickloy | |
Title: Vice President and Treasurer |
ADMINISTRATIVE AGENT: | BARCLAYS BANK PLC, as Agent, Issuing Bank and Lender | |
By /s/ Vanessa Kurbatskiy | ||
Name: Vanessa Kurbatskiy | ||
Title: Vice President |
LENDERS: | MIZUHO BANK, LTD., as a Lender and as an Issuing Bank |
By: /s/Nelson Chang | |
Name: Nelson Chang | |
Title: Authorized Signatory |
BANK OF AMERICA, N.A., as a Lender and as an Issuing Bank | |
By: /s/James B. Meanor | |
Name: James B. Meanor | |
Title: Managing Director |
JPMORGAN CHASE BANK, N.A., as a Lender and as an Issuing Bank | |
By: /s/ Nancy R. Barwig | |
Name: Nancy R. Barwig | |
Title: Credit Risk Director |
SUNTRUST BANK, as a Lender and as an Issuing Bank | |
By: /s/ Arize Agumadu | |
Name: Arize Agumadu | |
Title: Vice President |
WELLS FARGO BANK NATIONAL ASSOCIATION, as a Lender and as an Issuing Bank | |
By: /s/ Sheila Shaffer | |
Name: Sheila Shaffer | |
Title: Vice President |
MUFG UNION BANK, N.A., as a Lender and as an Issuing Bank | |
By: /s/ Maria Ferradas | |
Name: Maria Ferradas | |
Title: Director |
BNP PARIBAS, as a Lender and as an Issuing Bank | |
By: /s/ Christopher Sked | |
Name: Christopher Sked | |
Title: Managing Director | |
By: /s/ Julien Pecoud-Bouvet | |
Name: Julien Pecoud-Bouvet | |
Title: Vice President |
THE BANK OF NEW YORK MELLON, as a Lender | |
By: /s/ Mark W. Rogers | |
Name: Mark W. Rogers | |
Title: Vice President |
THE BANK OF NOVA SCOTIA, as a Lender | |
By: /s/ David Dewar | |
Name: David Dewar | |
Title: Director |
CITIBANK, N.A., as a Lender | |
By: /s/ Hans Y. Lin | |
Name: Hans Y. Lin | |
Title: Senior Vice President |
KEYBANK NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Paul J. Pace | |
Name: Paul J. Pace | |
Title: Senior Vice President |
ROYAL BANK OF CANADA, as a Lender | |
By: /s/ Rahul Shah | |
Name: Rahul Shah | |
Title: Authorized Signatory |
TD BANK, N.A., as a Lender | |
By: /s/ Vijay Prasad | |
Name: Vijay Prasad | |
Title: Senior Vice President |
US BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Holland H. Williams | |
Name: Holland H. Williams | |
Title: Vice President |
BRANCH BANKING & TRUST COMPANY, as a Lender | |
By: /s/ Lincoln LaCour | |
Name: Lincoln LaCour | |
Title: Assistant Vice President |
COBANK, ACB, as a Lender | |
By: /s/ Monika Wesorick | |
Name: Monika Wesorick | |
Title: Credit Manager, Vice President |
PNC BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Madeline L. Moran | |
Name: Madeline L. Moran | |
Title: Vice President |
Bank | Revolving Credit Commitment | Ratable Share |
Barclays Bank PLC | $34,500,000 | 6.9% |
Mizuho Bank, Ltd. | $34,500,000 | 6.9% |
Bank of America, N.A. | $34,500,000 | 6.9% |
JPMorgan Chase Bank, N.A. | $34,500,000 | 6.9% |
SunTrust Bank | $34,500,000 | 6.9% |
Wells Fargo Bank, National Association | $34,500,000 | 6.9% |
MUFG Union Bank, N.A. | $34,500,000 | 6.9% |
BNP Paribas | $34,500,000 | 6.9% |
The Bank of New York Mellon | $24,500,000 | 4.9% |
The Bank of Nova Scotia | $24,500,000 | 4.9% |
Citibank, N.A. | $24,500,000 | 4.9% |
KeyBank National Association | $24,500,000 | 4.9% |
Royal Bank of Canada | $24,500,000 | 4.9% |
TD Bank, N.A. | $24,500,000 | 4.9% |
U.S. Bank National Association | $24,500,000 | 4.9% |
Branch Banking & Trust Company | $17,500,000 | 3.5% |
CoBank, ACB | $17,500,000 | 3.5% |
PNC Bank, National Association | $17,500,000 | 3.5% |
TOTAL | $500,000,000 | 100% |
ARIZONA PUBLIC SERVICE COMPANY | ||
By _________________ | ||
Name: _________________ | ||
Title: _________________ |
Date | Amount of Advance | Amount of Principal Paid or Prepaid | Unpaid Principal Balance | Notation Made By |
(i) | The Business Day of the Proposed Borrowing is ____________, 20___. |
(ii) | The Type of Revolving Advances comprising the Proposed Borrowing is [Base Rate Advances] [Eurodollar Rate Advances]. |
(iii) | The aggregate amount of the Proposed Borrowing is $_____________. |
[(iv) | The initial Interest Period for each Eurodollar Rate Advance made as part of the Proposed Borrowing is ___month[s].] |
Very truly yours, | ||
ARIZONA PUBLIC SERVICE COMPANY | ||
By | ||
Name: | ||
Title: |
1. | Assignor: ________________________________ |
2. | Assignee: ________________________________ |
3. | Borrower: Arizona Public Service Company |
4. | Agent: Barclays Bank PLC, as the administrative agent under the Credit Agreement |
5. | Credit Agreement: The Five-Year Credit Agreement dated as of June 29, 2017, by and among the Borrower, the Lenders party thereto, the Agent and the Issuing Banks and other agents party thereto. |
6. | Assigned Interest: |
Aggregate Amount of Commitment for all Lenders | Amount of Commitment Assigned | Percentage Assigned of Commitment | CUSIP Number |
$ | $ | % | |
ASSIGNOR | ||
[NAME OF ASSIGNOR] | ||
By | ||
Name: | ||
Title: | ||
ASSIGNOR | ||
[NAME OF ASSIGNOR] | ||
By | ||
Name: | ||
Title: |
1. | Amendments to the Credit Agreement. Effective as of June 29, 2017 (the “Amendment Effective Date”) and subject to the satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is hereby amended as follows: |
2. | Conditions of Effectiveness. This Amendment shall become effective as of the Amendment Effective Date upon the Agent’s receipt of (a) duly executed counterparts of the signature pages hereof by each of the Borrower, the Required Lenders and the Agent and (b) such other documents, instruments and agreements as the Agent shall reasonably request. |
3. | Representations and Warranties and Reaffirmations of the Borrower. |
3.1. | The Borrower hereby represents and warrants that (i) this Amendment and the Credit Agreement as previously executed and as modified hereby constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar Laws affecting creditors’ rights generally, and (ii) no Default or Event of Default has occurred and is continuing. |
3.2. | Upon the effectiveness of this Amendment and after giving effect hereto, the Borrower hereby reaffirms all covenants, representations and warranties made in the Credit Agreement as modified hereby, and agrees that all such covenants, representations and warranties shall be deemed to have been remade as of the Amendment Effective Date, except that any such covenant, representation, or warranty that was made as of a specific date shall be considered reaffirmed only as of such date. |
4. | Reference to the Effect on the Credit Agreement. |
4.1. | Upon the effectiveness of Section 1 hereof, on and after the date hereof, each reference in the Credit Agreement (including any reference therein to “this Credit Agreement,” “this Agreement,” “hereunder,” “hereof,” “herein” or words of like |
4.2. | Except as specifically modified above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect, and are hereby ratified and confirmed. |
4.3. | The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith. |
4.4. | Upon satisfaction of the conditions set forth in Section 2 hereof and the execution hereof by the Borrower, the Required Lenders and the Agent, this Amendment shall be binding upon all parties to the Credit Agreement. |
4.5. | This Amendment shall constitute a Loan Document. |
5. | GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. |
6. | Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose. |
7. | Counterparts. This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act. |
PINNACLE WEST CAPITAL CORPORATION, as the Borrower | |||
By: /s/ Lee R. Nickloy | |||
Name: Lee R. Nickloy | |||
Title: Vice President and Treasurer |
BARCLAYS BANK PLC, as Agent and Lender | ||
By /s/ Vanessa Kurbatskiy | ||
Name: Vanessa Kurbatskiy | ||
Title: Vice President |
MIZUHO BANK, LTD., as a Lender | |
By: /s/Nelson Chang | |
Name: Nelson Chang | |
Title: Authorized Signatory |
BANK OF AMERICA, N.A., as a Lender | |
By: /s/James B. Meanor | |
Name: James B. Meanor | |
Title: Managing Director |
JPMORGAN CHASE BANK, N.A., as a Lender | |
By: /s/ Nancy R. Barwig | |
Name: Nancy R. Barwig | |
Title: Credit Risk Director |
SUNTRUST BANK, as a Lender | |
By: /s/ Arize Agumadu | |
Name: Arize Agumadu | |
Title: Vice President |
WELLS FARGO BANK NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Sheila Shaffer | |
Name: Sheila Shaffer | |
Title: Vice President |
MUFG UNION BANK, N.A., as a Lender and as an Issuing Bank | |
By: /s/ Maria Ferradas | |
Name: Maria Ferradas | |
Title: Director |
BNP PARIBAS, as a Lender and as an Issuing Bank | |
By: /s/ Christopher Sked | |
Name: Christopher Sked | |
Title: Managing Director | |
By: /s/ Julien Pecoud-Bouvet | |
Name: Julien Pecoud-Bouvet | |
Title: Vice President |
CITIBANK, N.A., as a Lender | |
By: /s/ Hans Y. Lin | |
Name: Hans Y. Lin | |
Title: Senior Vice President |
KEYBANK NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Paul J. Pace | |
Name: Paul J. Pace | |
Title: Senior Vice President |
ROYAL BANK OF CANADA, as a Lender | |
By: /s/ Rahul Shah | |
Name: Rahul Shah | |
Title: Authorized Signatory |
TD BANK, N.A., as a Lender | |
By: /s/ Vijay Prasad | |
Name: Vijay Prasad | |
Title: Senior Vice President |
THE BANK OF NEW YORK MELLON, as a Lender | |
By: /s/ Mark W. Rogers | |
Name: Mark W. Rogers | |
Title: Vice President |
THE BANK OF NOVA SCOTIA, as a Lender | |
By: /s/ David Dewar | |
Name: David Dewar | |
Title: Director |
US BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Holland H. Williams | |
Name: Holland H. Williams | |
Title: Vice President |
BRANCH BANKING & TRUST COMPANY, as a Lender | |
By: /s/ Lincoln LaCour | |
Name: Lincoln LaCour | |
Title: Assistant Vice President |
COBANK, ACB, as a Lender | |
By: /s/ Monika Wesorick | |
Name: Monika Wesorick | |
Title: Credit Manager, Vice President |
ZB, N.A. dba National Bank of Arizona, as a Lender | |
By: /s/ Sabina Aaronson | |
Name: Sabina Aaronson | |
Title: Vice President |
PNC BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Madeline L. Moran | |
Name: Madeline L. Moran | |
Title: Vice President |
1. | Amendments to the Credit Agreement. Effective as of July 31, 2017 (the “Amendment Effective Date”) and subject to the satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is hereby amended as follows: |
2. | Conditions of Effectiveness. This Amendment shall become effective as of the Amendment Effective Date upon the Agent’s receipt of (a) duly executed counterparts of the signature pages hereof by each of the Borrower, the Lenders, each Issuing Bank and the Agent (b) an opinion of in-house counsel of the Borrower in form and substance reasonably satisfactory to the Agent, (c) a certificate of the secretary or the associate secretary of the Borrower certifying (i) that there have been no changes in the certificate of incorporation or bylaws of the Borrower since August 31, 2016 (or, to the extent there have been any amendments to the certificate of incorporation or bylaws, since the date of the most recent such amendment and attaching thereto copies of any such amendments), (ii) resolutions of its Board of Directors authorizing the execution, delivery and performance of the Credit Agreement, as modified by this Amendment, and (iii) the incumbency and specimen signature of each of its officers authorized to sign this Amendment, (d) payment of the fees and expenses of Agent’s counsel and all other fees and expenses required to be paid on the Amendment Effective Date and (e) such other documents, instruments and agreements as the Agent shall reasonably request. |
3. | Representations and Warranties and Reaffirmations of the Borrower. |
3.1. | The Borrower hereby represents and warrants that (i) this Amendment and the Credit Agreement as previously executed and as modified hereby constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar Laws affecting creditors’ rights generally, and (ii) no Default or Event of Default has occurred and is continuing. |
3.2. | Upon the effectiveness of this Amendment and after giving effect hereto, the Borrower hereby reaffirms all covenants, representations and warranties made in the Credit Agreement as modified hereby, and agrees that all such covenants, representations and warranties shall be deemed to have been remade as of the Amendment Effective Date, except that any such covenant, representation, or warranty that was made as of a specific date shall be considered reaffirmed only as of such date. |
4. | Reference to the Effect on the Credit Agreement. |
4.1. | Upon the effectiveness of Section 1 hereof, on and after the date hereof, each reference in the Credit Agreement (including any reference therein to “this Credit Agreement,” “this Agreement,” “hereunder,” “hereof,” “herein” or words of like import referring thereto) or in any other Loan Document shall mean and be a reference to the Credit Agreement as modified hereby. |
4.2. | Except as specifically modified above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect, and are hereby ratified and confirmed. |
4.3. | The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith. |
4.4. | Upon satisfaction of the conditions set forth in Section 2 hereof and the execution hereof by the Borrower, the Lenders, each Issuing Bank and the Agent, this Amendment shall be binding upon all parties to the Credit Agreement. |
4.5. | This Amendment shall constitute a Loan Document. |
5. | GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. |
6. | Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose. |
7. | Counterparts. This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by telecopier or electronic .pdf file shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act. |
PINNACLE WEST CAPITAL CORPORATION, as the Borrower | |||
By: /s/ Lee R. Nickloy | |||
Name: Lee R. Nickloy | |||
Title: Vice President and Treasurer |
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as Agent, as an Issuing Bank and as a Lender | |||
By: /s/ Matthew Bly | |||
Name: Matthew Bly | |||
Title: Vice President |
JPMORGAN CHASE BANK, N.A., as a Lender | |||
By: /s/ Nancy R. Barwig | |||
Name: Nancy R. Barwig | |||
Title: Credit Risk Director |
1. | Amendments to the Credit Agreement. Effective as of June 29, 2017 (the “Amendment Effective Date”) and subject to the satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is hereby amended as follows: |
2. | Conditions of Effectiveness. This Amendment shall become effective as of the Amendment Effective Date upon the Agent’s receipt of (a) duly executed counterparts of the signature pages hereof by each of the Borrower, the Required Lenders and the Agent and (b) such other documents, instruments and agreements as the Agent shall reasonably request. |
3. | Representations and Warranties and Reaffirmations of the Borrower. |
3.1. | The Borrower hereby represents and warrants that (i) this Amendment and the Credit Agreement as previously executed and as modified hereby constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar Laws affecting creditors’ rights generally, and (ii) no Default or Event of Default has occurred and is continuing. |
3.2. | Upon the effectiveness of this Amendment and after giving effect hereto, the Borrower hereby reaffirms all covenants, representations and warranties made in the Credit Agreement as modified hereby, and agrees that all such covenants, representations and warranties shall be deemed to have been remade as of the Amendment Effective Date, except that any such covenant, representation, or warranty that was made as of a specific date shall be considered reaffirmed only as of such date. |
4. | Reference to the Effect on the Credit Agreement. |
4.1. | Upon the effectiveness of Section 1 hereof, on and after the date hereof, each reference in the Credit Agreement (including any reference therein to “this Credit Agreement,” “this Agreement,” “hereunder,” “hereof,” “herein” or words of like |
4.2. | Except as specifically modified above, the Credit Agreement and all other documents, instruments and agreements executed and/or delivered in connection therewith shall remain in full force and effect, and are hereby ratified and confirmed. |
4.3. | The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of the Agent or the Lenders, nor constitute a waiver of any provision of the Credit Agreement or any other documents, instruments and agreements executed and/or delivered in connection therewith. |
4.4. | Upon satisfaction of the conditions set forth in Section 2 hereof and the execution hereof by the Borrower, the Required Lenders and the Agent, this Amendment shall be binding upon all parties to the Credit Agreement. |
4.5. | This Amendment shall constitute a Loan Document. |
5. | GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. |
6. | Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose. |
7. | Counterparts. This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed counterpart of a signature page to this Amendment by telecopier shall be effective as delivery of a manually executed counterpart of this Amendment. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to any document to be signed in connection with this Amendment and the transactions contemplated hereby shall be deemed to include electronic signatures, deliveries or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act. |
ARIZONA PUBLIC SERVICE COMPANY, as the Borrower | |||
By: /s/ Lee R. Nickloy | |||
Name: Lee R. Nickloy | |||
Title: Vice President and Treasurer |
BARCLAYS BANK PLC, as Agent and Lender | ||
By /s/ Vanessa Kurbatskiy | ||
Name: Vanessa Kurbatskiy | ||
Title: Vice President |
MIZUHO BANK, LTD., as a Lender | |
By: /s/Nelson Chang | |
Name: Nelson Chang | |
Title: Authorized Signatory |
BANK OF AMERICA, N.A., as a Lender | |
By: /s/James B. Meanor | |
Name: James B. Meanor | |
Title: Managing Director |
JPMORGAN CHASE BANK, N.A., as a Lender | |
By: /s/ Nancy R. Barwig | |
Name: Nancy R. Barwig | |
Title: Credit Risk Director |
SUNTRUST BANK, as a Lender | |
By: /s/ Arize Agumadu | |
Name: Arize Agumadu | |
Title: Vice President |
WELLS FARGO BANK NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Sheila Shaffer | |
Name: Sheila Shaffer | |
Title: Vice President |
MUFG UNION BANK, N.A., as a Lender and as an Issuing Bank | |
By: /s/ Maria Ferradas | |
Name: Maria Ferradas | |
Title: Director |
BNP PARIBAS, as a Lender and as an Issuing Bank | |
By: /s/ Christopher Sked | |
Name: Christopher Sked | |
Title: Managing Director | |
By: /s/ Julien Pecoud-Bouvet | |
Name: Julien Pecoud-Bouvet | |
Title: Vice President |
CITIBANK, N.A., as a Lender | |
By: /s/ Hans Y. Lin | |
Name: Hans Y. Lin | |
Title: Senior Vice President |
KEYBANK NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Paul J. Pace | |
Name: Paul J. Pace | |
Title: Senior Vice President |
ROYAL BANK OF CANADA, as a Lender | |
By: /s/ Rahul Shah | |
Name: Rahul Shah | |
Title: Authorized Signatory |
TD BANK, N.A., as a Lender | |
By: /s/ Vijay Prasad | |
Name: Vijay Prasad | |
Title: Senior Vice President |
THE BANK OF NEW YORK MELLON, as a Lender | |
By: /s/ Mark W. Rogers | |
Name: Mark W. Rogers | |
Title: Vice President |
THE BANK OF NOVA SCOTIA, as a Lender | |
By: /s/ David Dewar | |
Name: David Dewar | |
Title: Director |
US BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Holland H. Williams | |
Name: Holland H. Williams | |
Title: Vice President |
BRANCH BANKING & TRUST COMPANY, as a Lender | |
By: /s/ Lincoln LaCour | |
Name: Lincoln LaCour | |
Title: Assistant Vice President |
COBANK, ACB, as a Lender | |
By: /s/ Monika Wesorick | |
Name: Monika Wesorick | |
Title: Credit Manager, Vice President |
ZB, N.A. dba National Bank of Arizona, as a Lender | |
By: /s/ Sabina Aaronson | |
Name: Sabina Aaronson | |
Title: Vice President |
PNC BANK, NATIONAL ASSOCIATION, as a Lender | |
By: /s/ Madeline L. Moran | |
Name: Madeline L. Moran | |
Title: Vice President |
Six Months Ended June 30, | Twelve Months Ended December 31, | ||||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||||
Earnings: | |||||||||||||||||||||||
Income from continuing operations attributable to common shareholders | $ | 190,755 | $ | 442,034 | $ | 437,257 | $ | 397,595 | $ | 406,074 | $ | 387,380 | |||||||||||
Income taxes | 93,178 | 236,411 | 237,720 | 220,705 | 230,591 | 237,317 | |||||||||||||||||
Fixed charges | 111,069 | 213,973 | 202,465 | 208,226 | 206,089 | 219,437 | |||||||||||||||||
Total earnings | $ | 395,002 | $ | 892,418 | $ | 877,442 | $ | 826,526 | $ | 842,754 | $ | 844,134 | |||||||||||
Fixed Charges: | |||||||||||||||||||||||
Interest expense | $ | 106,833 | $ | 205,720 | $ | 194,964 | $ | 200,950 | $ | 201,888 | $ | 214,616 | |||||||||||
Estimated interest portion of annual rents | 4,236 | 8,253 | 7,501 | 7,276 | 4,201 | 4,821 | |||||||||||||||||
Total fixed charges | $ | 111,069 | $ | 213,973 | $ | 202,465 | $ | 208,226 | $ | 206,089 | $ | 219,437 | |||||||||||
Ratio of Earnings to Fixed Charges (rounded down) | 3.55 | 4.17 | 4.33 | 3.96 | 4.08 | 3.84 |
Six Months Ended June 30, | Twelve Months Ended December 31, | ||||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||||
Earnings: | |||||||||||||||||||||||
Income from continuing operations attributable to common shareholders | $ | 192,270 | $ | 462,141 | $ | 450,274 | $ | 421,219 | $ | 424,969 | $ | 395,497 | |||||||||||
Income taxes | 97,175 | 245,842 | 245,841 | 237,360 | 245,095 | 244,396 | |||||||||||||||||
Fixed charges | 108,514 | 210,776 | 199,458 | 204,198 | 202,457 | 214,227 | |||||||||||||||||
Total earnings | $ | 397,959 | $ | 918,759 | $ | 895,573 | $ | 862,777 | $ | 872,521 | $ | 854,120 | |||||||||||
Fixed Charges: | |||||||||||||||||||||||
Interest charges | $ | 101,939 | $ | 197,811 | $ | 187,499 | $ | 193,119 | $ | 194,616 | $ | 205,533 | |||||||||||
Amortization of debt discount | 2,374 | 4,760 | 4,793 | 4,168 | 4,046 | 4,215 | |||||||||||||||||
Estimated interest portion of annual rents | 4,201 | 8,205 | 7,166 | 6,911 | 3,795 | 4,479 | |||||||||||||||||
Total fixed charges | $ | 108,514 | $ | 210,776 | $ | 199,458 | $ | 204,198 | $ | 202,457 | $ | 214,227 | |||||||||||
Ratio of Earnings to Fixed Charges (rounded down) | 3.66 | 4.35 | 4.49 | 4.22 | 4.30 | 3.98 |
Six Months Ended June 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||||
Earnings: | |||||||||||||||||||||||
Income from continuing operations attributable to common shareholders | $ | 190,755 | $ | 442,034 | $ | 437,257 | $ | 397,595 | $ | 406,074 | $ | 387,380 | |||||||||||
Income taxes | 93,178 | 236,411 | 237,720 | 220,705 | 230,591 | 237,317 | |||||||||||||||||
Fixed charges | 111,069 | 213,973 | 202,465 | 208,226 | 206,089 | 219,437 | |||||||||||||||||
Total earnings | $ | 395,002 | $ | 892,418 | $ | 877,442 | $ | 826,526 | $ | 842,754 | $ | 844,134 | |||||||||||
Fixed Charges: | |||||||||||||||||||||||
Interest expense | $ | 106,833 | $ | 205,720 | $ | 194,964 | $ | 200,950 | $ | 201,888 | $ | 214,616 | |||||||||||
Estimated interest portion of annual rents | 4,236 | 8,253 | 7,501 | 7,276 | 4,201 | 4,821 | |||||||||||||||||
Total fixed charges | $ | 111,069 | $ | 213,973 | $ | 202,465 | $ | 208,226 | $ | 206,089 | $ | 219,437 | |||||||||||
Preferred Stock Dividend Requirements: | |||||||||||||||||||||||
Income before income taxes attributable to common shareholders | $ | 283,933 | $ | 678,445 | $ | 674,977 | $ | 618,300 | $ | 636,665 | $ | 624,697 | |||||||||||
Net income from continuing operations attributable to common shareholders | 190,755 | 442,034 | 437,257 | 397,595 | 406,074 | 387,380 | |||||||||||||||||
Ratio of income before income taxes to net income | 1.49 | 1.53 | 1.54 | 1.56 | 1.57 | 1.61 | |||||||||||||||||
Preferred stock dividends | — | — | — | — | — | — | |||||||||||||||||
Preferred stock dividend requirements — ratio (above) times preferred stock dividends | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
Fixed Charges and Preferred Stock Dividend Requirements: | |||||||||||||||||||||||
Fixed charges | $ | 111,069 | $ | 213,973 | $ | 202,465 | $ | 208,226 | $ | 206,089 | $ | 219,437 | |||||||||||
Preferred stock dividend requirements | — | — | — | — | — | — | |||||||||||||||||
Total | $ | 111,069 | $ | 213,973 | $ | 202,465 | $ | 208,226 | $ | 206,089 | $ | 219,437 | |||||||||||
Ratio of Earnings to Fixed Charges (rounded down) | 3.55 | 4.17 | 4.33 | 3.96 | 4.08 | 3.84 |
1. | I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Donald E. Brandt | |
Donald E. Brandt | |
Chairman, President and Chief Executive Officer |
1. | I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ James R. Hatfield | |
James R. Hatfield | |
Executive Vice President and Chief Financial Officer |
1. | I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Donald E. Brandt | |
Donald E. Brandt | |
Chairman, President and Chief Executive Officer |
1. | I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ James R. Hatfield | |
James R. Hatfield | |
Executive Vice President and Chief Financial Officer |
/s/ Donald E. Brandt | |
Donald E. Brandt | |
Chairman, President and | |
Chief Executive Officer |
/s/ James R. Hatfield | |
James R. Hatfield | |
Executive Vice President and | |
Chief Financial Officer |
/s/ Donald E. Brandt | |
Donald E. Brandt | |
Chairman, President and | |
Chief Executive Officer |
/s/ James R. Hatfield | |
James R. Hatfield | |
Executive Vice President and | |
Chief Financial Officer |
Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Jul. 26, 2017 |
|
Entity Information [Line Items] | ||
Entity Registrant Name | PINNACLE WEST CAPITAL CORP | |
Entity Central Index Key | 0000764622 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2017 | |
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 | 111,624,528 | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | Q2 | |
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 | Jun. 30, 2017 | |
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 | 2017 | |
Document Fiscal Period Focus | Q2 |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
OPERATING REVENUES | $ 944,587 | $ 915,394 | $ 1,622,315 | $ 1,592,561 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 254,611 | 274,848 | 467,006 | 496,133 |
Operations and maintenance | 214,013 | 242,279 | 433,989 | 485,474 |
Depreciation and amortization | 125,739 | 123,073 | 253,366 | 242,549 |
Taxes other than income taxes | 44,289 | 42,117 | 88,125 | 84,618 |
Other expenses | 1,706 | 1,329 | 2,094 | 1,877 |
Total | 640,358 | 683,646 | 1,244,580 | 1,310,651 |
OPERATING INCOME | 304,229 | 231,748 | 377,735 | 281,910 |
OTHER INCOME (DEDUCTIONS) | ||||
Allowance for equity funds used during construction | 10,456 | 10,369 | 19,938 | 20,885 |
Other income (Note 8) | 484 | 197 | 964 | 314 |
Other expense (Note 8) | (3,822) | (2,842) | (7,502) | (6,880) |
Total | 7,118 | 7,724 | 13,400 | 14,319 |
INTEREST EXPENSE | ||||
Interest charges | 54,969 | 52,849 | 106,833 | 103,593 |
Allowance for borrowed funds used during construction | (4,906) | (5,301) | (9,378) | (10,528) |
Total | 50,063 | 47,548 | 97,455 | 93,065 |
INCOME BEFORE INCOME TAXES | 261,284 | 191,924 | 293,680 | 203,164 |
INCOME TAXES | 88,967 | 65,742 | 93,178 | 67,656 |
NET INCOME | 172,317 | 126,182 | 200,502 | 135,508 |
Less: Net income attributable to noncontrolling interests (Note 5) | 4,874 | 4,874 | 9,747 | 9,747 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 167,443 | $ 121,308 | $ 190,755 | $ 125,761 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING | ||||
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) | 111,797 | 111,368 | 111,763 | 111,336 |
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) | 112,345 | 112,004 | 112,270 | 111,930 |
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 1.50 | $ 1.09 | $ 1.71 | $ 1.13 |
Net income attributable to common shareholders - diluted (in dollars per share) | 1.49 | 1.08 | 1.70 | 1.12 |
DIVIDENDS DECLARED PER SHARE (in dollars per share) | $ 1.31 | $ 1.25 | $ 1.31 | $ 1.25 |
APS | ||||
ELECTRIC OPERATING REVENUES | $ 942,615 | $ 909,757 | $ 1,619,485 | $ 1,586,389 |
OPERATING EXPENSES | ||||
Fuel and purchased power | 259,892 | 274,848 | 476,995 | 496,133 |
Operations and maintenance | 208,286 | 233,712 | 420,505 | 472,423 |
Depreciation and amortization | 125,317 | 123,033 | 252,524 | 242,479 |
Income taxes | 92,381 | 70,444 | 103,754 | 76,294 |
Taxes other than income taxes | 43,949 | 42,036 | 87,447 | 84,446 |
Total | 729,825 | 744,073 | 1,341,225 | 1,371,775 |
OPERATING INCOME | 212,790 | 165,684 | 278,260 | 214,614 |
OTHER INCOME (DEDUCTIONS) | ||||
Income taxes | 3,856 | 1,721 | 6,579 | 3,536 |
Allowance for equity funds used during construction | 10,456 | 10,369 | 19,938 | 20,885 |
Other income (Note 8) | 1,142 | 5,747 | 2,204 | 6,357 |
Other expense (Note 8) | (5,651) | (4,430) | (10,029) | (9,180) |
Total | 9,803 | 13,407 | 18,692 | 21,598 |
INTEREST EXPENSE | ||||
Interest on long-term debt | 49,989 | 48,903 | 97,480 | 95,722 |
Interest on short-term borrowings | 2,331 | 1,930 | 4,459 | 4,007 |
Debt discount, premium and expense | 1,197 | 1,195 | 2,374 | 2,334 |
Allowance for borrowed funds used during construction | (4,906) | (4,999) | (9,378) | (10,039) |
Total | 48,611 | 47,029 | 94,935 | 92,024 |
NET INCOME | 173,982 | 132,062 | 202,017 | 144,188 |
Less: Net income attributable to noncontrolling interests (Note 5) | 4,874 | 4,874 | 9,747 | 9,747 |
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 169,108 | $ 127,188 | $ 192,270 | $ 134,441 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Net unrealized loss, tax expense | $ 4 | $ 80 | $ 679 | $ 626 |
Reclassification of net realized loss, tax expense (benefit) | (348) | (392) | 8 | (191) |
Pension and other postretirement benefits activity, tax benefit (expense) | 823 | 439 | 119 | (206) |
Arizona Public Service Company | ||||
Net unrealized loss, tax expense | 4 | 80 | 679 | 626 |
Reclassification of net realized loss, tax expense (benefit) | (348) | (392) | 8 | (191) |
Pension and other postretirement benefits activity, tax benefit (expense) | $ 808 | $ 403 | $ 218 | $ (156) |
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
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) | 111,642,680 | 111,392,053 |
Treasury stock at cost, shares (in shares) | 19,298 | 55,317 |
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, 2015 | 111,095,402 | 115,030 | 71,264,947 | ||||||||||||
Balance at beginning of period at Dec. 31, 2015 | $ 4,719,457 | $ 2,541,668 | $ (5,806) | $ 2,092,803 | $ (44,748) | $ 135,540 | $ 4,814,794 | $ 178,162 | $ 2,379,696 | $ 2,148,493 | $ (27,097) | $ 135,540 | |||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||
Net income | 135,508 | 125,761 | 9,747 | 144,188 | 134,441 | 9,747 | |||||||||
Other comprehensive income | 1,029 | 1,029 | 1,169 | 1,169 | |||||||||||
Dividends on common stock | (138,947) | (138,947) | (139,000) | (139,000) | |||||||||||
Issuance of common stock (in shares) | 80,098 | ||||||||||||||
Issuance of common stock | 7,830 | $ 7,830 | |||||||||||||
Purchase of treasury stock (in shares) | [1] | (71,962) | |||||||||||||
Purchase of treasury stock | [1] | (4,880) | $ (4,880) | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 185,092 | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 10,558 | $ 10,556 | 2 | 0 | |||||||||||
Capital activities by noncontrolling interests | (11,372) | (11,372) | (11,372) | (11,372) | |||||||||||
Ending balance (in shares) at Jun. 30, 2016 | 111,175,500 | 1,900 | 71,264,947 | ||||||||||||
Balance at end of period at Jun. 30, 2016 | 4,719,183 | $ 2,549,498 | $ (130) | 2,079,619 | (43,719) | 133,915 | 4,809,779 | $ 178,162 | 2,379,696 | 2,143,934 | (25,928) | 133,915 | |||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||
Net income | 126,182 | 132,062 | |||||||||||||
Other comprehensive income | 51 | 110 | |||||||||||||
Ending balance (in shares) at Jun. 30, 2016 | 111,175,500 | 1,900 | 71,264,947 | ||||||||||||
Balance at end of period at Jun. 30, 2016 | $ 4,719,183 | $ 2,549,498 | $ (130) | 2,079,619 | (43,719) | 133,915 | 4,809,779 | $ 178,162 | 2,379,696 | 2,143,934 | (25,928) | 133,915 | |||
Beginning balance (in shares) at Dec. 31, 2016 | 111,392,053 | 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 | 200,502 | 190,755 | 9,747 | 202,017 | 192,270 | 9,747 | |||||||||
Other comprehensive income | 196 | 196 | 311 | 311 | |||||||||||
Dividends on common stock | (146,204) | (146,204) | (146,200) | (146,200) | |||||||||||
Issuance of common stock (in shares) | 250,627 | ||||||||||||||
Issuance of common stock | 8,452 | $ 8,452 | |||||||||||||
Purchase of treasury stock (in shares) | [1] | (156,172) | |||||||||||||
Purchase of treasury stock | [1] | (12,430) | $ (12,430) | ||||||||||||
Reissuance of treasury stock for stock-based compensation and other (in shares) | 192,191 | ||||||||||||||
Reissuance of treasury stock for stock-based compensation and other | 15,021 | $ 15,010 | 11 | 0 | |||||||||||
Capital activities by noncontrolling interests | $ (11,372) | (11,372) | (11,372) | (11,372) | |||||||||||
Ending balance (in shares) at Jun. 30, 2017 | 111,642,680 | 111,642,680 | 19,298 | 71,264,947.000 | |||||||||||
Balance at end of period at Jun. 30, 2017 | $ 4,990,077 | $ 2,604,482 | $ (1,553) | 2,300,109 | (43,626) | 130,665 | 5,082,726 | $ 178,162 | 2,421,696 | 2,377,315 | (25,112) | 130,665 | |||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||
Net income | 172,317 | 173,982 | |||||||||||||
Other comprehensive income | $ (763) | (737) | |||||||||||||
Ending balance (in shares) at Jun. 30, 2017 | 111,642,680 | 111,642,680 | 19,298 | 71,264,947.000 | |||||||||||
Balance at end of period at Jun. 30, 2017 | $ 4,990,077 | $ 2,604,482 | $ (1,553) | $ 2,300,109 | $ (43,626) | $ 130,665 | $ 5,082,726 | $ 178,162 | $ 2,421,696 | $ 2,377,315 | $ (25,112) | $ 130,665 | |||
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Consolidation and Nature of Operations |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 5 for further discussion). Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors. Our condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations, and cash flows for the periods presented. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2016 Form 10-K. Certain line items are presented in more detail on the Condensed Consolidated Statements of Cash Flows than was presented in the prior years. The prior year amounts were reclassified to conform to the current year presentation. These reclassifications have no impact on net cash flows provided by operating activities. The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands):
Supplemental Cash Flow Information The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
|
Long-Term Debt and Liquidity Matters |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 June 30, 2017, 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 June 30, 2017, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $39.3 million of commercial paper borrowings. On July 31, 2017, Pinnacle West amended and restated its 364-day unsecured revolving credit facility to increase its capacity from $75 million to $125 million, and to extend the termination date of the facility from August 30, 2017 to July 30, 2018. Borrowings under the facility bear interest at LIBOR plus 0.80% per annum. At June 30, 2017, Pinnacle West had $57 million outstanding under the facility. APS On March 21, 2017, APS issued an additional $250 million par amount of its outstanding 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance commercial paper borrowings and to replenish cash temporarily used to fund capital expenditures. On June 29, 2017, APS replaced its $500 million revolving credit facility that would have matured in September 2020, with a new $500 million facility that matures in June 2022. At June 30, 2017, APS had two revolving credit facilities totaling $1 billion, including a $500 million facility that matures in May 2021 and the above-mentioned $500 million credit facility. 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 June 30, 2017, APS had $385.7 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 7 for a discussion of APS’s other outstanding letters of credit. Debt Fair Value Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy. Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
Debt Provisions An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At June 30, 2017, APS was in compliance with this common equity ratio requirement. Its total shareholder equity was approximately $5.0 billion, and total capitalization was approximately $9.4 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.8 billion, assuming APS’s total capitalization remains the same. |
Regulatory Matters |
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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 excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests 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 an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). The principal provisions of the application are described in detail in Note 3 of our 2016 Form 10-K. On March 1, 2017, the ACC Staff filed with the ACC a settlement term sheet. The settlement term sheet was agreed to by a majority of the stakeholders in the rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations. The settlement term sheet was converted into a definitive settlement agreement (the "2017 Settlement Agreement"), was signed by the supporting parties and was filed with the ACC on March 27, 2017. The 2017 Settlement Agreement was submitted to the administrative law judge ("ALJ"), whose decision regarding whether the settlement should be approved will be reviewed by the ACC. Hearings on the proposed settlement began on April 24, 2017 and the hearings were completed on May 2, 2017. Post-hearing briefing on the proposed settlement was completed on June 1, 2017. In its original filing, APS requested that the rate increase become effective July 1, 2017. In July 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. On January 13, 2017, the ALJ issued a procedural order delaying hearings on the case for approximately one month to allow parties to prepare testimony on the distributed generation ("DG") rate design issues addressed in the value and cost of DG decision. In light of this delay in the start of the hearings on the settlement, we expected a moderate delay in the scheduling of a final ACC vote on the settlement beyond the originally-anticipated July 1, 2017 date. On July 26, 2017, the ALJ issued a recommended opinion and order in the proceeding. The order recommends ACC approval of the 2017 Settlement Agreement without material modifications and recommends that the new rates go into effect on September 1, 2017. Parties to the proceeding may file exceptions to the recommended order on or before August 4, 2017. Following the filing of exceptions, the recommended order will be considered by the ACC for a final decision. On April 27, 2017, Commissioner Burns filed a motion requesting that the ALJ suspend and continue the rate case proceedings and facilitate an investigation to determine whether certain commissioners should be disqualified from further participation in the matter. The ACC denied the motion on June 20, 2017. See more information below under the heading "Subpoena from Arizona Corporation Commissioner Robert Burns." 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 million due to changes in depreciation schedules. Other key provisions of the agreement include the following:
Through a separate agreement, APS, industry representatives, and solar advocates commit to stand by the settlement agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC. APS cannot predict whether the 2017 Settlement Agreement will ultimately be approved by the ACC, or the exact timing of the ACC's consideration of the matter. Prior Rate Case Filing On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. APS requested that the increase become effective July 1, 2012. The request would have increased the average retail customer bill by approximately 6.6%. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications. The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of: (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs ("Base Fuel Rate") from $0.03757 to $0.03207 per kWh; and (3) the transfer of cost recovery for certain renewable energy projects from the RES surcharge to base rates in an estimated amount of $36.8 million. Other key provisions of the 2012 Settlement Agreement are described in detail in Note 3 of our 2016 Form 10-K. Cost Recovery Mechanisms APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms. Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. 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 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 ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC. On July 1, 2015, APS filed its 2016 RES Implementation Plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget. 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 includes the revenue neutral transfer of specific revenue requirements in accordance with the 2017 Settlement Agreement. The ACC has not yet ruled on APS's 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 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. 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. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent regulations of the United States Environmental Protection Agency ("EPA"). The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS anticipates that the ACC will schedule the proceedings once there is a decision in APS's pending rate case. 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 Standard; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery Mechanism (“LFCR”) mechanism. On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program. On June 1, 2016, APS filed its 2017 DSM Implementation Plan, in which APS proposes 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 Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on APS's 2017 DSM Plan. APS was required to file its 2018 DSM Implementation Plan by June 1, 2017, but the ACC granted APS's request to extend the deadline to file the 2018 DSM Implementation Plan until September 1, 2017. Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules. On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding. PSA Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
The PSA rate for the PSA year beginning February 1, 2017 is $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This new rate is comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. Transmission Rates, Transmission Cost Adjustor ("TCA") and Other Transmission Matters. In July 2008, the United States Federal Energy Regulatory Commission ("FERC") approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges"). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the 2012 Settlement Agreement, however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC. The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC staff. Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts. Effective June 1, 2016, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $24.9 million for the twelve-month period beginning June 1, 2016 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, 2016. 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 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. At this time, APS is unable to predict the outcome of this 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 distributed generation such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. The LFCR adjustment has a year-over-year cap of 1% of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. Distributed generation sales losses are determined from the metered output from the distributed generation units. APS files for a LFCR adjustment every January. APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase), to be effective for the first billing cycle of March 2016. The ACC approved the 2016 annual LFCR to be effective 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), to be effective for the first billing cycle of March 2017. On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, to be effective with the first billing cycle of April 2017. 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. Net Metering In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing was held in April 2016. On October 7, 2016, the ALJ 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 decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize 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 resource comparison proxy 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 resource comparison proxy method will be updated annually (between 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:
This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future 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 will become effective if the ACC approves it. APS cannot predict the outcome of this determination. The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases. 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 asserts 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. Consistent with Arizona statute, 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. In accordance with the 2017 Settlement Agreement described above, in the event the ACC approves the 2017 Settlement Agreement, these appeals will be withdrawn by TASC. The ACC's decision is expected to remain in effect during any legal challenge. System Benefits Charge The 2012 Settlement Agreement provided that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense. This adjustment is subsumed within the 2017 Settlement Agreement. Subpoena from Arizona Corporation Commissioner Robert Burns On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to 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 APS to produce all information previously requested through the subpoenas. APS did not produce the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West 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 with the ACC. On June 20, 2017, the ACC denied the motion to compel. The manner by which the courts can or should review this decision, as well as the timing and process for that review, is a subject of dispute and has not been decided. APS and Pinnacle West cannot predict the outcome of this matter. Four Corners On December 30, 2013, APS purchased Southern California Edison Company's ("SCE’s") 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $60 million as of June 30, 2017 and is being amortized in rates over a total of 10 years. On February 23, 2015, the Arizona School Boards Association and the Association of Business Officials filed a notice of appeal in Division 1 of the Arizona Court of Appeals of the ACC decision approving the rate adjustments. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals suspended the appeal pending the Arizona Supreme Court's decision in the System Improvement Benefits ("SIB") matter. The Arizona Court of Appeals reversed an ACC rate decision involving a water company regarding the ACC’s method of finding fair value in that case, which raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision, and on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor. The Arizona Court of Appeals ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. Supplemental briefing has been completed and the Arizona Court of Appeals has the matter under review. We cannot predict when or how this matter will be resolved. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the 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. APS cannot predict the outcome of either matter. 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 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 is currently recovering a return on and of the net book value of the unit in base rates. The 2017 Settlement Agreement described above contemplates continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs. APS believes it will be allowed recovery of the remaining net book value of Unit 2 ($112 million as of June 30, 2017), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of Cholla Unit 2, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted. 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, at which time a new lease will allow for decommissioning activities to begin after December 2019 instead of later this year. The new lease was approved by the Navajo Nation Tribal Council on June 26, 2017. Certain additional approvals are required for specific co-owners, which are expected to occur by late 2017. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior 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. 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 ($102 million as of June 30, 2017) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which 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. 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. Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands):
The detail of regulatory liabilities is as follows (dollars in thousands):
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Retirement Plans and Other Postretirement Benefits |
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Compensation and Retirement Disclosure [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 is currently in the process of seeking IRS approval to move approximately $145 million of the 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. While we do not expect to transfer any funds prior to 2018, as of June 30, 2017, such methodology would result in an amount of approximately $145 million being transferred to the new trust account. The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):
Contributions We have made voluntary contributions of $80 million to our pension plan year-to-date in 2017. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2017-2019 period. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans. |
Palo Verde Sale Leaseback Variable Interest Entities |
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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 and six months ended June 30, 2017 of $5 million and $10 million respectively, and for the three and six months ended June 30, 2016 of $5 million and $10 million respectively, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation. Our Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
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 $291 million beginning in 2017, 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. |
Derivative Accounting |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Accounting | Derivative Accounting We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. While we believe the economic hedges mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows. Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 10 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below. Cash flow hedge accounting was discontinued for the significant majority of our contracts after May 31, 2012. For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals. As of June 30, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
Gains and Losses from Derivative Instruments The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
During the next twelve months, we estimate that a net loss of $3 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 and six months ended June 30, 2017 and 2016 (dollars in thousands):
Derivative Instruments in the Condensed Consolidated Balance Sheets Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Condensed Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed Consolidated Balance Sheets. We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below. The significant majority of our derivative instruments are not currently designated as hedging instruments. The Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016, include gross liabilities of $1 million and $2 million, respectively, of derivative instruments designated as hedging instruments. The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2017 and December 31, 2016. 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.
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 June 30, 2017, Pinnacle West has no material risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s). The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2017 (dollars in thousands):
We also have energy-related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $126 million if our debt credit ratings were to fall below investment grade. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Palo Verde Nuclear Generating Station Spent Nuclear Fuel and Waste Disposal On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy ("DOE") in the United States Court of Federal Claims ("Court of Federal Claims"). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. APS has submitted three claims pursuant to the terms of the August 18, 2014 settlement agreement, for three separate time periods during July 1, 2011 through June 30, 2016. The DOE has approved and paid $65.2 million for these claims (APS’s share is $19 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement will be submitted to the DOE in the fourth quarter of 2017, and payment is expected in the second quarter of 2018. Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident up to approximately $13.4 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.0 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $127.3 million, subject to a maximum annual premium of $19 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $111.1 million, with a maximum annual retrospective premium of approximately $16.6 million. The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $24 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $64.8 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions. Contractual Obligations For the six months ended June 30, 2017, our fuel and purchased power commitments decreased approximately $670 million primarily due to updated estimated renewable energy purchases. The majority of these changes relate to the years 2022 and thereafter. Other than the items described above, there have been no material changes, as of June 30, 2017, outside the normal course of business in contractual obligations from the information provided in our 2016 Form 10-K. See Note 2 for discussion regarding changes in our long-term debt obligations. Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act ("Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are potentially responsible parties ("PRPs"). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study work plan ("RI/FS"). The OU3 working group parties have agreed to a schedule with EPA that calls for the submission of a revised draft RI/FS by November 2017. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated. On August 6, 2013, the Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, the Arizona Department of Environmental Quality ("ADEQ") sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID contractors filed ancillary lawsuits for recovery of costs against APS and the other defendants. In addition, on March 15, 2017, the Arizona District Court granted partial summary judgment to RID for one element of RID's lawsuit against APS and the other defendants. On May 12, 2017, the court denied a motion for reconsideration as to this order. The court's order for partial summary judgment on this issue is interlocutory, as it only relates to one element of the lawsuit. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Environmental Matters APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion residuals ("CCRs"). These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS. Regional Haze Rules. APS has received the final rulemaking imposing new pollution control requirements on Four Corners and the Navajo Plant. EPA will require these plants to install pollution control equipment that constitutes best available retrofit technology ("BART") to lessen the impacts of emissions on visibility surrounding the plants. EPA recently approved a proposed rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the recent Cholla BART approval. Four Corners. Based on EPA’s final standards, APS estimates that its 63% share of the cost of required controls for Four Corners Units 4 and 5 would be approximately $400 million. In addition, APS and El Paso Electric Company ("El Paso") entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. Navajo Transitional Energy Company, LLC ("NTEC") has the option to purchase the interest within a certain timeframe pursuant to an option granted to NTEC. In December 2015, NTEC notified APS of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. The parties are currently in discussions as to the future of the option transaction. The cost of the pollution controls related to the 7% interest is approximately $45 million, which will be assumed by the ultimate owner of the 7% interest. Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million. In October 2014, a coalition of environmental groups, an Indian tribe and others filed petitions for review in the United States Court of Appeals for the Ninth Circuit asking the Court to review EPA's final BART rule for the Navajo Plant. On March 20, 2017, the Court denied this petition for review and upheld the legality of EPA's final BART rule for the Navajo Plant. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant. Cholla. APS believes that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls with a cost to APS of approximately $100 million, is unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that is inconsistent with the state’s considered BART determinations under the regional haze program. Accordingly, on February 1, 2013, APS filed a Petition for Review of the final BART rule in the United States Court of Appeals for the Ninth Circuit. Briefing in the case was completed in February 2014. In September 2014, APS met with EPA to propose a compromise BART strategy. Pending certain regulatory approvals, APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the current BART requirements for NOx imposed on the Cholla units under EPA's BART FIP. APS’s proposal involves state and federal rulemaking processes. In light of these ongoing administrative proceedings, on February 19, 2015, APS, PacifiCorp (owner of Cholla Unit 4), and EPA jointly moved the court to sever and hold in abeyance those claims in the litigation pertaining to Cholla pending regulatory actions by the state and EPA. The court granted the parties' unopposed motion on February 20, 2015. On October 16, 2015, ADEQ issued a revised operating permit for Cholla, which incorporates APS's proposal, and subsequently submitted a proposed revision to the SIP to the EPA, which would incorporate the new permit terms. On June 30, 2016, EPA issued a proposed rule approving a revision to the Arizona SIP that incorporates APS’s compromise approach for compliance with the Regional Haze program. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and Internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. While EPA has chosen to regulate the disposal of CCR in landfills and surface impoundments as non-hazardous waste under the final rule, the agency makes clear that it will continue to evaluate any risks associated with CCR disposal and leaves open the possibility that it may regulate CCR as a hazardous waste under RCRA Subtitle C in the future. On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds. At this time, EPA has yet to publish guidance or proposed rules implementing the CCR provisions of the WIIN Act. In addition, we are unable to predict when Arizona will be able to develop a state-specific permitting program. It is unclear what effects the CCR provisions of the WIIN Act will have on APS's management of CCR. APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million, the majority of which has already been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must collect sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by October 12, 2018. Depending upon the results of such groundwater monitoring and data evaluations at each of Cholla, Four Corners and the Navajo Plant, we may be required to take corrective actions, the costs of which we are unable to reasonably estimate at this time. Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time, though, APS cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings. Clean Power Plan. On August 3, 2015, EPA finalized carbon pollution standards for electric generating units ("EGUs"). Shortly thereafter, a coalition of states, industry groups and electric utilities challenged the legality of these standards, including EPA's Clean Power Plan for existing EGUs, in the U.S. Court of Appeals for the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations under the Clean Power Plan. On March 28, 2017, President Trump issued an Executive Order that, among other things, instructs EPA to reevaluate Agency regulations concerning carbon emissions from EGUs and take appropriate action to suspend, revise or rescind the August 2015 carbon pollution standards for EGUs, including the Clean Power Plan. Also on March 28, 2017, the U.S. Department of Justice, on behalf of EPA, filed a motion with the U.S. Court of Appeals for the D.C. Circuit to hold the ongoing litigation over the August 2015 pollution standards in abeyance pending EPA action in accordance with the Executive Order. This motion was granted on April 28, 2017 by an order that held the case in abeyance for 60 days to give the litigation parties an opportunity to brief the Court as to whether to remand the proceedings back to EPA. At this time we cannot predict the outcome of EPA's review of the August 2015 carbon pollution standards and whether EPA will take action to suspend, rescind or revise these regulations. The carbon pollution standards for EGUs on state and tribal lands are described in detail in Note 10 of our 2016 Form 10-K. Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery. Federal Agency Environmental Lawsuit Related to Four Corners On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners. Four Corners Coal Supply Agreement Arbitration On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the 2016 Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant. NTEC is seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC alleges a shortfall in the Buyer’s purchases for the initial contract year of approximately $27 million. APS’s share of this amount is approximately $17 million. We cannot predict the timing or outcome of this arbitration; however we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows. Financial Assurances In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support certain debt arrangements, commodity contract collateral obligations, and other transactions. As of June 30, 2017, standby letters of credit totaled $5 million and will expire in 2017 and 2018. As of June 30, 2017, surety bonds expiring through 2019 totaled $62 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves. We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely. Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at June 30, 2017. Effective July 6, 2016, Pinnacle West has issued three parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners. |
Other Income and Other Expense |
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Other Income and Other Expense | Other Income and Other Expense The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Other Income and Other Expense | The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
(a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery). |
Earnings Per Share |
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Earnings Per Share | Earnings Per Share The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2017 and 2016 (in thousands, except per share amounts):
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are: Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes exchange traded equities, exchange traded derivative instruments, exchange traded mutual funds, cash equivalents, and investments in U.S. Treasury securities. Level 2 — Utilizes quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable (such as yield curves). This category includes non-exchange traded contracts such as forwards, options, swaps and certain investments in fixed income securities. Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable. Certain instruments have been valued using the concept of Net Asset Value (“NAV”), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, they are not traded on an exchange. Instruments valued using NAV, as a practical expedient, are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels. Recurring Fair Value Measurements We apply recurring fair value measurements to certain cash equivalents, derivative instruments, investments held in our nuclear decommissioning trust, plan assets held in our retirement and other benefit plans and coal reclamation trust investments. See Note 7 in the 2016 Form 10-K for the fair value discussion of plan assets held in our retirement and other benefit plans. Cash Equivalents Cash equivalents represent short-term investments with original maturities of three months or less in exchange traded money market funds that are valued using quoted prices in active markets. Coal Reclamation Escrow Account Coal reclamation escrow account represents investments restricted for coal mine reclamation funding related to Four Corners. The account investments may include fixed income instruments such as municipal bond securities and cash equivalents. Fixed income securities are classified as Level 2 and are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. Cash equivalents are classified as Level 1 and are valued as described above. Risk Management Activities — Derivative Instruments Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk. Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points. Option contracts are primarily valued using a Black-Scholes option valuation model, which utilizes both observable and unobservable inputs such as broker quotes, interest rates and price volatilities. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions. Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies. We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures. The risk control function reports to the chief financial officer’s organization. Investments Held in our Nuclear Decommissioning Trust The nuclear decommissioning trust invests in fixed income securities and equity securities. Equity securities are held indirectly through commingled funds. The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy. Cash equivalents reported within Level 1 represent investments held in a short-term investment exchange-traded mutual fund, which invests in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, and commercial paper. Fixed income securities issued by the U.S. Treasury held directly by the nuclear decommissioning trust are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities. We price securities using information provided by our trustee for our nuclear decommissioning trust assets. Our trustee uses pricing services that utilize the valuation methodologies described to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes. See Note 11 for additional discussion about our nuclear decommissioning trust. Fair Value Tables The following table presents the fair value at June 30, 2017, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
The following table presents the fair value at December 31, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
Fair Value Measurements Classified as Level 3 The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3). Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease. Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements. The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2017 and December 31, 2016:
The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
Amounts included in earnings are recorded in either operating revenues or fuel and purchased power depending on the nature of the underlying contract. Transfers reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period. We had no significant Level 1 transfers to or from any other hierarchy level. Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods. Financial Instruments Not Carried at Fair Value The carrying value of our net accounts receivable, accounts payable and short-term borrowings approximate fair value. Our short-term borrowings are classified within Level 2 of the fair value hierarchy. See Note 2 for our long-term debt fair values. |
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Investments, Debt and Equity Securities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Decommissioning Trusts | Nuclear Decommissioning Trusts To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. APS classifies investments in decommissioning trust funds as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. See Note 10 for a discussion of how fair value is determined and the classification of the nuclear decommissioning trust investments within the fair value hierarchy. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have deferred realized and unrealized gains and losses (including other-than-temporary impairments on investment securities) in other regulatory liabilities. The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2017 and December 31, 2016 (dollars in thousands):
The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2017 is as follows (dollars in thousands):
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New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | New Accounting Standards Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. We do not expect the adoption of this standard will have significant impacts on our financial statement results; however, adoption of the new standard will impact our disclosures relating to revenue, and may impact our presentation of revenue. Our evaluation is on-going, but our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. As of June 30, 2017 we do not have significant equity investments that would be impacted by this standard. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. At transition we do not expect this standard will have any financial statement impacts; however, the standard may have potential impacts on the accounting for future acquisitions occurring after adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. Our evaluation is ongoing, but at this time we do not expect the adoption of this guidance, at transition, will have a significant impact on our financial statement results. We are also currently evaluating the transition approach we will apply. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however we do not expect these changes will have a significant impact on our results of operations. |
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Changes in Accumulated Other Comprehensive Loss | Changes in Accumulated Other Comprehensive Loss The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Arizona Public Service Company | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Accumulated Other Comprehensive Loss | The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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New Accounting Standards (Policies) |
6 Months Ended |
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Jun. 30, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Standards | Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, will be effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We will adopt this standard on January 1, 2018, and expect to adopt the guidance using the modified retrospective transition approach. We do not expect the adoption of this standard will have significant impacts on our financial statement results; however, adoption of the new standard will impact our disclosures relating to revenue, and may impact our presentation of revenue. Our evaluation is on-going, but our revenues are derived primarily from sales of electricity to our regulated retail customers, and based on our assessment we do not expect the adoption of this guidance will impact the timing of our revenue recognition relating to these customers. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance will require certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard is effective for us on January 1, 2018. Certain aspects of the standard may require a cumulative effect adjustment and other aspects of the standard are required to be adopted prospectively. We plan on adopting this standard on January 1, 2018, and continue to evaluate the impacts the new guidance may have on our financial statements. As of June 30, 2017 we do not have significant equity investments that would be impacted by this standard. ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard will require a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that will initially be measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. The new standard will be effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach, with various optional practical expedients provided to facilitate transition. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The new standard is effective for us on January 1, 2018 using a prospective approach. At transition we do not expect this standard will have any financial statement impacts; however, the standard may have potential impacts on the accounting for future acquisitions occurring after adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard is effective for us on January 1, 2018. The guidance may be applied using either a retrospective or modified retrospective transition approach. Our evaluation is ongoing, but at this time we do not expect the adoption of this guidance, at transition, will have a significant impact on our financial statement results. We are also currently evaluating the transition approach we will apply. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes will require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component will be eligible for presentation as an operating income item, and all other cost components will be presented as non-operating items. This presentation change must be applied retrospectively. Furthermore, the new standard only allows the service cost component to be eligible for capitalization. The change in capitalization requirements must be applied prospectively. The new guidance is effective for us on January 1, 2018. We are currently evaluating this new accounting standard and the impacts it will have on our financial statements. The adoption of this guidance will change our financial statement presentation of net benefit costs and amounts eligible for capitalization; however we do not expect these changes will have a significant impact on our results of operations. |
Consolidation and Nature of Operations (Tables) |
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of reclassifications of the prior year | The following tables show the impacts of the reclassifications of the prior year's (previously reported) amounts (dollars in thousands):
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Summary of supplemental cash flow information | The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
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Long-Term Debt and Liquidity Matters (Tables) |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of estimated fair value of long-term debt, including current maturities | The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
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Regulatory Matters (Tables) |
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Jun. 30, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of changes in the deferred fuel and purchased power regulatory asset | The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2017 and 2016 (dollars in thousands):
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Schedule of regulatory assets | The detail of regulatory assets is as follows (dollars in thousands):
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Schedule of regulatory liabilities | The detail of regulatory liabilities is as follows (dollars in thousands):
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Retirement Plans and Other Postretirement Benefits (Tables) |
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Compensation and Retirement Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) | The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged to the regulatory asset or liability) (dollars in thousands):
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Palo Verde Sale Leaseback Variable Interest Entities (Tables) |
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||||||||||||||||||||||
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | Our Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016 include the following amounts relating to the VIEs (dollars in thousands):
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Derivative Accounting (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position) | As of June 30, 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
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Gains and losses from derivative instruments in designated cash flow accounting hedges relationships | The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Gains and losses from derivative instruments not designated as accounting hedges instruments | The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Schedule of offsetting assets | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2017 and December 31, 2016. 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.
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Schedule of offsetting liabilities | The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of June 30, 2017 and December 31, 2016. 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.
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Information about derivative instruments that have credit-risk-related contingent features | The following table provides information about our derivative instruments that have credit-risk-related contingent features at June 30, 2017 (dollars in thousands):
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Other Income and Other Expense (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Component of Other Income and Other Expense Nonoperating [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Detail of other income and other expense | The following table provides detail of Pinnacle West's Consolidated other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Arizona Public Service Company | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Component of Other Income and Other Expense Nonoperating [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Detail of other income and other expense | The following table provides detail of APS’s other income and other expense for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
(a) As defined by FERC, includes below-the-line non-operating utility expense (items excluded from utility rate recovery). |
Earnings Per Share (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of earnings per weighted average common share outstanding | The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for the three and six months ended June 30, 2017 and 2016 (in thousands, except per share amounts):
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Fair Value Measurements (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of assets and liabilities that are measured at fair value on a recurring basis | The following table presents the fair value at June 30, 2017, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
The following table presents the fair value at December 31, 2016, of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
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Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments | The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at June 30, 2017 and December 31, 2016:
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Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs | The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Nuclear Decommissioning Trusts (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments, Debt and Equity Securities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of APS's nuclear decommissioning trust fund assets | The following table includes the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust fund assets at June 30, 2017 and December 31, 2016 (dollars in thousands):
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Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds | The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in thousands):
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Fair value of fixed income securities, summarized by contractual maturities | The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2017 is as follows (dollars in thousands):
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Changes in Accumulated Other Comprehensive Loss (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component | The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
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Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, net of tax, by component | The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the three and six months ended June 30, 2017 and 2016 (dollars in thousands):
|
Consolidated and Nature of Operations - Schedule of Reclassification of Prior Period Adjustments (Details) - USD ($) $ in Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | $ 12,891 | $ 25,048 |
Change in other long-term liabilities | $ 13,279 | (16,037) |
As previously reported | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | 0 | |
Change in other long-term liabilities | 9,011 | |
Reclassifications to conform to current year presentation | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Stock compensation | 25,048 | |
Change in other long-term liabilities | $ (25,048) |
Consolidation and Nature of Operations (Details) - USD ($) $ in Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Cash paid during the period for: | ||
Income taxes, net of refunds | $ 2,062 | $ 2,503 |
Interest, net of amounts capitalized | 94,870 | 89,109 |
Significant non-cash investing and financing activities: | ||
Accrued capital expenditures | 80,517 | 55,286 |
Dividends declared but not yet paid | $ 73,113 | $ 69,484 |
Long-Term Debt and Liquidity Matters - Estimated Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | $ 4,399,520 | $ 4,146,785 |
Fair Value | 4,770,844 | 4,425,789 |
Pinnacle West | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 125,000 | 125,000 |
Fair Value | 125,000 | 125,000 |
Arizona Public Service Company | ||
Estimated fair value of long-term debt, including current maturities | ||
Carrying Amount | 4,274,520 | 4,021,785 |
Fair Value | $ 4,645,844 | $ 4,300,789 |
Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - APS - USD ($) $ in Millions |
Jun. 01, 2016 |
Dec. 31, 2015 |
Jun. 01, 2011 |
---|---|---|---|
Public Utilities, General Disclosures [Line Items] | |||
Net retail rate increase | $ 165.9 | $ 95.5 | |
Adjustor account balance transferred into base rates, amount | $ 267.6 | ||
Approximate percentage of increase in average customer bill | 5.74% | ||
Approximate percentage of increase in average residential customer bill | 7.96% |
Regulatory Matters - Four Corners and Cholla (Details) - APS - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Dec. 23, 2014 |
Dec. 30, 2013 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Dec. 31, 2015 |
|
SCE | Four Corners Units 4 and 5 | |||||
Business Acquisition [Line Items] | |||||
Ownership interest acquired | 48.00% | ||||
Settlement agreement, ACC approved rate adjustment, annualized customer impact | $ 57.1 | ||||
Net receipt due to negotiation of alternate arrangement | $ 40.0 | ||||
Four Corners cost deferral | SCE | Four Corners Units 4 and 5 | |||||
Business Acquisition [Line Items] | |||||
Regulatory assets, non-current | $ 60.0 | ||||
Regulatory noncurrent asset amortization period | 10 years | ||||
Retired power plant costs | |||||
Business Acquisition [Line Items] | |||||
Net book value | $ 112.0 | ||||
Navajo Plant | |||||
Business Acquisition [Line Items] | |||||
Net book value | $ 102.0 | ||||
Four Corners | SCE | |||||
Business Acquisition [Line Items] | |||||
Regulatory assets, non-current | $ 12.0 | ||||
Regulatory asset, write off amount | $ 12.0 |
Retirement Plans and Other Postretirement Benefits - Narrative (Details) |
6 Months Ended |
---|---|
Jun. 30, 2017
USD ($)
| |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Amount of other postretirement benefit trust assets for union employee medical costs | $ 145,000,000 |
Pension Benefits | |
Contributions | |
Voluntary employer contributions to pension plan | 80,000,000 |
Minimum employer contributions for the next three years | 0 |
Maximum employer contributions for the next two years (up to) | 300,000,000 |
Other Benefits | |
Contributions | |
Estimated future employer contributions in next three years | $ 1,000,000 |
Retirement Plans and Other Postretirement Benefits - Schedule of Net Benefit Cost (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Pension Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | $ 13,669 | $ 12,630 | $ 27,429 | $ 26,896 |
Interest cost on benefit obligation | 32,177 | 32,878 | 64,878 | 65,823 |
Expected return on plan assets | (43,425) | (43,161) | (87,135) | (86,953) |
Amortization of: | ||||
Prior service cost (credit) | 20 | 132 | 41 | 263 |
Net actuarial loss | 11,460 | 10,627 | 23,950 | 20,358 |
Net periodic benefit cost | 13,901 | 13,106 | 29,163 | 26,387 |
Portion of cost charged to expense | 6,894 | 6,433 | 14,461 | 12,951 |
Other Benefits | ||||
Retirement Plans and Other Benefits | ||||
Service cost — benefits earned during the period | 4,201 | 3,560 | 8,559 | 7,497 |
Interest cost on benefit obligation | 7,415 | 7,519 | 14,980 | 14,860 |
Expected return on plan assets | (13,350) | (9,125) | (26,701) | (18,247) |
Amortization of: | ||||
Prior service cost (credit) | (9,461) | (9,471) | (18,921) | (18,942) |
Net actuarial loss | 1,104 | 1,349 | 2,559 | 2,295 |
Net periodic benefit cost | (10,091) | (6,168) | (19,524) | (12,537) |
Portion of cost charged to expense | $ (5,004) | $ (3,027) | $ (9,682) | $ (6,153) |
Palo Verde Sale Leaseback Variable Interest Entities - Schedule of VIEs (Details) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | $ 111,580 | $ 113,515 |
Equity — Noncontrolling interests | 130,665 | 132,290 |
Arizona Public Service Company | ||
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 111,580 | 113,515 |
Equity — Noncontrolling interests | 130,665 | 132,290 |
Arizona Public Service Company | Consolidation of VIEs | ||
Amounts relating to the VIEs included in Condensed Consolidated Balance Sheets | ||
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation | 111,580 | 113,515 |
Equity — Noncontrolling interests | $ 130,665 | $ 132,290 |
Derivative Accounting - Schedule of Gross Notional Amounts Outstanding (Details) - Commodity Contracts |
6 Months Ended |
---|---|
Jun. 30, 2017
GWh
Bcf
| |
Outstanding gross notional amount of derivatives | |
Power | GWh | 908 |
Gas | Bcf | 247 |
Derivative Accounting - Derivative Instruments in the Balance Sheets (Details) - Commodity Contracts - USD ($) |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Assets | ||
Gross Recognized Derivatives | $ 17,244,000 | $ 54,798,000 |
Amounts Offset | (16,952,000) | (35,103,000) |
Net Recognized Derivatives | 292,000 | 19,695,000 |
Other | 70,000 | 0 |
Derivative assets | 362,000 | 19,695,000 |
Liabilities | ||
Gross Recognized Derivatives | (112,797,000) | (104,123,000) |
Amounts Offset | 20,152,000 | 35,103,000 |
Net Recognized Derivatives | (92,645,000) | (69,020,000) |
Other | (2,554,000) | (4,054,000) |
Amount Reported on Balance Sheet | (95,199,000) | (73,074,000) |
Assets and Liabilities | ||
Gross Recognized Derivatives | (95,553,000) | (49,325,000) |
Amounts Offset | 3,200,000 | 0 |
Net Recognized Derivatives | (92,353,000) | (49,325,000) |
Other | (2,484,000) | (4,054,000) |
Amount Reported on Balance Sheet | (94,837,000) | (53,379,000) |
Current Assets | ||
Assets | ||
Gross Recognized Derivatives | 15,624,000 | 48,094,000 |
Amounts Offset | (15,387,000) | (28,400,000) |
Net Recognized Derivatives | 237,000 | 19,694,000 |
Other | 70,000 | 0 |
Derivative assets | 307,000 | 19,694,000 |
Investments and Other Assets | ||
Assets | ||
Gross Recognized Derivatives | 1,620,000 | 6,704,000 |
Amounts Offset | (1,565,000) | (6,703,000) |
Net Recognized Derivatives | 55,000 | 1,000 |
Other | 0 | 0 |
Derivative assets | 55,000 | 1,000 |
Current Liabilities | ||
Liabilities | ||
Gross Recognized Derivatives | (64,646,000) | (50,182,000) |
Amounts Offset | 18,587,000 | 28,400,000 |
Net Recognized Derivatives | (46,059,000) | (21,782,000) |
Other | (2,554,000) | (4,054,000) |
Amount Reported on Balance Sheet | (48,613,000) | (25,836,000) |
Deferred Credits and Other | ||
Liabilities | ||
Gross Recognized Derivatives | (48,151,000) | (53,941,000) |
Amounts Offset | 1,565,000 | 6,703,000 |
Net Recognized Derivatives | (46,586,000) | (47,238,000) |
Other | 0 | 0 |
Amount Reported on Balance Sheet | $ (46,586,000) | $ (47,238,000) |
Derivative Accounting - Credit Risk and Credit Related Contingent Features (Details) - Commodity Contracts $ in Thousands |
Jun. 30, 2017
USD ($)
|
---|---|
Credit Risk and Credit-Related Contingent Features | |
Aggregate fair value of derivative instruments in a net liability position | $ 112,797 |
Cash collateral posted | 3,200 |
Additional cash collateral in the event credit-risk-related contingent features were fully triggered | $ 89,336 |
Commitments and Contingencies - Superfund-Related Matters, Southwest Power Outage and Clean Air Act (Details) - Arizona Public Service Company - Contaminated groundwater wells $ in Millions |
6 Months Ended | ||
---|---|---|---|
Dec. 16, 2016
plaintiff
|
Aug. 06, 2013
Defendant
|
Jun. 30, 2017
USD ($)
|
|
Loss Contingencies [Line Items] | |||
Costs related to investigation and study under Superfund site | $ | $ 2 | ||
Number of defendants against whom Roosevelt Irrigation District (RID) filed lawsuit | Defendant | 24 | ||
Number of plaintiffs | plaintiff | 2 |
Other Income and Other Expense (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Other income: | ||||
Interest income | $ 387 | $ 184 | $ 864 | $ 302 |
Investment gains — net | 0 | 13 | 0 | 13 |
Miscellaneous | 97 | 0 | 100 | (1) |
Total other income | 484 | 197 | 964 | 314 |
Other expense: | ||||
Non-operating costs | (3,401) | (2,085) | (5,360) | (4,133) |
Investment losses — net | (227) | (539) | (528) | (1,058) |
Miscellaneous | (194) | (218) | (1,614) | (1,689) |
Total other expense | (3,822) | (2,842) | (7,502) | (6,880) |
Arizona Public Service Company | ||||
Other income: | ||||
Interest income | 257 | 109 | 596 | 181 |
Gain on disposition of property | 260 | 4,989 | 567 | 5,321 |
Miscellaneous | 625 | 649 | 1,041 | 855 |
Total other income | 1,142 | 5,747 | 2,204 | 6,357 |
Other expense: | ||||
Non-operating costs | (3,753) | (2,719) | (5,918) | (4,685) |
Loss on disposition of property | (1,169) | (657) | (1,257) | (1,083) |
Miscellaneous | (729) | (1,054) | (2,854) | (3,412) |
Total other expense | $ (5,651) | $ (4,430) | $ (10,029) | $ (9,180) |
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Earnings Per Share [Abstract] | ||||
Net income attributable to common shareholders | $ 167,443 | $ 121,308 | $ 190,755 | $ 125,761 |
Weighted average common shares outstanding - basic (in shares) | 111,797 | 111,368 | 111,763 | 111,336 |
Net effect of dilutive securities: | ||||
Contingently issuable performance shares and restricted stock units (in shares) | 548 | 636 | 507 | 594 |
Weighted average common shares outstanding — diluted (in shares) | 112,345 | 112,004 | 112,270 | 111,930 |
Earnings per weighted-average common share outstanding | ||||
Net income attributable to common shareholders - basic (in dollars per share) | $ 1.50 | $ 1.09 | $ 1.71 | $ 1.13 |
Net income attributable to common shareholders - diluted (in dollars per share) | $ 1.49 | $ 1.08 | $ 1.70 | $ 1.12 |
Fair Value Measurements - Level 3 Rollforward Derivatives (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Net derivative balance at beginning of period | $ (41,685) | $ (39,507) | $ (47,406) | $ (32,979) |
Included in OCI | (6) | 104 | (6) | 104 |
Deferred as a regulatory asset or liability | 4,252 | 1,499 | (7,503) | (7,604) |
Settlements | 1,699 | 4,502 | 3,122 | 6,267 |
Transfers into Level 3 from Level 2 | (4,350) | 120 | (4,388) | 382 |
Transfers from Level 3 into Level 2 | 3,845 | 902 | 19,936 | 1,450 |
Net derivative balance at end of period | (36,245) | (32,380) | (36,245) | (32,380) |
Net unrealized gains included in earnings related to instruments still held at end of period | $ 0 | $ 0 | $ 0 | $ 0 |
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