Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Oct. 30, 2018 | |
Document Information [Line Items] | ||
Entity Registrant Name | PNM RESOURCES INC | |
Entity Central Index Key | 1,108,426 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 79,653,624 | |
PNM | ||
Document Information [Line Items] | ||
Entity Registrant Name | PUBLIC SERVICE CO OF NEW MEXICO | |
Entity Central Index Key | 81,023 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 39,117,799 | |
Texas-New Mexico Power Company | ||
Document Information [Line Items] | ||
Entity Registrant Name | TEXAS NEW MEXICO POWER CO | |
Entity Central Index Key | 22,767 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 6,358 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Earnings - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Electric Operating Revenues: | ||||
Contracts with customers | $ 400,023 | $ 392,607 | $ 1,042,033 | $ 1,016,384 |
Revenues | 422,666 | 419,900 | 1,092,857 | 1,112,398 |
Operating Expenses: | ||||
Administrative and general | 49,969 | 44,130 | 141,607 | 132,509 |
Regulatory disallowances and restructuring costs | (1,645) | 0 | 149 | 0 |
Depreciation and amortization | 61,580 | 58,821 | 180,365 | 172,829 |
Transmission and distribution costs | 19,394 | 16,801 | 54,800 | 50,309 |
Taxes other than income taxes | 20,492 | 19,808 | 60,094 | 57,820 |
Total operating expenses | 294,676 | 275,278 | 839,406 | 822,435 |
Operating income | 127,990 | 144,622 | 253,451 | 289,963 |
Other Income and Deductions: | ||||
Interest income | 3,400 | 3,582 | 11,862 | 12,348 |
Gains on investment securities | 2,463 | 5,406 | 1,081 | 17,730 |
Other income | 3,735 | 6,275 | 12,000 | 14,626 |
Other (deductions) | (2,624) | (6,709) | (9,867) | (17,372) |
Net other income and deductions | 6,974 | 8,554 | 15,076 | 27,332 |
Interest Charges | 30,492 | 32,106 | 96,868 | 96,137 |
Earnings before Income Taxes | 104,472 | 121,070 | 171,659 | 221,158 |
Income Taxes | 12,899 | 42,743 | 18,838 | 75,154 |
Net Earnings | 91,573 | 78,327 | 152,821 | 146,004 |
(Earnings) Attributable to Valencia Non-controlling Interest | (3,920) | (4,456) | (11,706) | (11,452) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Net Earnings Available for PNM Common Stock | $ 87,521 | $ 73,739 | $ 140,719 | $ 134,156 |
Net Earnings Attributable to PNMR per Common Share: | ||||
Basic (dollars per share) | $ 1.10 | $ 0.92 | $ 1.76 | $ 1.68 |
Diluted (dollars per share) | 1.09 | 0.92 | 1.76 | 1.67 |
Dividends Declared per Common Share (dollars per share) | $ 0.2650 | $ 0.2425 | $ 0.7950 | $ 0.7275 |
Alternative revenue programs | ||||
Electric Operating Revenues: | ||||
Revenues | $ (8,050) | $ (1,908) | $ (1,466) | $ 11,591 |
Other electric operating revenue | ||||
Electric Operating Revenues: | ||||
Revenues | 30,693 | 29,201 | 52,290 | 84,423 |
Electricity | ||||
Electric Operating Revenues: | ||||
Revenues | 422,666 | 419,900 | 1,092,857 | 1,112,398 |
Operating Expenses: | ||||
Cost of energy and energy production costs | 113,536 | 103,748 | 293,803 | 310,818 |
Electricity, Generation | ||||
Operating Expenses: | ||||
Cost of energy and energy production costs | 31,350 | 31,970 | 108,588 | 98,150 |
Service | ||||
Operating Expenses: | ||||
Depreciation and amortization | 61,580 | 58,821 | 180,365 | 172,829 |
PNM | ||||
Electric Operating Revenues: | ||||
Contracts with customers | 306,019 | 300,604 | 783,310 | 769,069 |
Revenues | 331,374 | 327,254 | 832,116 | 854,909 |
Operating Expenses: | ||||
Administrative and general | 44,923 | 39,888 | 129,571 | 120,598 |
Regulatory disallowances and restructuring costs | (1,645) | 0 | 149 | 0 |
Depreciation and amortization | 38,474 | 36,764 | 113,314 | 109,228 |
Transmission and distribution costs | 12,408 | 10,207 | 33,228 | 30,301 |
Taxes other than income taxes | 10,964 | 10,668 | 34,033 | 32,837 |
Total operating expenses | 228,858 | 211,864 | 648,430 | 637,749 |
Operating income | 102,516 | 115,390 | 183,686 | 217,160 |
Other Income and Deductions: | ||||
Interest income | 3,472 | 1,782 | 9,340 | 6,457 |
Gains on investment securities | 2,463 | 5,406 | 1,081 | 17,730 |
Other income | 2,137 | 3,762 | 6,821 | 10,270 |
Other (deductions) | (2,085) | (4,964) | (7,314) | (14,490) |
Net other income and deductions | 5,987 | 5,986 | 9,928 | 19,967 |
Interest Charges | 18,063 | 20,451 | 58,881 | 62,393 |
Earnings before Income Taxes | 90,440 | 100,925 | 134,733 | 174,734 |
Income Taxes | 9,012 | 35,642 | 11,009 | 58,865 |
Net Earnings | 81,428 | 65,283 | 123,724 | 115,869 |
(Earnings) Attributable to Valencia Non-controlling Interest | (3,920) | (4,456) | (11,706) | (11,452) |
Net Earnings Attributable to PNMR | 77,508 | 60,827 | 112,018 | 104,417 |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Net Earnings Available for PNM Common Stock | 77,376 | 60,695 | 111,622 | 104,021 |
PNM | Alternative revenue programs | ||||
Electric Operating Revenues: | ||||
Revenues | (5,338) | (2,551) | (3,484) | 1,417 |
PNM | Other electric operating revenue | ||||
Electric Operating Revenues: | ||||
Revenues | 30,693 | 29,201 | 52,290 | 84,423 |
PNM | Electricity | ||||
Operating Expenses: | ||||
Cost of energy and energy production costs | 92,384 | 82,367 | 229,547 | 246,635 |
PNM | Electricity, Generation | ||||
Operating Expenses: | ||||
Cost of energy and energy production costs | 31,350 | 31,970 | 108,588 | 98,150 |
Texas-New Mexico Power Company | ||||
Electric Operating Revenues: | ||||
Contracts with customers | 94,004 | 92,003 | 258,723 | 247,315 |
Revenues | 91,292 | 92,646 | 260,741 | 257,489 |
Operating Expenses: | ||||
Administrative and general | 9,781 | 10,765 | 29,342 | 30,402 |
Depreciation and amortization | 17,176 | 16,424 | 49,676 | 47,392 |
Transmission and distribution costs | 6,986 | 6,594 | 21,572 | 20,008 |
Taxes other than income taxes | 8,373 | 8,008 | 22,710 | 21,778 |
Total operating expenses | 63,468 | 63,172 | 187,556 | 183,763 |
Operating income | 27,824 | 29,474 | 73,185 | 73,726 |
Other Income and Deductions: | ||||
Other income | 1,300 | 2,258 | 4,276 | 3,621 |
Other (deductions) | (149) | (1,030) | (1,209) | (1,229) |
Net other income and deductions | 1,151 | 1,228 | 3,067 | 2,392 |
Interest Charges | 8,241 | 7,704 | 23,771 | 22,619 |
Earnings before Income Taxes | 20,734 | 22,998 | 52,481 | 53,499 |
Income Taxes | 4,634 | 8,271 | 11,602 | 18,964 |
Net Earnings Attributable to PNMR | $ 16,100 | $ 14,727 | 40,879 | 34,535 |
Net Earnings Attributable to PNMR per Common Share: | ||||
Dividends Declared per Common Share (dollars per share) | $ 0.2650 | $ 0.2425 | ||
Texas-New Mexico Power Company | Alternative revenue programs | ||||
Electric Operating Revenues: | ||||
Revenues | $ (2,712) | $ 643 | 2,018 | 10,174 |
Texas-New Mexico Power Company | Other electric operating revenue | ||||
Electric Operating Revenues: | ||||
Revenues | 0 | 0 | ||
Texas-New Mexico Power Company | Electricity | ||||
Operating Expenses: | ||||
Cost of energy and energy production costs | $ 21,152 | $ 21,381 | $ 64,256 | $ 64,183 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net Earnings | $ 91,573 | $ 78,327 | $ 152,821 | $ 146,004 |
Unrealized Gains on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | 1,044 | 4,528 | 2,142 | 13,648 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (266) | (2,526) | (2,598) | (6,786) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) | 1,410 | 987 | 4,236 | 2,961 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Change in fair market value, net of income tax (expense) benefit of $(3), $(4), $(618), and $108 | 8 | 6 | 1,813 | (170) |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(28), $(62), $(27), and $(187) | 81 | 99 | 75 | 297 |
Total Other Comprehensive Income | 2,277 | 3,094 | 5,668 | 9,950 |
Comprehensive Income | 93,850 | 81,421 | 158,489 | 155,954 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,920) | (4,456) | (11,706) | (11,452) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Comprehensive Income Attributable to PNMR | 89,798 | 76,833 | 146,387 | 144,106 |
PNM | ||||
Net Earnings | 81,428 | 65,283 | 123,724 | 115,869 |
Unrealized Gains on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | 1,044 | 4,528 | 2,142 | 13,648 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (266) | (2,526) | (2,598) | (6,786) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) | 1,410 | 987 | 4,236 | 2,961 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Total Other Comprehensive Income | 2,188 | 2,989 | 3,780 | 9,823 |
Comprehensive Income | 83,616 | 68,272 | 127,504 | 125,692 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,920) | (4,456) | (11,706) | (11,452) |
Comprehensive Income Attributable to PNMR | $ 79,696 | $ 63,816 | $ 115,798 | $ 114,240 |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | $ (356) | $ (2,871) | $ (730) | $ (8,654) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 91 | 1,601 | 885 | 4,302 |
Pension liability adjustment, income tax expense (benefit) | (480) | (626) | (1,442) | (1,878) |
Change in fair market value, income tax (expense) benefit | (3) | (4) | (618) | 108 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | (28) | (62) | (27) | (187) |
PNM | ||||
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | (356) | (2,871) | (730) | (8,654) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 91 | 1,601 | 885 | 4,302 |
Pension liability adjustment, income tax expense (benefit) | $ (480) | $ (626) | $ (1,442) | $ (1,878) |
Condensed Consolidated Statem_4
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Cash Flows From Operating Activities: | ||
Net Earnings | $ 152,821 | $ 146,004 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 207,406 | 200,286 |
Deferred income tax expense | 18,706 | 75,224 |
Net unrealized (gains) losses on commodity derivatives | (84) | 968 |
(Gains) on investment securities | (1,081) | (17,730) |
Stock based compensation expense | 4,551 | 5,322 |
Regulatory disallowances and restructuring costs | 149 | 0 |
Allowance for equity funds used during construction | (7,098) | (6,217) |
Other, net | 2,715 | 1,409 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (20,447) | (21,077) |
Materials and supplies | (8,731) | (203) |
Other current assets | (13,657) | 21,761 |
Other assets | 2,608 | (5,981) |
Accounts payable | (32,638) | 3,729 |
Accrued interest and taxes | 17,113 | 20,722 |
Other current liabilities | 4,220 | (1,588) |
Other liabilities | (9,656) | (6,292) |
Net cash flows from operating activities | 316,897 | 416,337 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (365,484) | (353,423) |
Proceeds from sales of investment securities | 911,899 | 456,577 |
Purchases of investment securities | (920,217) | (461,126) |
Principal repayments on Westmoreland Loan | 56,640 | 28,770 |
Investments in NMRD | (9,000) | 0 |
Other, net | (365) | 160 |
Net cash flows from investing activities | (326,527) | (329,042) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | (42,800) | (20,600) |
Long-term borrowings | 829,652 | 317,000 |
Repayment of long-term debt | (650,162) | (263,323) |
Proceeds from stock option exercise | 937 | 1,739 |
Awards of common stock | (12,505) | (13,816) |
Dividends paid | (63,721) | (58,344) |
Valencia’s transactions with its owner | (12,677) | (12,963) |
Amounts received under transmission interconnection arrangements | 0 | 11,879 |
Refunds paid under transmission interconnection arrangements | (2,246) | (9,368) |
Debt issuance costs and other, net | (5,858) | (1,872) |
Net cash flows from financing activities | 40,620 | (49,668) |
Change in Cash, Restricted Cash, and Equivalents | 30,990 | 37,627 |
Cash, Restricted Cash, and Equivalents at End of Period | 34,964 | 43,149 |
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | ||
At beginning of period | 0 | 1,000 |
At end of period | 0 | 0 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 81,203 | 75,356 |
Income taxes paid (refunded), net | 842 | 625 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | 16,177 | (4,499) |
PNM | ||
Cash Flows From Operating Activities: | ||
Net Earnings | 123,724 | 115,869 |
Net earnings | 112,018 | 104,417 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 137,224 | 134,541 |
Deferred income tax expense | 11,894 | 59,866 |
Net unrealized (gains) losses on commodity derivatives | (84) | 968 |
(Gains) on investment securities | (1,081) | (17,730) |
Regulatory disallowances and restructuring costs | 149 | 0 |
Allowance for equity funds used during construction | (5,473) | (5,908) |
Other, net | 2,495 | 1,705 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (14,164) | (13,881) |
Materials and supplies | (7,308) | 1,385 |
Other current assets | (15,493) | 23,488 |
Other assets | 11,829 | 6,925 |
Accounts payable | (23,990) | 123 |
Accrued interest and taxes | 13,560 | 16,221 |
Other current liabilities | (14,838) | (17,988) |
Other liabilities | (12,228) | (8,792) |
Net cash flows from operating activities | 206,216 | 296,792 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (177,550) | (206,499) |
Proceeds from sales of investment securities | 911,899 | 456,577 |
Purchases of investment securities | (920,217) | (461,126) |
Other, net | 141 | 150 |
Net cash flows from investing activities | (185,727) | (210,898) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | (39,800) | (61,000) |
Long-term borrowings | 450,000 | 257,000 |
Repayment of long-term debt | (450,025) | (232,000) |
Dividends paid | (396) | (396) |
Valencia’s transactions with its owner | (12,677) | (12,963) |
Amounts received under transmission interconnection arrangements | 68,200 | 11,879 |
Refunds paid under transmission interconnection arrangements | (2,246) | (9,368) |
Debt issuance costs and other, net | (3,167) | (1,000) |
Net cash flows from financing activities | 9,889 | (47,848) |
Change in Cash, Restricted Cash, and Equivalents | 30,378 | 38,046 |
Cash, Restricted Cash, and Equivalents at End of Period | 31,486 | 39,370 |
Restricted Cash Included in Other Current Assets on Condensed Consolidated Balance Sheets: | ||
At beginning of period | 0 | 1,000 |
At end of period | 0 | 0 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 50,160 | 48,627 |
Income taxes paid (refunded), net | 0 | 0 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | (27) | (9,399) |
Texas-New Mexico Power Company | ||
Cash Flows From Operating Activities: | ||
Net earnings | 40,879 | 34,535 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 51,076 | 48,754 |
Deferred income tax expense | (3,259) | 8,578 |
Allowance for equity funds used during construction | (1,624) | (309) |
Other, net | 184 | (296) |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (6,283) | (7,196) |
Materials and supplies | (1,423) | (1,588) |
Other current assets | 759 | (1,674) |
Other assets | (9,169) | (13,799) |
Accounts payable | (4,277) | 669 |
Accrued interest and taxes | 18,389 | 13,550 |
Other current liabilities | 6,092 | 945 |
Other liabilities | 2,613 | 1,633 |
Net cash flows from operating activities | 93,957 | 83,802 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (170,785) | (106,914) |
Net cash flows from investing activities | (170,785) | (106,914) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | 17,500 | 0 |
Short-term borrowings (repayments) - affiliate, net | 4,100 | (4,600) |
Long-term borrowings | 80,000 | 60,000 |
Dividends paid | (25,804) | (29,663) |
Debt issuance costs and other, net | (668) | (874) |
Net cash flows from financing activities | 75,128 | 24,863 |
Cash, Restricted Cash, and Equivalents at End of Period | 0 | |
Change in Cash and Cash Equivalents | (1,700) | 1,751 |
Cash and Cash Equivalents at Beginning of Period | 1,700 | 671 |
Cash and Cash Equivalents at End of Period | 0 | 2,422 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 16,338 | 16,721 |
Income taxes paid (refunded), net | 842 | 750 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | $ 12,822 | $ (251) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Current Assets: | ||
Cash and cash equivalents | $ 34,964 | $ 3,974 |
Accounts receivable, net of allowance for uncollectible accounts | 108,648 | 90,473 |
Unbilled revenues | 53,832 | 54,055 |
Other receivables | 22,246 | 17,582 |
Current portion of Westmoreland Loan | 0 | 3,576 |
Materials, supplies, and fuel stock | 75,234 | 66,502 |
Regulatory assets | 7,261 | 2,933 |
Commodity derivative instruments | 1,083 | 1,088 |
Income taxes receivable | 7,589 | 6,879 |
Other current assets | 53,068 | 47,358 |
Total current assets | 363,925 | 294,420 |
Other Property and Investments: | ||
Long-term portion of Westmoreland Loan | 0 | 53,064 |
Investment securities | 331,746 | 323,524 |
Equity investment in NMRD | 26,029 | 16,510 |
Other investments | 348 | 503 |
Non-utility property | 3,404 | 3,404 |
Total other property and investments | 361,527 | 397,005 |
Utility Plant: | ||
Plant in service and held for future use | 7,527,250 | 7,238,285 |
Less accumulated depreciation and amortization | 2,683,626 | 2,592,692 |
Net plant in service and plant held for future use | 4,843,624 | 4,645,593 |
Construction work in progress | 227,367 | 245,933 |
Nuclear fuel, net of accumulated amortization | 92,838 | 88,701 |
Net utility plant | 5,163,829 | 4,980,227 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 580,828 | 600,672 |
Goodwill | 278,297 | 278,297 |
Commodity derivative instruments | 2,741 | 3,556 |
Other deferred charges | 97,848 | 91,926 |
Total deferred charges and other assets | 959,714 | 974,451 |
Total assets | 6,848,995 | 6,646,103 |
Current Liabilities: | ||
Short-term debt | 262,600 | 305,400 |
Current installments of long-term debt | 471,880 | 256,895 |
Accounts payable | 72,568 | 121,383 |
Customer deposits | 10,833 | 11,028 |
Accrued interest and taxes | 80,181 | 62,357 |
Regulatory liabilities | 9,300 | 2,309 |
Commodity derivative instruments | 1,092 | 1,182 |
Dividends declared | 21,240 | 21,240 |
Other current liabilities | 50,781 | 53,850 |
Total current liabilities | 980,475 | 835,644 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 2,142,631 | 2,180,750 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 586,295 | 547,210 |
Regulatory liabilities | 925,116 | 933,578 |
Asset retirement obligations | 155,203 | 146,679 |
Accrued pension liability and postretirement benefit cost | 80,871 | 94,003 |
Commodity derivative instruments | 2,741 | 3,556 |
Other deferred credits | 127,612 | 131,706 |
Total deferred credits and other liabilities | 1,877,838 | 1,856,732 |
Total liabilities | 5,000,944 | 4,873,126 |
Commitments and Contingencies (Note 11) | ||
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 |
Company common stockholders’ equity: | ||
Common stock | 1,150,648 | 1,157,665 |
Accumulated other comprehensive income (loss), net of income taxes | (101,480) | (95,940) |
Retained earnings | 722,130 | 633,528 |
Total stockholders' equity | 1,771,298 | 1,695,253 |
Non-controlling interest in Valencia | 65,224 | 66,195 |
Total equity | 1,836,522 | 1,761,448 |
Total liabilities and stockholders' equity | 6,848,995 | 6,646,103 |
PNM | ||
Current Assets: | ||
Cash and cash equivalents | 31,486 | 1,108 |
Accounts receivable, net of allowance for uncollectible accounts | 79,526 | 67,227 |
Unbilled revenues | 43,239 | 43,869 |
Other receivables | 21,158 | 14,541 |
Affiliate receivables | 8,855 | 9,486 |
Materials, supplies, and fuel stock | 68,167 | 60,859 |
Regulatory assets | 7,063 | 2,139 |
Commodity derivative instruments | 1,083 | 1,088 |
Income taxes receivable | 4,294 | 3,410 |
Other current assets | 46,467 | 39,904 |
Total current assets | 311,338 | 243,631 |
Other Property and Investments: | ||
Investment securities | 331,746 | 323,524 |
Other investments | 142 | 283 |
Non-utility property | 96 | 96 |
Total other property and investments | 331,984 | 323,903 |
Utility Plant: | ||
Plant in service and held for future use | 5,681,620 | 5,501,070 |
Less accumulated depreciation and amortization | 2,087,595 | 2,029,534 |
Net plant in service and plant held for future use | 3,594,025 | 3,471,536 |
Construction work in progress | 141,174 | 204,079 |
Nuclear fuel, net of accumulated amortization | 92,838 | 88,701 |
Net utility plant | 3,828,037 | 3,764,316 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 440,346 | 459,239 |
Goodwill | 51,632 | 51,632 |
Commodity derivative instruments | 2,741 | 3,556 |
Other deferred charges | 76,683 | 75,286 |
Total deferred charges and other assets | 571,402 | 589,713 |
Total assets | 5,042,761 | 4,921,563 |
Current Liabilities: | ||
Short-term debt | 0 | 39,800 |
Current installments of long-term debt | 199,993 | 23 |
Accounts payable | 53,131 | 77,094 |
Affiliate payables | 3,148 | 22,875 |
Customer deposits | 10,833 | 11,028 |
Accrued interest and taxes | 48,389 | 33,945 |
Regulatory liabilities | 5,796 | 784 |
Commodity derivative instruments | 1,092 | 1,182 |
Dividends declared | 132 | 132 |
Other current liabilities | 30,582 | 31,633 |
Total current liabilities | 353,096 | 218,496 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 1,456,109 | 1,657,887 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 480,479 | 449,012 |
Regulatory liabilities | 736,123 | 754,441 |
Asset retirement obligations | 154,171 | 145,707 |
Accrued pension liability and postretirement benefit cost | 74,368 | 86,124 |
Commodity derivative instruments | 2,741 | 3,556 |
Other deferred credits | 171,345 | 106,442 |
Total deferred credits and other liabilities | 1,619,227 | 1,545,282 |
Total liabilities | 3,428,432 | 3,421,665 |
Commitments and Contingencies (Note 11) | ||
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 |
Company common stockholders’ equity: | ||
Common stock | 1,264,918 | 1,264,918 |
Accumulated other comprehensive income (loss), net of income taxes | (104,521) | (97,093) |
Retained earnings | 377,179 | 254,349 |
Total stockholders' equity | 1,537,576 | 1,422,174 |
Non-controlling interest in Valencia | 65,224 | 66,195 |
Total equity | 1,602,800 | 1,488,369 |
Total liabilities and stockholders' equity | 5,042,761 | 4,921,563 |
Texas-New Mexico Power Company | ||
Current Assets: | ||
Cash and cash equivalents | 0 | 1,700 |
Accounts receivable, net of allowance for uncollectible accounts | 29,122 | 23,246 |
Unbilled revenues | 10,593 | 10,186 |
Other receivables | 2,315 | 2,860 |
Affiliate receivables | 0 | 336 |
Materials, supplies, and fuel stock | 7,067 | 5,643 |
Regulatory assets | 198 | 794 |
Other current assets | 1,490 | 1,131 |
Total current assets | 50,785 | 45,896 |
Other Property and Investments: | ||
Other investments | 206 | 220 |
Non-utility property | 2,240 | 2,240 |
Total other property and investments | 2,446 | 2,460 |
Utility Plant: | ||
Plant in service and held for future use | 1,602,210 | 1,504,778 |
Less accumulated depreciation and amortization | 477,213 | 460,858 |
Net plant in service and plant held for future use | 1,124,997 | 1,043,920 |
Construction work in progress | 77,456 | 34,350 |
Net utility plant | 1,202,453 | 1,078,270 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 140,482 | 141,433 |
Goodwill | 226,665 | 226,665 |
Other deferred charges | 6,011 | 6,046 |
Total deferred charges and other assets | 373,158 | 374,144 |
Total assets | 1,628,842 | 1,500,770 |
Current Liabilities: | ||
Short-term debt | 17,500 | 0 |
Short-term debt - affiliate | 4,100 | 0 |
Current installments of long-term debt | 171,889 | 0 |
Accounts payable | 12,714 | 29,812 |
Affiliate payables | 3,792 | 667 |
Accrued interest and taxes | 48,008 | 29,619 |
Regulatory liabilities | 3,504 | 1,525 |
Other current liabilities | 3,102 | 2,450 |
Total current liabilities | 264,609 | 64,073 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 388,404 | 480,620 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 123,318 | 126,415 |
Regulatory liabilities | 188,993 | 179,137 |
Asset retirement obligations | 843 | 793 |
Accrued pension liability and postretirement benefit cost | 6,503 | 7,879 |
Other deferred credits | 6,692 | 7,448 |
Total deferred credits and other liabilities | 326,349 | 321,672 |
Total liabilities | 979,362 | 866,365 |
Commitments and Contingencies (Note 11) | ||
Company common stockholders’ equity: | ||
Common stock | 64 | 64 |
Paid-in-capital | 504,166 | 504,166 |
Retained earnings | 145,250 | 130,175 |
Total stockholders' equity | 649,480 | 634,405 |
Total liabilities and stockholders' equity | $ 1,628,842 | $ 1,500,770 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Allowance for uncollectible accounts | $ 1,433 | $ 1,081 |
Accumulated depreciation, nuclear fuel | $ 49,376 | $ 43,524 |
Cumulative preferred stock of subsidiary, stated value (in dollars per share) | $ 100 | $ 100 |
Cumulative preferred stock of subsidiary, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Cumulative preferred stock of subsidiary, shares issued (in shares) | 115,293 | 115,293 |
Cumulative preferred stock of subsidiary, shares outstanding (in shares) | 115,293 | 115,293 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 120,000,000 | 120,000,000 |
Common stock, shares issued (in shares) | 79,653,624 | 79,653,624 |
Common stock, shares outstanding (in shares) | 79,653,624 | 79,653,624 |
PNM | ||
Allowance for uncollectible accounts | $ 1,433 | $ 1,081 |
Accumulated depreciation, nuclear fuel | $ 49,376 | $ 43,524 |
Cumulative preferred stock, stated value (in dollars per share) | $ 100 | $ 100 |
Cumulative preferred stock, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Cumulative preferred stock, shares issued (in shares) | 115,293 | 115,293 |
Cumulative preferred stock, shares outstanding (in shares) | 115,293 | 115,293 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 40,000,000 | 40,000,000 |
Common stock, shares issued (in shares) | 39,117,799 | 39,117,799 |
Common stock, shares outstanding (in shares) | 39,117,799 | 39,117,799 |
Texas-New Mexico Power Company | ||
Common stock, par value (in dollars per share) | $ 10 | $ 10 |
Common stock, shares authorized (in shares) | 12,000,000 | 12,000,000 |
Common stock, shares issued (in shares) | 6,358 | 6,358 |
Common stock, shares outstanding (in shares) | 6,358 | 6,358 |
Condensed Consolidated Statem_5
Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Thousands | Total | Total PNMR Common Stockholders’ Equity | Common Stock | AOCI | Retained Earnings | Non- controlling Interest in Valencia | PNM | PNMTotal PNMR Common Stockholders’ Equity | PNMCommon Stock | PNMAOCI | PNMRetained Earnings | PNMNon- controlling Interest in Valencia | Texas-New Mexico Power Company | Texas-New Mexico Power CompanyCommon Stock | Texas-New Mexico Power CompanyPaid-in Capital | Texas-New Mexico Power CompanyRetained Earnings |
Beginning balance at Dec. 31, 2016 | $ (92,451) | $ (92,428) | ||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings before subsidiary preferred stock dividends | $ 146,004 | $ 115,869 | ||||||||||||||
Net earnings | 104,417 | $ 34,535 | ||||||||||||||
Total other comprehensive income | 9,950 | 9,823 | ||||||||||||||
Subsidiary preferred stock dividends | (396) | |||||||||||||||
Dividends declared on common stock | (29,700) | |||||||||||||||
Ending balance at Sep. 30, 2017 | (82,501) | (82,605) | ||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Cumulative effect adjustment (Note 7) | (11,208) | $ 11,208 | (11,208) | $ 11,208 | ||||||||||||
Balance, as adjusted | 1,761,448 | $ 1,695,253 | $ 1,157,665 | (107,148) | 644,736 | $ 66,195 | 1,488,369 | $ 1,422,174 | $ 1,264,918 | (108,301) | 265,557 | $ 66,195 | ||||
Beginning balance at Dec. 31, 2017 | 1,761,448 | 1,695,253 | 1,157,665 | (95,940) | 633,528 | 66,195 | 1,488,369 | 1,422,174 | 1,264,918 | (97,093) | 254,349 | 66,195 | ||||
Beginning balance TNMP at Dec. 31, 2017 | 1,695,253 | 1,422,174 | 634,405 | $ 64 | $ 504,166 | $ 130,175 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings before subsidiary preferred stock dividends | 152,821 | 141,115 | 141,115 | 11,706 | 123,724 | 112,018 | 112,018 | 11,706 | ||||||||
Net earnings | 112,018 | 40,879 | 40,879 | |||||||||||||
Total other comprehensive income | 5,668 | 5,668 | 5,668 | 3,780 | 3,780 | 3,780 | ||||||||||
Subsidiary preferred stock dividends | (396) | (396) | (396) | |||||||||||||
Dividends declared on preferred stock | (396) | (396) | (396) | |||||||||||||
Dividends declared on common stock | (63,325) | (63,325) | (63,325) | (25,804) | (25,804) | |||||||||||
Proceeds from stock option exercise | 937 | 937 | 937 | |||||||||||||
Awards of common stock | (12,505) | (12,505) | (12,505) | |||||||||||||
Stock based compensation expense | 4,551 | 4,551 | 4,551 | |||||||||||||
Valencia’s transactions with its owner | (12,677) | (12,677) | (12,677) | (12,677) | ||||||||||||
Ending balance at Sep. 30, 2018 | 1,836,522 | $ 1,771,298 | $ 1,150,648 | $ (101,480) | $ 722,130 | $ 65,224 | 1,602,800 | $ 1,537,576 | $ 1,264,918 | $ (104,521) | $ 377,179 | $ 65,224 | ||||
Ending balance TNMP at Sep. 30, 2018 | $ 1,771,298 | $ 1,537,576 | $ 649,480 | $ 64 | $ 504,166 | $ 145,250 |
Significant Accounting Policies
Significant Accounting Policies and Responsibility for Financial Statements | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies and Responsibility for Financial Statements | Significant Accounting Policies and Responsibility for Financial Statements Financial Statement Preparation In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2018 and December 31, 2017 , the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2018 and 2017, and cash flows for the nine months ended September 30, 2018 and 2017 . The preparation of financial statements in conformity 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 the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year. The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2017 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2018 financial statement presentation. These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2017 Annual Reports on Form 10-K. GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP. Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 6). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants. PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated. Dividends on Common Stock Dividends on PNMR’s common stock are declared by the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock attributable to the second quarter of $0.2650 per share in July 2018 and $0.2425 in July 2017, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock for the third quarter of $0.2650 per share in September 2018 and $0.2425 per share in September 2017, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. TNMP declared and paid cash dividends on common stock to PNMR of $25.8 million and $29.7 million in the nine months ended September 30, 2018 and 2017. Investment in NM Renewable Development, LLC As discussed in Note 1 of the 2017 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 34.3 MW. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations. In the nine months ended September 30, 2018, PNMR Development made cash contributions of $9.0 million to NMRD to be used primarily for its construction activities. For the three and nine months ended September 30, 2018, NMRD had revenues of $1.0 million and $2.5 million and net earnings of $0.5 million and $1.0 million . At September 30, 2018, NMRD had $2.3 million of current assets, $50.4 million of property, plant, and equipment and other assets, $0.7 million of current liabilities, and $52.0 million of owners’ equity. Cash and Restricted Cash Additional information concerning the Company’s policy for recording cash and cash equivalents is discussed in Note 1 of the 2017 Annual Reports on Form 10-K. In November 2016, the FASB issued Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230) , which requires amounts generally described as restricted cash and restricted cash equivalents (collectively, “restricted cash”) to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not require that restricted cash be reflected as cash in the statement of financial position and does not provide a definition of what should be considered restricted cash. During 2015, PNM received a deposit of $8.2 million from a third party that was restricted for PNM’s construction of transmission interconnection facilities for that party. During 2016, PNM utilized $7.2 million of such third-party deposits to offset construction costs for the interconnection facilities. The remaining $1.0 million was held as restricted cash until the second quarter of 2017, at which time a refund was made to the third party. The balances of this deposit arrangement were included in other current assets on the balance sheets of PNMR and PNM. Under the terms of the BTMU Term Loan Agreement (Note 9), all cash of NM Capital was restricted to be used for payments required under that agreement or for taxes and fees. On May 22, 2018, Westmoreland repaid the Westmoreland Loan in full. NM Capital used a portion of the proceeds to repay all its obligations under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements (Note 6). Cash held by NM Capital was included in cash and cash equivalents on the balance sheets of PNMR and was less than $0.1 million at December 31, 2017. The Company adopted ASU 2016-18 as of January 1, 2018, its required effective date. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for the statement of cash flows in each period presented. Accordingly, PNM made retrospective adjustments to its Condensed Consolidated Statements of Cash Flows to increase beginning cash, restricted cash, and equivalents at January 1, 2017 by $1.0 million and to reduce operating cash in-flows – other current assets by $1.0 million during the nine months ending September 30, 2017. In addition, the beginning and ending balances of cash, restricted cash, and equivalents are presented on the Condensed Consolidated Statements of Cash Flows. No other changes were made to the Condensed Consolidated Financial Statements in connection with the adoption of ASU 2016-18. New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2016-02 – Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 will require that a liability be recorded on the balance sheet for all leases, based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. ASU 2016-02 originally required that leases be recognized and measured as of the earliest period presented using a modified retrospective approach with all periods presented being restated and presented under the new guidance. The ASU allows entities to apply certain practical expedients to arrangements that exist upon adoption or that expired during the periods presented. As further discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, and equipment. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. In addition, the Company also routinely enters into land easements and right-of-way agreements. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, is conducting outreach activities across its lines of business, and is in the process of implementing software to help administer and account for its leasing activities. The Company has made significant progress in identifying arrangements that may be classified as leases under ASU 2016-02 in addition to those currently classified as operating leases. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company anticipates its leases of vehicles and certain office equipment commencing after January 1, 2019 will be classified as financing leases. The Company is in the process of analyzing each of the identified contractual arrangements to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company anticipates this process will continue throughout 2018. The Company will adopt this standard effective as of January 1, 2019, its required effective date. The Company anticipates it will elect the “package” of practical expedients provided by ASU 2016-02 upon adoption. As a result, the Company will not reassess, as of the date of adoption, whether contracts should be accounted for as leases under ASU 2016-02, the classification of contracts accounted for as leases (as operating or financing), or whether any initial direct costs associated with contracts accounted for as leases should be recognized as a component of right-of-use assets. In January 2018, the FASB issued ASU 2018-01, which clarifies that land easements are to be evaluated under ASU 2016-02, but provides an additional optional practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under the current guidance. The Company has numerous land easements and right-of-way agreements that would fall under this clarification. The only such agreement that has been accounted for as a lease under current guidance is the right-of-way agreement with the Navajo Nation, which is discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. The Company anticipates it will elect to use the practical expedient for its existing and expired land easements upon adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which provides entities an optional transitional relief method to apply ASU 2016-02 as of the date of initial application of the standard rather than as of the earliest period presented. The Company anticipates it will elect to use this optional transitional relief method. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date, although early adoption is permitted beginning on January 1, 2019. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019, although early adoption is permitted. At adoption, ASU 2017-12 is to be applied prospectively and allows entities to record a cumulative-effect adjustment at the transition date as well as allowing entities to elect certain practical expedients upon adoption. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 9, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 7, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not currently designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements. Accounting Standards Update 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 8 of the Notes to the Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on January 1, 2021, although early adoption is permitted, and requires retrospective application. As discussed in Note 12 of the Notes to the Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14, but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. PNM PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates. TNMP TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities. Corporate and Other The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development, NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. Eliminations of intercompany income and expense transactions are reflected in the Corporate and Other segment. The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended September 30, 2018 Electric operating revenues $ 331,374 $ 91,292 $ — $ 422,666 Cost of energy 92,384 21,152 — 113,536 Utility margin 238,990 70,140 — 309,130 Other operating expenses 98,000 25,140 (3,580 ) 119,560 Depreciation and amortization 38,474 17,176 5,930 61,580 Operating income (loss) 102,516 27,824 (2,350 ) 127,990 Interest income 3,472 — (72 ) 3,400 Other income (deductions) 2,515 1,151 (92 ) 3,574 Interest charges (18,063 ) (8,241 ) (4,188 ) (30,492 ) Segment earnings (loss) before income taxes 90,440 20,734 (6,702 ) 104,472 Income taxes (benefit) 9,012 4,634 (747 ) 12,899 Segment earnings (loss) 81,428 16,100 (5,955 ) 91,573 Valencia non-controlling interest (3,920 ) — — (3,920 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 77,376 $ 16,100 $ (5,955 ) $ 87,521 Nine Months Ended September 30, 2018 Electric operating revenues $ 832,116 $ 260,741 $ — $ 1,092,857 Cost of energy 229,547 64,256 — 293,803 Utility margin 602,569 196,485 — 799,054 Other operating expenses 305,569 73,624 (13,955 ) 365,238 Depreciation and amortization 113,314 49,676 17,375 180,365 Operating income (loss) 183,686 73,185 (3,420 ) 253,451 Interest income 9,340 — 2,522 11,862 Other income (deductions) 588 3,067 (441 ) 3,214 Interest charges (58,881 ) (23,771 ) (14,216 ) (96,868 ) Segment earnings (loss) before income taxes 134,733 52,481 (15,555 ) 171,659 Income taxes (benefit) 11,009 11,602 (3,773 ) 18,838 Segment earnings (loss) 123,724 40,879 (11,782 ) 152,821 Valencia non-controlling interest (11,706 ) — — (11,706 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 111,622 $ 40,879 $ (11,782 ) $ 140,719 At September 30, 2018: Total Assets $ 5,042,761 $ 1,628,842 $ 177,392 $ 6,848,995 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended September 30, 2017 Electric operating revenues $ 327,254 $ 92,646 $ — $ 419,900 Cost of energy 82,367 21,381 — 103,748 Utility margin 244,887 71,265 — 316,152 Other operating expenses 92,733 25,367 (5,391 ) 112,709 Depreciation and amortization 36,764 16,424 5,633 58,821 Operating income (loss) 115,390 29,474 (242 ) 144,622 Interest income 1,782 — 1,800 3,582 Other income (deductions) 4,204 1,228 (460 ) 4,972 Interest charges (20,451 ) (7,704 ) (3,951 ) (32,106 ) Segment earnings (loss) before income taxes 100,925 22,998 (2,853 ) 121,070 Income taxes (benefit) 35,642 8,271 (1,170 ) 42,743 Segment earnings (loss) 65,283 14,727 (1,683 ) 78,327 Valencia non-controlling interest (4,456 ) — — (4,456 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 60,695 $ 14,727 $ (1,683 ) $ 73,739 Nine Months Ended September 30, 2017 Electric operating revenues $ 854,909 $ 257,489 $ — $ 1,112,398 Cost of energy 246,635 64,183 — 310,818 Utility margin 608,274 193,306 — 801,580 Other operating expenses 281,886 72,188 (15,286 ) 338,788 Depreciation and amortization 109,228 47,392 16,209 172,829 Operating income (loss) 217,160 73,726 (923 ) 289,963 Interest income 6,457 — 5,891 12,348 Other income (deductions) 13,510 2,392 (918 ) 14,984 Interest charges (62,393 ) (22,619 ) (11,125 ) (96,137 ) Segment earnings (loss) before income taxes 174,734 53,499 (7,075 ) 221,158 Income taxes (benefit) 58,865 18,964 (2,675 ) 75,154 Segment earnings (loss) 115,869 34,535 (4,400 ) 146,004 Valencia non-controlling interest (11,452 ) — — (11,452 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 104,021 $ 34,535 $ (4,400 ) $ 134,156 At September 30, 2017: Total Assets $ 5,023,816 $ 1,465,219 $ 208,219 $ 6,697,254 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to customers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2018 and 2017 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2017, as originally reported $ 13,169 $ (110,262 ) $ (97,093 ) $ 1,153 $ (95,940 ) Cumulative effect adjustment (Note 7) (11,208 ) — (11,208 ) — (11,208 ) Balance at January 1, 2018, as adjusted 1,961 (110,262 ) (108,301 ) 1,153 (107,148 ) Amounts reclassified from AOCI (pre-tax) (3,483 ) 5,678 2,195 102 2,297 Income tax impact of amounts reclassified 885 (1,442 ) (557 ) (27 ) (584 ) Other OCI changes (pre-tax) 2,872 — 2,872 2,431 5,303 Income tax impact of other OCI changes (730 ) — (730 ) (618 ) (1,348 ) Net after-tax change (456 ) 4,236 3,780 1,888 5,668 Balance at September 30, 2018 $ 1,505 $ (106,026 ) $ (104,521 ) $ 3,041 $ (101,480 ) Balance at December 31, 2016 $ 4,320 $ (96,748 ) $ (92,428 ) $ (23 ) $ (92,451 ) Amounts reclassified from AOCI (pre-tax) (11,088 ) 4,839 (6,249 ) 484 (5,765 ) Income tax impact of amounts reclassified 4,302 (1,878 ) 2,424 (187 ) 2,237 Other OCI changes (pre-tax) 22,302 — 22,302 (278 ) 22,024 Income tax impact of other OCI changes (8,654 ) — (8,654 ) 108 (8,546 ) Net after-tax change 6,862 2,961 9,823 127 9,950 Balance at September 30, 2017 $ 11,182 $ (93,787 ) $ (82,605 ) $ 104 $ (82,501 ) The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities in gains (losses) on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 87,521 $ 73,739 $ 140,719 $ 134,156 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 215 284 210 215 Average Shares – Basic 79,869 79,938 79,864 79,869 Dilutive Effect of Common Stock Equivalents: Stock options and restricted stock 111 216 126 263 Average Shares – Diluted 79,980 80,154 79,990 80,132 Net Earnings Per Share of Common Stock: Basic $ 1.10 $ 0.92 $ 1.76 $ 1.68 Diluted $ 1.09 $ 0.92 $ 1.76 $ 1.67 |
Electric Operating Revenues
Electric Operating Revenues | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Electric Operating Revenues | Electric Operating Revenues PNMR is an investor-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP. Revenue Recognition Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales billed to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on daily generation volumes, estimated customer usage by class, line losses, historical trends and experience, and applicable customer rates. Amounts billed are generally due within the next month. The Company does not incur incremental costs to obtain contracts for its energy services. PNM’s wholesale electricity sales are recorded as electric operating revenues and wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are subject to unplanned netting are recorded net in earnings. A “book-out” is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract. Unrealized gains and losses on derivative contracts that are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold (Note 7). In May 2014, the FASB issued ASU 2014-09 – Revenue from Contracts with Customers (Topic 606) . The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also revises the disclosure requirements regarding revenue and requires that revenue from contracts with customers be reported separately from other revenues. ASU 2014-09 provides that it could be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company adopted ASU 2014-09 effective as of January 1, 2018, its required effective date, using the modified retrospective method of adoption. The adoption of ASU 2014-09 did not result in changes to the nature, amount, and timing of the Company’s existing revenue recognition processes or information technology infrastructure. Therefore, the adoption of ASU 2014-09 had no effect on the amount of revenue recorded in 2018 compared to the amount that would have been recorded under prior GAAP, no effect on total electric operating revenues or any other caption within the Company’s financial statements, and no cumulative effect adjustment was recorded. Revenues for 2018 are presented in accordance with the standard on the Condensed Consolidated Statements of Earnings and 2017 revenues are presented on a comparative basis. Additional disclosures to further disaggregate 2018 revenues are presented below. Under ASU 2014-09, PNM and TNMP recognize revenue as they satisfy performance obligations, which typically occurs as the customer or end-user consumes the electric service provided. Electric services are typically for a bundle of services that are distinct and transferred to the end-user in one performance obligation measured by KWh or KW. Electric operating revenues are recorded in the period of energy delivery, including estimated unbilled amounts. As permitted under GAAP, the Company has elected to exclude all sales and similar taxes from revenue. Revenue from contracts with customers is recorded based upon the total authorized tariff price at the time electric service is rendered, including amounts billed under arrangements qualifying as an Alternative Revenue Program (“ARP”). ARP arrangements are agreements between PNM or TNMP and its regulator that allows PNM or TNMP to adjust future rates in response to past activities or completed events, if certain criteria are met. GAAP requires that ARP revenues be reported separately from contracts with customers. ARP revenues in a given period include the recognition of “originating” ARP revenues (i.e. when the regulator-specific conditions are met) in the period, offset by the reversal of ARP revenues billed to customers in that period. Sources of Revenue Additional information about the nature of revenues is provided below. Additional information about matters affecting PNM’s and TNMP’s regulated revenues is provided in Note 12. Revenue from Contracts with Customers PNM NMPRC Regulated Retail Electric Service – PNM provides electric generation, transmission, and distribution service to its rate-regulated customers in New Mexico. PNM’s retail electric service territory covers a large area of north central New Mexico, including the cities of Albuquerque, Rio Rancho, and Santa Fe, and certain areas of southern New Mexico. Customer rates for retail electric service are set by the NMPRC and revenue is recognized as energy is delivered to the customer. PNM invoices customers on a monthly basis for electric service and generally collects billed amounts within one month. Transmission Service to Third Parties – PNM owns transmission lines that are interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. Transmission customers receive service for the transmission of energy owned by the customer utilizing PNM’s transmission facilities. Customers generally receive transmission services, which are regulated by FERC, from PNM through PNM’s Open Access Transmission Tariff (“OATT”) or a specific contract. Customers are billed based on capacity and energy components on a monthly basis. Other – On January 1, 2018, PNM acquired a 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC (Note 11). PNM sells power from 36 MW of this capacity to a third party at a fixed price that is recorded as revenue from contracts with customers. PNM is obligated to deliver power under this arrangement only when SJGS Unit 4 is operating. Other market sales from this 65 MW interest are recorded in other electric operating revenues. TNMP PUCT Regulated Retail Electric Service – TNMP provides transmission and distribution services in Texas under the provisions of TECA and the Texas Public Utility Regulatory Act. TNMP is subject to traditional cost-of-service regulation with respect to rates and service under the jurisdiction of the PUCT and certain municipalities. TNMP’s transmission and distribution activities are solely within ERCOT and not subject to traditional rate regulation by FERC. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. Revenue is recognized as energy is delivered to the consumer. TNMP invoices REPs on a monthly basis and is generally paid within a month. Transmission Cost of Service (“TCOS”) – TNMP is a transmission service provider that is allowed to recover its TCOS through a network transmission rate that is approved by the PUCT. TCOS customers are other utilities that receive service for the transmission of energy owned by the customer utilizing TNMP’s transmission facilities. Alternative Revenue Programs ARP revenues, which are discussed above, include recovery or refund provisions under PNM’s renewable energy rider and true-ups to PNM’s formula transmission rates; TNMP’s AMS surcharge, transmission cost recovery factor, and rate impacts of the 2017 change in the corporate income tax rate; and the energy efficiency incentive bonus at both PNM and TNMP. GAAP provides for the recognition of regulatory assets and liabilities for the difference between ARP revenues and amounts billed under those programs. Regulatory assets and liabilities are amortized into earnings as amounts are billed. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the NMPRC, PUCT, and FERC. Other Electric Operating Revenues Other electric operating revenues consist primarily of PNM’s sales for resale meeting the definition of a derivative under GAAP. Derivatives are not considered contracts with customers under ASU 2014-09. PNM engages in activities meeting the definition of derivatives to optimize its existing jurisdictional assets and long-term power agreements through spot market, hour-ahead, day-ahead, week-ahead, month-ahead, and other sales of excess generation not required to fulfill retail load and contractual commitments. Through December 31, 2017, PNM’s 134 MW share of Unit 3 at PVNGS was excluded from retail rates and was being sold in the wholesale market. In December 2015, the NMPRC approved PNM’s request to include PVNGS Unit 3 as a jurisdictional resource to service New Mexico retail customers beginning in 2018. Disaggregation of Revenues A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects ARP revenues and other revenues. PNM TNMP PNMR Consolidated Three Months Ended September 30, 2018 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 138,091 $ 40,227 $ 178,318 Commercial 121,755 28,850 150,605 Industrial 17,919 4,402 22,321 Public authority 6,872 1,390 8,262 Economy energy service 6,158 — 6,158 Transmission 13,538 16,743 30,281 Miscellaneous 1,686 2,392 4,078 Total revenues from contracts with customers 306,019 94,004 400,023 Alternative revenue programs (5,338 ) (2,712 ) (8,050 ) Other electric operating revenues 30,693 — 30,693 Total Electric Operating Revenues $ 331,374 $ 91,292 $ 422,666 PNM TNMP PNMR Consolidated Nine Months Ended September 30, 2018 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 334,767 $ 100,808 $ 435,575 Commercial 315,256 84,084 399,340 Industrial 45,976 12,891 58,867 Public authority 16,726 4,205 20,931 Economy energy service 19,825 — 19,825 Transmission 40,128 49,995 90,123 Miscellaneous 10,632 6,740 17,372 Total revenues from contracts with customers 783,310 258,723 1,042,033 Alternative revenue programs (3,484 ) 2,018 (1,466 ) Other electric operating revenues 52,290 — 52,290 Total Electric Operating Revenues $ 832,116 $ 260,741 $ 1,092,857 Contract balances Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed to the customer or end-user, including amounts under ARP programs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for uncollectible accounts, includes $76.9 million at September 30, 2018 and $61.8 million at December 31, 2017 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers. Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of September 30, 2018. Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Under its OATT, PNM accepts upfront consideration for capacity reservations requested by transmission customers, which requires PNM to defer the customer’s transmission capacity rights for a specific period of time. PNM recognizes the revenue of these capacity reservations over the period it defers the customer’s capacity rights. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one calendar year. Deferred revenues on these arrangements are recorded as contract liabilities. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated. Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows: PNM TNMP PNMR Consolidated (In thousands) Balance at December 31, 2017 $ 349 $ — $ 349 Consideration received in advance of service to be provided 4,174 1,512 5,686 Deferred revenue earned (3,304 ) (1,134 ) (4,438 ) Balance at September 30, 2018 $ 1,219 $ 378 $ 1,597 |
Variable Interest Entities
Variable Interest Entities | 9 Months Ended |
Sep. 30, 2018 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | Variable Interest Entities GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. Additional information concerning PNM’s VIEs is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Valencia PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2018 , PNM paid $4.9 million and $14.7 million for fixed charges and $0.5 million and $1.4 million for variable charges. For the three and nine months ended September 30, 2017 , PNM paid $4.9 million and $14.7 million for fixed charges and $0.9 million and $1.2 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of 50% of book value reduced by related indebtedness or 50% of fair market value. PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third-party entity that owns Valencia is a VIE and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates Valencia in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the Condensed Consolidated Financial Statements of PNM although PNM has no legal ownership interest or voting control of the VIE. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest. Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (In thousands) Operating revenues $ 5,368 $ 5,859 $ 16,047 $ 15,880 Operating expenses (1,448 ) (1,403 ) (4,341 ) (4,428 ) Earnings attributable to non-controlling interest $ 3,920 $ 4,456 $ 11,706 $ 11,452 Financial Position September 30, December 31, 2018 2017 (In thousands) Current assets $ 3,449 $ 2,688 Net property, plant, and equipment 62,698 64,109 Total assets 66,147 66,797 Current liabilities 923 602 Owners’ equity – non-controlling interest $ 65,224 $ 66,195 Westmoreland San Juan LLC (“WSJ”) and SJCC As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland Coal Company (“Westmoreland”), on January 31, 2016, as well as the $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to possible loss in the event of a default by WSJ under the Westmoreland Loan and/or performance was required under the letter of credit support. Principal payments under the Westmoreland Loan began on August 1, 2016 and were required quarterly thereafter. Interest was also paid quarterly beginning on May 3, 2016. The Westmoreland Loan required that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it was fully repaid. As discussed in Note 11, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid on May 22, 2018. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan Agreement. The Westmoreland Loan was secured by the assets of and the equity interests in SJCC. PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS CSA. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations. On May 21, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC indicating it had obtained a new credit agreement with certain of its existing creditors that provided Westmoreland with additional financing. In the May 21, 2018 Form 8-K, Westmoreland indicated that “A portion of the proceeds of the Financing have been used to refinance in full the Company’s and its subsidiaries’ existing asset-based revolving credit facilities and Westmoreland San Juan, LLC’s existing term loan facility.” As mentioned above, the Westmoreland Loan was repaid in full in May 2018. On October 9, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC announcing it had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. In the October 9, 2018 Form 8-K, Westmoreland indicated that is has agreed to terms with its secured creditors that will allow it to fund its normal course operations and that will allow it to continue to serve its customers during the course of the bankruptcy case (Note 11). Both WSJ and SJCC are considered to be VIEs. PNMR’s analysis of these arrangements concluded that Westmoreland, as the parent of WSJ, has the ability to direct the SJCC mining operations, which is the factor that most significantly impacts the economic performance of WSJ and SJCC. NM Capital’s rights under the Westmoreland Loan were the typical protective rights of a lender, but did not give NM Capital any oversight over mining operations. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of Westmoreland and its subsidiaries, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation. PNM’s involvement through the SJGS CSA is a protective right rather than a participating right and Westmoreland has the power to direct the activities that most significantly impact the economic performance of SJCC. The SJGS CSA requires SJCC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation. If SJCC is able to mine more efficiently than anticipated, its economic performance will be improved. Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted. Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs at September 30, 2018. |
Fair Value of Derivative and Ot
Fair Value of Derivative and Other Financial Instruments | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value of Derivative and Other Financial Instruments [Abstract] | |
Fair Value of Derivative and Other Financial Instruments | Fair Value of Derivative and Other Financial Instruments Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk, including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique. Energy Related Derivative Contracts Overview The primary objective for the use of commodity derivative instruments, including energy contracts, options, swaps, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its customers. PNM is exposed to market risk for the needs of its customers not covered under a FPPAC. PNM was exposed to market risk for its share of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 became a jurisdictional resource to serve New Mexico retail customers. Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC (Note 11). PNM entered into agreements to sell power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022, subject to certain conditions. Under these agreements, PNM is obligated to deliver 36 MW of power only when SJGS Unit 4 is operating. These agreements are not considered derivatives because there is no notional amount due to the unit-contingent nature of the transactions. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. TNMP does not enter into energy related derivative contracts. Commodity Risk Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations. PNM monitors the market risk of its commodity contracts in accordance with approved risk and credit policies. Accounting for Derivatives Under derivative accounting and related rules for energy contracts, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the nine months ended September 30, 2018 and the year ended December 31, 2017, PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The derivative contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. PNM has no trading transactions. Commodity Derivatives PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges September 30, December 31, (In thousands) Current assets $ 1,083 $ 1,088 Deferred charges 2,741 3,556 3,824 4,644 Current liabilities (1,092 ) (1,182 ) Long-term liabilities (2,741 ) (3,556 ) (3,833 ) (4,738 ) Net $ (9 ) $ (94 ) Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives. Included in the above table are equal amounts of assets and liabilities aggregating $3.8 million at September 30, 2018 and $4.6 million at December 31, 2017 , which result from PNM’s hazard sharing arrangements with Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial. At September 30, 2018 and December 31, 2017 , PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2018 and December 31, 2017 , amounts posted as cash collateral under margin arrangements were $0.5 million and $0.8 million . At September 30, 2018 and December 31, 2017 , obligations to return cash collateral were $1.0 million and $0.9 million . Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets. PNM has a NMPRC-approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. There were no amounts hedged under this plan as of September 30, 2018 or December 31, 2017. The following table presents the effect of mark-to-market commodity derivative instruments on PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Electric operating revenues $ (93 ) $ (2,237 ) $ (95 ) $ 5,697 Cost of energy 93 (14 ) 97 (5,289 ) Total gain $ — $ (2,251 ) $ 2 $ 408 Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh September 30, 2018 100,000 4,800 December 31, 2017 100,000 — PNM has contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral. At September 30, 2018 and December 31, 2017 , PNM had no such contracts in a liability position. Non-Derivative Financial Instruments The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Investment securities are carried at fair value. Investment securities consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At September 30, 2018 and December 31, 2017 , the fair value of investment securities included $298.4 million and $293.7 million for the NDT and $33.3 million and $29.8 million for the mine reclamation trusts. In January 2016, the FASB issued Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10), which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged. The accounting required by ASU 2016-01 is to be applied prospectively with a cumulative effect adjustment recorded as of the beginning of the year of adoption. ASU 2016-01 also revises certain presentation and disclosure requirements. Accordingly, the following information for 2018 is presented under ASU 2016-01 and the information for 2017 is presented under prior GAAP. Prior to 2018, PNM classified all debt and equity investments held in the NDT and coal mine reclamation trusts as available-for-sale securities. Unrealized losses on these securities were recorded immediately through earnings and unrealized gains were recorded in AOCI until the securities were sold. On January 1, 2018, PNM recorded an after-tax cumulative effect adjustment of $11.2 million to reclassify unrealized holding gains on equity securities held in the NDT and coal mine reclamation trusts from AOCI to retained earnings on the Condensed Consolidated Balance Sheets. After January 1, 2018, all gains and losses resulting from sales and changes in the fair value of equity securities are recognized in earnings. Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table. Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 (In thousands) Equity securities: Net gains from equity securities sold $ 113 $ 5,443 Net gains from equity securities still held 2,943 2,636 Total net gains on equity securities 3,056 8,079 Available-for-sale debt securities: Net (losses) on debt securities (593 ) (6,998 ) Net gains on investment securities $ 2,463 $ 1,081 The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $ (0.8) million and $ (4.6) million for the three and nine months ended September 30, 2018 and $ 0.1 million and $ 1.1 million for the three and nine months ended September 30, 2017 . Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Proceeds from sales $ 117,801 $ 98,532 $ 911,899 $ 456,577 Gross realized gains $ 3,460 $ 8,128 $ 17,030 $ 24,745 Gross realized (losses) $ (3,149 ) $ (2,829 ) $ (14,018 ) $ (8,150 ) Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At December 31, 2017, PNMR’s held-to-maturity debt securities consisted of the Westmoreland Loan. In May 2018, the full amount owed under the Westmoreland Loan was repaid (Note 11). The Company has no available-for-sale debt securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings. At September 30, 2018 , the available-for-sale debt securities held by PNM, had the following final maturities: Fair Value (In thousands) Within 1 year $ 9,986 After 1 year through 5 years 59,944 After 5 years through 10 years 67,585 After 10 years through 15 years 10,375 After 15 years through 20 years 11,151 After 20 years 46,887 $ 205,928 Fair Value Disclosures The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the nine months ended September 30, 2018 or the year ended December 31, 2017 . For investment securities, Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For Level 2 fair values, the pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. Fair values of Level 2 investments in mutual funds are equal to net asset value as of year-end. Level 3 investments are comprised of corporate term loans. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. The valuation of Level 3 investments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates, and cash flows. For the Westmoreland Loan, fair values were determined using an internal valuation model of discounted cash flows that took into consideration discount rates observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services. Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale securities. Under ASU 2016-01, PNM does not classify its investments in equity instruments as available-for-sale securities beginning January 1, 2018. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) September 30, 2018 Cash and cash equivalents $ 3,527 $ 3,527 $ — $ — Equity securities: Corporate stocks, common 40,017 40,017 — — Corporate stocks, preferred 7,239 1,587 5,652 — Mutual funds and other 75,035 75,035 — — Available-for-sale debt securities: U.S. Government 25,689 15,400 10,289 — $ 23 International Government 8,460 — 8,460 — 90 Municipals 51,280 — 51,280 — 78 Corporate and other 120,499 — 117,445 3,054 1,827 $ 331,746 $ 135,566 $ 193,126 $ 3,054 $ 2,018 Commodity derivative assets $ 3,824 $ — $ 3,824 $ — Commodity derivative liabilities (3,833 ) — (3,833 ) — Net $ (9 ) $ — $ (9 ) $ — December 31, 2017 Available-for-sale securities Cash and cash equivalents $ 52,636 $ 52,636 $ — $ — Equity securities: Domestic value 40,032 40,032 — — $ 4,011 Domestic growth 35,456 35,456 — — 3,995 International and other 45,867 42,332 3,535 — 6,810 Fixed income securities: U.S. Government 34,317 33,645 672 — 273 Municipals 48,076 — 48,076 — 1,225 Corporate and other 67,140 — 67,140 — 1,714 $ 323,524 $ 204,101 $ 119,423 $ — $ 18,028 Commodity derivative assets $ 4,644 $ — $ 4,644 $ — Commodity derivative liabilities (4,738 ) — (4,738 ) — Net $ (94 ) $ — $ (94 ) $ — A reconciliation of the changes in Level 3 fair value measurements is as follows: Corporate Debt (In thousands) Balance at December 31, 2017 $ — Actual return on assets sold during the period (6 ) Actual return on assets still held at period end 16 Purchases 5,234 Sales (2,190 ) Balance at September 30, 2018 $ 3,054 The carrying amounts and fair values of investments in the Westmoreland Loan, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 September 30, 2018 (In thousands) PNMR Long-term debt $ 2,614,511 $ 2,642,154 $ — $ 2,642,154 $ — Other investments $ 348 $ 348 $ 348 $ — $ — PNM Long-term debt $ 1,656,102 $ 1,665,064 $ — $ 1,665,064 $ — Other investments $ 142 $ 142 $ 142 $ — $ — TNMP Long-term debt $ 560,293 $ 580,017 $ — $ 580,017 $ — Other investments $ 206 $ 206 $ 206 $ — $ — December 31, 2017 PNMR Long-term debt $ 2,437,645 $ 2,554,836 $ — $ 2,554,836 $ — Westmoreland Loan $ 56,640 $ 66,588 $ — $ — $ 66,588 Other investments $ 503 $ 503 $ 503 $ — $ — PNM Long-term debt $ 1,657,910 $ 1,727,135 $ — $ 1,727,135 $ — Other investments $ 283 $ 283 $ 283 $ — $ — TNMP Long-term debt $ 480,620 $ 527,563 $ — $ 527,563 $ — Other investments $ 220 $ 220 $ 220 $ — $ — |
Stock-Based Compensation
Stock-Based Compensation | 9 Months Ended |
Sep. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. The Company has not awarded stock options since 2010. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, awards to employees vest ratably over three years from the grant date of the award. However, awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. Awards of restricted stock to non-employee members of the Board are expensed over a one year vesting period. The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized over the performance period as required service is provided and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2018 and December 31, 2017 , PNMR had unrecognized expense related to stock awards of $4.4 million and $3.8 million , which are expected to be recognized over an average of 1.64 and 1.53 years. PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and, when used to reduce income taxes payable, classified as cash flows from operating activities. The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period. The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Nine Months Ended September 30, Restricted Shares and Performance Based Shares 2018 2017 Expected quarterly dividends per share $ 0.2650 $ 0.2425 Risk-free interest rate 2.38 % 1.50 % Market-Based Shares Dividend yield 2.96 % 2.67 % Expected volatility 19.12 % 20.80 % Risk-free interest rate 2.36 % 1.54 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months ended September 30, 2018 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2017 189,045 $ 31.11 193,441 $ 9.98 Granted 221,062 $ 29.65 — $ — Exercised (235,868 ) $ 28.44 (109,441 ) $ 8.56 Forfeited (6,054 ) $ 31.37 — $ — Expired — $ — — $ — Outstanding at September 30, 2018 168,185 $ 32.93 84,000 $ 11.82 PNMR’s stock-based compensation program provides for performance and market targets through 2020. Included as granted and as exercised in the above table are 97,697 previously awarded shares that were earned for the 2015 through 2017 performance measurement period and ratified by the Board in February 2018 (based upon achieving market targets at “target” levels, weighted at 60% , and performance targets at below “target” levels, weighted at 40% ). Excluded from the above table are maximums of 132,729 , 130,302 , and 146,941 shares for the three -year performance periods ending in 2018, 2019, and 2020 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible. Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR met specific performance targets at the end of 2016 and 2017 and he remained an employee of the Company. If PNMR achieved the specified performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 based on a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares. Similarly, if PNMR achieved the specified performance target for the period from January 1, 2015 through December 31, 2017, he was to receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. The specified performance target was achieved at the end of 2017 and the Board ratified him receiving $275,000 of PNMR common stock in February 2018 based on the market value per share of $35.85 on the grant date of March 2, 2018, or 7,670 shares, which are included in the above table. The retention award was made under the PEP and was approved by the Board on December 9, 2014. In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she was to receive 17,953 of the total shares if PNMR achieved specific performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving the 17,953 shares in February 2018, which are included in the above table. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include the restricted stock shares that remain unvested under this retention award agreement. At September 30, 2018 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $2.3 million with a weighted-average remaining contract life of 1.3 years. At September 30, 2018 , no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date. The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Nine Months Ended September 30, Restricted Stock 2018 2017 Weighted-average grant date fair value $ 29.65 $ 23.06 Total fair value of restricted shares that vested (in thousands) $ 8,493 $ 5,666 Stock Options Weighted-average grant date fair value of options granted $ — $ — Total fair value of options that vested (in thousands) $ — $ — Total intrinsic value of options exercised (in thousands) $ 3,016 $ 2,234 |
Financing
Financing | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Financing | Financing The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Prior to July 2018, each of the Company’s revolving credit facilities and term loans contained a single financial covenant, which required the maintenance of a debt-to-capitalization ratio of less than or equal to 65% . In July 2018, the PNMR Revolving Credit Facility, the PNMR 2016 One -Year Term Loan (as extended), the PNMR 2016 Two -Year Term Loan, and the PNMR Development Revolving Credit Facility were each amended such that PNMR is now required to maintain a debt-to-capitalization ratio of less than or equal to 70% . The debt-to-capitalization ratio requirement remains at less than or equal to 65% for PNM and TNMP agreements. The Company’s revolving credit facilities and term loans generally also contain customary covenants, events of default, cross-default provisions, and change-of-control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Financing Activities As discussed in Note 11, NM Capital, a wholly-owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent, as of February 1, 2016. The BTMU Term Loan Agreement had a maturity date of February 1, 2021 and bore interest at a rate based on LIBOR plus a customary spread. PNMR, as parent company of NM Capital, guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity subsidiary of Westmoreland to finance Westmoreland’s purchase of SJCC. See Note 6. The BTMU Term Loan Agreement required that NM Capital utilize all amounts, less taxes and fees, it received under the Westmoreland Loan to repay the BTMU Term Loan Agreement. On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining principal of $43.0 million owed under the BTMU Term Loan Agreement. These payments effectively terminated the loan agreements. In addition, PNMR’s guarantee of NM Capital’s obligations was also effectively terminated. On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11). On July 28, 2017, PNM entered into an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principal amount of SUNs (the “PNM 2018 SUNs”) offered in private placement transactions. On May 14, 2018, PNM issued $350.0 million of the PNM 2018 SUNs under that agreement and used the proceeds to repay an equal amount of PNM’s 7.95% SUNs that matured on May 15, 2018. On July 31, 2018, PNM issued the remaining $100.0 million of the PNM 2018 SUNs and used the proceeds to repay an equal amount of PNM’s 7.50% SUNs on August 1, 2018. The PNM 2017 Senior Unsecured Note Agreement includes customary covenants, including a covenant that requires PNM to maintain a debt-to-capitalization ratio of less than or equal to 65% , customary events of default, including a cross-default provision, and covenants regarding parity of financial covenants, liens and guarantees with respect to PNM’s material credit facilities. In the event of a change of control, PNM will be required to offer to prepay the PNM 2018 SUNs at par. PNM will have the right to redeem any or all of the PNM 2018 SUNs prior to their respective maturities, subject to payment of a customary make-whole premium. Information concerning the maturities and interest rates on the PNM 2018 SUNs is as follows: Funding Maturity Principal Interest Date Date Amount Rate (In millions) May 14, 2018 May 15, 2023 $ 55.0 3.15 % May 14, 2018 May 15, 2025 104.0 3.45 % May 14, 2018 May 15, 2028 88.0 3.68 % May 14, 2018 May 15, 2033 38.0 3.93 % May 14, 2018 May 15, 2038 45.0 4.22 % May 14, 2018 May 15, 2048 20.0 4.50 % 350.0 July 31, 2018 August 1, 2028 15.0 3.78 % July 31, 2018 August 1, 2048 85.0 4.60 % 100.0 $ 450.0 On March 9, 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% SUNs (the “PNMR 2018 SUNs”), which mature on March 9, 2021. The proceeds from the offering were used to repay the $150.0 million PNMR 2015 Term Loan Agreement and to reduce borrowings under the PNMR Revolving Credit Facility. On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which is shown as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three and nine months ended September 30, 2018, PNM recognized $0.8 million and $1.5 million of interest expense under the agreement. At September 30, 2018, PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million , excluding unpaid interest, is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements. On June 28, 2018, TNMP entered into an agreement, under which TNMP issued $60.0 million aggregate principal amount of 3.85% first mortgage bonds, due 2028. On July 25, 2018, TNMP entered into a $20.0 million term loan agreement (the “TNMP 2018 Term Loan Agreement”) that bears interest at a variable rate and has a maturity of July 25, 2020. TNMP used the proceeds from these issuances to repay short-term borrowings and for TNMP’s general corporate purposes. At September 30, 2018 , variable interest rates were 3.03% on the $100.0 million PNMR 2016 Two -Year Term Loan, which matures in December 2018, 2.98% on the $200.0 million PNM 2017 Term Loan Agreement, which matures in January 2019, and 2.94% on the $20.0 million TNMP 2018 Term Loan Agreement, which matures in July 2020. Short-term Debt and Liquidity Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million . Both facilities currently expire on October 22, 2022, but contain options to be extended through October 2024. However, one lender whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitments beyond October 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility beginning on November 1, 2020. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that expires on December 12, 2022. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds and matures on September 23, 2022. In July 2018, the PNMR Revolving Credit Facility was amended to provide for two one -year extension options, subject to approval by a majority of the lenders. In October 2018, and after receiving NMPRC approval, the PNM Revolving Credit Facility was amended to add two one -year extension options, subject to approval by a majority of the lenders. On February 26, 2018, PNMR Development entered into a revolving credit facility with Wells Fargo Bank, National Association, as lender, which allows PNMR Development to borrow up to $24.5 million on a revolving credit basis and also provides for the issuance of letters of credit. The facility expires on February 25, 2019, bears interest at a variable rate, and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development uses the facility to finance its participation in NMRD and other activities. Short-term debt outstanding consisted of: September 30, December 31, Short-term Debt 2018 2017 (In thousands) PNM: PNM Revolving Credit Facility $ — $ 39,800 PNM 2017 New Mexico Credit Facility — — — 39,800 TNMP Revolving Credit Facility 17,500 — PNMR: PNMR Revolving Credit Facility 120,600 165,600 PNMR 2016 One-Year Term Loan (as extended) 100,000 100,000 PNMR Development Revolving Credit Facility 24,500 — $ 262,600 $ 305,400 At September 30, 2018 , the weighted average interest rate was 3.34% for the PNMR Revolving Credit Facility, 2.99% for the TNMP Revolving Credit Facility, 3.07% for the PNMR Development Revolving Credit Facility, and 3.02% for the PNMR 2016 One -Year Term Loan (as extended). In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $4.7 million , $2.5 million , and $0.1 million at September 30, 2018 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of September 30, 2018 and December 31, 2017, TNMP had $4.1 million and zero of intercompany borrowings from PNMR. In 2017, PNMR entered into three separate four -year hedging agreements whereby it effectively established fixed interest rates of 1.926% , 1.823% , and 1.629% , plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million , of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. These hedge agreements had fair value gains totaling $4.0 million at September 30, 2018 that is included in other deferred charges and $1.4 million at December 31, 2017 that is included in other current assets on the Condensed Consolidated Balance Sheets. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement. At October 30, 2018 , PNMR, PNM, TNMP, and PNMR Development had availability of $168.8 million , $397.5 million , $47.4 million , and none under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $40.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 30, 2018 , on a consolidated basis, was $653.7 million for PNMR. As of October 30, 2018 , PNM and TNMP had borrowings from PNMR under their intercompany loan agreements of zero and $5.4 million . At October 30, 2018 , PNMR, PNM, and TNMP had invested cash of $0.9 million , $55.3 million , and none . The Company’s debt arrangements have various maturities and expiration dates. These maturities include the $200.0 million PNM 2017 Term Loan Agreement, which matures on January 18, 2019. TNMP has $172.3 million of first mortgage bonds that are due in April 2019. The $100.0 million PNMR 2016 One-Year Term Loan (as extended) matures on December 14, 2018 and the $100.0 million PNMR 2016 Two -Year Term Loan matures on December 21, 2018. The Company has no other long-term debt due through September 30, 2019. The $24.5 million PNMR Development Revolving Credit Facility expires on February 25, 2019. Additional information on debt maturities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. |
Pension and Other Postretiremen
Pension and Other Postretirement Benefit Plans | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Pension and Other Postretirement Benefit Plans | Pension and Other Postretirement Benefit Plans PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of the periodic cost or income to the extent included in retail rates (a “prepaid pension asset”). Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. In March 2017, the FASB issued Accounting Standards Update 2017-07 – Compensation - Retirement Benefits (Topic 715) to improve the presentation of net periodic pension and other postretirement benefit costs. Prior to ASU 2017-07, the Company presented all of its net periodic benefit costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. ASU 2017-07 requires the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net periodic benefit cost (the “non-service cost components”) are required to be presented separately from the service cost component and outside of operating income. ASU 2017-07 also limits capitalization of net periodic benefit costs to only the service cost component. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net periodic benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net periodic benefit costs. The Company adopted ASU 2017-07 as of January 1, 2018, its required effective date. In accordance with the standard, the PNM and PNMR Condensed Consolidated Statements of Earnings reflect a reclassification from administrative and general expenses to other (deductions) for the non-service cost components of net periodic benefit costs in the amount of $2.1 million and $6.4 million , net of amounts capitalized prior to the adoption of the standard, in the three and nine months ended September 30, 2017. The non-service components of TNMP’s net periodic benefit costs in 2017 were insignificant. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net periodic benefit costs as regulatory assets and liabilities to the extent attributable to regulated operations. During the three and nine months ended September 30, 2018 , PNM recorded $1.1 million and $3.2 million of non-service cost as other (deductions), which is net of $0.1 million and $0.3 million deferred as regulatory assets, and TNMP recorded $0.1 million and $0.3 million of non-service cost to other income, which is net of less than $0.1 million and $0.1 million deferred as regulatory liabilities. PNM Plans The following table presents the components of the PNM Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 21 $ 24 $ — $ — Interest cost 6,068 6,727 860 1,006 155 174 Expected return on plan assets (8,672 ) (8,451 ) (1,353 ) (1,308 ) — — Amortization of net (gain) loss 4,087 4,001 588 921 90 78 Amortization of prior service cost (241 ) (241 ) (416 ) (416 ) — — Net periodic benefit cost $ 1,242 $ 2,036 $ (300 ) $ 227 $ 245 $ 252 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 62 $ 72 $ — $ — Interest cost 18,203 20,181 2,579 3,019 467 523 Expected return on plan assets (26,014 ) (25,352 ) (4,061 ) (3,923 ) — — Amortization of net (gain) loss 12,261 12,004 1,765 2,762 269 235 Amortization of prior service cost (724 ) (724 ) (1,248 ) (1,248 ) — — Net periodic benefit cost $ 3,726 $ 6,109 $ (903 ) $ 682 $ 736 $ 758 PNM did not make any contributions to its pension plan trust in the nine months ended September 30, 2018 and 2017 and does not anticipate making any contributions to the pension plan in 2018 -2021, but expects to contribute $5.5 million in 2022, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.0% to 5.1% . Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the nine months ended September 30, 2018 and 2017. PNM does not expect to make any contributions to the OPEB trust in 2018-2022. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.3 million in the three and nine months ended September 30, 2018 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2017 and are expected to total $1.6 million during 2018 and $5.7 million for 2019-2022. TNMP Plans The following table presents the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 33 $ 36 $ — $ — Interest cost 656 722 119 139 7 8 Expected return on plan assets (991 ) (945 ) (135 ) (114 ) — — Amortization of net (gain) loss 272 231 (56 ) (20 ) 4 2 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ (63 ) $ 8 $ (39 ) $ 41 $ 11 $ 10 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 100 $ 107 $ — $ — Interest cost 1,969 2,165 358 417 22 25 Expected return on plan assets (2,972 ) (2,834 ) (406 ) (342 ) — — Amortization of net (gain) loss 816 692 (170 ) (60 ) 11 7 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ (187 ) $ 23 $ (118 ) $ 122 $ 33 $ 32 TNMP did not make any contributions to its pension plan trust in the nine months ended September 30, 2018 and 2017 and does not anticipate making any contributions in 2018 -2022, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.0% to 5.1% . Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions of zero and $0.3 million to the OPEB trust in the three and nine months ended September 30, 2018 and zero and $0.7 million in the three and nine months ended September 30, 2017. TNMP expects to make no additional contributions to the OPEB trust in 2018 and $1.4 million for 2019-2022. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and nine months ended September 30, 2018 and 2017 and are expected to total $0.1 million during 2018 and $0.4 million in 2019-2022. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Overview There are various claims and lawsuits pending against the Company. In addition, the Company is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows. With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. The Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows. Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. Commitments and Contingencies Related to the Environment Nuclear Spent Fuel and Waste Disposal Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the DC Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high-level waste from PVNGS. In August 2014, APS and the DOE entered into a settlement agreement, which established a process for the payment of claims for costs incurred through December 31, 2016. The settlement agreement has been extended to December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations. PNM estimates that it will incur approximately $57.7 million (in 2016 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the nuclear fuel is consumed. At September 30, 2018 and December 31, 2017 , PNM had a liability for interim storage costs of $12.5 million and $12.3 million included in other deferred credits. PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation. The Clean Air Act Regional Haze In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress by adopting a new SIP every ten years. In the first SIP planning period, states were required to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have been installed by the beginning of 2018. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule. EPA also provided a companion draft guidance document for public comment. The new rule delayed the due date for the next cycle of SIPs from 2019 to 2021, altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures, and gave new authority to federal land managers to seek additional emission reduction measures outside of the states’ planning process. Finally, the rule made several procedural changes to the regional haze program, including changes to the schedule and process for states to file 5 -year progress reports. EPA’s new rule was challenged by numerous parties. On January 19, 2018, EPA filed a motion to hold the case in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for reconsideration of the 2017 rule revisions. On January 30, 2018, the court placed the case in abeyance and directed EPA to file status reports on 90 -day intervals beginning April 30, 2018. On September 11, 2018, EPA released a memo titled “Regional Haze Reform Roadmap.” The memo covers forthcoming tools and guidance to support states in their SIP development processes for the second planning period, including updated 2028 visibility modeling. SIPs for the second compliance period are due in July 2021. EPA plans to initiate a notice-and-comment rulemaking to address certain aspects of its Regional Haze Rule. EPA’s decision to revisit the rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters. SJGS BART Compliance – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. Note 16 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K contains detailed information concerning the BART compliance process, including interactions with governmental agencies responsible for environmental oversight and the NMPRC approval process. In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS. Under the approved plan, the installation of selective non-catalytic reduction technology (“SNCR”) on SJGS Units 1 and 4 was completed in early 2016 and Units 2 and 3 were retired in December 2017. In addition to the required SNCR equipment, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. The December 2015 NMPRC order also provided, among other things, that: • PNM was granted a CCN to acquire an additional 132 MW in SJGS Unit 4 effective January 1, 2018 • PNM was granted a CCN for 134 MW of PVNGS Unit 3 as a jurisdictional resource to serve New Mexico customers beginning January 1, 2018 • PNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant plant • No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022 (see Other SJGS Matters below and Note 12) NEE filed a notice of appeal with the NM Supreme Court of the NMPRC’s December 2015 order alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious. The parties presented oral argument to the court on January 25, 2017. On March 5, 2018, the NM Supreme Court issued its opinion affirming the NMPRC’s December 2015 order, thereby denying NEE’s appeal. A request for rehearing of the NM Supreme Court’s decision was not filed by the statutory deadline. This matter is now concluded. NEE Complaint – On March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC. See Coal Supply below. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with WSJ, in light of Westmoreland’s financial condition, could be harmful to PNM’s customers. PNM responded requesting the NMPRC deny the motion and that NEE’s prior complaint be dismissed. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments requesting additional information about the financing and noting that the Westmoreland Loan was paid in full on May 22, 2018. NEE and NMPRC staff responded on July 16, 2018. NEE continues its request that the NMPRC investigate whether Westmoreland’s financial condition could adversely affect PNM’s customers. The NMPRC staff response requested that PNM provide certain additional information about the financing transactions and stated an order to show cause requested by NEE is not warranted. On October 11, 2018, PNM filed a supplemental response notifying the NMPRC that Westmoreland had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code on October 9, 2018. PNM’s supplemental response indicated Westmoreland had agreed to terms with its secured creditors that will allow it to continue to fund normal-course operations and to continue to serve its customers during the course of the bankruptcy case. See Note 6. PNM’s supplemental response also included a letter from the United States Southern District of Texas Bankruptcy Court indicating that, subject to specified conditions, Westmoreland is authorized to “perform under its coal contracts and to conduct its business under the ordinary course of business” without seeking Court approval. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict the outcome of these matters. SJGS Ownership Restructuring Matters – As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, SJGS was jointly owned by PNM and eight other entities. The SJPPA that governs the operation of SJGS expires on July 1, 2022. In connection with the plan to comply with EPA regional haze rules at SJGS, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. On July 31, 2015, the SJGS participants executed the San Juan Project Restructuring Agreement (“SJGS RA”). The SJGS RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit. The SJGS RA became effective contemporaneously with the effectiveness of the new SJGS CSA. The effectiveness of the new SJGS CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which occurred on January 31, 2016 as discussed in Coal Supply below. Other SJGS Matters – Although the SJGS RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant. PNM’s 2017 IRP (Note 12) filed with the NMPRC on July 3, 2017 presented resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 (see Coal Supply below) and for scenarios that assumed SJGS will cease operations after mid-2022. The 2017 IRP data shows that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers. The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS would require PNM to make a formal abandonment filing with the NMPRC. The final determination of PNM’s exit from SJGS would be subject to NMPRC review and approval. PNM would also be required to obtain NMPRC approval of replacement power resources through formal CCN filings. The December 2015 NMPRC order discussed above authorized PNM to acquire 132 MW of SJGS Unit 4 as a New Mexico jurisdictional resource and 65 MW of SJGS Unit 4 as merchant plant. That order also provides that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM would not be allowed to recover the undepreciated investment of its 132 MW interest. PNM is currently depreciating all its investments in SJGS through 2053, the expected life approved by the NMPRC. PNM’s undepreciated investment in SJGS at September 30, 2018 was $405.5 million , which includes interests in the 132 MW and the 65 MW of $20.3 million and $10.1 million . In the event of an early retirement of SJGS, PNM would be exposed to loss of its undepreciated investments in the facility and other costs, including costs associated with coal mine reclamation discussed below, if recovery of these items is not approved by the NMPRC. The financial impact of early retirement and the NMPRC approval process are influenced by factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and related mine, as well as overall political and economic conditions in New Mexico. Because of the uncertainty in obtaining the required approvals, PNM is unable to predict the outcome of this matter. Four Corners On August 6, 2012, EPA issued its Four Corners FIP with a final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close Units 1, 2, and 3 by January 1, 2014 and install selective catalytic reduction technology (“SCR”) post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. Installation of SCRs on Four Corners Unit 5 was completed in March 2018 and the installation on Unit 4 was completed in June 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lbs./MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations. PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $88.6 million , including amounts incurred through September 30, 2018 and PNM’s AFUDC. See Note 17 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and Note 12 for a discussion of the treatment of these costs in PNM’s NM 2016 Rate Case. The agreements governing the operation of Four Corners and its coal supply expire in 2031. The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business or regulatory considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners. Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for 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 ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016. The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. The parties anticipate oral arguments will be heard in early 2019. PNM cannot predict if such appeal will be successful and, if it is successful, the outcome of further district court proceedings. Carbon Dioxide Emissions On August 3, 2015, EPA established final standards to limit CO 2 emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified, and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule is re-evaluated, which was granted. On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the NSPS for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance. On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the Federal Register on October 16, 2017 and comments were due by April 26, 2018. Any final rule will be subject to judicial review. In a separate but related action, on December 28, 2017, EPA published the Advance Notice of Proposed Rulemaking for replacement of the Clean Power Plan. On December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. Comments to EPA’s new rule were due by February 26, 2018. On August 31, 2018, EPA published a proposed rule, which is informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The proposed Affordable Clean Energy rule, among other things, would establish guidelines that replace the “outside-the-fenceline” control measures and specific numerical emission rates for existing EGUs. These measures are replaced with a list of “candidate technologies” for heat rate improvement measures, which include both technologies and operational changes, that EPA has identified as Best System of Emission Reduction (“BSER”). States would determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable through application of the selected BSER. States will have three years from when the rule is finalized to submit a plan to EPA. EPA will then have one year to determine if each proposed plan is acceptable. If states do not submit a plan, or if a state’s plan is not acceptable, EPA will develop a federal plan for the state to implement. EPA is also proposing revisions to the NSR program that would provide coal-fired power plants more latitude to make efficiency improvements consistent with BSER without triggering NSR permit requirements. Comments on the proposed Affordable Clean Energy rule were due to EPA by October 31, 2018. The proposed Affordable Clean Energy rule and the 2015 federal plan released concurrently with the Clean Power Plan are important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the proposed Affordable Clean Energy rule or the Clean Power Plan on the Navajo Nation. PNM is unable to predict the financial or operational impacts on Four Corners if the Affordable Clean Energy rule, the Clean Power Plan, or other future GHG reduction rulemaking are ultimately implemented and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation. PNM’s review of the CO 2 emission reductions standards under the proposed Affordable Clean Energy rule and the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, promulgation of the Affordable Clean Energy rule, other future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any. National Ambient Air Quality Standards (“NAAQS”) The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO 2 , ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO 2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO 2 and the 24-hour SO 2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO 2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO 2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO 2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO 2 sources to identify maximum 1-hour SO 2 concentrations. This characterization would result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO 2 NAAQS. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO 2 emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required that: (1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO 2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs./MMBTU or higher in 2012; (2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule. SJGS and Four Corners SO 2 emissions are below the thresholds set forth in (1) above. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree. The letters outline the schedule that EPA expects states to follow in moving forward with new SO 2 non-attainment designations. NMED did not receive a letter. On August 11, 2015, EPA released the Data Requirements Rule for SO 2 , telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO 2 NAAQS. On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO 2 standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO 2 emissions. On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO 2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO 2, and particulate matter. These reductions help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above. On May 29, 2018, EPA released a proposed rule that would retain the primary health-based NAAQS for SOx. EPA is proposing to retain the current 1-hour standard for SO 2 , which is 75 parts per billion (“ppb”), based on the 3 -year average of the 99th percentile of daily maximum 1-hour SO 2 concentrations. SO 2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS. On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data is affected by events outside an area’s control. The proposed rule is important in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are particularly subject to elevated background ozone transport from natural local sources, such as wildfires, and transported via winds from |
Regulatory and Rate Matters
Regulatory and Rate Matters | 9 Months Ended |
Sep. 30, 2018 | |
Regulated Operations [Abstract] | |
Regulatory and Rate Matters | Regulatory and Rate Matters The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. PNM New Mexico General Rate Cases New Mexico 2015 General Rate Case (“NM 2015 Rate Case”) On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates. The application proposed a revenue increase of $123.5 million , including base non-fuel revenues of $121.7 million . PNM’s application was based on a future test year (“FTY”) period beginning October 1, 2015 and proposed a ROE of 10.5% . The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and economic factors. The application included several proposed changes in rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included higher customer and demand charges, a revenue decoupling pilot program applicable to residential and small commercial customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 13). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from the SJGS CSA (Note 11). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA, which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million . On August 4, 2016, the Hearing Examiner in the case issued a recommended decision (the “August 2016 RD”). The August 2016 RD proposed an increase in non-fuel revenues of $41.3 million compared to the $121.5 million increase requested by PNM. Major components of the difference in the increase in non-fuel revenues proposed in the August 2016 RD, included: • A ROE of 9.575% compared to the 10.5% requested by PNM • Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 13); the August 2016 RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year when the August 2016 RD was issued), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases • Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 13) and related property taxes, which were $1.5 million per year when the August 2016 RD was issued; the August 2016 RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes • Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 11); PNM’s share of the costs of installing the BDT equipment was $52.3 million of which $40.0 million was included in rate base in PNM’s rate request • Disallowing recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges The August 2016 RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The August 2016 RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. In addition, the August 2016 RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The August 2016 RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The August 2016 RD proposed approving PNM’s proposals for revised depreciation rates (except the August 2016 RD would require depreciation on Four Corners be calculated based on a 2041 life rather than the 2031 life proposed by PNM), the inclusion of construction work in progress in rate base, and ratemaking treatment of the “prepaid pension asset.” The August 2016 RD proposed retail customers receive 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. The August 2016 RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the August 2016 RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the August 2016 RD. On September 28, 2016, the NMPRC issued an order that authorized PNM to implement an increase in non-fuel rates of $61.2 million , effective for bills sent to customers after September 30, 2016. The order generally approved the August 2016 RD, but with certain significant modifications. The modifications to the August 2016 RD included: • Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million ; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued • Allowing full recovery of the rent expense and property taxes associated with the extended leases for capacity, aggregating 114.6 MW, in Palo Verde Units 1 and 2 • Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases • Recovery of assumed operating and maintenance expense savings of $0.3 million annually related to BDT On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. In addition, PNM’s statement indicated it is appealing the following specific elements of the NMPRC’s order: • Disallowance of recovery of the full purchase price, representing fair market value, of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016 • Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM • Disallowance of recovery of future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases • Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT The issues that are being appealed by the various cross-appellants include: • The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2 • The NMPRC allowing PNM to recover the costs incurred under the new Four Corners CSA • The revised method to collect PNM’s fuel and purchased power costs under the FPPAC • The final rate design • The NMPRC allowing PNM to include the “prepaid pension asset” in rate base NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court orally stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court was held on October 30, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals. GAAP requires a loss to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. As of September 30, 2016, PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicated it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. As of September 30, 2016, PNM estimated it would take a minimum of 15 months from the date PNM filed its appeal for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order would remain in effect. PNM concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss was 15 months of capital cost recovery that the order disallowed for PNM’s investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss was a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million at September 30, 2016 for the capital costs that would not be recovered during that 15 -month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM could no longer assert that those assets were probable of being recovered through the ratemaking process. PNM also evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. PNM does not believe the issues raised in the cross-appeals have substantial merit. Accordingly, PNM does not believe that the likelihood of the cross-appeals being successful is probable and, therefore, no loss has been recorded related to the issues subject to the cross-appeals. Since the NM Supreme Court did not issue a decision on the appeals related to the NM 2015 Rate Case by December 31, 2017, which was 15 months from the date of the NMPRC’s order in that case, PNM reevaluated the accounting consequences of the order in the NM 2015 Rate Case. At December 31, 2017, PNM estimated the most likely period for the NM Supreme Court to issue a decision in the case and for the NMPRC to take action on any remanded issues was seven months. As a result, PNM recorded an additional pre-tax loss of $3.1 million at December 31, 2017, representing seven months of capital cost recovery that the order disallowed and would not be recovered through July 31, 2018. In June 2018, PNM again reevaluated the estimated time frame it would take for the resolution of this matter. As of June 30, 2018, PNM estimated it would take an additional five months for the NM Supreme Court to issue a decision and for any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional pre-tax loss of $1.8 million at June 30, 2018, representing additional capital cost recovery that the order disallowed and would not be recovered through October 31, 2018. In September 2018, PNM again reevaluated the estimated time frame it would take for resolution of the matter. PNM continues to believe it is reasonably possible that PNM will be successful on the issues it is appealing and that it is not probable the cross appeals will be successful. Based on the proceedings to date in the appeal process and other actions by the NM Supreme Court, PNM estimates it will take an additional four months from September 30, 2018 for the NM Supreme Court to issue a decision and for any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional pre-tax loss of $0.9 million at September 30, 2018, representing capital costs that the order disallowed and will not be recovered through January 31, 2019. Further losses will be recorded if the currently estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended. PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudent and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of September 30, 2018 , such losses could include: • The remaining costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity in excess of the recovery permitted under the NMPRC’s order; the net book value of such excess amount was $73.9 million , after considering the losses recorded to date • The undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity in PVNGS Unit 2 purchased by PNM in January 2016 was being leased by PNM; the net book value of these improvements was $ 38.3 million , after considering the losses recorded to date • The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $50.3 million , after considering the losses recorded to date Although PNM does not believe that the likelihood of the cross-appeals being successful is probable, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases, aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $147.5 million (which amount includes $73.9 million that is the subject of PNM’s appeal discussed above) at September 30, 2018 , after considering the losses recorded to date. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and “prepaid pension asset” in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have a financial impact to PNM. PNM is unable to predict the outcome of this matter. New Mexico 2016 General Rate Case (“NM 2016 Rate Case”) On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request were: • An increase in base non-fuel revenues of $99.2 million • Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application) • ROE of 10.125% • Drivers of revenue deficiency ◦ Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 11) ◦ Infrastructure investments, including environmental upgrades at Four Corners ◦ Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors ◦ Updates in the FERC/retail jurisdictional allocations • Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation ◦ Increased customer and demand charges ◦ A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions were held, but no agreements were reached by March 27, 2017, after which the date for filing a stipulation was extended. In early May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form, but allowed the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed the issues raised by the Hearing Examiners. NEE was the sole party opposing the revised stipulation. The terms of the revised stipulation, which required NMPRC approval in order to take effect, included: • A revenue increase totaling $62.3 million , with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019 • A ROE of 9.575% • Full recovery of PNM’s investment in SCRs at Four Corners with a debt-only return • An agreement to not implement non-fuel base rate changes, other than changes related to PNM’s rate riders, with an effective date prior to January 1, 2020 • An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws enacted prior to November 1, 2018 and effective and applicable to PNM by January 1, 2019 and to true-up PNM’s cost of debt for refinancing transactions through 2018 • Returning to customers over a three -year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 14) to the extent attributable to PNM’s retail operations • PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket • PNM would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028 A hearing on the revised stipulation was held in August 2017. On October 31, 2017, the Hearing Examiners issued a Certification of Stipulation recommending a Modified Revised Stipulation. The significant changes to the revised stipulation in the Hearing Examiners’ Modified Revised Stipulation included: • Identifying PNM’s decision to continue its participation in Four Corners as imprudent • Disallowing PNM’s ability to collect a debt or equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018 • Recommending a temporary disallowance of $36.8 million of PNM’s projected capital improvements at SJGS through December 31, 2018 On December 20, 2017, the NMPRC issued an Order Partially Adopting Certification of Stipulation, which approved the Hearing Examiners’ Certification of Stipulation with certain changes. Substantive changes from the Certification of Stipulation included requiring the impacts of changes related to the reduction in the federal corporate income tax rate be implemented effective January 1, 2018 rather than January 1, 2019 and deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding. On December 28, 2017, PNM filed a Motion for Rehearing and Request for Oral Argument asking the NMPRC to vacate their December 20, 2017 order and allow the parties to present oral argument. Additionally, several Signatories to the revised stipulation filed a Joint Motion for Partial Rehearing asking that the NMPRC approve the revised stipulation without modification. On January 2, 2018, NEE filed a response urging the NMPRC to reject PNM’s Motion. On January 3, 2018, the NMPRC vacated its December 20, 2017 order and granted the motions for rehearing. The rehearing was held on January 10, 2018. The NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The Revised Order approved the Hearing Examiners’ Certification of Stipulation with certain changes including: • Requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt (aggregating an estimated $47.6 million ) be implemented in 2018 rather than January 1, 2019 • Deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to PNM’s next rate case • Disallowing PNM’s ability to collect an equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowed recovery of the total $148.1 million of investments with a debt-only return • Requiring PNM to reduce the requested $62.3 million increase in non-fuel revenue by $9.1 million • Implementation of the first phase of the rate increase for services rendered, rather than bills sent, beginning February 1, 2018 and of the second phase for services rendered beginning January 1, 2019 On January 16, 2018, PNM requested clarifying changes to the Revised Order to adjust the $9.1 million reduction to $4.4 million , asserting that $4.7 million of the reduction was duplicative. On January 17, 2018, the NMPRC issued an order approving the adjustment requested by PNM. On January 19, 2018, PNM and the Signatories filed a joint notice of acceptance of the Revised Order, as amended. On January 31, 2018, the NMPRC issued an order closing the docket in the NM 2016 Rate Case. After implementation of changes to the federal corporate income tax rate and cost of debt, the final order results in a net increase to PNM’s non-fuel revenue requirement of $10.3 million . PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and will implement the rest of the increase for service rendered beginning January 1, 2019. GAAP required PNM to recognize a loss to reflect that PNM will not earn an equity return on $148.1 million of investments at Four Corners. As of December 31, 2017, PNM recorded a pre-tax regulatory disallowance of $27.9 million . The amount of the loss was calculated by determining the present value of disallowed cash flows, which equals the difference between the cash flows resulting from recovery of those investments at PNM’s embedded cost of debt and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC. On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case. On March 7, 2018, NEE filed its statement of issues with the NM Supreme Court requesting, among other things, that the NMPRC be required to identify PNM’s decision to continue its participation in Four Corners as imprudent and to deny any recovery related to PNM’s $148.1 million investments in that facility. NEE’s Brief in Chief was filed on July 16, 2018 and PNM’s Answer Brief was filed on October 12, 2018. Several parties to the case have intervened in the appeal as intervenor-appellees in support of the NMPRC’s final decisions in the Revised Order. Although PNM does not believe it is probable that NEE’s appeal will be successful, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to remand the case to the NMPRC and the NMPRC identified PNM’s continued involvement in Four Corners as imprudent with no recovery of the $148.1 million of investments in Four Corners, PNM would be required to record additional losses for the remaining amount of those investments (after considering the $27.9 million disallowance recorded in 2017). In addition, PNM’s future investments in Four Corners, which could be required under the participation agreement governing that facility, could also be subject to disallowance. PNM cannot predict the outcome of this matter. Investigation/Rulemaking Concerning NMPRC Ratemaking Policies On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method should be established for determining ROE; should the ROE be subject to reward or penalty based on utilities meeting or failing to meet certain metrics, which could include customer complaints, outages, peak demand reductions, and RPS and energy efficiency compliance; whether recovery of utility rate case expenses should be limited to 50% unless the case is settled; whether intervenors should be allowed to recover their expenses if the NMPRC accepts their position; whether parties should have access to software used by utilities to support their positions; and how regulatory assets should be authorized and recovered. Initial comments were filed in July 2017 and several public workshops have been held. PNM cannot predict the outcome of this proceeding. Renewable Portfolio Standard The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 30% wind, 20% solar, 3% distributed generation, and 5% other. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. PNM makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Included in PNM’s approved procurement plans are the following renewable energy resources: • 157 MW of PNM-owned solar-PV facilities, including 50 MW of PNM-owned solar-PV facilities approved by the NMPRC in PNM’s 2018 renewable energy procurement plan that will be constructed in 2018 and 2019 • A PPA through 2044 for the output of New Mexico Wind, having a current aggregate capacity of 204 MW, and a PPA through 2035 for the output of Red Mesa Wind, having an aggregate capacity of 102 MW • A PPA through 2042 for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current capacity of the facility is 4 MW • Solar distributed generation, aggregating 95.9 MW at September 30, 2018 , owned by customers or third parties from whom PNM purchases any net excess output and RECs • Solar and wind RECs as needed to meet the RPS requirements PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome. PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan met RPS and diversity requirements for 2017 and 2018 using existing resources and PNM did not propose any significant new procurements. PNM projected that its plan would slightly exceed the RCT in 2017 and would be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determined a variance was necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a recommended decision recommending that the plan be approved as filed and also found that a variance from the RCT was not required. The NMPRC approved the recommended decision on November 23, 2016. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM requested approval to |
Lease Commitments
Lease Commitments | 9 Months Ended |
Sep. 30, 2018 | |
Leases [Abstract] | |
Lease Commitments | Lease Commitments The Company leases office buildings, vehicles, and other equipment. In addition, PNM leases interests in Units 1 and 2 of PVNGS and certain right-of-way agreements are classified as leases. All of the Company’s leases are currently accounted for as operating leases. See New Accounting Pronouncements in Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options under the PVNGS leases. The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.25 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.76 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors, and take title to the leased interests. If such an event had occurred as of September 30, 2018 , amounts due to the lessors under the circumstances described above would be up to $163.8 million , payable on January 15, 2019 in addition to the scheduled lease payments due on January 15, 2019. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes On December 22, 2017, comprehensive changes in United States federal income taxes were enacted through legislation commonly known as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act makes many significant modifications to the tax laws, including reducing the federal corporate income tax rate from 35% to 21% effective January 1, 2018. The Tax Act also eliminates federal bonus depreciation for utilities effective September 28, 2017 and, effective January 1, 2018, limits interest deductibility for non-utility businesses and limits the deductibility of certain officer compensation. Although most of the provisions of the Tax Act are not effective until 2018, GAAP required that some effects be recognized in 2017. Under the asset and liability method of accounting for income taxes used by the Company, deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to reverse. At the date of enactment of the Tax Act, the Company had net deferred tax liabilities for its regulated activities and net deferred tax assets for non-regulated activities. As a result of the change in the federal corporate income tax rate, the Company re-measured and adjusted its deferred tax assets and liabilities as of December 31, 2017. The portion of that adjustment not related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax assets and an increase in income tax expense. The portion related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax liabilities and an increase in regulatory liabilities, based on the assumption that PNM and TNMP will be required to return the benefit to ratepayers over time. PNM’s NM 2016 Rate Case (Note 12) reflects that assumption by including an amortization of the estimated benefit of the reduction in existing deferred federal corporate income taxes as a reduction to customer rates over a twenty-one year period beginning in 2018. On January 25, 2018, the PUCT issued an order requiring Texas utilities, including TNMP, to begin recording regulatory liabilities for the effects of the Tax Act with the stated purpose of reflecting those effects in the utility bills of Texas ratepayers. During the three and nine months ended September 30, 2018 , TNMP reduced revenue and recorded a regulatory liability of $1.5 million and $4.2 million in accordance with the PUCT’s order. The TNMP 2018 Rate Case filed on May 30, 2018, and related settlement agreement include a reduction in customer rates to reflect the impacts of the Tax Act, including amortization of the regulatory liability related to the 2017 re-measurement of deferred tax liabilities and to reduce the federal corporate income tax rate to 21% (Note 12). In December 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides guidance to address the application of GAAP to reflect the Tax Act in circumstances where all information and analysis of the Tax Act is not yet available or complete. This bulletin provides for up to a one-year period in which to complete the required analyses and accounting for the impacts of the Tax Act. The Company believes it made reasonable estimates of the effects of the Tax Act and reflected the impacts in the Consolidated Financial Statements included in the 2017 Annual Reports on Form 10-K. However, the reported effects on the Company’s deferred tax assets and liabilities, regulatory assets and liabilities, and income tax expense are provisional and it is possible that changes to United States Treasury regulations, IRS interpretations of the provisions of the Tax Act, actions by the NMPRC, PUCT, and FERC, or the Company’s further analysis of historical records could cause these estimates to change. Through September 30, 2018 , no significant adjustments to the impacts reflected in the 2017 Consolidated Financial Statements included in the 2017 Annual Reports on Form 10-K have been identified. In August 2018, the IRS issued new guidance clarifying the deductibility of executive compensation under Section 162(m) of the Internal Revenue Code as amended by the Tax Act. In addition, the IRS issued proposed regulations interpreting Tax Act amendments to depreciation provisions of the Internal Revenue Code which would allow the Company to claim a bonus depreciation deduction on certain construction projects placed in service during the fourth quarter of 2017. The Company is currently evaluating the IRS’s new guidance and proposed regulations and anticipates it will record adjustments, if any, prior to December 31, 2018. In 2013, New Mexico House Bill 641 reduced the New Mexico corporate income tax rate from 7.6% to 5.9% . The rate reduction is being phased-in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in the year ended December 31, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities and an increase in a regulatory liability, based on the assumption that PNM would be required to return the benefit to customers over time. PNM’s NM 2016 Rate Case (Note 12) reflects the benefit of the lower New Mexico corporate income tax rate being returned to customers over a three-year period beginning February 1, 2018. In addition, the portion of the adjustment that was not related to PNM’s regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities resulted in refinements of the impacts of this change in tax rates being recorded periodically through December 31, 2017, at which time the impacts of the rate reduction were fully phased-in. In the three months ended March 31, 2017, PNM’s regulatory liability was reduced by $4.8 million , which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were reduced by $0.1 million in the three months ended March 31, 2017, increasing income tax expense by less than $0.1 million for PNM and $0.1 million for the Corporate and Other segment. As required under GAAP, the Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. In interim periods, income tax expense is calculated by applying the anticipated annual effective tax rate to year-to-date earnings before income taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, including excess tax benefits related to stock awards, be excluded from the estimated annual effective tax rate calculation. At September 30, 2018 , PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2018 would be 12.35% , 9.51% , and 22.78% . These rates reflect the reduced federal corporate income tax rate of 21% , which rates are adjusted to reflect permanent differences between earnings determined in accordance with GAAP and taxable income, as well as state income taxes. The primary permanent difference is the reduction in income tax expense resulting from the amortization of excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case. During the three and nine months ended September 30, 2018 , income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced by excess tax benefits related to stock awards of zero and $1.4 million for PNMR, zero and $1.0 million for PNM, and less than $0.1 million and $0.4 million for TNMP. |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions PNMR, PNM, TNMP, and NMRD are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. In addition, PNMR provides construction and operations and maintenance services to NMRD, a 50% owned subsidiary of PNMR Development (Note 1), and PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Services billings: PNMR to PNM $ 22,972 $ 23,451 $ 69,122 $ 71,044 PNMR to TNMP 8,074 7,828 24,497 23,771 PNM to TNMP 104 115 281 302 TNMP to PNMR 35 35 105 106 TNMP to PNM — 8 — 154 PNMR to NMRD 32 — 162 — Renewable energy purchases: PNM from NMRD 969 — 2,343 — Interconnection billings: PNM to NMRD 47 — 2,099 — PNM to PNMR — — 68,200 — Interest billings: PNMR to PNM 844 3 1,653 14 PNM to PNMR 75 71 211 163 PNMR to TNMP 65 66 87 126 Income tax sharing payments: PNMR to PNM — — — — TNMP to PNMR — — — — |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. PNMR’s reporting units that currently have goodwill are PNM and TNMP. Additional information concerning the Company’s goodwill is contained in Note 18 of Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price has occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required if, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, GAAP currently requires the entity to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how a goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis. For its annual evaluations performed as of April 1, 2017, PNMR performed qualitative analyses for both the PNM and TNMP reporting units. The qualitative analysis was performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2016 quantitative analysis. This analysis considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including the then estimated impacts of the proposed revised stipulation in PNM’s NM 2016 Rate Case, the impacts of potential outcomes of the matters appealed to the NM Supreme Court under the NM 2015 Rate Case, and the impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. This evaluation also considered changes in TNMP’s regulatory environment such as the PUCT’s then proposed amendments to the interim transmission cost of service filing rule, as well as potential outcomes associated with TNMP’s anticipated general rate case filing. The qualitative analysis also considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2017 carrying values of PNM or TNMP exceeded their fair values. For its annual evaluations performed as of April 1, 2018, PNMR performed a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the PNM reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for the reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2018 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million , exceeded its carrying value by approximately 19% . The 2018 qualitative analysis for the TNMP reporting unit was performed by considering changes in expectations of future financial performance since the April 1, 2016 quantitative analysis that indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million , exceeded its carrying value by approximately 32% and the April 1, 2017 qualitative analysis. The 2018 analysis considered events specific to TNMP such as the potential impacts of legal and regulatory matters discussed in Note 12, including potential adverse outcomes in the TNMP 2018 Rate Case, which was filed in May 2018. Both the PNM quantitative analysis and the TNMP qualitative analysis considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it is not more likely than not that the April 1, 2018 carrying values of PNM or TNMP exceed their fair values. As indicated above, the annual evaluations performed as of April 1, 2018 and 2017 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 2018 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below their carrying values. |
Significant Accounting Polici_2
Significant Accounting Policies and Responsibility for Financial Statements (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 6). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants. PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated. |
New Accounting Pronouncements | 2016-18. New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2016-02 – Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 will require that a liability be recorded on the balance sheet for all leases, based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. ASU 2016-02 originally required that leases be recognized and measured as of the earliest period presented using a modified retrospective approach with all periods presented being restated and presented under the new guidance. The ASU allows entities to apply certain practical expedients to arrangements that exist upon adoption or that expired during the periods presented. As further discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, and equipment. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. In addition, the Company also routinely enters into land easements and right-of-way agreements. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, is conducting outreach activities across its lines of business, and is in the process of implementing software to help administer and account for its leasing activities. The Company has made significant progress in identifying arrangements that may be classified as leases under ASU 2016-02 in addition to those currently classified as operating leases. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company anticipates its leases of vehicles and certain office equipment commencing after January 1, 2019 will be classified as financing leases. The Company is in the process of analyzing each of the identified contractual arrangements to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company anticipates this process will continue throughout 2018. The Company will adopt this standard effective as of January 1, 2019, its required effective date. The Company anticipates it will elect the “package” of practical expedients provided by ASU 2016-02 upon adoption. As a result, the Company will not reassess, as of the date of adoption, whether contracts should be accounted for as leases under ASU 2016-02, the classification of contracts accounted for as leases (as operating or financing), or whether any initial direct costs associated with contracts accounted for as leases should be recognized as a component of right-of-use assets. In January 2018, the FASB issued ASU 2018-01, which clarifies that land easements are to be evaluated under ASU 2016-02, but provides an additional optional practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under the current guidance. The Company has numerous land easements and right-of-way agreements that would fall under this clarification. The only such agreement that has been accounted for as a lease under current guidance is the right-of-way agreement with the Navajo Nation, which is discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K. The Company anticipates it will elect to use the practical expedient for its existing and expired land easements upon adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, which provides entities an optional transitional relief method to apply ASU 2016-02 as of the date of initial application of the standard rather than as of the earliest period presented. The Company anticipates it will elect to use this optional transitional relief method. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date, although early adoption is permitted beginning on January 1, 2019. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019, although early adoption is permitted. At adoption, ASU 2017-12 is to be applied prospectively and allows entities to record a cumulative-effect adjustment at the transition date as well as allowing entities to elect certain practical expedients upon adoption. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 9, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8 of the Notes to Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 7, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not currently designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements. Accounting Standards Update 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 8 of the Notes to the Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on January 1, 2021, although early adoption is permitted, and requires retrospective application. As discussed in Note 12 of the Notes to the Consolidated Financial Statements in the 2017 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14, but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and, when used to reduce income taxes payable, classified as cash flows from operating activities. |
Variable Interest Entities | GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Summary of Financial Information by Segment | The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended September 30, 2018 Electric operating revenues $ 331,374 $ 91,292 $ — $ 422,666 Cost of energy 92,384 21,152 — 113,536 Utility margin 238,990 70,140 — 309,130 Other operating expenses 98,000 25,140 (3,580 ) 119,560 Depreciation and amortization 38,474 17,176 5,930 61,580 Operating income (loss) 102,516 27,824 (2,350 ) 127,990 Interest income 3,472 — (72 ) 3,400 Other income (deductions) 2,515 1,151 (92 ) 3,574 Interest charges (18,063 ) (8,241 ) (4,188 ) (30,492 ) Segment earnings (loss) before income taxes 90,440 20,734 (6,702 ) 104,472 Income taxes (benefit) 9,012 4,634 (747 ) 12,899 Segment earnings (loss) 81,428 16,100 (5,955 ) 91,573 Valencia non-controlling interest (3,920 ) — — (3,920 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 77,376 $ 16,100 $ (5,955 ) $ 87,521 Nine Months Ended September 30, 2018 Electric operating revenues $ 832,116 $ 260,741 $ — $ 1,092,857 Cost of energy 229,547 64,256 — 293,803 Utility margin 602,569 196,485 — 799,054 Other operating expenses 305,569 73,624 (13,955 ) 365,238 Depreciation and amortization 113,314 49,676 17,375 180,365 Operating income (loss) 183,686 73,185 (3,420 ) 253,451 Interest income 9,340 — 2,522 11,862 Other income (deductions) 588 3,067 (441 ) 3,214 Interest charges (58,881 ) (23,771 ) (14,216 ) (96,868 ) Segment earnings (loss) before income taxes 134,733 52,481 (15,555 ) 171,659 Income taxes (benefit) 11,009 11,602 (3,773 ) 18,838 Segment earnings (loss) 123,724 40,879 (11,782 ) 152,821 Valencia non-controlling interest (11,706 ) — — (11,706 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 111,622 $ 40,879 $ (11,782 ) $ 140,719 At September 30, 2018: Total Assets $ 5,042,761 $ 1,628,842 $ 177,392 $ 6,848,995 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended September 30, 2017 Electric operating revenues $ 327,254 $ 92,646 $ — $ 419,900 Cost of energy 82,367 21,381 — 103,748 Utility margin 244,887 71,265 — 316,152 Other operating expenses 92,733 25,367 (5,391 ) 112,709 Depreciation and amortization 36,764 16,424 5,633 58,821 Operating income (loss) 115,390 29,474 (242 ) 144,622 Interest income 1,782 — 1,800 3,582 Other income (deductions) 4,204 1,228 (460 ) 4,972 Interest charges (20,451 ) (7,704 ) (3,951 ) (32,106 ) Segment earnings (loss) before income taxes 100,925 22,998 (2,853 ) 121,070 Income taxes (benefit) 35,642 8,271 (1,170 ) 42,743 Segment earnings (loss) 65,283 14,727 (1,683 ) 78,327 Valencia non-controlling interest (4,456 ) — — (4,456 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 60,695 $ 14,727 $ (1,683 ) $ 73,739 Nine Months Ended September 30, 2017 Electric operating revenues $ 854,909 $ 257,489 $ — $ 1,112,398 Cost of energy 246,635 64,183 — 310,818 Utility margin 608,274 193,306 — 801,580 Other operating expenses 281,886 72,188 (15,286 ) 338,788 Depreciation and amortization 109,228 47,392 16,209 172,829 Operating income (loss) 217,160 73,726 (923 ) 289,963 Interest income 6,457 — 5,891 12,348 Other income (deductions) 13,510 2,392 (918 ) 14,984 Interest charges (62,393 ) (22,619 ) (11,125 ) (96,137 ) Segment earnings (loss) before income taxes 174,734 53,499 (7,075 ) 221,158 Income taxes (benefit) 58,865 18,964 (2,675 ) 75,154 Segment earnings (loss) 115,869 34,535 (4,400 ) 146,004 Valencia non-controlling interest (11,452 ) — — (11,452 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 104,021 $ 34,535 $ (4,400 ) $ 134,156 At September 30, 2017: Total Assets $ 5,023,816 $ 1,465,219 $ 208,219 $ 6,697,254 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2018 and 2017 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2017, as originally reported $ 13,169 $ (110,262 ) $ (97,093 ) $ 1,153 $ (95,940 ) Cumulative effect adjustment (Note 7) (11,208 ) — (11,208 ) — (11,208 ) Balance at January 1, 2018, as adjusted 1,961 (110,262 ) (108,301 ) 1,153 (107,148 ) Amounts reclassified from AOCI (pre-tax) (3,483 ) 5,678 2,195 102 2,297 Income tax impact of amounts reclassified 885 (1,442 ) (557 ) (27 ) (584 ) Other OCI changes (pre-tax) 2,872 — 2,872 2,431 5,303 Income tax impact of other OCI changes (730 ) — (730 ) (618 ) (1,348 ) Net after-tax change (456 ) 4,236 3,780 1,888 5,668 Balance at September 30, 2018 $ 1,505 $ (106,026 ) $ (104,521 ) $ 3,041 $ (101,480 ) Balance at December 31, 2016 $ 4,320 $ (96,748 ) $ (92,428 ) $ (23 ) $ (92,451 ) Amounts reclassified from AOCI (pre-tax) (11,088 ) 4,839 (6,249 ) 484 (5,765 ) Income tax impact of amounts reclassified 4,302 (1,878 ) 2,424 (187 ) 2,237 Other OCI changes (pre-tax) 22,302 — 22,302 (278 ) 22,024 Income tax impact of other OCI changes (8,654 ) — (8,654 ) 108 (8,546 ) Net after-tax change 6,862 2,961 9,823 127 9,950 Balance at September 30, 2017 $ 11,182 $ (93,787 ) $ (82,605 ) $ 104 $ (82,501 ) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Computation of Earnings Per Share | Information regarding the computation of earnings per share is as follows: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 87,521 $ 73,739 $ 140,719 $ 134,156 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 215 284 210 215 Average Shares – Basic 79,869 79,938 79,864 79,869 Dilutive Effect of Common Stock Equivalents: Stock options and restricted stock 111 216 126 263 Average Shares – Diluted 79,980 80,154 79,990 80,132 Net Earnings Per Share of Common Stock: Basic $ 1.10 $ 0.92 $ 1.76 $ 1.68 Diluted $ 1.09 $ 0.92 $ 1.76 $ 1.67 |
Electric Operating Revenues (Ta
Electric Operating Revenues (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects ARP revenues and other revenues. PNM TNMP PNMR Consolidated Three Months Ended September 30, 2018 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 138,091 $ 40,227 $ 178,318 Commercial 121,755 28,850 150,605 Industrial 17,919 4,402 22,321 Public authority 6,872 1,390 8,262 Economy energy service 6,158 — 6,158 Transmission 13,538 16,743 30,281 Miscellaneous 1,686 2,392 4,078 Total revenues from contracts with customers 306,019 94,004 400,023 Alternative revenue programs (5,338 ) (2,712 ) (8,050 ) Other electric operating revenues 30,693 — 30,693 Total Electric Operating Revenues $ 331,374 $ 91,292 $ 422,666 PNM TNMP PNMR Consolidated Nine Months Ended September 30, 2018 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 334,767 $ 100,808 $ 435,575 Commercial 315,256 84,084 399,340 Industrial 45,976 12,891 58,867 Public authority 16,726 4,205 20,931 Economy energy service 19,825 — 19,825 Transmission 40,128 49,995 90,123 Miscellaneous 10,632 6,740 17,372 Total revenues from contracts with customers 783,310 258,723 1,042,033 Alternative revenue programs (3,484 ) 2,018 (1,466 ) Other electric operating revenues 52,290 — 52,290 Total Electric Operating Revenues $ 832,116 $ 260,741 $ 1,092,857 |
Contract with Customer, Asset and Liability | Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows: PNM TNMP PNMR Consolidated (In thousands) Balance at December 31, 2017 $ 349 $ — $ 349 Consideration received in advance of service to be provided 4,174 1,512 5,686 Deferred revenue earned (3,304 ) (1,134 ) (4,438 ) Balance at September 30, 2018 $ 1,219 $ 378 $ 1,597 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Variable Interest Entities [Abstract] | |
Summarized Financial Information | Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (In thousands) Operating revenues $ 5,368 $ 5,859 $ 16,047 $ 15,880 Operating expenses (1,448 ) (1,403 ) (4,341 ) (4,428 ) Earnings attributable to non-controlling interest $ 3,920 $ 4,456 $ 11,706 $ 11,452 Financial Position September 30, December 31, 2018 2017 (In thousands) Current assets $ 3,449 $ 2,688 Net property, plant, and equipment 62,698 64,109 Total assets 66,147 66,797 Current liabilities 923 602 Owners’ equity – non-controlling interest $ 65,224 $ 66,195 |
Fair Value of Derivative and _2
Fair Value of Derivative and Other Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value of Derivative and Other Financial Instruments [Abstract] | |
Summary of Derivatives | PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges September 30, December 31, (In thousands) Current assets $ 1,083 $ 1,088 Deferred charges 2,741 3,556 3,824 4,644 Current liabilities (1,092 ) (1,182 ) Long-term liabilities (2,741 ) (3,556 ) (3,833 ) (4,738 ) Net $ (9 ) $ (94 ) |
Effect of Mark-to-Market on Earnings, Excluding Tax Effects | The following table presents the effect of mark-to-market commodity derivative instruments on PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Electric operating revenues $ (93 ) $ (2,237 ) $ (95 ) $ 5,697 Cost of energy 93 (14 ) 97 (5,289 ) Total gain $ — $ (2,251 ) $ 2 $ 408 |
Schedule of Net Buy (Sell) Volume Positions | The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh September 30, 2018 100,000 4,800 December 31, 2017 100,000 — |
Schedule of Gross Realized Gains and Losses | The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $ (0.8) million and $ (4.6) million for the three and nine months ended September 30, 2018 and $ 0.1 million and $ 1.1 million for the three and nine months ended September 30, 2017 . Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Proceeds from sales $ 117,801 $ 98,532 $ 911,899 $ 456,577 Gross realized gains $ 3,460 $ 8,128 $ 17,030 $ 24,745 Gross realized (losses) $ (3,149 ) $ (2,829 ) $ (14,018 ) $ (8,150 ) Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table. Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 (In thousands) Equity securities: Net gains from equity securities sold $ 113 $ 5,443 Net gains from equity securities still held 2,943 2,636 Total net gains on equity securities 3,056 8,079 Available-for-sale debt securities: Net (losses) on debt securities (593 ) (6,998 ) Net gains on investment securities $ 2,463 $ 1,081 |
Investments Classified by Contractual Maturity Date | At September 30, 2018 , the available-for-sale debt securities held by PNM, had the following final maturities: Fair Value (In thousands) Within 1 year $ 9,986 After 1 year through 5 years 59,944 After 5 years through 10 years 67,585 After 10 years through 15 years 10,375 After 15 years through 20 years 11,151 After 20 years 46,887 $ 205,928 |
Schedule of Investments | Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale securities. Under ASU 2016-01, PNM does not classify its investments in equity instruments as available-for-sale securities beginning January 1, 2018. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) September 30, 2018 Cash and cash equivalents $ 3,527 $ 3,527 $ — $ — Equity securities: Corporate stocks, common 40,017 40,017 — — Corporate stocks, preferred 7,239 1,587 5,652 — Mutual funds and other 75,035 75,035 — — Available-for-sale debt securities: U.S. Government 25,689 15,400 10,289 — $ 23 International Government 8,460 — 8,460 — 90 Municipals 51,280 — 51,280 — 78 Corporate and other 120,499 — 117,445 3,054 1,827 $ 331,746 $ 135,566 $ 193,126 $ 3,054 $ 2,018 Commodity derivative assets $ 3,824 $ — $ 3,824 $ — Commodity derivative liabilities (3,833 ) — (3,833 ) — Net $ (9 ) $ — $ (9 ) $ — December 31, 2017 Available-for-sale securities Cash and cash equivalents $ 52,636 $ 52,636 $ — $ — Equity securities: Domestic value 40,032 40,032 — — $ 4,011 Domestic growth 35,456 35,456 — — 3,995 International and other 45,867 42,332 3,535 — 6,810 Fixed income securities: U.S. Government 34,317 33,645 672 — 273 Municipals 48,076 — 48,076 — 1,225 Corporate and other 67,140 — 67,140 — 1,714 $ 323,524 $ 204,101 $ 119,423 $ — $ 18,028 Commodity derivative assets $ 4,644 $ — $ 4,644 $ — Commodity derivative liabilities (4,738 ) — (4,738 ) — Net $ (94 ) $ — $ (94 ) $ — |
Summary of Level 3 Measurements | A reconciliation of the changes in Level 3 fair value measurements is as follows: Corporate Debt (In thousands) Balance at December 31, 2017 $ — Actual return on assets sold during the period (6 ) Actual return on assets still held at period end 16 Purchases 5,234 Sales (2,190 ) Balance at September 30, 2018 $ 3,054 |
Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value | The carrying amounts and fair values of investments in the Westmoreland Loan, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 September 30, 2018 (In thousands) PNMR Long-term debt $ 2,614,511 $ 2,642,154 $ — $ 2,642,154 $ — Other investments $ 348 $ 348 $ 348 $ — $ — PNM Long-term debt $ 1,656,102 $ 1,665,064 $ — $ 1,665,064 $ — Other investments $ 142 $ 142 $ 142 $ — $ — TNMP Long-term debt $ 560,293 $ 580,017 $ — $ 580,017 $ — Other investments $ 206 $ 206 $ 206 $ — $ — December 31, 2017 PNMR Long-term debt $ 2,437,645 $ 2,554,836 $ — $ 2,554,836 $ — Westmoreland Loan $ 56,640 $ 66,588 $ — $ — $ 66,588 Other investments $ 503 $ 503 $ 503 $ — $ — PNM Long-term debt $ 1,657,910 $ 1,727,135 $ — $ 1,727,135 $ — Other investments $ 283 $ 283 $ 283 $ — $ — TNMP Long-term debt $ 480,620 $ 527,563 $ — $ 527,563 $ — Other investments $ 220 $ 220 $ 220 $ — $ — |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Activity | The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Nine Months Ended September 30, Restricted Shares and Performance Based Shares 2018 2017 Expected quarterly dividends per share $ 0.2650 $ 0.2425 Risk-free interest rate 2.38 % 1.50 % Market-Based Shares Dividend yield 2.96 % 2.67 % Expected volatility 19.12 % 20.80 % Risk-free interest rate 2.36 % 1.54 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months ended September 30, 2018 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2017 189,045 $ 31.11 193,441 $ 9.98 Granted 221,062 $ 29.65 — $ — Exercised (235,868 ) $ 28.44 (109,441 ) $ 8.56 Forfeited (6,054 ) $ 31.37 — $ — Expired — $ — — $ — Outstanding at September 30, 2018 168,185 $ 32.93 84,000 $ 11.82 The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Nine Months Ended September 30, Restricted Stock 2018 2017 Weighted-average grant date fair value $ 29.65 $ 23.06 Total fair value of restricted shares that vested (in thousands) $ 8,493 $ 5,666 Stock Options Weighted-average grant date fair value of options granted $ — $ — Total fair value of options that vested (in thousands) $ — $ — Total intrinsic value of options exercised (in thousands) $ 3,016 $ 2,234 |
Financing (Tables)
Financing (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | Information concerning the maturities and interest rates on the PNM 2018 SUNs is as follows: Funding Maturity Principal Interest Date Date Amount Rate (In millions) May 14, 2018 May 15, 2023 $ 55.0 3.15 % May 14, 2018 May 15, 2025 104.0 3.45 % May 14, 2018 May 15, 2028 88.0 3.68 % May 14, 2018 May 15, 2033 38.0 3.93 % May 14, 2018 May 15, 2038 45.0 4.22 % May 14, 2018 May 15, 2048 20.0 4.50 % 350.0 July 31, 2018 August 1, 2028 15.0 3.78 % July 31, 2018 August 1, 2048 85.0 4.60 % 100.0 $ 450.0 |
Schedule of Short-term Debt | Short-term debt outstanding consisted of: September 30, December 31, Short-term Debt 2018 2017 (In thousands) PNM: PNM Revolving Credit Facility $ — $ 39,800 PNM 2017 New Mexico Credit Facility — — — 39,800 TNMP Revolving Credit Facility 17,500 — PNMR: PNMR Revolving Credit Facility 120,600 165,600 PNMR 2016 One-Year Term Loan (as extended) 100,000 100,000 PNMR Development Revolving Credit Facility 24,500 — $ 262,600 $ 305,400 |
Pension and Other Postretirem_2
Pension and Other Postretirement Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Net Benefit Costs | The following table presents the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 33 $ 36 $ — $ — Interest cost 656 722 119 139 7 8 Expected return on plan assets (991 ) (945 ) (135 ) (114 ) — — Amortization of net (gain) loss 272 231 (56 ) (20 ) 4 2 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ (63 ) $ 8 $ (39 ) $ 41 $ 11 $ 10 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 100 $ 107 $ — $ — Interest cost 1,969 2,165 358 417 22 25 Expected return on plan assets (2,972 ) (2,834 ) (406 ) (342 ) — — Amortization of net (gain) loss 816 692 (170 ) (60 ) 11 7 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ (187 ) $ 23 $ (118 ) $ 122 $ 33 $ 32 The following table presents the components of the PNM Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 21 $ 24 $ — $ — Interest cost 6,068 6,727 860 1,006 155 174 Expected return on plan assets (8,672 ) (8,451 ) (1,353 ) (1,308 ) — — Amortization of net (gain) loss 4,087 4,001 588 921 90 78 Amortization of prior service cost (241 ) (241 ) (416 ) (416 ) — — Net periodic benefit cost $ 1,242 $ 2,036 $ (300 ) $ 227 $ 245 $ 252 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2018 2017 2018 2017 2018 2017 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 62 $ 72 $ — $ — Interest cost 18,203 20,181 2,579 3,019 467 523 Expected return on plan assets (26,014 ) (25,352 ) (4,061 ) (3,923 ) — — Amortization of net (gain) loss 12,261 12,004 1,765 2,762 269 235 Amortization of prior service cost (724 ) (724 ) (1,248 ) (1,248 ) — — Net periodic benefit cost $ 3,726 $ 6,109 $ (903 ) $ 682 $ 736 $ 758 |
Regulatory and Rate Matters (Ta
Regulatory and Rate Matters (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Regulated Operations [Abstract] | |
Schedule of Rate Increases for Transmission Costs | The following sets forth TNMP’s recent interim transmission cost rate increases: Effective Date Approved Increase in Rate Base Annual Increase in Revenue (In millions) September 8, 2016 $ 9.5 $ 1.8 March 14, 2017 30.2 4.8 September 13, 2017 27.5 4.7 March 27, 2018 32.0 0.6 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In thousands) Services billings: PNMR to PNM $ 22,972 $ 23,451 $ 69,122 $ 71,044 PNMR to TNMP 8,074 7,828 24,497 23,771 PNM to TNMP 104 115 281 302 TNMP to PNMR 35 35 105 106 TNMP to PNM — 8 — 154 PNMR to NMRD 32 — 162 — Renewable energy purchases: PNM from NMRD 969 — 2,343 — Interconnection billings: PNM to NMRD 47 — 2,099 — PNM to PNMR — — 68,200 — Interest billings: PNMR to PNM 844 3 1,653 14 PNM to PNMR 75 71 211 163 PNMR to TNMP 65 66 87 126 Income tax sharing payments: PNMR to PNM — — — — TNMP to PNMR — — — — |
Significant Accounting Polici_3
Significant Accounting Policies and Responsibility for Financial Statements (Details) | Aug. 24, 2018power_purchase_agreement | Sep. 30, 2018USD ($)$ / sharesMW | Jun. 30, 2018$ / shares | Dec. 31, 2017USD ($)power_purchase_agreement | Sep. 30, 2017USD ($)$ / shares | Jun. 30, 2017USD ($)$ / shares | Sep. 30, 2018USD ($)$ / sharesMW | Sep. 30, 2017USD ($)$ / shares | Sep. 05, 2017MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Business Acquisition [Line Items] | |||||||||||
Payment defaults under agreements | $ 0 | $ 0 | |||||||||
Dividends declared per common share (dollars per share) | $ / shares | $ 0.2650 | $ 0.2425 | $ 0.7950 | $ 0.7275 | |||||||
Dividends declared on common stock | $ 63,325,000 | ||||||||||
Revenues | $ 422,666,000 | $ 419,900,000 | 1,092,857,000 | $ 1,112,398,000 | |||||||
Construction work in progress | 227,367,000 | $ 245,933,000 | 227,367,000 | ||||||||
Owners' equity | 1,771,298,000 | 1,695,253,000 | 1,771,298,000 | ||||||||
Cash and cash equivalents | $ 34,964,000 | 3,974,000 | $ 43,149,000 | $ 34,964,000 | 43,149,000 | $ 5,522,000 | |||||
NMRD | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Renewable energy capacity in operating (in mw) | MW | 34.3 | 34.3 | |||||||||
Texas-New Mexico Power Company | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Dividends declared per common share (dollars per share) | $ / shares | $ 0.2650 | $ 0.2650 | $ 0.2425 | $ 0.2425 | |||||||
Dividends declared on common stock | $ 25,804,000 | 29,700,000 | |||||||||
Revenues | $ 91,292,000 | $ 92,646,000 | 260,741,000 | 257,489,000 | |||||||
Net earnings | 16,100,000 | $ 14,727,000 | 40,879,000 | $ 34,535,000 | |||||||
Construction work in progress | 77,456,000 | 34,350,000 | 77,456,000 | ||||||||
Owners' equity | 649,480,000 | 634,405,000 | 649,480,000 | ||||||||
Cash and cash equivalents | 0 | 1,700,000 | 0 | ||||||||
NMRD | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenues | 1,000,000 | 2,500,000 | |||||||||
Net earnings | 500,000 | 1,000,000 | |||||||||
Cash | 2,300,000 | 2,300,000 | |||||||||
Construction work in progress | 50,400,000 | 50,400,000 | |||||||||
Accounts payable | 700,000 | 700,000 | |||||||||
Owners' equity | $ 52,000,000 | $ 52,000,000 | |||||||||
PNMR Development | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Solar generation capacity (in megawatts) | MW | 30 | 30 | 50 | ||||||||
PNMR Development | NMRD | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Ownership percentage | 50.00% | 50.00% | |||||||||
PNMR Development and AEP OnSite | NMRD | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Contribution to construction activities | $ 9,000,000 | ||||||||||
PNM | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenues | $ 331,374,000 | $ 327,254,000 | 832,116,000 | $ 854,909,000 | |||||||
Net earnings | 77,508,000 | 60,827,000 | 112,018,000 | 104,417,000 | |||||||
Construction work in progress | 141,174,000 | 204,079,000 | 141,174,000 | ||||||||
Owners' equity | 1,537,576,000 | 1,422,174,000 | 1,537,576,000 | ||||||||
Third party deposits | $ 1,000,000 | 7,200,000 | $ 8,200,000 | ||||||||
Cash and cash equivalents | $ 31,486,000 | 1,108,000 | $ 39,370,000 | $ 31,486,000 | $ 39,370,000 | 1,324,000 | |||||
Accounting Standards Update 2016-18 | PNM | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash and cash equivalents | $ 1,000,000 | $ 1,000,000 | |||||||||
Accounting Standards Update 2016-18 | NMCUC | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash and cash equivalents | $ 100,000 | ||||||||||
Facebook Data Center | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Number of additional PPAs | power_purchase_agreement | 2 | 3 | |||||||||
Power purchase agreement term | 25 years | 25 years |
Segment Information - Summarize
Segment Information - Summarized Financial Information (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)segment | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) | |
Segment Reporting Information [Line Items] | |||||
Number of operating segments | segment | 1 | ||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | $ 422,666 | $ 419,900 | $ 1,092,857 | $ 1,112,398 | |
Utility margin | 309,130 | 316,152 | 799,054 | 801,580 | |
Other operating expenses | 119,560 | 112,709 | 365,238 | 338,788 | |
Depreciation and amortization | 61,580 | 58,821 | 180,365 | 172,829 | |
Operating income | 127,990 | 144,622 | 253,451 | 289,963 | |
Interest income | 3,400 | 3,582 | 11,862 | 12,348 | |
Other income (deductions) | 3,574 | 4,972 | 3,214 | 14,984 | |
Interest charges | (30,492) | (32,106) | (96,868) | (96,137) | |
Earnings before Income Taxes | 104,472 | 121,070 | 171,659 | 221,158 | |
Income taxes (benefit) | 12,899 | 42,743 | 18,838 | 75,154 | |
Net Earnings | 91,573 | 78,327 | 152,821 | 146,004 | |
Valencia non-controlling interest | (3,920) | (4,456) | (11,706) | (11,452) | |
Subsidiary preferred stock dividends | (132) | (132) | (396) | (396) | |
Net Earnings Available for PNM Common Stock | 87,521 | 73,739 | 140,719 | 134,156 | |
Total Assets | 6,848,995 | 6,697,254 | 6,848,995 | 6,697,254 | $ 6,646,103 |
Goodwill | 278,297 | 278,297 | 278,297 | 278,297 | $ 278,297 |
PNM | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Utility margin | 238,990 | 244,887 | 602,569 | 608,274 | |
Other operating expenses | 98,000 | 92,733 | 305,569 | 281,886 | |
Depreciation and amortization | 38,474 | 36,764 | 113,314 | 109,228 | |
Operating income | 102,516 | 115,390 | 183,686 | 217,160 | |
Interest income | 3,472 | 1,782 | 9,340 | 6,457 | |
Other income (deductions) | 2,515 | 4,204 | 588 | 13,510 | |
Interest charges | (18,063) | (20,451) | (58,881) | (62,393) | |
Earnings before Income Taxes | 90,440 | 100,925 | 134,733 | 174,734 | |
Income taxes (benefit) | 9,012 | 35,642 | 11,009 | 58,865 | |
Net Earnings | 81,428 | 65,283 | 123,724 | 115,869 | |
Valencia non-controlling interest | (3,920) | (4,456) | (11,706) | (11,452) | |
Subsidiary preferred stock dividends | (132) | (132) | (396) | (396) | |
Net Earnings Available for PNM Common Stock | 77,376 | 60,695 | 111,622 | 104,021 | |
Total Assets | 5,042,761 | 5,023,816 | 5,042,761 | 5,023,816 | |
Goodwill | 51,632 | 51,632 | 51,632 | 51,632 | |
TNMP | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Utility margin | 70,140 | 71,265 | 196,485 | 193,306 | |
Other operating expenses | 25,140 | 25,367 | 73,624 | 72,188 | |
Depreciation and amortization | 17,176 | 16,424 | 49,676 | 47,392 | |
Operating income | 27,824 | 29,474 | 73,185 | 73,726 | |
Interest income | 0 | 0 | 0 | 0 | |
Other income (deductions) | 1,151 | 1,228 | 3,067 | 2,392 | |
Interest charges | (8,241) | (7,704) | (23,771) | (22,619) | |
Earnings before Income Taxes | 20,734 | 22,998 | 52,481 | 53,499 | |
Income taxes (benefit) | 4,634 | 8,271 | 11,602 | 18,964 | |
Net Earnings | 16,100 | 14,727 | 40,879 | 34,535 | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | 16,100 | 14,727 | 40,879 | 34,535 | |
Total Assets | 1,628,842 | 1,465,219 | 1,628,842 | 1,465,219 | |
Goodwill | 226,665 | 226,665 | 226,665 | 226,665 | |
Corporate and Other | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Utility margin | 0 | 0 | 0 | 0 | |
Other operating expenses | (3,580) | (5,391) | (13,955) | (15,286) | |
Depreciation and amortization | 5,930 | 5,633 | 17,375 | 16,209 | |
Operating income | (2,350) | (242) | (3,420) | (923) | |
Interest income | (72) | 1,800 | 2,522 | 5,891 | |
Other income (deductions) | (92) | (460) | (441) | (918) | |
Interest charges | (4,188) | (3,951) | (14,216) | (11,125) | |
Earnings before Income Taxes | (6,702) | (2,853) | (15,555) | (7,075) | |
Income taxes (benefit) | (747) | (1,170) | (3,773) | (2,675) | |
Net Earnings | (5,955) | (1,683) | (11,782) | (4,400) | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | (5,955) | (1,683) | (11,782) | (4,400) | |
Total Assets | 177,392 | 208,219 | 177,392 | 208,219 | |
Goodwill | 0 | 0 | 0 | 0 | |
Electricity | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 422,666 | 419,900 | 1,092,857 | 1,112,398 | |
Cost of energy | 113,536 | 103,748 | 293,803 | 310,818 | |
Electricity | PNM | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 331,374 | 327,254 | 832,116 | 854,909 | |
Cost of energy | 92,384 | 82,367 | 229,547 | 246,635 | |
Electricity | TNMP | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 91,292 | 92,646 | 260,741 | 257,489 | |
Cost of energy | 21,152 | 21,381 | 64,256 | 64,183 | |
Electricity | Corporate and Other | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 0 | 0 | 0 | 0 | |
Cost of energy | $ 0 | $ 0 | $ 0 | $ 0 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | $ 1,761,448 | ||||
Balance, as adjusted | $ 1,761,448 | ||||
Amounts reclassified from AOCI (pre-tax) | 2,297 | $ (5,765) | |||
Income tax impact of amounts reclassified | (584) | 2,237 | |||
Other OCI changes (pre-tax) | 5,303 | 22,024 | |||
Income tax impact of other OCI changes | (1,348) | (8,546) | |||
Total Other Comprehensive Income | $ 2,277 | $ 3,094 | 5,668 | 9,950 | |
Ending balance | 1,836,522 | 1,836,522 | |||
Fair Value Adjustment for Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | 1,153 | (23) | |||
Cumulative effect adjustment (Note 7) | 0 | ||||
Balance, as adjusted | 1,153 | ||||
Amounts reclassified from AOCI (pre-tax) | 102 | 484 | |||
Income tax impact of amounts reclassified | (27) | (187) | |||
Other OCI changes (pre-tax) | 2,431 | (278) | |||
Income tax impact of other OCI changes | (618) | 108 | |||
Total Other Comprehensive Income | 1,888 | 127 | |||
Ending balance | 3,041 | 104 | 3,041 | 104 | |
AOCI | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | (95,940) | (92,451) | |||
Cumulative effect adjustment (Note 7) | (11,208) | ||||
Balance, as adjusted | (107,148) | ||||
Total Other Comprehensive Income | 5,668 | ||||
Ending balance | (101,480) | (82,501) | (101,480) | (82,501) | |
PNM | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | 1,488,369 | ||||
Balance, as adjusted | 1,488,369 | ||||
Amounts reclassified from AOCI (pre-tax) | 2,195 | (6,249) | |||
Income tax impact of amounts reclassified | (557) | 2,424 | |||
Other OCI changes (pre-tax) | 2,872 | 22,302 | |||
Income tax impact of other OCI changes | (730) | (8,654) | |||
Total Other Comprehensive Income | 2,188 | 2,989 | 3,780 | 9,823 | |
Ending balance | 1,602,800 | 1,602,800 | |||
PNM | Unrealized Gains on Available-for-Sale Securities | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | 13,169 | 4,320 | |||
Cumulative effect adjustment (Note 7) | (11,208) | ||||
Balance, as adjusted | 1,961 | ||||
Amounts reclassified from AOCI (pre-tax) | (3,483) | (11,088) | |||
Income tax impact of amounts reclassified | 885 | 4,302 | |||
Other OCI changes (pre-tax) | 2,872 | 22,302 | |||
Income tax impact of other OCI changes | (730) | (8,654) | |||
Total Other Comprehensive Income | (456) | 6,862 | |||
Ending balance | 1,505 | 11,182 | 1,505 | 11,182 | |
PNM | Pension Liability Adjustment | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | (110,262) | (96,748) | |||
Cumulative effect adjustment (Note 7) | 0 | ||||
Balance, as adjusted | (110,262) | ||||
Amounts reclassified from AOCI (pre-tax) | 5,678 | 4,839 | |||
Income tax impact of amounts reclassified | (1,442) | (1,878) | |||
Total Other Comprehensive Income | 4,236 | 2,961 | |||
Ending balance | (106,026) | (93,787) | (106,026) | (93,787) | |
PNM | AOCI | |||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||||
Beginning balance | (97,093) | (92,428) | |||
Cumulative effect adjustment (Note 7) | (11,208) | ||||
Balance, as adjusted | $ (108,301) | ||||
Total Other Comprehensive Income | 3,780 | ||||
Ending balance | $ (104,521) | $ (82,605) | $ (104,521) | $ (82,605) |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Earnings Per Share [Abstract] | ||||
Net Earnings Available for PNM Common Stock | $ 87,521 | $ 73,739 | $ 140,719 | $ 134,156 |
Average Number of Common Shares: | ||||
Outstanding during period (in shares) | 79,654 | 79,654 | 79,654 | 79,654 |
Vested awards of restricted stock (in shares) | 215 | 284 | 210 | 215 |
Average Shares – Basic (in shares) | 79,869 | 79,938 | 79,864 | 79,869 |
Dilutive Effect of Common Stock Equivalents: | ||||
Stock options and restricted stock (in shares) | 111 | 216 | 126 | 263 |
Average Shares – Diluted (in shares) | 79,980 | 80,154 | 79,990 | 80,132 |
Net Earnings Per Share of Common Stock: | ||||
Basic (in dollars per share) | $ 1.10 | $ 0.92 | $ 1.76 | $ 1.68 |
Diluted (in dollars per share) | $ 1.09 | $ 0.92 | $ 1.76 | $ 1.67 |
Electric Operating Revenues - D
Electric Operating Revenues - Disaggregation of revenues (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | $ 400,023 | $ 392,607 | $ 1,042,033 | $ 1,016,384 |
Revenues | 422,666 | 419,900 | 1,092,857 | 1,112,398 |
PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 306,019 | 300,604 | 783,310 | 769,069 |
Revenues | 331,374 | 327,254 | 832,116 | 854,909 |
TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 94,004 | 92,003 | 258,723 | 247,315 |
Revenues | 91,292 | 92,646 | 260,741 | 257,489 |
Residential | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 178,318 | 435,575 | ||
Residential | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 138,091 | 334,767 | ||
Residential | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 40,227 | 100,808 | ||
Commercial | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 150,605 | 399,340 | ||
Commercial | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 121,755 | 315,256 | ||
Commercial | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 28,850 | 84,084 | ||
Industrial | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 22,321 | 58,867 | ||
Industrial | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 17,919 | 45,976 | ||
Industrial | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 4,402 | 12,891 | ||
Public authority | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 8,262 | 20,931 | ||
Public authority | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 6,872 | 16,726 | ||
Public authority | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,390 | 4,205 | ||
Economy energy service | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 6,158 | 19,825 | ||
Economy energy service | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 6,158 | 19,825 | ||
Economy energy service | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 0 | 0 | ||
Transmission | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 30,281 | 90,123 | ||
Transmission | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 13,538 | 40,128 | ||
Transmission | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 16,743 | 49,995 | ||
Miscellaneous | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 4,078 | 17,372 | ||
Miscellaneous | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 1,686 | 10,632 | ||
Miscellaneous | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues from contracts with customers | 2,392 | 6,740 | ||
Alternative revenue programs | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | (8,050) | (1,908) | (1,466) | 11,591 |
Alternative revenue programs | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | (5,338) | (2,551) | (3,484) | 1,417 |
Alternative revenue programs | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | (2,712) | 643 | 2,018 | 10,174 |
Other electric operating revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 30,693 | 29,201 | 52,290 | 84,423 |
Other electric operating revenues | PNM | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 30,693 | $ 29,201 | 52,290 | $ 84,423 |
Other electric operating revenues | TNMP | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 0 | $ 0 |
Electric Operating Revenues - N
Electric Operating Revenues - Narrative (Details) | Sep. 30, 2018USD ($)utilityMW | Dec. 31, 2017USD ($)MW |
Disaggregation of Revenue [Line Items] | ||
Number of regulated utilities | utility | 2 | |
Contract assets | $ | $ 0 | |
PNM | ||
Disaggregation of Revenue [Line Items] | ||
Expected exposure to market risk (in megawatts) | 65 | |
Power to be sold to third party (in megawatts) | 36 | |
Customer contracts | PNM | ||
Disaggregation of Revenue [Line Items] | ||
Accounts receivable | $ | $ 76,900,000 | $ 61,800,000 |
Clean Air Act, SNCR | Palo Verde Nuclear Generating Station Unit 3 | PNM | ||
Disaggregation of Revenue [Line Items] | ||
Number of megawatts nuclear generation (in megawatts) | 134 |
Electric Operating Revenues - C
Electric Operating Revenues - Changes in contract liabilities (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | $ 349 |
Consideration received in advance of service to be provided | 5,686 |
Deferred revenue earned | (4,438) |
Ending balance | 1,597 |
PNM | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 349 |
Consideration received in advance of service to be provided | 4,174 |
Deferred revenue earned | (3,304) |
Ending balance | 1,219 |
TNMP | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 0 |
Consideration received in advance of service to be provided | 1,512 |
Deferred revenue earned | (1,134) |
Ending balance | $ 378 |
Variable Interest Entities (Det
Variable Interest Entities (Details) | Feb. 01, 2016USD ($) | Sep. 30, 2018USD ($)MW | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)MW | Sep. 30, 2017USD ($) | May 22, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 31, 2016USD ($) |
Results of Operations | ||||||||
Earnings attributable to non-controlling interest | $ 3,920,000 | $ 4,456,000 | $ 11,706,000 | $ 11,452,000 | ||||
Financial Position | ||||||||
Current assets | 363,925,000 | 363,925,000 | $ 294,420,000 | |||||
Total assets | 6,848,995,000 | 6,697,254,000 | 6,848,995,000 | 6,697,254,000 | 6,646,103,000 | |||
Current liabilities | 980,475,000 | 980,475,000 | 835,644,000 | |||||
Owners’ equity – non-controlling interest | 65,224,000 | 65,224,000 | 66,195,000 | |||||
PNM | ||||||||
Results of Operations | ||||||||
Earnings attributable to non-controlling interest | 3,920,000 | 4,456,000 | 11,706,000 | 11,452,000 | ||||
Financial Position | ||||||||
Current assets | 311,338,000 | 311,338,000 | 243,631,000 | |||||
Total assets | 5,042,761,000 | 5,042,761,000 | 4,921,563,000 | |||||
Current liabilities | 353,096,000 | 353,096,000 | 218,496,000 | |||||
Owners’ equity – non-controlling interest | 65,224,000 | 65,224,000 | 66,195,000 | |||||
PNM | Valencia | ||||||||
Variable Interest Entity [Line Items] | ||||||||
Payment for fixed costs | 4,900,000 | 4,900,000 | 14,700,000 | 14,700,000 | ||||
Payment for variable costs | 500,000 | 900,000 | $ 1,400,000 | 1,200,000 | ||||
Long-term contract option to purchase, ownership percentage (up to) | 50.00% | |||||||
Long-term contract option to purchase, purchase price - percentage of adjusted NBV | 50.00% | |||||||
Long-term contract option to purchase, purchase price - percentage of FMV | 50.00% | |||||||
Results of Operations | ||||||||
Operating revenues | 5,368,000 | 5,859,000 | $ 16,047,000 | 15,880,000 | ||||
Operating expenses | (1,448,000) | (1,403,000) | (4,341,000) | (4,428,000) | ||||
Earnings attributable to non-controlling interest | 3,920,000 | $ 4,456,000 | 11,706,000 | $ 11,452,000 | ||||
Financial Position | ||||||||
Current assets | 3,449,000 | 3,449,000 | 2,688,000 | |||||
Net property, plant, and equipment | 62,698,000 | 62,698,000 | 64,109,000 | |||||
Total assets | 66,147,000 | 66,147,000 | 66,797,000 | |||||
Current liabilities | 923,000 | 923,000 | 602,000 | |||||
Owners’ equity – non-controlling interest | $ 65,224,000 | $ 65,224,000 | $ 66,195,000 | |||||
PNM | Valencia | Purchased through May 2028 | ||||||||
Variable Interest Entity [Line Items] | ||||||||
Number of megawatts purchased (in megawatts) | MW | 158 | 158 | ||||||
NM Capital | San Juan Generating Station | Coal supply | ||||||||
Variable Interest Entity [Line Items] | ||||||||
Loan agreement among several entities | $ 125,000,000 | |||||||
Cash used to support bank letter or credit arrangement | $ 30,300,000 | $ 30,300,000 | $ 30,300,000 | |||||
NM Capital | San Juan Coal Company, Westmoreland | Coal supply | ||||||||
Variable Interest Entity [Line Items] | ||||||||
Repayment of line of credit | $ 50,100,000 |
Fair Value of Derivative and _3
Fair Value of Derivative and Other Financial Instruments - Overview and Commodity Derivatives (Details) | Sep. 30, 2018USD ($)MW | Dec. 31, 2017USD ($) |
Derivatives, Fair Value [Line Items] | ||
Current assets | $ 1,083,000 | $ 1,088,000 |
Deferred charges | 2,741,000 | 3,556,000 |
Current liabilities | (1,092,000) | (1,182,000) |
Long-term liabilities | (2,741,000) | (3,556,000) |
Obligations to return cash | $ 1,000,000 | 900,000 |
PNM | ||
Derivatives, Fair Value [Line Items] | ||
Expected exposure to market risk (in megawatts) | MW | 65 | |
Power to be sold to third party (in megawatts) | MW | 36 | |
Current assets | $ 1,083,000 | 1,088,000 |
Deferred charges | 2,741,000 | 3,556,000 |
Current liabilities | (1,092,000) | (1,182,000) |
Long-term liabilities | (2,741,000) | (3,556,000) |
Amounts recognized for right to reclaim cash | 0 | 0 |
Cash collateral under margin arrangements | 500,000 | 800,000 |
PNM | Designated as Hedging Instrument | Commodity derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 1,083,000 | 1,088,000 |
Deferred charges | 2,741,000 | 3,556,000 |
Derivative Asset | 3,824,000 | 4,644,000 |
Current liabilities | (1,092,000) | (1,182,000) |
Long-term liabilities | (2,741,000) | (3,556,000) |
Derivative Liability | (3,833,000) | (4,738,000) |
Net | (9,000) | (94,000) |
PNM | Designated as Hedging Instrument | Commodity derivatives | Fuel and purchased power costs | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 0 | |
PNM | Designated as Hedging Instrument | Commodity derivatives | Hazard sharing arrangement | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset | $ 3,800,000 | $ 4,600,000 |
Fair Value of Derivative and _4
Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNM - Designated as Hedging Instrument - Commodity derivatives - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain | $ 0 | $ (2,251) | $ 2 | $ 408 |
Electric operating revenues | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain | (93) | (2,237) | (95) | 5,697 |
Cost of energy | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain | $ 93 | $ (14) | $ 97 | $ (5,289) |
Fair Value of Derivative and _5
Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018USD ($)MMBTUMWh | Dec. 31, 2017USD ($)MMBTUMWh | |
Derivative [Line Items] | ||
Contract in a liability position | $ | $ 0 | $ 0 |
PNM | Commodity derivatives | Fair value hedging | Buy | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MMBTU | 100,000 | 100,000 |
PNM | Commodity derivatives | Fair value hedging | Sell | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MWh | 4,800 | 0 |
Fair Value of Derivative and _6
Fair Value of Derivative and Other Financial Instruments - Investments in NDT (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Equity securities: | ||
Net gains from equity securities sold | $ 113 | $ 5,443 |
Net gains from equity securities still held | 2,943 | 2,636 |
Total net gains on equity securities | 3,056 | 8,079 |
Available-for-sale debt securities: | ||
Net (losses) on debt securities | (593) | (6,998) |
Net gains on investment securities | $ 2,463 | $ 1,081 |
Fair Value of Derivative and _7
Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Jan. 01, 2018 | Dec. 31, 2017 | |
Debt Securities, Available-for-sale [Line Items] | ||||||
Available-for-sale debt securities, fair value | $ 0 | $ 0 | ||||
Other than temporary impairments | 0 | |||||
PNM | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
(Increase)/decrease in other than temporary losses of available-for-sale securities, net portion recognized in earnings | (800,000) | $ 100,000 | (4,600,000) | $ 1,100,000 | ||
Proceeds from sales | 117,801,000 | 98,532,000 | 911,899,000 | 456,577,000 | ||
Gross realized gains | 3,460,000 | 8,128,000 | 17,030,000 | 24,745,000 | ||
Gross realized (losses) | (3,149,000) | $ (2,829,000) | (14,018,000) | $ (8,150,000) | ||
Nuclear Decommissioning Trust | Recurring | PNM | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
Available-for-sale securities | 298,400,000 | 298,400,000 | $ 293,700,000 | |||
Mine Reclamation Trust | Recurring | PNM | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
Available-for-sale securities | $ 33,300,000 | $ 33,300,000 | 29,800,000 | |||
Retained Earnings | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
Cumulative effect adjustment (Note 7) | 11,208,000 | |||||
Retained Earnings | PNM | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
Cumulative effect adjustment (Note 7) | $ 11,208,000 | |||||
Accounting Standards Update 2016-01 | Retained Earnings | ||||||
Debt Securities, Available-for-sale [Line Items] | ||||||
Cumulative effect adjustment (Note 7) | $ 11,200,000 |
Fair Value of Derivative and _8
Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) - PNMR and PNM $ in Thousands | Sep. 30, 2018USD ($) |
Available-for-Sale | |
Within 1 year | $ 9,986 |
After 1 year through 5 years | 59,944 |
After 5 years through 10 years | 67,585 |
After 10 years through 15 years | 10,375 |
After 15 years through 20 years | 11,151 |
After 20 years | 46,887 |
Available-for-sale debt securities | $ 205,928 |
Fair Value of Derivative and _9
Fair Value of Derivative and Other Financial Instruments - Items Recorded and Presented by Level of Hierarchy (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Transfers between levels | $ 0 | $ 0 | ||
Long-term debt | $ 2,642,154,000 | 2,642,154,000 | 2,554,836,000 | |
Westmoreland Loan | 66,588,000 | |||
Other investments | 348,000 | 348,000 | 503,000 | |
Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Westmoreland Loan | 0 | |||
Other investments | 348,000 | 348,000 | 503,000 | |
Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 2,642,154,000 | 2,642,154,000 | 2,554,836,000 | |
Westmoreland Loan | 0 | |||
Other investments | 0 | 0 | 0 | |
Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Westmoreland Loan | 66,588,000 | |||
Other investments | 0 | 0 | 0 | |
Carrying Amount | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 2,614,511,000 | 2,614,511,000 | 2,437,645,000 | |
Westmoreland Loan | 56,640,000 | |||
Other investments | 348,000 | 348,000 | 503,000 | |
PNM | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 1,665,064,000 | 1,665,064,000 | 1,727,135,000 | |
Other investments | 142,000 | 142,000 | 283,000 | |
PNM | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Other investments | 142,000 | 142,000 | 283,000 | |
PNM | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 1,665,064,000 | 1,665,064,000 | 1,727,135,000 | |
Other investments | 0 | 0 | 0 | |
PNM | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Other investments | 0 | 0 | 0 | |
PNM | Carrying Amount | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 1,656,102,000 | 1,656,102,000 | 1,657,910,000 | |
Other investments | 142,000 | 142,000 | 283,000 | |
TNMP | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 580,017,000 | 580,017,000 | 527,563,000 | |
Other investments | 206,000 | 206,000 | 220,000 | |
TNMP | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Other investments | 206,000 | 206,000 | 220,000 | |
TNMP | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 580,017,000 | 580,017,000 | 527,563,000 | |
Other investments | 0 | 0 | 0 | |
TNMP | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 0 | 0 | 0 | |
Other investments | 0 | 0 | 0 | |
TNMP | Carrying Amount | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt | 560,293,000 | 560,293,000 | 480,620,000 | |
Other investments | 206,000 | 206,000 | 220,000 | |
Recurring | PNM | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 331,746,000 | 331,746,000 | 323,524,000 | |
Recurring | PNM | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 135,566,000 | 135,566,000 | 204,101,000 | |
Recurring | PNM | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 193,126,000 | 193,126,000 | 119,423,000 | |
Recurring | PNM | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 3,054,000 | 3,054,000 | 0 | |
Investments, unrealized gain | 2,018,000 | $ 18,028,000 | ||
Recurring | PNM | Commodity derivatives | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Commodity derivative assets | 3,824,000 | 3,824,000 | 4,644,000 | |
Commodity derivative liabilities | (3,833,000) | (3,833,000) | (4,738,000) | |
Net | (9,000) | (9,000) | (94,000) | |
Recurring | PNM | Commodity derivatives | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Commodity derivative assets | 0 | 0 | 0 | |
Commodity derivative liabilities | 0 | 0 | 0 | |
Net | 0 | 0 | 0 | |
Recurring | PNM | Commodity derivatives | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Commodity derivative assets | 3,824,000 | 3,824,000 | 4,644,000 | |
Commodity derivative liabilities | (3,833,000) | (3,833,000) | (4,738,000) | |
Net | (9,000) | (9,000) | (94,000) | |
Recurring | PNM | Commodity derivatives | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Commodity derivative assets | 0 | 0 | 0 | |
Commodity derivative liabilities | 0 | 0 | 0 | |
Net | 0 | 0 | 0 | |
Recurring | PNM | Cash and cash equivalents | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash and cash equivalents | 3,527,000 | 3,527,000 | 52,636,000 | |
Recurring | PNM | Cash and cash equivalents | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash and cash equivalents | 3,527,000 | 3,527,000 | 52,636,000 | |
Recurring | PNM | Cash and cash equivalents | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash and cash equivalents | 0 | 0 | 0 | |
Recurring | PNM | Cash and cash equivalents | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash and cash equivalents | 0 | 0 | 0 | |
Recurring | PNM | Corporate stocks, common | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 40,017,000 | 40,017,000 | ||
Recurring | PNM | Corporate stocks, common | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 40,017,000 | 40,017,000 | ||
Recurring | PNM | Corporate stocks, common | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | 0 | ||
Recurring | PNM | Corporate stocks, common | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | 0 | ||
Recurring | PNM | Corporate stocks, preferred | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 7,239,000 | 7,239,000 | ||
Recurring | PNM | Corporate stocks, preferred | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 1,587,000 | 1,587,000 | ||
Recurring | PNM | Corporate stocks, preferred | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 5,652,000 | 5,652,000 | ||
Recurring | PNM | Corporate stocks, preferred | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | 0 | ||
Recurring | PNM | Mutual funds and other | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 75,035,000 | 75,035,000 | ||
Recurring | PNM | Mutual funds and other | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 75,035,000 | 75,035,000 | ||
Recurring | PNM | Mutual funds and other | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | 0 | ||
Recurring | PNM | Mutual funds and other | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | 0 | ||
Recurring | PNM | Domestic value | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 40,032,000 | |||
Recurring | PNM | Domestic value | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 40,032,000 | |||
Recurring | PNM | Domestic value | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | |||
Recurring | PNM | Domestic value | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | |||
Investments, unrealized gain | 4,011,000 | |||
Recurring | PNM | Domestic growth | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 35,456,000 | |||
Recurring | PNM | Domestic growth | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 35,456,000 | |||
Recurring | PNM | Domestic growth | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | |||
Recurring | PNM | Domestic growth | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | |||
Investments, unrealized gain | 3,995,000 | |||
Recurring | PNM | International and other | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 45,867,000 | |||
Recurring | PNM | International and other | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 42,332,000 | |||
Recurring | PNM | International and other | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 3,535,000 | |||
Recurring | PNM | International and other | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Equity securities | 0 | |||
Investments, unrealized gain | 6,810,000 | |||
Recurring | PNM | U.S. Government | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 25,689,000 | 25,689,000 | 34,317,000 | |
Recurring | PNM | U.S. Government | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 15,400,000 | 15,400,000 | 33,645,000 | |
Recurring | PNM | U.S. Government | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 10,289,000 | 10,289,000 | 672,000 | |
Recurring | PNM | U.S. Government | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | 0 | |
Investments, unrealized gain | 23,000 | 273,000 | ||
Recurring | PNM | International Government | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 8,460,000 | 8,460,000 | ||
Recurring | PNM | International Government | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | ||
Recurring | PNM | International Government | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 8,460,000 | 8,460,000 | ||
Recurring | PNM | International Government | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | ||
Investments, unrealized gain | 90,000 | |||
Recurring | PNM | Municipals | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 51,280,000 | 51,280,000 | 48,076,000 | |
Recurring | PNM | Municipals | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | 0 | |
Recurring | PNM | Municipals | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 51,280,000 | 51,280,000 | 48,076,000 | |
Recurring | PNM | Municipals | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | 0 | |
Investments, unrealized gain | 78,000 | 1,225,000 | ||
Recurring | PNM | Corporate and other | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 120,499,000 | 120,499,000 | 67,140,000 | |
Recurring | PNM | Corporate and other | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 0 | 0 | 0 | |
Recurring | PNM | Corporate and other | Level 2 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 117,445,000 | 117,445,000 | 67,140,000 | |
Recurring | PNM | Corporate and other | Level 3 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Available-for-sale debt securities | 3,054,000 | $ 3,054,000 | $ 0 | |
Investments, unrealized gain | $ 1,827,000 | $ 1,714,000 |
Fair Value of Derivative and_10
Fair Value of Derivative and Other Financial Instruments - Reconciliation of changes in Level 3 fair value measurements (Details) - Corporate Debt - Level 3 $ in Thousands | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Beginning balance | $ 0 |
Actual return on assets sold during the period | (6) |
Actual return on assets still held at period end | 16 |
Purchases | 5,234 |
Sales | (2,190) |
Ending balance | $ 3,054 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) | Mar. 02, 2018 | Mar. 03, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Feb. 28, 2018 | Feb. 28, 2017 | Mar. 31, 2015 | Jan. 01, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Vesting period | 1 year | ||||||||
Unrecognized expense related to stock awards | $ 4,400,000 | $ 3,800,000 | |||||||
Restricted Stock, Shares | |||||||||
Expired (in shares) | 0 | ||||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | |||||||||
Expired (in dollars per share) | $ 0 | ||||||||
Stock Options, Shares | |||||||||
Outstanding at beginning of period (in shares) | 193,441 | ||||||||
Granted (in shares) | 0 | ||||||||
Exercised (in shares) | (109,441) | ||||||||
Forfeited (in shares) | 0 | ||||||||
Expired (in shares) | 0 | ||||||||
Outstanding at end of period (in shares) | 84,000 | 193,441 | |||||||
Stock Options, Weighted- Average Exercise Price | |||||||||
Outstanding at beginning of period (in dollars per share) | $ 9.98 | ||||||||
Granted (in dollars per share) | 0 | ||||||||
Exercised (in dollars per share) | 8.56 | ||||||||
Forfeited (in dollars per share) | 0 | ||||||||
Expired (in dollars per share) | 0 | ||||||||
Outstanding at end of period (in dollars per share) | 11.82 | $ 9.98 | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||||||||
Weighted-average grant date fair value of options granted (in dollars per share) | $ 0 | $ 0 | |||||||
Total fair value of options that vested | $ 0 | $ 0 | |||||||
Total intrinsic value of options exercised | $ 3,016,000 | $ 2,234,000 | |||||||
Executive Vice President and Chief Financial Officer | Common Stock | Achieved performance target for 2015 and 2016 | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Value of stock awarded | $ 100,000 | ||||||||
Number of shares available for grant | 275,000 | 100,000 | |||||||
Restricted Stock, Shares | |||||||||
Granted (in shares) | 7,670 | 2,754 | |||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | |||||||||
Granted (in dollars per share) | $ 35.85 | $ 36.30 | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||||||||
Weighted-average grant date fair value (in dollars per share) | $ 35.85 | $ 36.30 | |||||||
Executive Vice President and Chief Financial Officer | Common Stock | Achieved performance target for 2015, 2016 and 2017 | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Value of stock awarded | $ 275,000 | ||||||||
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2019 and she remains an employee | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 53,859 | ||||||||
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2017 and she remains an employee | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 17,953 | ||||||||
Restricted Shares and Performance Based Shares | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Period of time stock expense is expected to be recognized | 1 year 7 months 20 days | 1 year 6 months 11 days | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||||||||
Expected quarterly dividends per share (in dollars per share) | $ 0.2650 | $ 0.2425 | |||||||
Risk-free interest rate | 2.38% | 1.50% | |||||||
Restricted Stock | |||||||||
Restricted Stock, Shares | |||||||||
Outstanding at beginning of period (in shares) | 189,045 | ||||||||
Granted (in shares) | 221,062 | ||||||||
Exercised (in shares) | (235,868) | ||||||||
Forfeited (in shares) | (6,054) | ||||||||
Expired (in shares) | 0 | ||||||||
Outstanding at end of period (in shares) | 168,185 | 189,045 | |||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | |||||||||
Outstanding at beginning of period (in dollars per share) | $ 31.11 | ||||||||
Granted (in dollars per share) | 29.65 | $ 23.06 | |||||||
Exercised (in dollars per share) | 28.44 | ||||||||
Forfeited (in dollars per share) | 31.37 | ||||||||
Expired (in dollars per share) | 0 | ||||||||
Outstanding at end of period (in dollars per share) | $ 32.93 | $ 31.11 | |||||||
Stock Options, Shares | |||||||||
Expired (in shares) | 0 | ||||||||
Stock Options, Weighted- Average Exercise Price | |||||||||
Expired (in dollars per share) | $ 0 | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||||||||
Weighted-average grant date fair value (in dollars per share) | $ 29.65 | $ 23.06 | |||||||
Total fair value of restricted shares that vested | $ 8,493,000 | $ 5,666,000 | |||||||
Performance Shares | Executive | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Shares granted (in shares) | 97,697 | ||||||||
Weighted percentage assigned to achieving market targets | 60.00% | ||||||||
Weighted percentage assigned to achieving performance targets | 40.00% | ||||||||
Maximum number of shares awarded in year 1 (in shares) | 132,729 | ||||||||
Maximum number of shares awarded in year 2 (in shares) | 130,302 | ||||||||
Maximum number of shares awarded in year 3 (in shares) | 146,941 | ||||||||
Performance period | 3 years | ||||||||
Market-Based Shares | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||||||||
Risk-free interest rate | 2.36% | 1.54% | |||||||
Dividend yield | 2.96% | 2.67% | |||||||
Expected volatility | 19.12% | 20.80% | |||||||
Stock options | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Aggregate intrinsic value of stock options outstanding | $ 2,300,000 | ||||||||
Weighted-average remaining contract life | 1 year 3 months 4 days | ||||||||
Number of outstanding stock options with an exercise price greater than the closing price (in shares) | 0 | ||||||||
Performance Equity Plan | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||||
Vesting period | 3 years | ||||||||
Vesting rate | 100.00% |
Financing - Financing Activitie
Financing - Financing Activities (Details) - USD ($) | Apr. 09, 2018 | Jul. 28, 2017 | Feb. 01, 2016 | Jul. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Jul. 25, 2018 | Jun. 28, 2018 | May 22, 2018 | May 14, 2018 | Mar. 09, 2018 | Dec. 31, 2017 | Jul. 20, 2017 | Oct. 21, 2016 | Mar. 09, 2015 |
Debt Instrument [Line Items] | |||||||||||||||||
Interest Charges | $ 30,492,000 | $ 32,106,000 | $ 96,868,000 | $ 96,137,000 | |||||||||||||
Other deferred credits | 127,612,000 | $ 127,612,000 | $ 131,706,000 | ||||||||||||||
PNMR 2016 One Year Term Loan | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Term of loan | 1 year | 1 year | |||||||||||||||
PNMR 2016 Two-Year Term Loan | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Term of loan | 2 years | 2 years | |||||||||||||||
Term loans | $ 100,000,000 | $ 100,000,000 | |||||||||||||||
Variable interest rate | 3.03% | 3.03% | |||||||||||||||
PNM | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Interest Charges | $ 18,063,000 | 20,451,000 | $ 58,881,000 | 62,393,000 | |||||||||||||
Other deferred credits | 171,345,000 | $ 171,345,000 | 106,442,000 | ||||||||||||||
PNM | Maximum | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Maturity term over which financings require regulator approval (more than) | 18 months | ||||||||||||||||
NM Capital | Coal supply | San Juan Coal Company, Westmoreland | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Repayment of line of credit | $ 50,100,000 | ||||||||||||||||
Payments to fund long-term loans to unaffiliated third party | $ 125,000,000 | ||||||||||||||||
Texas-New Mexico Power Company | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Interest Charges | 8,241,000 | $ 7,704,000 | $ 23,771,000 | $ 22,619,000 | |||||||||||||
Other deferred credits | 6,692,000 | 6,692,000 | 7,448,000 | ||||||||||||||
Repayments from transmission interconnection arrangement | 4,100,000 | $ 4,100,000 | $ 0 | ||||||||||||||
Line of credit | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Ratio of debt to capital (less than or equal to) | 70.00% | 65.00% | |||||||||||||||
BTMU Term Loan Agreement | NM Capital | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Repayment of line of credit | 125,000,000 | $ 43,000,000 | |||||||||||||||
Term loans | $ 125,000,000 | ||||||||||||||||
Letter of credit | PNMR | JPM LOC Facility | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 30,300,000 | ||||||||||||||||
Senior Unsecured Notes | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 300,000,000 | ||||||||||||||||
Stated interest rate | 3.25% | ||||||||||||||||
Senior Unsecured Notes | PNM | Senior Unsecured Note Agreement (SUNs) | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 450,000,000 | 450,000,000 | $ 450,000,000 | ||||||||||||||
Debt-to-Capital ratio | 65.00% | ||||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 350,000,000 | ||||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018 | Plan | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | 350,000,000 | 350,000,000 | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018 | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 100,000,000 | ||||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018 | Plan | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | 100,000,000 | 100,000,000 | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.15% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 55,000,000 | $ 55,000,000 | |||||||||||||||
Stated interest rate | 3.15% | 3.15% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.45% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 104,000,000 | $ 104,000,000 | |||||||||||||||
Stated interest rate | 3.45% | 3.45% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.68% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 88,000,000 | $ 88,000,000 | |||||||||||||||
Stated interest rate | 3.68% | 3.68% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.93% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 38,000,000 | $ 38,000,000 | |||||||||||||||
Stated interest rate | 3.93% | 3.93% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 4.22% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 45,000,000 | $ 45,000,000 | |||||||||||||||
Stated interest rate | 4.22% | 4.22% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 4.50% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 20,000,000 | $ 20,000,000 | |||||||||||||||
Stated interest rate | 4.50% | 4.50% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018, Interest rate of 3.78% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 15,000,000 | $ 15,000,000 | |||||||||||||||
Stated interest rate | 3.78% | 3.78% | |||||||||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018, Interest rate of 4.60% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 85,000,000 | $ 85,000,000 | |||||||||||||||
Stated interest rate | 4.60% | 4.60% | |||||||||||||||
PNMR 2015 Term Loan Agreement | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Term loans | $ 150,000,000 | ||||||||||||||||
Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 172,300,000 | $ 172,300,000 | $ 60,000,000 | ||||||||||||||
Stated interest rate | 2.94% | 3.85% | |||||||||||||||
TNMP Term Loan Agreement | Texas-New Mexico Power Company | TNMP Term Loan Agreement | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 20,000,000 | ||||||||||||||||
PNM 2017 Term Loan Agreement | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Interest rate at period end | 2.98% | 2.98% | |||||||||||||||
Term loan agreement with banks | PNM | PNM 2017 Term Loan Agreement | JPMorgan Chase Bank, N.A. and U.S. Bank National Association | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 200,000,000 | ||||||||||||||||
Term loan agreement with banks | Texas-New Mexico Power Company | TNMP Term Loan Agreement | JPMorgan Chase Bank, N.A. and U.S. Bank National Association | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Aggregate principal amount | $ 20,000,000 | ||||||||||||||||
Unsecured debt | PNM | Senior Unsecured Notes, Maturity in May 2018, 7.95% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Stated interest rate | 7.95% | ||||||||||||||||
Unsecured debt | PNM | Senior Unsecured Notes, Maturity in August 2018, 7.50% | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Stated interest rate | 7.50% | 7.50% | |||||||||||||||
Deposit Related To Potential Transmission Interconnections | PNMR Development | |||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||
Amount of related party transaction | $ 68,200,000 | ||||||||||||||||
Interest Charges | $ 800,000 | $ 1,500,000 | |||||||||||||||
Other deferred credits | $ 68,200,000 |
Financing - Short-term Debt and
Financing - Short-term Debt and Liquidity (Details) | Sep. 26, 2018Extension | Jul. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($)derivative | Nov. 01, 2020USD ($) | Oct. 30, 2018USD ($) | Jul. 25, 2018 | Jun. 28, 2018USD ($) | Mar. 09, 2018USD ($) | Feb. 26, 2018USD ($) | Jul. 20, 2017USD ($) | Dec. 21, 2016USD ($) |
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | $ 262,600,000 | $ 305,400,000 | ||||||||||
Letters of credit outstanding | 4,700,000 | |||||||||||
Senior Unsecured Notes | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Debt issued | $ 300,000,000 | |||||||||||
Stated interest rate | 3.25% | |||||||||||
Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | $ 653,700,000 | |||||||||||
PNMR | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | 168,800,000 | |||||||||||
Consolidated invested cash | 900,000 | |||||||||||
PNMR Development Revolving Credit Facility | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | 24,500,000 | 0 | ||||||||||
PNMR 2016 One-Year Term Loan (as extended) | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | $ 100,000,000 | $ 100,000,000 | $ 100,000,000 | |||||||||
Weighted-average interest rate for short-term debt | 3.02% | |||||||||||
Term of loan | 1 year | 1 year | ||||||||||
Variable Rate Short-Term Debt | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Term of derivatives | 4 years | |||||||||||
Debt issued | $ 50,000,000 | |||||||||||
PNMR 2016 Two-Year Term Loan | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | $ 100,000,000 | |||||||||||
Term of loan | 2 years | 2 years | ||||||||||
PNMR Revolving Credit Facility | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | $ 10,000,000 | |||||||||||
Number of extensions | Extension | 2 | |||||||||||
Lease term extension period | 1 year | |||||||||||
PNMR Revolving Credit Facility | PNMR | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Weighted-average interest rate for short-term debt | 3.34% | |||||||||||
PNMR Revolving Credit Facility | Forecast | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | $ 290,000,000 | |||||||||||
TNMP Revolving Credit Facility | PNMR | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Weighted-average interest rate for short-term debt | 2.99% | |||||||||||
PNMR Development Revolving Credit Facility | PNMR | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Weighted-average interest rate for short-term debt | 3.07% | |||||||||||
PNM | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | $ 0 | 39,800,000 | ||||||||||
Letters of credit outstanding | 2,500,000 | |||||||||||
PNM | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | 397,500,000 | |||||||||||
Consolidated invested cash | 55,300,000 | |||||||||||
PNM | Lines of credit | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
NMPRC approved credit facility | 40,000,000 | |||||||||||
Short-term debt | $ 0 | 0 | ||||||||||
PNM | Lines of credit | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | 40,000,000 | |||||||||||
PNM | SUNs, Issuance in August 2018 | Senior Unsecured Notes | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Debt issued | $ 100,000,000 | |||||||||||
PNM | Senior Unsecured Notes, Due 2018, at 7 point 50 percent | Unsecured debt | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Stated interest rate | 7.50% | |||||||||||
PNM | Plan | SUNs, Issuance in August 2018 | Senior Unsecured Notes | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Debt issued | $ 100,000,000 | |||||||||||
PNM | PNM Revolving Credit Facility | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | 40,000,000 | |||||||||||
PNM | PNM Revolving Credit Facility | Forecast | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | $ 360,000,000 | |||||||||||
TNMP | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt | 17,500,000 | 0 | ||||||||||
Letters of credit outstanding | 100,000 | |||||||||||
Short-term debt – affiliate | 4,100,000 | 0 | ||||||||||
TNMP | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | 47,400,000 | |||||||||||
Consolidated invested cash | 0 | |||||||||||
TNMP | First Mortgage Bonds | Mortgages | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Debt issued | 172,300,000 | $ 60,000,000 | ||||||||||
Stated interest rate | 2.94% | 3.85% | ||||||||||
PNMR Development | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Remaining borrowing capacity | 0 | |||||||||||
PNMR Development | PNMR 2018 Revolving Credit Facility | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | $ 24,500,000 | |||||||||||
Revolving credit facility | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | 300,000,000 | |||||||||||
Short-term debt | 120,600,000 | 165,600,000 | ||||||||||
Revolving credit facility | PNM | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | 400,000,000 | |||||||||||
Short-term debt | 0 | 39,800,000 | ||||||||||
Revolving credit facility | TNMP | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Financing capacity | 75,000,000 | |||||||||||
Short-term debt | 17,500,000 | $ 0 | ||||||||||
Revolving credit facility | TNMP | First mortgage bonds | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Collateral amount | 75,000,000 | |||||||||||
Affiliated entity | PNM | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt – affiliate | 0 | |||||||||||
Affiliated entity | TNMP | Subsequent event | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Short-term debt – affiliate | $ 5,400,000 | |||||||||||
Interest rate contract | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Number of derivatives | derivative | 3 | |||||||||||
Interest rate 1 | Variable Rate Short-Term Debt | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Fixed interest rate | 1.926% | |||||||||||
Interest rate 2 | Variable Rate Short-Term Debt | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Fixed interest rate | 1.823% | |||||||||||
Interest rate 3 | Variable Rate Short-Term Debt | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Fixed interest rate | 1.629% | |||||||||||
Interest rate 3 | Level 2 | Cash Flow Hedge | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Fair value gain (loss) | $ 4,000,000 | $ 1,400,000 | ||||||||||
JPMorgan Chase Bank, N.A. and U.S. Bank National Association | PNM | PNM 2017 Term Loan Agreement | Term loan agreement with banks | ||||||||||||
Short-term Debt [Line Items] | ||||||||||||
Debt issued | $ 200,000,000 |
Pension and Other Postretirem_3
Pension and Other Postretirement Benefit Plans (Details) - USD ($) | 3 Months Ended | 6 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Other (deductions) | $ 2,624,000 | $ 6,709,000 | $ 9,867,000 | $ 17,372,000 | |
Other income | 3,735,000 | 6,275,000 | 12,000,000 | 14,626,000 | |
PNM | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other (deductions) | 2,085,000 | 4,964,000 | 7,314,000 | 14,490,000 | |
Other income | 2,137,000 | 3,762,000 | 6,821,000 | 10,270,000 | |
PNM | Pension Plan | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 0 | 0 | 0 | 0 | |
Interest cost | 6,068,000 | 6,727,000 | 18,203,000 | 20,181,000 | |
Expected return on plan assets | (8,672,000) | (8,451,000) | (26,014,000) | (25,352,000) | |
Amortization of net (gain) loss | 4,087,000 | 4,001,000 | 12,261,000 | 12,004,000 | |
Amortization of prior service cost | (241,000) | (241,000) | (724,000) | (724,000) | |
Net Periodic Benefit Cost | 1,242,000 | 2,036,000 | 3,726,000 | 6,109,000 | |
Contributions by employer | 0 | 0 | |||
Total expected employer contributions for future fiscal years | 0 | 0 | |||
Expected employer contributions in year 5 | 5,500,000 | $ 5,500,000 | |||
PNM | Pension Plan | Minimum | |||||
Components of Net Periodic Benefit Cost | |||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.00% | ||||
PNM | Pension Plan | Maximum | |||||
Components of Net Periodic Benefit Cost | |||||
Assumptions used calculating net periodic benefit cost, discount rate | 5.10% | ||||
PNM | OPEB Plan | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 21,000 | 24,000 | $ 62,000 | 72,000 | |
Interest cost | 860,000 | 1,006,000 | 2,579,000 | 3,019,000 | |
Expected return on plan assets | (1,353,000) | (1,308,000) | (4,061,000) | (3,923,000) | |
Amortization of net (gain) loss | 588,000 | 921,000 | 1,765,000 | 2,762,000 | |
Amortization of prior service cost | (416,000) | (416,000) | (1,248,000) | (1,248,000) | |
Net Periodic Benefit Cost | (300,000) | 227,000 | (903,000) | 682,000 | |
Contributions by employer | 0 | 0 | |||
PNM | Executive Retirement Program | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 0 | 0 | 0 | 0 | |
Interest cost | 155,000 | 174,000 | 467,000 | 523,000 | |
Expected return on plan assets | 0 | 0 | 0 | 0 | |
Amortization of net (gain) loss | 90,000 | 78,000 | 269,000 | 235,000 | |
Amortization of prior service cost | 0 | 0 | 0 | 0 | |
Net Periodic Benefit Cost | 245,000 | 252,000 | 736,000 | 758,000 | |
Contributions by employer | 400,000 | 400,000 | 1,300,000 | 1,200,000 | |
Total expected employer contributions for fiscal year | 1,600,000 | 1,600,000 | |||
Estimated employer contributions in Year 2-5 | 5,700,000 | 5,700,000 | |||
TNMP | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other (deductions) | 149,000 | 1,030,000 | 1,209,000 | 1,229,000 | |
Other income | 1,300,000 | 2,258,000 | 4,276,000 | 3,621,000 | |
TNMP | Pension Plan | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 0 | 0 | 0 | 0 | |
Interest cost | 656,000 | 722,000 | 1,969,000 | 2,165,000 | |
Expected return on plan assets | (991,000) | (945,000) | (2,972,000) | (2,834,000) | |
Amortization of net (gain) loss | 272,000 | 231,000 | 816,000 | 692,000 | |
Amortization of prior service cost | 0 | 0 | 0 | 0 | |
Net Periodic Benefit Cost | (63,000) | 8,000 | (187,000) | 23,000 | |
Contributions by employer | 0 | 0 | |||
Estimated employer contributions in Year 2-5 | 0 | $ 0 | |||
TNMP | Pension Plan | Minimum | |||||
Components of Net Periodic Benefit Cost | |||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.00% | ||||
TNMP | Pension Plan | Maximum | |||||
Components of Net Periodic Benefit Cost | |||||
Assumptions used calculating net periodic benefit cost, discount rate | 5.10% | ||||
TNMP | OPEB Plan | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 33,000 | 36,000 | $ 100,000 | 107,000 | |
Interest cost | 119,000 | 139,000 | 358,000 | 417,000 | |
Expected return on plan assets | (135,000) | (114,000) | (406,000) | (342,000) | |
Amortization of net (gain) loss | (56,000) | (20,000) | (170,000) | (60,000) | |
Amortization of prior service cost | 0 | 0 | 0 | 0 | |
Net Periodic Benefit Cost | (39,000) | 41,000 | (118,000) | 122,000 | |
Contributions by employer | 0 | 0 | 300,000 | 700,000 | |
Estimated employer contributions in Year 2-5 | 1,400,000 | 1,400,000 | |||
TNMP | Executive Retirement Program | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 0 | 0 | 0 | 0 | |
Interest cost | 7,000 | 8,000 | 22,000 | 25,000 | |
Expected return on plan assets | 0 | 0 | 0 | 0 | |
Amortization of net (gain) loss | 4,000 | 2,000 | 11,000 | 7,000 | |
Amortization of prior service cost | 0 | 0 | 0 | 0 | |
Net Periodic Benefit Cost | 11,000 | 10,000 | 33,000 | 32,000 | |
Total expected employer contributions for fiscal year | 100,000 | 100,000 | |||
Estimated employer contributions in Year 2-5 | 400,000 | 400,000 | |||
TNMP | Executive Retirement Program | Maximum | |||||
Components of Net Periodic Benefit Cost | |||||
Contributions by employer | 100,000 | 100,000 | 100,000 | 100,000 | |
Accounting Standards Update 2017-07 | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other (deductions) | $ 2,100,000 | $ 6,400,000 | |||
Accounting Standards Update 2017-07 | PNM | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other (deductions) | 1,100,000 | 3,200,000 | |||
Non-service cost deferred as regulatory assets | 100,000 | 300,000 | |||
Accounting Standards Update 2017-07 | TNMP | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Other income | 100,000 | 300,000 | |||
Non-service cost deferred as regulatory liability | $ 100,000 | $ 100,000 | |||
Forecast | TNMP | OPEB Plan | |||||
Components of Net Periodic Benefit Cost | |||||
Contributions by employer | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Public Utilities, Commitments And Contingencies [Line Items] | ||
Estimate of possible loss | $ 57.7 | |
Other deferred credits | ||
Public Utilities, Commitments And Contingencies [Line Items] | ||
Loss contingency accrual | $ 12.5 | $ 12.3 |
Commitments and Contingencies_2
Commitments and Contingencies - The Clean Air Act (Details) $ in Millions | Mar. 02, 2015lb / MMBTUT | Sep. 30, 2018USD ($)lbsofnox / mmbtuoptionjoint_ownerT | May 29, 2018parts_per_billion | Dec. 31, 2017MW | Jan. 26, 2016state | Dec. 31, 2015MW | Oct. 01, 2015parts_per_billion | Sep. 30, 2015parts_per_billion | May 14, 2015lb / MMBTU | Dec. 30, 2013 | Apr. 30, 2013well | Feb. 28, 2013lawsuitstatemine | Aug. 06, 2012compliance_alternative | Dec. 31, 1999state |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Undepreciated investment in ownership to be obtained | $ 405.5 | |||||||||||||
Number of options for meeting BTA standards | option | 7 | |||||||||||||
Expected number of additional monitoring wells | 38 | |||||||||||||
Clean Air Act related to regional haze | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of states to address regional haze (in states) | state | 50 | |||||||||||||
Potential to emit tons per year of visibility impairing pollution (in tons, more than) | T | 250 | |||||||||||||
Clean Power Plan | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of states that filed a petition against the Clean Power Plan | state | 29 | |||||||||||||
San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of other joint owners | joint_owner | 8 | |||||||||||||
PNM | National Ambient Air Quality Standards, 2015 EPA Legal Settlement | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Period of time to act on settlement | 16 months | |||||||||||||
Emissions tons of SO2 per year (more than) | T | 16,000 | |||||||||||||
PNM | WEG v OSM lawsuit | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of mines impacted | mine | 7 | |||||||||||||
Number of states impacted | state | 4 | |||||||||||||
Number of claims for relief, filed | lawsuit | 15 | |||||||||||||
PNM | Santa Fe generating station | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of wells with elevated levels of nitrates | well | 3 | |||||||||||||
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR Hearing Examiner, Recommended Denial | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Additional ownership to be obtained (in megawatts) | MW | 132 | |||||||||||||
Undepreciated interest in ownership to be obtained | $ 20.3 | |||||||||||||
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Additional ownership to be obtained (in megawatts) | MW | 65 | |||||||||||||
Undepreciated interest in ownership to be obtained | $ 10.1 | |||||||||||||
PNM | Palo Verde Nuclear Generating Station Unit 3 | Clean Air Act, SNCR | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of megawatts nuclear generation (in megawatts) | MW | 134 | |||||||||||||
PNM | Four Corners | Clean Air Act related to post combustion controls | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of compliance alternatives | compliance_alternative | 2 | |||||||||||||
Plant requirement to meet NOx emissions limit (in pounds of NOx per MMBTU) | lbsofnox / mmbtu | 0.015 | |||||||||||||
Plant requirement to meet opacity limit | 20.00% | |||||||||||||
Rule imposes opacity limitation on certain fugitive dust emissions from coal and material handling operations | 20.00% | |||||||||||||
Estimate of possible loss | $ 88.6 | |||||||||||||
PNM | Four Corners Units 4 and 5 (Coal) | Clean Air Act related to post combustion controls | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Ownership percentage | 13.00% | |||||||||||||
PNM | Four Corners Units 1, 2 and 3 (Coal) | Clean Air Act related to post combustion controls | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Ownership percentage | 0.00% | |||||||||||||
PNM | San Juan Generating Station | WEG v OSM lawsuit | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Number of claims for relief, filed | lawsuit | 2 | |||||||||||||
Minimum | PNM | National Ambient Air Quality Standards, 2015 EPA Legal Settlement | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Emissions tons of SO2 per year (more than) | T | 2,600 | |||||||||||||
One-hour SO2 emissions rate (in pounds per MMBTU) | lb / MMBTU | 0.45 | |||||||||||||
Maximum | PNM | San Juan Generating Station and Four Corners | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Government standard emission limit (in ozone parts per million) | parts_per_billion | 75 | 70 | 75 | |||||||||||
San Juan Generating Station | PNM | National Ambient Air Quality Standards | ||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||
Revised SO2 emissions (in pounds per MMBTU) | lb / MMBTU | 0.10 |
Commitments and Contingencies_3
Commitments and Contingencies - Coal Supply (Details) | Oct. 05, 2018T | Jun. 29, 2018USD ($) | Feb. 01, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) | May 22, 2018USD ($) | Feb. 01, 2018 | Jun. 30, 2017USD ($) | Feb. 01, 2017 | Sep. 30, 2016USD ($) | Aug. 01, 2016payment | Jan. 31, 2016USD ($) |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Other current assets | $ 53,068,000 | $ 53,068,000 | $ 47,358,000 | |||||||||||||
Regulatory disallowances and restructuring costs | (1,645,000) | $ 0 | 149,000 | $ 0 | ||||||||||||
PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Other current assets | 46,467,000 | 46,467,000 | 39,904,000 | |||||||||||||
Regulatory disallowances and restructuring costs | (1,645,000) | $ 0 | 149,000 | $ 0 | ||||||||||||
PNM | Surface | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Regulatory assets | 100,000,000 | 100,000,000 | ||||||||||||||
PNM | Loss on long-term purchase commitment | Surface | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Increase (decrease) for interim storage costs liability | 30,000,000 | |||||||||||||||
Loss contingency accrual | 39,500,000 | 39,500,000 | 41,400,000 | |||||||||||||
Final reclamation, capped amount to be collected | 100,000,000 | |||||||||||||||
PNM | Loss on long-term purchase commitment | Underground | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Increase (decrease) for interim storage costs liability | 10,000,000 | |||||||||||||||
Loss contingency accrual | 14,300,000 | 14,300,000 | 14,700,000 | |||||||||||||
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Surface | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Regulatory disallowances and restructuring costs | $ 16,500,000 | |||||||||||||||
Estimate of possible loss | 87,500,000 | 87,500,000 | ||||||||||||||
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Underground | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Estimate of possible loss | $ 101,200,000 | $ 101,200,000 | ||||||||||||||
Coal supply | PNM | San Juan Generating Station | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Other current assets | 26,300,000 | |||||||||||||||
Estimated increase in coal cost | 6.90% | 6.90% | 51.00% | |||||||||||||
Coal supply | NM Capital | San Juan Generating Station | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Payments to fund long-term loans to unaffiliated third party | $ 125,000,000 | |||||||||||||||
Loan agreement among several entities | 125,000,000 | |||||||||||||||
Interest rate | 12.25% | 9.25% | ||||||||||||||
Requirement to post reclamation bonds | $ 118,700,000 | $ 118,700,000 | ||||||||||||||
Cash used to support bank letter or credit arrangement | 30,300,000 | 30,300,000 | $ 30,300,000 | |||||||||||||
Coal supply | NM Capital | San Juan Coal Company, Westmoreland | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Payments to fund long-term loans to unaffiliated third party | 125,000,000 | |||||||||||||||
Prepayment penalty | 0 | 0 | ||||||||||||||
Repayment of line of credit | $ 50,100,000 | |||||||||||||||
BTMU Term Loan Agreement | NM Capital | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Long-term debt | 125,000,000 | |||||||||||||||
Repayment of line of credit | $ 125,000,000 | $ 43,000,000 | ||||||||||||||
Increase in coal mine decommissioning liability | PNM | San Juan Generating Station | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Estimated underpaid surface mining royalties under proposed rate change | $ 4,500,000 | |||||||||||||||
Increase in coal mine decommissioning liability | PNM | Loss on long-term purchase commitment | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Estimated underpaid surface mining royalties under proposed rate change | 2,500,000 | 2,500,000 | ||||||||||||||
Mine Reclamation Trust | PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Required contribution to Reclamation Trust, current fiscal year | 6,400,000 | 6,400,000 | ||||||||||||||
Reclamation trust funding, year 2 | 8,700,000 | 8,700,000 | ||||||||||||||
Reclamation trust funding, year 3 | 9,200,000 | 9,200,000 | ||||||||||||||
San Juan Generating Station | Loss on long-term purchase commitment | PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Annual funding post-term reclamation trust | $ 5,800,000 | |||||||||||||||
Four Corners | Mine Reclamation Trust | PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Required contribution to Reclamation Trust, current fiscal year | $ 2,300,000 | |||||||||||||||
Reclamation trust funding, year 2 | 2,300,000 | 2,300,000 | ||||||||||||||
Reclamation trust funding, year 3 | $ 2,300,000 | $ 2,300,000 | ||||||||||||||
Number of annual installment payments | payment | 13 | |||||||||||||||
Four Corners Coal Supply Arbitration | PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Payments for legal settlements | $ 4,900,000 | |||||||||||||||
Four Corners Coal Supply Arbitration, Period March 1, 2018 through June 30, 2018 | PNM | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Payments for legal settlements | $ 1,400,000 | |||||||||||||||
Subsequent event | Coal supply | PNM | San Juan Generating Station | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
Reduction in coal obligation | T | 111,668 | |||||||||||||||
Continuous highwall mining | San Juan Generating Station | ||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||
PNM's share estimated underpaid surface mining royalties under proposed rate change | 46.30% | 46.30% | ||||||||||||||
Estimated underpaid surface mining royalties under proposed rate change | $ 5,000,000 | $ 5,000,000 |
Commitments and Contingencies_4
Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details) | Mar. 28, 2017 | Sep. 30, 2012landowner | Apr. 30, 2010city | Sep. 30, 2018USD ($)generating_unit | Oct. 31, 2018USD ($) | Dec. 01, 2015Allotment_Parcel | Jul. 13, 2015a | Jan. 22, 2015Allotment_Parcel | Feb. 27, 2014lawsuit | Aug. 31, 2013 |
Continuous highwall mining | San Juan Generating Station | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Proposed retroactive surface mining royalty rate | 12.50% | |||||||||
Surface mining royalty rate applied | 8.00% | |||||||||
Estimated underpaid surface mining royalties under proposed rate change | $ 5,000,000 | |||||||||
PNM's share estimated underpaid surface mining royalties under proposed rate change | 46.30% | |||||||||
PNM | Navajo Nation Allottee Matters | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Number of landowners involved in the appeal | landowner | 43 | |||||||||
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel | 2 | 10 | ||||||||
Area of land (in acres) | a | 15.49 | |||||||||
Number of allotment parcels at issue that are not to be condemned | Allotment_Parcel | 2 | |||||||||
Number of allotment parcels at issue | Allotment_Parcel | 5 | |||||||||
PNM | Palo Verde Nuclear Generating Station | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Number of cities to provide cooling water | city | 5 | |||||||||
Term of agreement for cooling water | 40 years | |||||||||
PNM | Palo Verde Nuclear Generating Station | Nuclear plant | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Ownership percentage in nuclear reactor | 10.20% | |||||||||
Number of units | generating_unit | 3 | |||||||||
Maximum potential assessment per incident | $ 38,900,000 | |||||||||
Annual payment limitation related to incident | 5,800,000 | |||||||||
Aggregate amount of all risk insurance | 2,750,000,000 | |||||||||
Maximum amount under Nuclear Electric Insurance Limited | 5,400,000 | |||||||||
PNM | Maximum | Palo Verde Nuclear Generating Station | Nuclear plant | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Liability insurance coverage | 13,200,000,000 | |||||||||
Liability insurance coverage sublimit | 2,250,000,000 | |||||||||
First Choice | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Additional tax due plus penalties and interest | 5,000,000 | |||||||||
Commercial providers | PNM | Palo Verde Nuclear Generating Station | Nuclear plant | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Liability insurance coverage | 450,000,000 | |||||||||
Industry Wide Retrospective Assessment Program | PNM | Palo Verde Nuclear Generating Station | Nuclear plant | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Liability insurance coverage | $ 12,700,000,000 | |||||||||
Pending litigation | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Number of pending claims | lawsuit | 2 | |||||||||
Written notification to terminate agreement, minimum period of time required | 30 days | |||||||||
Settled litigation | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Number of pending claims | lawsuit | 1 | |||||||||
Subsequent event | State and Local Jurisdiction | First Choice | ||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||
Adjustment from settlement with taxing authority | $ 900,000 |
Regulatory and Rate Matters - P
Regulatory and Rate Matters - PNM (Details) $ in Thousands | Sep. 30, 2018USD ($)leaseservice_rateMW | Aug. 24, 2018power_purchase_agreementFacilityMW | Jun. 30, 2018USD ($) | Apr. 13, 2018USD ($) | Mar. 17, 2018USD ($) | Jan. 31, 2018USD ($) | Jan. 16, 2018USD ($) | Jan. 10, 2018USD ($) | Dec. 31, 2017USD ($) | Nov. 08, 2017USD ($) | Jul. 26, 2017USD ($)GWh | Jul. 03, 2017 | Jun. 21, 2017 | Jun. 01, 2017GWhMW | May 23, 2017USD ($) | Apr. 14, 2017USD ($)GWhprogram | Jan. 11, 2017USD ($) | Dec. 07, 2016USD ($) | Sep. 28, 2016USD ($)MW | Aug. 04, 2016USD ($)MW | May 04, 2016 | Apr. 15, 2016USD ($)GWhprogram | Jan. 16, 2016lease | Aug. 27, 2015USD ($) | Jan. 15, 2015 | Jul. 01, 2014 | Sep. 30, 2016USD ($) | Sep. 30, 2018USD ($)leaseservice_rateMW | Dec. 31, 2017USD ($)power_purchase_agreement | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)leaseservice_rateMW | Sep. 30, 2017USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($) | Aug. 22, 2018USD ($) | Jun. 20, 2018MW | Mar. 21, 2018MW | Nov. 07, 2017 | Oct. 31, 2017USD ($) | Oct. 17, 2017MW | Sep. 05, 2017MW | May 12, 2017USD ($)signatory | Oct. 26, 2016MW | Jul. 01, 2016USD ($) | Jun. 30, 2016meeting | Feb. 26, 2016USD ($) | Jan. 31, 2016leaseMW | Jan. 15, 2016USD ($)leaseMW |
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ (1,645) | $ 0 | $ 149 | $ 0 | |||||||||||||||||||||||||||||||||||||||||||||
Increase (decrease) in Non-fuel Revenue Requirement | $ 10,300 | ||||||||||||||||||||||||||||||||||||||||||||||||
Percent of non-fuel revenue requirement change implemented | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||
Excess return on jurisdictional equity that would require refund | 0.50% | 0.50% | 0.50% | ||||||||||||||||||||||||||||||||||||||||||||||
Application filed for new electric service rates | service_rate | 2 | 2 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||
PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ (1,645) | 0 | $ 149 | 0 | |||||||||||||||||||||||||||||||||||||||||||||
Filing frequency for energy efficiency plans | 3 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Modification percentage to funding levels | 0.1 | ||||||||||||||||||||||||||||||||||||||||||||||||
Planning period covered of IRP | 20 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of statewide meetings hosted | meeting | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||
Estimated insurance deductible | $ 2,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
Exposure to cost of repairs | $ 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
Ownership percentage | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||
PNMR Development | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 30 | 30 | 30 | 50 | |||||||||||||||||||||||||||||||||||||||||||||
Construction of solar generation capacity (in megawatts) | MW | 10 | 10 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||
2015 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ 123,500 | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) of non-fuel revenue | $ 121,500 | $ 121,700 | $ 121,500 | ||||||||||||||||||||||||||||||||||||||||||||||
Requested return on equity | 10.50% | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) for fuel related costs | (42,900) | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) for non-fuel related revenues | (200) | ||||||||||||||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended rate increase (decrease) of non-fuel revenue | $ 41,300 | ||||||||||||||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended return on equity | 9.575% | ||||||||||||||||||||||||||||||||||||||||||||||||
Approved rate increase (decrease) | $ 61,200 | ||||||||||||||||||||||||||||||||||||||||||||||||
Estimated period of time for supreme court appeal decision | 15 months | ||||||||||||||||||||||||||||||||||||||||||||||||
Estimate of possible loss | $ 147,500 | $ 147,500 | $ 147,500 | ||||||||||||||||||||||||||||||||||||||||||||||
2014 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Future test year period | 12 months | ||||||||||||||||||||||||||||||||||||||||||||||||
Period of time after the filing of a rate case application | 13 months | ||||||||||||||||||||||||||||||||||||||||||||||||
Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of megawatts of Solar PV facilities | MW | 157 | 157 | 157 | ||||||||||||||||||||||||||||||||||||||||||||||
Current output in the geothermal facility (in megawatts) | MW | 4 | 4 | 4 | ||||||||||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 95.9 | 95.9 | 95.9 | ||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW | 50 | 50 | 50 | ||||||||||||||||||||||||||||||||||||||||||||||
Renewable Energy Rider | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Recorded revenues from renewable rider | $ 8,700 | $ 9,400 | $ 30,400 | $ 33,600 | |||||||||||||||||||||||||||||||||||||||||||||
Integrated Resource Plan, 2011 | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Frequency of IRP filings | 3 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Planning period covered of IRP | 20 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Energy Imbalance Market | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Initial Capital Investments To Be Recovered | $ 20,900 | ||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Other Expenses To Be Recovered | $ 7,400 | ||||||||||||||||||||||||||||||||||||||||||||||||
Advanced Metering Infrastructure Costs | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Estimated costs to be recovered | $ 95,100 | $ 87,200 | |||||||||||||||||||||||||||||||||||||||||||||||
Estimated future investment | $ 33,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
Facebook Data Center | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of additional PPAs | power_purchase_agreement | 2 | 3 | |||||||||||||||||||||||||||||||||||||||||||||||
Power purchase agreement term | 25 years | 25 years | |||||||||||||||||||||||||||||||||||||||||||||||
Facebook Data Center | Casa Mesa Wind | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 50 | ||||||||||||||||||||||||||||||||||||||||||||||||
Facebook Data Center | Avangrid Renewables, LLC | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 166 | ||||||||||||||||||||||||||||||||||||||||||||||||
Facebook Data Center | Route 66 Solar Energy Center | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 100 | 50 | |||||||||||||||||||||||||||||||||||||||||||||||
Number Of Solar Facilities | Facility | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 2 Leases | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of megawatts purchased (in megawatts) | MW | 64.1 | 64.1 | 64.1 | 64.1 | 64.1 | ||||||||||||||||||||||||||||||||||||||||||||
Number of leases under which assets were purchased | lease | 3 | 3 | 3 | 3 | 3 | 3 | |||||||||||||||||||||||||||||||||||||||||||
Estimated annual property tax expense | $ 800 | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of leases under which lease term was extended | lease | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
Lease term extension period | 8 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of megawatts nuclear generation (in megawatts) | MW | 114.6 | 114.6 | 114.6 | ||||||||||||||||||||||||||||||||||||||||||||||
Net book value | $ 73,900 | $ 73,900 | $ 73,900 | ||||||||||||||||||||||||||||||||||||||||||||||
Net book value of capitalized improvements | 38,300 | 38,300 | 38,300 | ||||||||||||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 2 Leases | 2015 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Hearing examiner's proposed disallowance of recovery | $ 163,300 | ||||||||||||||||||||||||||||||||||||||||||||||||
Initial rate base value | $ 83,700 | ||||||||||||||||||||||||||||||||||||||||||||||||
Disallowance of the recovery underpreciated costs of capitalized leasehold improvements | 43,800 | ||||||||||||||||||||||||||||||||||||||||||||||||
Period of time for which capital improvements were disallowed | 15 months | ||||||||||||||||||||||||||||||||||||||||||||||||
Pre-tax regulatory disallowance | 900 | $ 1,800 | $ 3,100 | $ 6,800 | |||||||||||||||||||||||||||||||||||||||||||||
Period of time to issue a decision and take action on remanded issues | 5 months | 7 months | |||||||||||||||||||||||||||||||||||||||||||||||
Alvarado square | 2015 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended amount to not be recovered from retail customers | 4,500 | ||||||||||||||||||||||||||||||||||||||||||||||||
Pre-tax regulatory disallowance of costs recorded as regulatory assets and deferred charges | $ 4,500 | ||||||||||||||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 1 Leases, extended | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Estimated annual property tax expense | $ 1,500 | ||||||||||||||||||||||||||||||||||||||||||||||||
Estimated annual rent expense | 18,100 | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of leases under which lease term was extended | lease | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||
Lease term extension period | 8 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 1 Leases, extended | 2015 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Recovery of assumed operating and maintenance expense savings annually | $ 300 | ||||||||||||||||||||||||||||||||||||||||||||||||
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Net book value | $ 50,300 | $ 50,300 | $ 50,300 | ||||||||||||||||||||||||||||||||||||||||||||||
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | 2015 Electric Rate Case | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested base rate increase (decrease) | 40,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Installation capital costs | $ 52,300 | ||||||||||||||||||||||||||||||||||||||||||||||||
NMPRC | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ 99,200 | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested return on equity | 10.125% | ||||||||||||||||||||||||||||||||||||||||||||||||
Number of additional signatories | signatory | 13 | ||||||||||||||||||||||||||||||||||||||||||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 21 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory disallowance | $ 27,900 | $ 27,900 | |||||||||||||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | ||||||||||||||||||||||||||||||||||||||||||||||||
NMPRC | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ (4,400) | $ (9,100) | $ 62,300 | ||||||||||||||||||||||||||||||||||||||||||||||
Requested return on equity | 9.575% | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested initial rate increase (decrease) | $ 32,300 | ||||||||||||||||||||||||||||||||||||||||||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) duplicative amount | $ 4,700 | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 1 | GWh | 80 | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW | 50 | 50 | 50 | ||||||||||||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | ||||||||||||||||||||||||||||||||||||||||||||||||
Notice of proposed dismissal, period to show good cause | 30 days | ||||||||||||||||||||||||||||||||||||||||||||||||
Required Percentage by 2011 | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 10.00% | 10.00% | 10.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Required Percentage by 2015 | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 15.00% | 15.00% | 15.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Required Percentage by 2020 | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 20.00% | 20.00% | 20.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Minimum | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Profit incentive sliding scale multiplier | 7.10% | ||||||||||||||||||||||||||||||||||||||||||||||||
Minimum | Wind | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 30.00% | 30.00% | 30.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Minimum | Solar | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 20.00% | 20.00% | 20.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Minimum | Distributed generation | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 3.00% | 3.00% | 3.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Minimum | Other | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 5.00% | 5.00% | 5.00% | ||||||||||||||||||||||||||||||||||||||||||||||
Maximum | Renewable Portfolio Standard | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Reasonable cost threshold | 3.00% | 3.00% | 3.00% | 3.00% | |||||||||||||||||||||||||||||||||||||||||||||
Profit incentive sliding scale multiplier | 9.00% | ||||||||||||||||||||||||||||||||||||||||||||||||
New Mexico Wind | Renewable Portfolio Standard 2014 | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of megawatts for wind energy | MW | 204 | ||||||||||||||||||||||||||||||||||||||||||||||||
New Mexico Wind | NMPRC | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 2 | GWh | 105 | ||||||||||||||||||||||||||||||||||||||||||||||||
Red Mesa Wind | Renewable Portfolio Standard 2014 | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of megawatts for wind energy | MW | 102 | ||||||||||||||||||||||||||||||||||||||||||||||||
Lightning Dock Geothermal | NMPRC | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 1 | GWh | 55 | ||||||||||||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 2 | GWh | 77 | ||||||||||||||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | 2017 Energy Efficiency and Load Management Program | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 26,000 | $ 28,000 | |||||||||||||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 2,400 | ||||||||||||||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 75 | ||||||||||||||||||||||||||||||||||||||||||||||||
Profit incentive | $ 1,800 | ||||||||||||||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | Proposed 2018 Portfolio | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 23,600 | $ 25,100 | |||||||||||||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 1,900 | ||||||||||||||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 53 | ||||||||||||||||||||||||||||||||||||||||||||||||
Projected incentive earnings | $ 2,300 | $ 1,900 | $ 2,100 | ||||||||||||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 69 | 70 | |||||||||||||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | Proposed 2019 Portfolio | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 24,900 | $ 28,200 | |||||||||||||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 1,700 | $ 2,100 | |||||||||||||||||||||||||||||||||||||||||||||||
Four Corners | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory disallowance | $ 90,100 | $ 148,100 | |||||||||||||||||||||||||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ 47,600 | ||||||||||||||||||||||||||||||||||||||||||||||||
Forecast | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Pre-tax regulatory disallowance | $ 36,800 | $ 58,000 | |||||||||||||||||||||||||||||||||||||||||||||||
Forecast | NMPRC | PNM | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
Proposed revision to rider that will allow for recovery | $ 49,600 | $ 43,500 | |||||||||||||||||||||||||||||||||||||||||||||||
Discount Rate | |||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||
WACC | 0.0959 | 0.0771 |
Regulatory and Rate Matters - T
Regulatory and Rate Matters - TNMP Narrative (Details) $ in Millions | Nov. 02, 2018USD ($) | May 30, 2018USD ($) | Jul. 30, 2011USD ($) | Sep. 30, 2018USD ($)advanced_meter | Sep. 30, 2018USD ($)advanced_meter | Dec. 31, 2017USD ($) | Aug. 06, 2018USD ($) |
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Unrecovered investment revenue | $ 21.8 | ||||||
TNMP | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Net regulatory liability | $ 37.8 | ||||||
Reduction to revenue | $ 1.5 | $ 4.2 | |||||
Energy efficiency cost recovery, requested change amount | 5.7 | $ 5.6 | |||||
Energy efficiency cost recovery, requested bonus | 0.9 | $ 0.8 | $ 0.8 | $ 0.8 | |||
TNMP | 2018 TNMP Rate Case | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Requested rate increase (decrease) | $ 25.9 | ||||||
Requested return on equity | 10.50% | ||||||
Requested cost of debt | 7.20% | ||||||
Requested debt capital structure | 50.00% | ||||||
Requested equity capital structure | 50.00% | ||||||
New rate rider recovery, amount | $ 7.7 | ||||||
Regulatory liabilities | 146.5 | ||||||
Net regulatory liability | $ 14.4 | ||||||
TNMP | Advanced Meter System Deployment and Surcharge Request | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Approved deployment costs | $ 113.4 | ||||||
Collection of deployment costs through surcharge period | 12 years | ||||||
Number of advanced meters installed (more than) | advanced_meter | 242,000 | 242,000 | |||||
Subsequent event | TNMP | 2018 TNMP Rate Case | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Requested rate increase (decrease) | $ 10 | ||||||
Requested return on equity | 9.65% | ||||||
Requested cost of debt | 6.44% | ||||||
Requested debt capital structure | 55.00% | ||||||
Requested equity capital structure | 45.00% | ||||||
Investments excluded from rate request | $ 11.7 |
Regulatory and Rate Matters -_2
Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - TNMP - USD ($) $ in Millions | Mar. 27, 2018 | Sep. 13, 2017 | Mar. 14, 2017 | Sep. 08, 2016 |
Transmission Cost of Service Rates | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Approved Increase in Rate Base | $ 30.2 | $ 9.5 | ||
Annual Increase in Revenue | $ 4.8 | $ 1.8 | ||
PUCT | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Requested rate increase (decrease) | $ 32 | $ 27.5 | ||
Proposed increase (decrease) in revenues | $ 0.6 | $ 4.7 |
Lease Commitments (Details)
Lease Commitments (Details) - PNM $ in Millions | Jan. 15, 2016USD ($)leaseMW | Sep. 30, 2018USD ($)lease | Jan. 31, 2016lease | Jan. 16, 2016lease | Jan. 15, 2015lease |
Palo Verde Nuclear Generating Station, Unit 1 Leases | |||||
Operating Leased Assets [Line Items] | |||||
Number of leases, expiring | 4 | ||||
Number of leases under which lease term was extended | 4 | ||||
Palo Verde Nuclear Generating Station, Unit 2 Leases | |||||
Operating Leased Assets [Line Items] | |||||
Number of leases, expiring | 4 | ||||
Number of leases under which lease term was extended | 1 | ||||
Number of leases under which assets were purchased | 3 | 3 | 3 | 3 | |
Leased capacity to be purchased (in megawatts) | MW | 32.76 | ||||
Palo Verde Nuclear Generating Station, Unit 2 Leases, 31.25 MW | |||||
Operating Leased Assets [Line Items] | |||||
Number of leases under which assets were purchased | 1 | ||||
Payment to lessors | $ | $ 78.1 | ||||
Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 | |||||
Operating Leased Assets [Line Items] | |||||
Leased capacity to be purchased (in megawatts) | MW | 31.25 | ||||
Palo Verde Nuclear Generating Station, Unit 2 Leases, 32.76 MW | |||||
Operating Leased Assets [Line Items] | |||||
Number of leases under which assets were purchased | 2 | ||||
Payment to lessors | $ | $ 85.2 | ||||
Palo Verde Nuclear Generating Station | |||||
Operating Leased Assets [Line Items] | |||||
Loss contingency, lease arrangements (up to) | $ | $ 163.8 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | May 23, 2017 | Sep. 30, 2018 | Mar. 31, 2017 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2014 | Dec. 31, 2013 |
Income Tax Contingency [Line Items] | |||||||
New Mexico Corporate tax rate, 2014 | 7.60% | ||||||
New Mexico Corporate tax rate, effective by 2018 | 5.90% | ||||||
Increase (decrease) in deferred tax assets as a result of tax rate changes | $ (0.1) | ||||||
Increase (decrease) in tax expense due to tax rate change (less than for 2017) | 0.1 | ||||||
Tax benefits related to stock awards | $ 0 | $ 1.4 | |||||
Corporate and Other | |||||||
Income Tax Contingency [Line Items] | |||||||
Increase (decrease) in tax expense due to tax rate change (less than for 2017) | 0.1 | ||||||
TNMP | |||||||
Income Tax Contingency [Line Items] | |||||||
Increase (decrease) in regulatory liability | 1.5 | 4.2 | |||||
Tax benefits related to stock awards | 0.1 | 0.4 | |||||
PNM | |||||||
Income Tax Contingency [Line Items] | |||||||
Increase (decrease) in regulatory liability | $ (4.8) | ||||||
Tax benefits related to stock awards | $ 0 | $ 1 | |||||
Forecast | |||||||
Income Tax Contingency [Line Items] | |||||||
Effective tax rate | 12.35% | ||||||
Forecast | TNMP | |||||||
Income Tax Contingency [Line Items] | |||||||
Effective tax rate | 22.78% | ||||||
Forecast | PNM | |||||||
Income Tax Contingency [Line Items] | |||||||
Effective tax rate | 9.51% | ||||||
NMPRC | |||||||
Income Tax Contingency [Line Items] | |||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 21 years | ||||||
NMPRC | PNM | |||||||
Income Tax Contingency [Line Items] | |||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Related Party Transaction [Line Items] | ||||
Ownership percentage | 50.00% | 50.00% | ||
Services billings: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 22,972 | $ 23,451 | $ 69,122 | $ 71,044 |
Services billings: | PNMR to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 8,074 | 7,828 | 24,497 | 23,771 |
Services billings: | PNM to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 104 | 115 | 281 | 302 |
Services billings: | TNMP to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 35 | 35 | 105 | 106 |
Services billings: | TNMP to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 8 | 0 | 154 |
Services billings: | PNMR to NMRD | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 32 | 0 | 162 | 0 |
Renewable energy purchases: | PNM from NMRD | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 969 | 0 | 2,343 | 0 |
Interconnection billings: | PNM from NMRD | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 47 | 0 | 2,099 | 0 |
Interconnection billings: | PNM to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 0 | 68,200 | 0 |
Interest billings: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 844 | 3 | 1,653 | 14 |
Interest billings: | PNMR to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 65 | 66 | 87 | 126 |
Interest billings: | PNM to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 75 | 71 | 211 | 163 |
Income tax sharing payments: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 0 | 0 | 0 |
Income tax sharing payments: | TNMP to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 0 | $ 0 | $ 0 | $ 0 |
Goodwill (Details)
Goodwill (Details) - USD ($) | Apr. 01, 2017 | Dec. 31, 2017 | Sep. 30, 2018 | Apr. 01, 2018 | Sep. 30, 2017 |
Goodwill [Line Items] | |||||
Goodwill | $ 278,297,000 | $ 278,297,000 | $ 278,297,000 | ||
Impairments of goodwill | $ 0 | 0 | |||
PNM | |||||
Goodwill [Line Items] | |||||
Goodwill | 51,632,000 | 51,632,000 | $ 51,600,000 | ||
Goodwill fair value exceeded by its carrying value | 19.00% | ||||
TNMP | |||||
Goodwill [Line Items] | |||||
Goodwill | $ 226,665,000 | $ 226,665,000 | $ 226,700,000 | ||
Goodwill fair value exceeded by its carrying value | 32.00% |