Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Jul. 24, 2015 | |
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 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 79,653,624 | |
Public Service Company of New Mexico [Member] | ||
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 [Member] | ||
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 | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Electric Operating Revenues | $ 352,887 | $ 346,160 | $ 685,755 | $ 675,057 |
Operating Expenses: | ||||
Cost of energy | 114,038 | 109,419 | 229,683 | 222,033 |
Administrative and general | 39,928 | 45,235 | 83,787 | 89,093 |
Energy production costs | 44,790 | 45,846 | 87,459 | 93,134 |
Regulatory disallowances | 1,529 | 0 | 1,744 | 0 |
Depreciation and amortization | 46,049 | 42,163 | 91,510 | 84,130 |
Transmission and distribution costs | 16,868 | 16,068 | 33,354 | 32,974 |
Taxes other than income taxes | 17,271 | 16,133 | 36,234 | 33,644 |
Total operating expenses | 280,473 | 274,864 | 563,771 | 555,008 |
Operating income | 72,414 | 71,296 | 121,984 | 120,049 |
Other Income and Deductions: | ||||
Interest income | 1,941 | 2,040 | 3,691 | 4,158 |
Gains on available-for-sale securities | 5,556 | 4,699 | 9,580 | 7,272 |
Other income | 5,717 | 3,180 | 10,679 | 4,754 |
Other (deductions) | (3,707) | (2,169) | (7,370) | (5,102) |
Net other income and deductions | 9,507 | 7,750 | 16,580 | 11,082 |
Interest Charges | 28,913 | 29,972 | 59,186 | 59,506 |
Earnings before Income Taxes | 53,008 | 49,074 | 79,378 | 71,625 |
Income Taxes | 17,353 | 15,893 | 25,870 | 22,313 |
Net Earnings | 35,655 | 33,181 | 53,508 | 49,312 |
(Earnings) Attributable to Valencia Non-controlling Interest | (3,850) | (3,908) | (7,231) | (7,439) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (264) | (264) |
Net Earnings Attributable to PNMR | 31,673 | 29,141 | 46,013 | 41,609 |
Net Earnings Available for PNM Common Stock | $ 31,673 | $ 29,141 | $ 46,013 | $ 41,609 |
Net Earnings Attributable to PNMR per Common Share: | ||||
Basic (dollars per share) | $ 0.40 | $ 0.37 | $ 0.58 | $ 0.52 |
Diluted (dollars per share) | 0.40 | 0.36 | 0.57 | 0.52 |
Dividends Declared per Common Share (dollars per share) | $ 0.200 | $ 0.185 | $ 0.400 | $ 0.37 |
Public Service Company of New Mexico [Member] | ||||
Electric Operating Revenues | $ 275,450 | $ 275,704 | $ 537,390 | $ 538,441 |
Operating Expenses: | ||||
Cost of energy | 95,728 | 92,642 | 193,594 | 189,268 |
Administrative and general | 36,956 | 40,603 | 76,524 | 79,213 |
Energy production costs | 44,790 | 45,846 | 87,459 | 93,134 |
Regulatory disallowances | 1,529 | 0 | 1,744 | 0 |
Depreciation and amortization | 29,002 | 27,023 | 57,405 | 54,105 |
Transmission and distribution costs | 10,272 | 10,183 | 21,040 | 21,510 |
Taxes other than income taxes | 9,994 | 9,601 | 20,790 | 20,100 |
Total operating expenses | 228,271 | 225,898 | 458,556 | 457,330 |
Operating income | 47,179 | 49,806 | 78,834 | 81,111 |
Other Income and Deductions: | ||||
Interest income | 1,946 | 2,065 | 3,717 | 4,193 |
Gains on available-for-sale securities | 5,556 | 4,699 | 9,580 | 7,272 |
Other income | 4,901 | 2,443 | 8,292 | 3,555 |
Other (deductions) | (3,011) | (1,630) | (4,615) | (3,647) |
Net other income and deductions | 9,392 | 7,577 | 16,974 | 11,373 |
Interest Charges | 19,681 | 20,023 | 39,640 | 39,835 |
Earnings before Income Taxes | 36,890 | 37,360 | 56,168 | 52,649 |
Income Taxes | 11,527 | 13,106 | 17,302 | 17,189 |
Net Earnings | 25,363 | 24,254 | 38,866 | 35,460 |
(Earnings) Attributable to Valencia Non-controlling Interest | (3,850) | (3,908) | (7,231) | (7,439) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (264) | (264) |
Net Earnings Attributable to PNMR | 21,513 | 20,346 | 31,635 | 28,021 |
Net Earnings Available for PNM Common Stock | 21,381 | 20,214 | 31,371 | 27,757 |
Texas-New Mexico Power Company [Member] | ||||
Electric Operating Revenues | 77,437 | 70,456 | 148,365 | 136,616 |
Operating Expenses: | ||||
Cost of energy | 18,310 | 16,777 | 36,089 | 32,765 |
Administrative and general | 8,042 | 8,768 | 17,875 | 18,609 |
Depreciation and amortization | 13,591 | 12,003 | 27,049 | 23,844 |
Transmission and distribution costs | 6,596 | 5,885 | 12,314 | 11,464 |
Taxes other than income taxes | 6,169 | 5,758 | 12,378 | 11,408 |
Total operating expenses | 52,708 | 49,191 | 105,705 | 98,090 |
Operating income | 24,729 | 21,265 | 42,660 | 38,526 |
Other Income and Deductions: | ||||
Interest income | 0 | 0 | 0 | 0 |
Other income | 792 | 586 | 2,332 | 1,006 |
Other (deductions) | 1 | (72) | (248) | (304) |
Net other income and deductions | 793 | 514 | 2,084 | 702 |
Interest Charges | 6,856 | 6,655 | 13,781 | 13,252 |
Earnings before Income Taxes | 18,666 | 15,124 | 30,963 | 25,976 |
Income Taxes | 6,801 | 5,590 | 11,404 | 9,640 |
Net Earnings | 11,865 | 9,534 | 19,559 | 16,336 |
(Earnings) Attributable to Valencia Non-controlling Interest | 0 | 0 | 0 | 0 |
Preferred Stock Dividend Requirements of Subsidiary | 0 | 0 | 0 | 0 |
Net Earnings Attributable to PNMR | 11,865 | 9,534 | 19,559 | 16,336 |
Net Earnings Available for PNM Common Stock | $ 11,865 | $ 9,534 | $ 19,559 | $ 16,336 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Net Earnings | $ 35,655 | $ 33,181 | $ 53,508 | $ 49,312 |
Net earnings | 31,673 | 29,141 | 46,013 | 41,609 |
Unrealized Gain on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | (413) | 3,999 | 3,744 | 6,046 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (5,087) | (3,397) | (7,624) | (5,369) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 905 | 780 | 1,810 | 1,560 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Change in fair market value, net of income tax (expense) benefit | 0 | 0 | 0 | (100) |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) | 0 | 79 | 0 | 115 |
Net change after income taxes | (4,595) | 1,461 | (2,070) | 2,252 |
Comprehensive Income | 31,060 | 34,642 | 51,438 | 51,564 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,850) | (3,908) | (7,231) | (7,439) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (264) | (264) |
Comprehensive Income Attributable to PNMR | 27,078 | 30,602 | 43,943 | 43,861 |
Public Service Company of New Mexico [Member] | ||||
Net Earnings | 25,363 | 24,254 | 38,866 | 35,460 |
Net earnings | 21,513 | 20,346 | 31,635 | 28,021 |
Unrealized Gain on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | (413) | 3,999 | 3,744 | 6,046 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (5,087) | (3,397) | (7,624) | (5,369) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 905 | 780 | 1,810 | 1,560 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Net change after income taxes | (4,595) | 1,382 | (2,070) | 2,237 |
Comprehensive Income | 20,768 | 25,636 | 36,796 | 37,697 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,850) | (3,908) | (7,231) | (7,439) |
Comprehensive Income Attributable to PNMR | 16,918 | 21,728 | 29,565 | 30,258 |
Texas-New Mexico Power Company [Member] | ||||
Net Earnings | 11,865 | 9,534 | 19,559 | 16,336 |
Net earnings | 11,865 | 9,534 | 19,559 | 16,336 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Change in fair market value, net of income tax (expense) benefit | 0 | 0 | 0 | (100) |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) | 0 | 79 | 0 | 115 |
Net change after income taxes | 0 | 79 | 0 | 15 |
Comprehensive Income Attributable to PNMR | $ 11,865 | $ 9,613 | $ 19,559 | $ 16,351 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Unrealized holding gains (losses) arising during the period, income tax benefit (expense) | $ 266 | $ (2,602) | $ (2,413) | $ (3,809) |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense (benefit) | 3,278 | 2,210 | 4,913 | 3,488 |
Pension liability adjustment, income tax (expense) benefit | (583) | (508) | (1,166) | (1,016) |
Change in fair market value, income tax benefit (expense) | 0 | 0 | 0 | 53 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | 0 | (42) | 0 | (61) |
Public Service Company of New Mexico [Member] | ||||
Unrealized holding gains (losses) arising during the period, income tax benefit (expense) | 266 | (2,602) | (2,413) | (3,809) |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense (benefit) | 3,278 | 2,210 | 4,913 | 3,488 |
Pension liability adjustment, income tax (expense) benefit | (583) | (508) | (1,166) | (1,016) |
Texas-New Mexico Power Company [Member] | ||||
Change in fair market value, income tax benefit (expense) | 0 | 0 | 0 | 53 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | $ 0 | $ (42) | $ 0 | $ (61) |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Cash Flows From Operating Activities: | ||
Net Earnings | $ 53,508 | $ 49,312 |
Net earnings | 46,013 | 41,609 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 108,891 | 103,436 |
Deferred income tax expense | 26,675 | 24,252 |
Net unrealized (gains) losses on commodity derivatives | 6,127 | 3,187 |
Realized (gains) on available-for-sale securities | (9,580) | (7,272) |
Stock based compensation expense | 2,761 | 3,399 |
Regulatory disallowances | 1,744 | 0 |
Other, net | (1,926) | 38 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (20,899) | (17,543) |
Materials, supplies, and fuel stock | (8,285) | 6,346 |
Other current assets | 16,342 | (20,688) |
Other assets | 8,062 | 18,237 |
Accounts payable | (20,777) | (29,384) |
Accrued interest and taxes | (4,380) | (2,830) |
Other current liabilities | (10,195) | (3,341) |
Other liabilities | (38,394) | (3,343) |
Net cash flows from operating activities | 109,674 | 123,806 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (232,964) | (160,893) |
Proceeds from sales of available-for-sale securities | 94,522 | 53,119 |
Purchases of available-for-sale securities | (94,905) | (54,338) |
Return of principal on PVNGS lessor notes | 14,188 | 10,231 |
Other, net | 2,694 | 750 |
Net cash flows from investing activities | (216,465) | (151,131) |
Cash Flows From Financing Activities: | ||
Short-term borrowings (repayments), net | 82,000 | (44,200) |
Long-term borrowings | 214,300 | 255,000 |
Repayment of long-term debt | (158,066) | (125,000) |
Proceeds from stock option exercise | 7,347 | 4,446 |
Awards of common stock | (18,814) | (13,939) |
Dividends paid | (32,125) | (29,732) |
Valencia’s transactions with its owner | (7,614) | (8,189) |
Other, net | (2,107) | (1,482) |
Net cash flows from financing activities | 84,921 | 36,904 |
Change in Cash and Cash Equivalents | (21,870) | 9,579 |
Cash and Cash Equivalents at Beginning of Period | 28,274 | 2,533 |
Cash and Cash Equivalents at End of Period | 6,404 | 12,112 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 56,309 | 54,712 |
Income taxes paid (refunded), net | (1,231) | (2,534) |
Supplemental schedule of noncash investing activities: | ||
Changes in accrued plant additions | (743) | (7,909) |
Public Service Company of New Mexico [Member] | ||
Cash Flows From Operating Activities: | ||
Net Earnings | 38,866 | 35,460 |
Net earnings | 31,635 | 28,021 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 73,701 | 71,327 |
Deferred income tax expense | 18,464 | 19,716 |
Net unrealized (gains) losses on commodity derivatives | 6,127 | 3,187 |
Realized (gains) on available-for-sale securities | (9,580) | (7,272) |
Regulatory disallowances | 1,744 | 0 |
Other, net | (2,958) | 193 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (15,283) | (13,885) |
Materials, supplies, and fuel stock | (7,860) | 6,447 |
Other current assets | 15,882 | (22,588) |
Other assets | 7,568 | 18,790 |
Accounts payable | (21,315) | (26,737) |
Accrued interest and taxes | 412 | (1,575) |
Other current liabilities | (3,259) | 3,943 |
Other liabilities | (34,729) | (3,193) |
Net cash flows from operating activities | 67,780 | 83,813 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (172,937) | (92,567) |
Proceeds from sales of available-for-sale securities | 94,522 | 53,119 |
Purchases of available-for-sale securities | (94,905) | (54,338) |
Return of principal on PVNGS lessor notes | 14,188 | 10,231 |
Other, net | 2,859 | (70) |
Net cash flows from investing activities | (156,273) | (83,625) |
Cash Flows From Financing Activities: | ||
Short-term borrowings (repayments), net | 51,100 | (49,200) |
Short-term borrowings (repayments), affiliate, net | 0 | (32,500) |
Long-term borrowings | 64,300 | 175,000 |
Repayment of long-term debt | (39,300) | (75,000) |
Dividends paid | (264) | (264) |
Valencia’s transactions with its owner | (7,614) | (8,189) |
Other, net | (1,659) | (700) |
Net cash flows from financing activities | 66,563 | 9,147 |
Change in Cash and Cash Equivalents | (21,930) | 9,335 |
Cash and Cash Equivalents at Beginning of Period | 25,480 | 21 |
Cash and Cash Equivalents at End of Period | 3,550 | 9,356 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 36,977 | 36,601 |
Income taxes paid (refunded), net | (1,450) | (215) |
Supplemental schedule of noncash investing activities: | ||
Changes in accrued plant additions | (2,813) | (5,595) |
Texas-New Mexico Power Company [Member] | ||
Cash Flows From Operating Activities: | ||
Net Earnings | 19,559 | 16,336 |
Net earnings | 19,559 | 16,336 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 27,839 | 25,728 |
Deferred income tax expense | 6,175 | 6,162 |
Other, net | (90) | (38) |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (5,616) | (3,658) |
Materials, supplies, and fuel stock | (425) | (101) |
Other current assets | (1,264) | (803) |
Other assets | 68 | (273) |
Accounts payable | 385 | 1,381 |
Accrued interest and taxes | (173) | (726) |
Other current liabilities | 2,530 | 2,167 |
Other liabilities | (4,132) | 365 |
Net cash flows from operating activities | 44,856 | 46,540 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (50,256) | (64,502) |
Net cash flows from investing activities | (50,256) | (64,502) |
Cash Flows From Financing Activities: | ||
Short-term borrowings (repayments), net | 24,000 | 0 |
Short-term borrowings (repayments), affiliate, net | (18,600) | (4,200) |
Long-term borrowings | 0 | 80,000 |
Repayment of long-term debt | 0 | (50,000) |
Dividends paid | 0 | (6,803) |
Other, net | 0 | (783) |
Net cash flows from financing activities | 5,400 | 18,214 |
Change in Cash and Cash Equivalents | 0 | 252 |
Cash and Cash Equivalents at Beginning of Period | 1 | 1 |
Cash and Cash Equivalents at End of Period | 1 | 253 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 12,990 | 11,847 |
Income taxes paid (refunded), net | 950 | (304) |
Supplemental schedule of noncash investing activities: | ||
Changes in accrued plant additions | $ (2,311) | $ (1,038) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 6,404 | $ 28,274 |
Accounts receivable, net of allowance for uncollectible accounts | 94,703 | 87,038 |
Unbilled revenues | 75,527 | 63,719 |
Other receivables | 30,027 | 39,857 |
Materials, supplies, and fuel stock | 71,913 | 63,628 |
Regulatory assets | 23,142 | 47,855 |
Commodity derivative instruments | 4,550 | 11,232 |
Income taxes receivable | 5,934 | 6,360 |
Current portion of accumulated deferred income taxes | 26,383 | 26,383 |
Other current assets | 71,482 | 58,471 |
Total current assets | 410,065 | 432,817 |
Other Property and Investments: | ||
Investment in PVNGS lessor notes | 0 | 9,538 |
Available-for-sale securities | 253,550 | 250,145 |
Other investments | 507 | 1,762 |
Non-utility property | 3,404 | 3,406 |
Total other property and investments | 257,461 | 264,851 |
Utility Plant: | ||
Plant in service and plant held for future use | 6,085,078 | 5,941,581 |
Less accumulated depreciation and amortization | 2,017,711 | 1,939,760 |
Net plant in service and plant held for future use | 4,067,367 | 4,001,821 |
Construction work in progress | 261,049 | 190,389 |
Nuclear fuel, net of accumulated amortization | 81,275 | 77,796 |
Net utility plant | 4,409,691 | 4,270,006 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 474,426 | 491,007 |
Goodwill | 278,297 | 278,297 |
Other deferred charges | 97,078 | 92,347 |
Total deferred charges and other assets | 849,801 | 861,651 |
Total assets | 5,927,018 | 5,829,325 |
Current Liabilities: | ||
Short-term debt | 187,600 | 105,600 |
Current installments of long-term debt | 300,000 | 333,066 |
Accounts payable | 88,509 | 110,029 |
Customer deposits | 12,711 | 12,555 |
Accrued interest and taxes | 49,452 | 53,863 |
Regulatory liabilities | 2,202 | 1,703 |
Commodity derivative instruments | 1,153 | 1,209 |
Dividends declared | 132 | 16,063 |
Other current liabilities | 59,345 | 70,194 |
Total current liabilities | 701,104 | 704,282 |
Long-term Debt | 1,731,158 | 1,642,024 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 918,519 | 891,111 |
Regulatory liabilities | 470,558 | 466,143 |
Asset retirement obligations | 108,406 | 104,170 |
Accrued pension liability and postretirement benefit cost | 70,583 | 110,738 |
Commodity derivative instruments | 0 | 477 |
Other deferred credits | 101,282 | 103,759 |
Total deferred credits and other liabilities | 1,669,348 | 1,676,398 |
Total liabilities | $ 4,101,610 | $ 4,022,704 |
Commitments and Contingencies (See Note 11) | ||
Cumulative preferred stock of subsidiary without mandatory redemption requirements | $ 11,529 | $ 11,529 |
Company common stockholders’ equity: | ||
Common stock outstanding | 1,165,003 | 1,173,845 |
Accumulated other comprehensive income (loss), net of income taxes | (63,825) | (61,755) |
Retained earnings | 639,538 | 609,456 |
Total Company common stockholders' equity | 1,740,716 | 1,721,546 |
Non-controlling interest in Valencia | 73,163 | 73,546 |
Total equity | 1,813,879 | 1,795,092 |
Total liabilities and stockholders' equity | 5,927,018 | 5,829,325 |
Public Service Company of New Mexico [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 3,550 | 25,480 |
Accounts receivable, net of allowance for uncollectible accounts | 70,342 | 67,622 |
Unbilled revenues | 65,277 | 54,140 |
Other receivables | 29,751 | 37,622 |
Affiliate receivables | 10,746 | 8,853 |
Materials, supplies, and fuel stock | 68,719 | 60,859 |
Regulatory assets | 17,699 | 43,980 |
Commodity derivative instruments | 4,550 | 11,232 |
Income taxes receivable | 5,816 | 6,105 |
Current portion of accumulated deferred income taxes | 12,418 | 12,418 |
Other current assets | 64,082 | 53,095 |
Total current assets | 352,950 | 381,406 |
Other Property and Investments: | ||
Investment in PVNGS lessor notes | 0 | 9,538 |
Available-for-sale securities | 253,550 | 250,145 |
Other investments | 265 | 397 |
Non-utility property | 96 | 96 |
Total other property and investments | 253,911 | 260,176 |
Utility Plant: | ||
Plant in service and plant held for future use | 4,698,267 | 4,581,066 |
Less accumulated depreciation and amortization | 1,542,034 | 1,486,406 |
Net plant in service and plant held for future use | 3,156,233 | 3,094,660 |
Construction work in progress | 217,860 | 169,673 |
Nuclear fuel, net of accumulated amortization | 81,275 | 77,796 |
Net utility plant | 3,455,368 | 3,342,129 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 344,472 | 357,045 |
Goodwill | 51,632 | 51,632 |
Other deferred charges | 85,946 | 81,264 |
Total deferred charges and other assets | 482,050 | 489,941 |
Total assets | 4,544,279 | 4,473,652 |
Current Liabilities: | ||
Short-term debt | 51,100 | 0 |
Current installments of long-term debt | 300,000 | 214,300 |
Accounts payable | 67,553 | 86,055 |
Affiliate payables | 20,991 | 18,232 |
Customer deposits | 12,711 | 12,555 |
Accrued interest and taxes | 29,817 | 29,298 |
Regulatory liabilities | 2,202 | 1,703 |
Commodity derivative instruments | 1,153 | 1,209 |
Dividends declared | 20,132 | 132 |
Other current liabilities | 45,276 | 52,053 |
Total current liabilities | 550,935 | 415,537 |
Long-term Debt | 1,215,676 | 1,276,357 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 734,871 | 715,814 |
Regulatory liabilities | 431,552 | 425,481 |
Asset retirement obligations | 107,377 | 103,182 |
Accrued pension liability and postretirement benefit cost | 63,340 | 102,850 |
Commodity derivative instruments | 0 | 477 |
Other deferred credits | 83,679 | 86,023 |
Total deferred credits and other liabilities | 1,420,819 | 1,433,827 |
Total liabilities | $ 3,187,430 | $ 3,125,721 |
Commitments and Contingencies (See Note 11) | ||
Cumulative preferred stock of subsidiary without mandatory redemption requirements | $ 11,529 | $ 11,529 |
Company common stockholders’ equity: | ||
Common stock outstanding | 1,061,776 | 1,061,776 |
Accumulated other comprehensive income (loss), net of income taxes | (63,825) | (61,755) |
Retained earnings | 274,206 | 262,835 |
Total Company common stockholders' equity | 1,272,157 | 1,262,856 |
Non-controlling interest in Valencia | 73,163 | 73,546 |
Total equity | 1,345,320 | 1,336,402 |
Total liabilities and stockholders' equity | 4,544,279 | 4,473,652 |
Texas-New Mexico Power Company [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 1 | 1 |
Accounts receivable, net of allowance for uncollectible accounts | 24,361 | 19,416 |
Unbilled revenues | 10,250 | 9,579 |
Other receivables | 712 | 2,063 |
Materials, supplies, and fuel stock | 3,194 | 2,769 |
Regulatory assets | 5,443 | 3,875 |
Current portion of accumulated deferred income taxes | 6,398 | 6,398 |
Other current assets | 2,117 | 938 |
Total current assets | 52,476 | 45,039 |
Other Property and Investments: | ||
Other investments | 242 | 242 |
Non-utility property | 2,240 | 2,240 |
Total other property and investments | 2,482 | 2,482 |
Utility Plant: | ||
Plant in service and plant held for future use | 1,207,232 | 1,182,112 |
Less accumulated depreciation and amortization | 391,169 | 375,407 |
Net plant in service and plant held for future use | 816,063 | 806,705 |
Construction work in progress | 32,149 | 16,538 |
Net utility plant | 848,212 | 823,243 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 129,954 | 133,962 |
Goodwill | 226,665 | 226,665 |
Other deferred charges | 9,073 | 8,850 |
Total deferred charges and other assets | 365,692 | 369,477 |
Total assets | 1,268,862 | 1,240,241 |
Current Liabilities: | ||
Short-term debt | 29,000 | 5,000 |
Short-term debt – affiliate | 4,100 | 22,700 |
Accounts payable | 12,277 | 14,203 |
Affiliate payables | 4,123 | 2,469 |
Accrued interest and taxes | 28,401 | 28,574 |
Dividends declared | 7,694 | 0 |
Other current liabilities | 3,116 | 2,271 |
Total current liabilities | 88,711 | 75,217 |
Long-term Debt | 365,482 | 365,667 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 224,260 | 217,945 |
Regulatory liabilities | 39,006 | 40,662 |
Asset retirement obligations | 884 | 848 |
Accrued pension liability and postretirement benefit cost | 7,243 | 7,888 |
Other deferred credits | 6,746 | 7,349 |
Total deferred credits and other liabilities | 278,139 | 274,692 |
Total liabilities | $ 732,332 | $ 715,576 |
Commitments and Contingencies (See Note 11) | ||
Company common stockholders’ equity: | ||
Common stock outstanding | $ 64 | $ 64 |
Paid-in-capital | 404,166 | 404,166 |
Retained earnings | 132,300 | 120,435 |
Total Company common stockholders' equity | 536,530 | 524,665 |
Total liabilities and stockholders' equity | $ 1,268,862 | $ 1,240,241 |
Condensed Consolidated Balance7
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Allowance for uncollectible accounts | $ 1,363 | $ 1,466 |
Accumulated depreciation, nuclear fuel | $ 45,138 | $ 44,507 |
Cumulative preferred stock of subsidiary, stated value | $ 100 | $ 100 |
Cumulative preferred stock of subsidiary, shares authorized | 10,000,000 | 10,000,000 |
Cumulative preferred stock of subsidiary, shares issued | 115,293 | 115,293 |
Cumulative preferred stock of subsidiary, shares outstanding | 115,293 | 115,293 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 120,000,000 | 120,000,000 |
Common stock, shares issued | 79,653,624 | 79,653,624 |
Common stock, shares outstanding | 79,653,624 | 79,653,624 |
Public Service Company of New Mexico [Member] | ||
Allowance for uncollectible accounts | $ 1,363 | $ 1,466 |
Accumulated depreciation, nuclear fuel | $ 45,138 | $ 44,507 |
Cumulative preferred stock, stated value | $ 100 | $ 100 |
Cumulative preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Cumulative preferred stock, shares issued | 115,293 | 115,293 |
Cumulative preferred stock, shares outstanding | 115,293 | 115,293 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares issued | 39,117,799 | 39,117,799 |
Common stock, shares outstanding | 39,117,799 | 39,117,799 |
Texas-New Mexico Power Company [Member] | ||
Common stock, par value | $ 10 | $ 10 |
Common stock, shares authorized | 12,000,000 | 12,000,000 |
Common stock, shares issued | 6,358 | 6,358 |
Common stock, shares outstanding | 6,358 | 6,358 |
Condensed Consolidated Stateme8
Condensed Consolidated Statement of Changes in Equity - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands | Total | Parent [Member] | Common Stock [Member] | AOCI [Member] | Retained Earnings [Member] | Non-controlling Interest in Valencia [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member]Parent [Member] | Public Service Company of New Mexico [Member]Common Stock [Member] | Public Service Company of New Mexico [Member]AOCI [Member] | Public Service Company of New Mexico [Member]Retained Earnings [Member] | Public Service Company of New Mexico [Member]Non-controlling Interest in Valencia [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member]Common Stock [Member] | Texas-New Mexico Power Company [Member]Additional Paid-in Capital [Member] | Texas-New Mexico Power Company [Member]Retained Earnings [Member] |
Beginning balance at Dec. 31, 2014 | $ 1,795,092 | $ 1,721,546 | $ 1,173,845 | $ (61,755) | $ 609,456 | $ 73,546 | $ 1,336,402 | $ 1,262,856 | $ 1,061,776 | $ (61,755) | $ 262,835 | $ 73,546 | ||||
Beginning balance TNMP at Dec. 31, 2014 | 1,721,546 | 1,262,856 | $ 524,665 | $ 64 | $ 404,166 | $ 120,435 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Proceeds from stock option exercise | 7,347 | 7,347 | 7,347 | |||||||||||||
Awards of common stock | (18,814) | (18,814) | (18,814) | |||||||||||||
Excess tax (shortfall) from stock-based payment arrangements | (136) | (136) | (136) | |||||||||||||
Stock based compensation expense | 2,761 | 2,761 | 2,761 | |||||||||||||
Valencia’s transactions with its owner | (7,614) | (7,614) | (7,614) | (7,614) | ||||||||||||
Net Earnings | 53,508 | 46,277 | 46,277 | 7,231 | 38,866 | 31,635 | 0 | 31,635 | $ 7,231 | 19,559 | ||||||
Net earnings | 46,013 | 31,635 | 19,559 | 19,559 | ||||||||||||
Subsidiary preferred stock dividends | (264) | (264) | (264) | |||||||||||||
Total other comprehensive income | (2,070) | (2,070) | (2,070) | (2,070) | (2,070) | (2,070) | 0 | 0 | ||||||||
Dividends declared on common stock | (15,931) | (15,931) | (15,931) | (20,000) | (20,000) | 0 | (20,000) | (7,694) | (7,694) | |||||||
Dividends declared on preferred stock | (264) | (264) | 0 | (264) | ||||||||||||
Ending balance at Jun. 30, 2015 | 1,813,879 | $ 1,740,716 | $ 1,165,003 | $ (63,825) | $ 639,538 | $ 73,163 | 1,345,320 | $ 1,272,157 | $ 1,061,776 | $ (63,825) | $ 274,206 | $ 73,163 | ||||
Ending balance TNMP at Jun. 30, 2015 | $ 1,740,716 | $ 1,272,157 | $ 536,530 | $ 64 | $ 404,166 | $ 132,300 |
Significant Accounting Policies
Significant Accounting Policies and Responsibility for Financial Statements | 6 Months Ended |
Jun. 30, 2015 | |
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 June 30, 2015 and December 31, 2014 and the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2015 and 2014 , and the consolidated cash flows for the six months ended June 30, 2015 and 2014 . 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 2014 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 financial statement presentation. These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual 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 2014 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 began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. 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’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14. Dividends on Common Stock Dividends on PNMR’s common stock are declared by its 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 considered to be 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 considered to be for the second quarter of $0.200 per share in July 2015 and $0.185 in July 2014, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. PNM and TNMP declared cash dividends on common stock to PNMR of $20.0 million and $7.7 million in June 2015 that were paid on July 1, 2015. PNM declared no dividends on its common stock in the six months ended June 30, 2014. TNMP declared and paid cash dividends of $6.8 million in the six months ended June 30, 2014. New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606) On May 28, 2014, the FASB issued ASU No. 2014-09. 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. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard was to be effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. On July 9, 2015, the FASB approved a one-year deferral in the effective date of ASU 2014-09, with early adoption as of the original effective date permitted. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is analyzing the impacts of this new standard. Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at June 30, 2015 , amounted to $11.8 million for PNMR, $7.5 million for PNM, and $4.2 million for TNMP. Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a material impact on the financial statements other than the disclosure and presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient. |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2015 | |
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 Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 31,673 $ 29,141 $ 46,013 $ 41,609 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 99 110 105 146 Average Shares – Basic 79,753 79,764 79,759 79,800 Dilutive Effect of Common Stock Equivalents (1) : Stock options and restricted stock 380 464 384 508 Average Shares – Diluted 80,133 80,228 80,143 80,308 Net Earnings Per Share of Common Stock: Basic $ 0.40 $ 0.37 $ 0.58 $ 0.52 Diluted $ 0.40 $ 0.36 $ 0.57 $ 0.52 (1) Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015 . |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2015 | |
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 provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates. TNMP TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. Corporate and Other The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. 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 Consolidated (In thousands) Three Months Ended June 30, 2015 Electric operating revenues $ 275,450 $ 77,437 $ — $ 352,887 Cost of energy 95,728 18,310 — 114,038 Margin 179,722 59,127 — 238,849 Other operating expenses 103,541 20,807 (3,962 ) 120,386 Depreciation and amortization 29,002 13,591 3,456 46,049 Operating income (loss) 47,179 24,729 506 72,414 Interest income 1,946 — (5 ) 1,941 Other income (deductions) 7,446 793 (673 ) 7,566 Net interest charges (19,681 ) (6,856 ) (2,376 ) (28,913 ) Segment earnings (loss) before income taxes 36,890 18,666 (2,548 ) 53,008 Income taxes (benefit) 11,527 6,801 (975 ) 17,353 Segment earnings (loss) 25,363 11,865 (1,573 ) 35,655 Valencia non-controlling interest (3,850 ) — — (3,850 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 21,381 $ 11,865 $ (1,573 ) $ 31,673 Six Months Ended June 30, 2015 Electric operating revenues $ 537,390 $ 148,365 $ — $ 685,755 Cost of energy 193,594 36,089 — 229,683 Margin 343,796 112,276 — 456,072 Other operating expenses 207,557 42,567 (7,546 ) 242,578 Depreciation and amortization 57,405 27,049 7,056 91,510 Operating income 78,834 42,660 490 121,984 Interest income 3,717 — (26 ) 3,691 Other income (deductions) 13,257 2,084 (2,452 ) 12,889 Net interest charges (39,640 ) (13,781 ) (5,765 ) (59,186 ) Segment earnings (loss) before income taxes 56,168 30,963 (7,753 ) 79,378 Income taxes (benefit) 17,302 11,404 (2,836 ) 25,870 Segment earnings (loss) 38,866 19,559 (4,917 ) 53,508 Valencia non-controlling interest (7,231 ) — — (7,231 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 31,371 $ 19,559 $ (4,917 ) $ 46,013 At June 30, 2015: Total Assets $ 4,544,279 $ 1,268,862 $ 113,877 $ 5,927,018 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other Consolidated (In thousands) Three Months Ended June 30, 2014 Electric operating revenues $ 275,704 $ 70,456 $ — $ 346,160 Cost of energy 92,642 16,777 — 109,419 Margin 183,062 53,679 — 236,741 Other operating expenses 106,233 20,411 (3,362 ) 123,282 Depreciation and amortization 27,023 12,003 3,137 42,163 Operating income 49,806 21,265 225 71,296 Interest income 2,065 — (25 ) 2,040 Other income (deductions) 5,512 514 (316 ) 5,710 Net interest charges (20,023 ) (6,655 ) (3,294 ) (29,972 ) Segment earnings (loss) before income taxes 37,360 15,124 (3,410 ) 49,074 Income taxes (benefit) 13,106 5,590 (2,803 ) 15,893 Segment earnings (loss) 24,254 9,534 (607 ) 33,181 Valencia non-controlling interest (3,908 ) — — (3,908 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 20,214 $ 9,534 $ (607 ) $ 29,141 Six Months Ended June 30, 2014 Electric operating revenues $ 538,441 $ 136,616 $ — $ 675,057 Cost of energy 189,268 32,765 — 222,033 Margin 349,173 103,851 — 453,024 Other operating expenses 213,957 41,481 (6,593 ) 248,845 Depreciation and amortization 54,105 23,844 6,181 84,130 Operating income 81,111 38,526 412 120,049 Interest income 4,193 — (35 ) 4,158 Other income (deductions) 7,180 702 (958 ) 6,924 Net interest charges (39,835 ) (13,252 ) (6,419 ) (59,506 ) Segment earnings (loss) before income taxes 52,649 25,976 (7,000 ) 71,625 Income taxes (benefit) 17,189 9,640 (4,516 ) 22,313 Segment earnings (loss) 35,460 16,336 (2,484 ) 49,312 Valencia non-controlling interest (7,439 ) — — (7,439 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 27,757 $ 16,336 $ (2,484 ) $ 41,609 At June 30, 2014: Total Assets $ 4,290,529 $ 1,208,517 $ 105,146 $ 5,604,192 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 6 Months Ended |
Jun. 30, 2015 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2015 and 2014 is as follows: Accumulated Other Comprehensive Income (Loss) PNM TNMP PNMR Unrealized Fair Value Gain on Pension Adjustment Available-for- Liability for Cash Flow Sale Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2014 $ 28,008 $ (89,763 ) $ (61,755 ) $ — $ (61,755 ) Amounts reclassified from AOCI (pre-tax) (12,537 ) 2,976 (9,561 ) — (9,561 ) Income tax impact of amounts reclassified 4,913 (1,166 ) 3,747 — 3,747 Other OCI changes (pre-tax) 6,157 — 6,157 — 6,157 Income tax impact of other OCI changes (2,413 ) — (2,413 ) — (2,413 ) Net change after income taxes (3,880 ) 1,810 (2,070 ) — (2,070 ) Balance at June 30, 2015 $ 24,128 $ (87,953 ) $ (63,825 ) $ — $ (63,825 ) Balance at December 31, 2013 $ 25,748 $ (83,625 ) $ (57,877 ) $ (263 ) $ (58,140 ) Amounts reclassified from AOCI (pre-tax) (8,857 ) 2,576 (6,281 ) 176 (6,105 ) Income tax impact of amounts reclassified 3,488 (1,016 ) 2,472 (61 ) 2,411 Other OCI changes (pre-tax) 9,855 — 9,855 (153 ) 9,702 Income tax impact of other OCI changes (3,809 ) — (3,809 ) 53 (3,756 ) Net change after income taxes 677 1,560 2,237 15 2,252 Balance at June 30, 2014 $ 26,425 $ (82,065 ) $ (55,640 ) $ (248 ) $ (55,888 ) Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the six months ended June 30, 2015 and 2014 , approximately 23.0% and 23.0% of the amount reclassified was capitalized into construction work in process and approximately 2.7% and 2.1% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings. |
Variable Interest Entities
Variable Interest Entities | 6 Months Ended |
Jun. 30, 2015 | |
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. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2014 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 operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and six months ended June 30, 2015 , PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.6 million for variable charges. For the three and six months ended June 30, 2014 , PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.7 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 obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity 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 the entity in its financial statements. 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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 (In thousands) Operating revenues $ 5,251 $ 5,307 $ 10,155 $ 10,238 Operating expenses (1,401 ) (1,399 ) (2,924 ) (2,799 ) Earnings attributable to non-controlling interest $ 3,850 $ 3,908 $ 7,231 $ 7,439 Financial Position June 30, December 31, 2015 2014 (In thousands) Current assets $ 3,284 $ 2,513 Net property, plant, and equipment 71,180 72,321 Total assets 74,464 74,834 Current liabilities 1,301 1,288 Owners’ equity – non-controlling interest $ 73,163 $ 73,546 During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million , prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia subsequently submitted a counter-proposal to PNM in April 2015. PNM is evaluating the terms of the counter-proposal. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed. PVNGS Leases PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provided PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provided PNM with options to renew the leases at fixed rates set forth in the leases for 2 years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional 6 years if the appraised remaining useful lives and fair value of the leased assets were greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of June 30, 2015 , these payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $150.5 million , including the renewal terms of the leases that PNM has elected to renew. Under certain circumstances (for example, final shutdown of the plant, 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 beneficial owners and take title to the leased interests. If such an event had occurred as of June 30, 2015 , PNM could have been required to pay the beneficial owners up to $217.3 million on July 15, 2015 in addition to the regularly scheduled lease payments. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $18.4 million at June 30, 2015 and $26.0 million at December 31, 2014 , which are included in other current liabilities on the Condensed Consolidated Balance Sheets. PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to renewal and purchase options, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. Rio Bravo, formerly known as Delta PNM had a 20 -year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease. In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. PNM changed the name of the facility to Rio Bravo. PNM made fixed and variable payments to Delta under the PPA. For the three and six months ended June 30, 2014 , PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.3 million and $0.5 million . PNM recovered the variable energy charges through its FPPAC. Delta informed PNM that for the three and six months ended June 30, 2014 its revenue was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million . PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM. |
Lease Commitments
Lease Commitments | 6 Months Ended |
Jun. 30, 2015 | |
Leases [Abstract] | |
Lease Commitments | Lease Commitments The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and, through April 1, 2015, an interest in the EIP transmission line. All of the Company’s leases are accounted for as operating leases. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, including information regarding renewal and purchase options, and actions taken by PNM 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 elected to purchase the assets underlying those leases on the expiration date of the original leases and has entered into agreements with the lessors that establish the purchase prices, representing the fair market value, to be paid on January 15, 2016 by PNM for the assets underlying the leases. The leases remain in existence and PNM will record the purchases at the termination of the leases on January 15, 2016. PNM will pay $78.1 million for the assets underlying one of the Unit 2 leases, which is for 31.25 MW of the entitlement from PVNGS Unit 2. PNM will pay $85.2 million for the assets underlying the other two Unit 2 leases, which are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the agreement regarding these two leases, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014, $83.4 million on June 30, 2015, and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014, $2.8 million on June 30, 2015, and declines to $1.2 million on January 14, 2016. Currently, PNMR does not anticipate that PNMR Development will exercise the early purchase option. At March 31, 2015, PNM owned 60% of the EIP and leased the other 40% , under a lease that expired on April 1, 2015. Following procedures set forth in the lease, PNM and the lessor entered into a definitive agreement for PNM to exercise its option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million . PNM closed on the purchase on April 1, 2015 and recorded the purchase at that date. |
Fair Value of Derivative and Ot
Fair Value of Derivative and Other Financial Instruments | 6 Months Ended |
Jun. 30, 2015 | |
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 Energy Related Derivative Contracts Overview The primary objective for the use of derivative instruments, including energy contracts, options, 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. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. 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. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Commodity Risk Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open 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 in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies. Accounting for Derivatives Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the six months ended June 30, 2015 and the year ended December 31, 2014, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The 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. The Company has no trading transactions. 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. Commodity Derivatives Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges June 30, December 31, PNMR and PNM (In thousands) Current assets $ 4,550 $ 11,232 4,550 11,232 Current liabilities (1,153 ) (1,209 ) Long-term liabilities — (477 ) (1,153 ) (1,686 ) Net $ 3,397 $ 9,546 Included in the above table are $1.5 million of current assets at June 30, 2015 and $3.0 million of current assets at December 31, 2014 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. 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. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at June 30, 2015 and December 31, 2014. At June 30, 2015 and December 31, 2014 , PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at June 30, 2015 and December 31, 2014 , amounts posted as cash collateral under margin arrangements were $1.6 million and $3.8 million for both PNMR and PNM. At June 30, 2015 and December 31, 2014, obligations to return cash collateral were $0.2 million and $0.2 million , for both PNMR and PNM. 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. The table above includes less than $0.1 million of current assets at June 30, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan. The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 PNMR and PNM (In thousands) Electric operating revenues $ 1,003 $ (324 ) $ 531 $ (4,475 ) Cost of energy (99 ) 57 (149 ) 245 Total gain (loss) $ 904 $ (267 ) $ 382 $ (4,230 ) Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh PNMR and PNM June 30, 2015 865,000 (968,305 ) December 31, 2014 650,000 (1,919,000 ) In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral. The table below presents information about the Company’s 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. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. Contingent Feature – Credit Rating Downgrade Contractual Liability Existing Cash Collateral Net Exposure (In thousands) PNMR and PNM June 30, 2015 $ 1,143 $ — $ 83 December 31, 2014 $ 1,686 $ — $ 167 Sale of Power from PVNGS Unit 3 Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011 , PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of June 30, 2015 , PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales. 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. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 11). At June 30, 2015 and December 31, 2014 , the fair value of available-for-sale securities included $247.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. June 30, 2015 December 31, 2014 Unrealized Gains Fair Value Unrealized Gains Fair Value PNMR and PNM (In thousands) Cash and cash equivalents $ — $ 3,940 $ — $ 8,276 Equity securities: Domestic value 15,015 45,750 17,418 45,340 Domestic growth 19,850 78,515 21,354 74,053 International and other 1,147 17,057 156 16,599 Fixed income securities: U.S. Government 276 30,421 903 22,563 Municipals 3,098 58,986 5,851 68,973 Corporate and other 411 18,881 666 14,341 $ 39,797 $ 253,550 $ 46,348 $ 250,145 The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM 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 change in realized impairment losses of $(1.2) million and $(0.8) million for the three and six months ended June 30, 2015 and $0.1 million and $0.6 million for the three and six months ended June 30, 2014. Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Proceeds from sales $ 62,670 $ 30,316 $ 94,522 $ 53,119 Gross realized gains $ 8,329 $ 5,364 $ 13,465 $ 8,482 Gross realized (losses) $ (1,578 ) $ (755 ) $ (3,119 ) $ (1,794 ) Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments. The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no securities impairments considered to be “other than temporary” included in AOCI. All such impairments have been recognized in earnings. At June 30, 2015 , the available-for-sale and held-to-maturity debt securities had the following final maturities: Fair Value Available-for-Sale Held-to-Maturity PNMR and PNM PNMR PNM (In thousands) Within 1 year $ 4,656 $ 17,230 $ 17,230 After 1 year through 5 years 21,533 639 — After 5 years through 10 years 22,577 — — After 10 years through 15 years 10,137 — — After 15 years through 20 years 10,727 — — After 20 years 38,658 — — $ 108,288 $ 17,869 $ 17,230 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. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. 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 three and six months ended June 30, 2015 and the year ended December 31, 2014 . For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. 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. 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. For investments categorized as Level 3, primarily the PVNGS lessor notes and certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are 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 on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at June 30, 2015 and December 31, 2014 for items recorded at fair value. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) June 30, 2015 (In thousands) PNMR and PNM Available-for-sale securities Cash and cash equivalents $ 3,940 $ 3,940 $ — Equity securities: Domestic value 45,750 45,750 — Domestic growth 78,515 78,515 — International and other 17,057 17,057 — Fixed income securities: U.S. Government 30,421 29,131 1,290 Municipals 58,986 — 58,986 Corporate and other 18,881 4,119 14,762 $ 253,550 $ 178,512 $ 75,038 Commodity derivative assets $ 4,550 $ — $ 4,550 Commodity derivative liabilities (1,153 ) — (1,153 ) Net $ 3,397 $ — $ 3,397 December 31, 2014 PNMR and PNM Available-for-sale securities Cash and cash equivalents $ 8,276 $ 8,276 $ — Equity securities: Domestic value 45,340 45,340 — Domestic growth 74,053 74,053 — International and other 16,599 16,599 — Fixed income securities: U.S. Government 22,563 20,808 1,755 Municipals 68,973 — 68,973 Corporate and other 14,341 4,843 9,498 $ 250,145 $ 169,919 $ 80,226 Commodity derivative assets $ 11,232 $ — $ 11,232 Commodity derivative liabilities (1,686 ) — (1,686 ) Net $ 9,546 $ — $ 9,546 The carrying amounts and fair values of investments in PVNGS lessor notes, 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 June 30, 2015 (In thousands) PNMR Long-term debt $ 2,031,158 $ 2,205,847 $ — $ 2,205,847 $ — Investment in PVNGS lessor notes $ 16,568 $ 17,230 $ — $ — $ 17,230 Other investments $ 507 $ 1,146 $ 507 $ — $ 639 PNM Long-term debt $ 1,515,676 $ 1,644,887 $ — $ 1,644,887 $ — Investment in PVNGS lessor notes $ 16,568 $ 17,230 $ — $ — $ 17,230 Other investments $ 265 $ 265 $ 265 $ — $ — TNMP Long-term debt $ 365,482 $ 410,961 $ — $ 410,961 $ — Other investments $ 242 $ 242 $ 242 $ — $ — December 31, 2014 PNMR Long-term debt $ 1,975,090 $ 2,173,117 $ — $ 2,173,117 $ — Investment in PVNGS lessor notes $ 31,232 $ 32,836 $ — $ — $ 32,836 Other investments $ 1,762 $ 2,375 $ 639 $ — $ 1,736 PNM Long-term debt $ 1,490,657 $ 1,624,222 $ — $ 1,624,222 $ — Investment in PVNGS lessor notes $ 31,232 $ 32,836 $ — $ — $ 32,836 Other investments $ 397 $ 397 $ 397 $ — $ — TNMP Long-term debt $ 365,667 $ 427,356 $ — $ 427,356 $ — Other investments $ 242 $ 242 $ 242 $ — $ — |
Stock-Based Compensation
Stock-Based Compensation | 6 Months Ended |
Jun. 30, 2015 | |
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. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. 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 2014 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, the awards vest ratably over three years from the grant date of the award. However, certain 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. The stock-based compensation expense related to restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period 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 June 30, 2015 and December 31, 2014 , PNMR had unrecognized expense related to stock awards of $7.8 million and $6.5 million . 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 grant date fair value for other restricted stock awards 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 following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Six Months Ended June 30, Restricted Shares and Performance Based Shares 2015 2014 Expected quarterly dividends per share $ 0.200 $ 0.185 Risk-free interest rate 0.92 % 0.62 % Market-Based Shares Dividend yield 2.87 % 2.82 % Expected volatility 18.73 % 25.11 % Risk-free interest rate 1.00 % 0.64 % The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the six months ended June 30, 2015 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2014 258,770 $ 22.31 920,505 $ 20.39 Granted 340,020 $ 20.34 — $ — Exercised (348,095 ) $ 18.59 (210,945 ) $ 20.07 Forfeited — $ — (1,000 ) $ 30.50 Expired — $ — (66,201 ) $ 27.90 Outstanding at June 30, 2015 250,695 $ 24.82 642,359 $ 19.51 PNMR’s stock-based compensation program provides for performance and market targets through 2017. Included as granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012 through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets at “target” levels, weighted at 60% , and performance targets at “maximum” levels, weighted at 40% ). Excluded from the above table, are maximums of 180,970 , 165,628 , and 168,258 shares for the three-year performance periods ending in 2015, 2016, and 2017 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible. In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015, which shares are included as granted and exercised in the above table. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement. 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 meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement. 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 would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement. At June 30, 2015 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $4.7 million with a weighted-average remaining contract life of 2.62 years. At June 30, 2015 , the exercise price of 245,950 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value. The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: Six Months Ended June 30, Restricted Stock 2015 2014 Weighted-average grant date fair value $ 20.34 $ 21.27 Total fair value of restricted shares that vested (in thousands) $ 6,470 $ 4,854 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) $ 1,759 $ 1,779 |
Financing
Financing | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Financing | Financing Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Financing Activities On March 5, 2014, PNM entered into a $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM 2013 Term Loan Agreement and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.14% at June 30, 2015 , must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision. On December 22, 2014, PNM entered into a multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million . PNM drew the remaining capacity of $25.0 million on May 8, 2015 resulting in outstanding borrowings at June 30, 2015 of $125.0 million , which are included in current maturities of long-term debt on the Condensed Consolidated Balance Sheet. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.77% at June 30, 2015. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw Term Loan Agreement has a cross default provision and a change of control provision. On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.19% at June 30, 2015 , and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNMR 2015 Term Loan Agreement has a cross default provision and a change of control provision. At December 31, 2014, PNMR had an aggregate outstanding principal amount of $118.8 million of its 9.25% Senior Unsecured Notes, Series A, which were due on May 15, 2015. PNMR repaid all of the 9.25% Senior Unsecured Notes, Series A at the scheduled maturity, utilizing proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility. At December 31, 2014, PNM had a $39.3 million series of outstanding Senior Unsecured Notes, Pollution Control Revenue Bonds, which have a final maturity of June 1, 2043. The PCRBs were subject to mandatory tender for remarketing on June 1, 2015 and were successfully remarketed on that date. The notes now bear interest at 2.40% , continue to have an outstanding amount of $39.3 million , and are subject to mandatory tender for remarketing on June 1, 2020. Short-term Debt 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 of these facilities mature on October 31, 2019 and provide for an additional one-year extension option, subject to approval by a majority of the lenders. 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. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At June 30, 2015 , TNMP had $4.1 million in borrowings from PNMR under its intercompany loan agreement. At June 30, 2015 , the weighted average interest rate was 1.69% for the PNMR Revolving Credit Facility, 1.44% for the PNM Revolving Credit Facility, 1.44% for the PNM New Mexico Credit Facility, 1.19% for the TNMP Revolving Credit Facility, and 1.04% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of: June 30, December 31, Short-term Debt 2015 2014 (In thousands) PNM: Revolving credit facility $ 31,100 $ — PNM New Mexico Credit Facility 20,000 — TNMP – Revolving credit facility 29,000 5,000 PNMR: Revolving credit facility 7,500 600 PNMR Term Loan Agreement 100,000 100,000 $ 187,600 $ 105,600 At July 24, 2015 , PNMR, PNM, and TNMP had $293.2 million , $353.6 million , and $42.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $30.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 24, 2015 , on a consolidated basis, was $719.7 million for PNMR. As of July 24, 2015 , PNM had $18.7 million and TNMP had $13.2 million in borrowings from PNMR under their intercompany loan agreements. At July 24, 2015 , PNMR, PNM and TNMP had consolidated invested cash of $1.9 million , none , and none . |
Pension and Other Postretiremen
Pension and Other Postretirement Benefit Plans | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [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. Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. PNM Plans The following tables present the components of the PNM Plans’ net periodic benefit cost: Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 51 $ 45 $ — $ — Interest cost 7,064 7,541 1,023 1,159 190 205 Expected return on plan assets (9,831 ) (9,511 ) (1,403 ) (1,410 ) — — Amortization of net (gain) loss 3,705 3,255 491 556 81 52 Amortization of prior service cost (241 ) (241 ) (160 ) (336 ) — — Net periodic benefit cost $ 697 $ 1,044 $ 2 $ 14 $ 271 $ 257 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 102 $ 91 $ — $ — Interest cost 14,127 15,082 2,045 2,315 380 411 Expected return on plan assets (19,662 ) (19,022 ) (2,805 ) (2,819 ) — — Amortization of net (gain) loss 7,410 6,510 983 1,113 162 105 Amortization of prior service cost (483 ) (483 ) (321 ) (672 ) — — Net periodic benefit cost $ 1,392 $ 2,087 $ 4 $ 28 $ 542 $ 516 PNM made contributions to its pension plan trust of zero and $30.0 million in the three and six months ended June 30, 2015 and made no contributions in the three and six months ended June 30, 2014. PNM does not anticipate making additional contributions to its pension trust in 2015 . Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2016-2019 are estimated to total $22.0 million . These anticipated contributions were developed using current funding assumptions, with discount rates of 4.8% to 5.5% . Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $1.6 million in the three and six months ended June 30, 2015 and $0.8 million and $1.6 million in the three and six months ended June 30, 2014. PNM expects to make contributions to the OPEB trust totaling $3.5 million in 2015 and $14.0 million for 2016-2019. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.9 million in the three and six months ended June 30, 2015 and $0.4 million and $0.7 million in the three and six months ended June 30, 2014 and are expected to total $1.5 million during 2015 . TNMP Plans The following tables present the components of the TNMP Plans’ net periodic benefit cost (income): Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost (Income) Service cost $ — $ — $ 62 $ 59 $ — $ — Interest cost 761 798 152 155 9 10 Expected return on plan assets (1,105 ) (1,132 ) (130 ) (133 ) — — Amortization of net (gain) loss 195 166 — (31 ) 1 — Amortization of prior service cost — — — 8 — — Net Periodic Benefit Cost (Income) $ (149 ) $ (168 ) $ 84 $ 58 $ 10 $ 10 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost (Income) Service cost $ — $ — $ 124 $ 119 $ — $ — Interest cost 1,521 1,597 304 309 18 20 Expected return on plan assets (2,210 ) (2,263 ) (260 ) (267 ) — — Amortization of net (gain) loss 391 333 — (61 ) 2 — Amortization of prior service cost — — — 16 — — Net Periodic Benefit Cost (Income) $ (298 ) $ (333 ) $ 168 $ 116 $ 20 $ 20 TNMP made no contribution to its pension trust in 2014 and does not anticipate making any contributions in 2015 -2019 based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These expectations were developed using current funding assumptions, including discount rates of 4.8% and 5.5% . 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 no contributions to the OPEB trust in the three and six months ended June 30, 2015 and $0.3 million in the three and six months ended June 30, 2014. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2015 and $1.4 million for 2016-2019. 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 six months ended June 30, 2015 and 2014 and are expected to total $0.1 million during 2015 . |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Overview There are various claims and lawsuits pending against the Company. The Company also 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. Nevertheless, 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, and 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 2014 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 D.C. 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. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement was $5.9 million , substantially all of which was credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a claim for costs paid between July 1, 2011 and June 30, 2014 and agreed to a settlement amount of $42.0 million in March 2015. PNM’s share of the settlement, which amounted to $4.3 million , including $3.1 million credited back to PNM’s customers, was recorded in the three months ended March 31, 2015. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement. PNM estimates that it will incur approximately $58.0 million (in 2013 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 fuel is consumed. At June 30, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.5 million and $12.3 million included in other deferred credits. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision. The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012. In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter. 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. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero . PNM anticipates challenges to this action and is unable to predict its ultimate outcome. 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. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states 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 is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018. SJGS BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP. PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties. During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014. Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….” Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million . The costs for the project to install SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA. Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3% . Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP. NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested: • Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs • A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018 • An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million • A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS The December 20, 2013 NMPRC filing identified a new 177 MW natural gas-fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. On June 30, 2015, PNM filed an application for a CCN for the gas facility, which is currently contemplated to be rated at 187 MW, to be located at SJGS. PNM estimates the cost of these identified resources would be approximately $212.5 million . These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements were memorialized in the resolution and term sheet described below. On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by other intervenors. Under the terms of the stipulation, PNM: • Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017 • Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million • Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at June 30, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $278 million • Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ( $1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at June 30, 2015, PNM’s net book value of PVNGS Unit 3 was approximately $147 million • Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million • Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that: • PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below • PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval • PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015 If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC and satisfaction of any material conditions precedent, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million . On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at its net book value on December 31, 2017, approval of recovery of an estimated $128.5 million , representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The certification recommends that the parties be given seven days to decide whether to accept any modifications after the NMPRC issues an order. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million . On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below. On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015. The order provided that PNM could request an extension of the required filing date to August 1, 2015 if such request was based on specific and verifiable facts. PNM subsequently requested an extension, citing that certain of the owners of SJGS were governmental entities and required the additional time in order to meet statutory public notice and meeting requirements. The NMPRC granted PNM an extension to August 1, 2015 to file the executed restructuring agreement. On July 1, 2015, PNM filed the executed coal supply and related agreements described under Coal Supply below with the NMPRC. On July 1, 2015, PNM also filed partially executed agreements related to restructuring discussed under SJGS Ownership Restructuring Matters below. On July 31, 2015, PNM filed fully executed restructuring agreements, along with testimony supporting the agreements and a CCN for the 132 MW of additional SJGS Unit 4 capacity. In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. A mediation process is on-going. A public hearing on PNM’s application concerning BART for SJGS is scheduled to begin on September 30, 2015. Although PNM expects a decision from the NMPRC in the fourth quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter. SJGS Ownership Restructuring Matters – As discussed in the 2014 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the currently effective contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4. The SJGS participants engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would 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, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7% . On September 2, 2014, the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022. In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014. On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS. On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into a Capacity Option and Funding Agreement (“COFA”), which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR guarantees the obligations of PNMR Development under the COFA. The COFA will terminate on the earliest of January 1, 2016, the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because ano |
Regulatory and Rate Matters
Regulatory and Rate Matters | 6 Months Ended |
Jun. 30, 2015 | |
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 2014 Annual Reports on Form 10-K. PNM 2014 Electric Rate Case On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million , effective January 1, 2016. PNM’s proposed ROE was 10.5% . The requested base rate increase, combined with other rate changes, represented an average bill increase of 7.69% . PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, was related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs was a contributing factor to the decline in PNM’s energy sales since the last rate case and accounted for the balance of the rate increase after accounting for offsetting cost reductions. PNM proposed several changes to 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 increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters. On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommended that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM could reapply for a general rate increase by remedying the files and providing other supporting documents. PNM did not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the future test year statute. PNM further argued that its application should be suspended, rather than dismissed. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application and dismissed PNM’s application. This NMPRC order did not address the Hearing Examiner’s recommendation regarding when a future test period could begin relative to a rate case application date. On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagrees with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application. On June 25, 2015, PNM filed a Notice of Appeal to the New Mexico Supreme Court, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the New Mexico Supreme Court to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the Supreme Court and ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at Supreme Court and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition and parameters of a FTY for rate cases. PNM opposes the motion. Responses to the motion are due August 17, 2015. On July 31, 2015, PNM and the NMPRC filed a joint motion for a limited 30-day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case; this motion is opposed by ABCWUA. Based on the above NMPRC rulings, PNM currently anticipates filing, in the third quarter of 2015, a new application with the NMPRC to increase rates. The contemplated rate request would be updated to include current circumstances. New rates would be expected to become effective in the third quarter of 2016. 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. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and 3% distributed generation. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they 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 filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million , a 20 -year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million , and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million . PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million . The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the 2014 Electric Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In the fourth quarter of 2014 and the second quarter of 2015, PNM procured the additional renewable resources to meet the 2013 and 2014 RPS requirement for $0.1 million and less than $0.1 million . The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. A public hearing on the 2016 procurement plan is scheduled to begin on September 1, 2015 and an order from the NMPRC is expected by November 30, 2015. PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Renewable Energy Rider The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next electric rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5% , PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million , reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015. PNM proposes to recover $42.4 million through the rider in 2016 in its 2016 renewable energy procurement plan. Energy Efficiency and Load Management Program Costs Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 recommending that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification. Upon approval, the stipulation established program budgets and the incentive amounts discussed below. Disincentives/Incentives The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing the NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million . In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million . PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved. Energy Efficiency Rulemaking On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. Integrated Resource Plan NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20 -year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. San Juan Generating Station Units 2 and 3 Retirement On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification, is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters. Four Corners Right of First Refusal On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. The ROFR expired unexercised 120 days from the date of the notice. Application for Certificate of Convenience and Necessity On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. PNM estimates the cost of the facility to be $133.2 million . PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party filed a motion to consolidate this case with the SJGS Unit 2 and 3 retirement case. The NMPRC has not yet acted on PNM’s application or on the motion. PNM cannot predict the outcome of this proceeding. Formula Transmission Rate Case In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula. On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement. Firm-Requirements Wholesale Customers Navopache Electric Cooperative, Inc. In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. On May 8, 2015, PNM filed an intervention with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA, and holding the hearing in abeyance to provide time for settlement judge procedures, which have begun. PNM is unable to predict the outcome of this matter. City of Gallup, New Mexico Contract PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million , which PNM recorded in other income during the three months ended June 30, 2015. TNMP Advanced Meter System Deployment In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12 -year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5 -year period. In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of July 24, 2015, 96 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows. Energy Efficiency TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.6 million , including a performance bonus for 2012 of $0.7 million , beginning March 1, 2014. On September 11, 2014, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.7 million beginning March 1, 2015, including a performance bonus for 2013 of $1.5 million . On May 29, 2015, TNMP filed its 2016 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.9 million , including a performance bonus of $0.6 million , to be collected beginning March 1, 2016. A hearing on the application is scheduled for August 28, 2015. TNMP records incentive bonuses upon approval by the PUCT. Transmission Cost of Service Rates TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s most recent interim transmission cost rate increases: Effective Date Approved Increase in Rate Base Annual Increase in Revenue (in millions) September 17, 2013 $ 18.1 $ 2.8 March 13, 2014 18.2 2.9 September 8, 2014 25.2 4.2 March 16, 2015 27.1 4.4 On July 17, 2015, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $7.0 million , which would increase revenues by $1.4 million annually. The application is pending before the PUCT. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce 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. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment 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 will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million , which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment. In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. As a result of the settlement, the Company received net federal tax refunds of $2.0 million . The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million , TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment. On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million , after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment. |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Services billings: PNMR to PNM $ 21,340 $ 22,190 $ 44,067 $ 43,256 PNMR to TNMP 6,591 6,963 13,680 14,224 PNM to TNMP 184 133 288 242 TNMP to PNMR — — — — Interest billings: PNMR to TNMP 54 83 133 180 PNMR to PNM 22 — 28 54 PNM to PNMR 26 25 55 51 Income tax sharing payments: PNMR to PNM — — 1,450 — PNMR to TNMP — — — — |
Goodwill
Goodwill | 6 Months Ended |
Jun. 30, 2015 | |
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. 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. PNMR's reporting units that have goodwill are PNM and TNMP. 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 would consider 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 had occurred. An entity would consider 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 should place 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 should consider 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 would evaluate, 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. 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, a quantitative analysis is not required. In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. 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, 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 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. 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. For the annual evaluations performed as of April 1, 2015 and 2014, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the 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 each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The annual evaluations performed as of April 1, 2015 and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2015 and 2014 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million , exceeded its carrying value by approximately 25% and 30% . The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million , exceeded its carrying value by approximately 26% . Since the April 1, 2015 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 20 of Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. |
Significant Accounting Polici24
Significant Accounting Policies and Responsibility for Financial Statements (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
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 began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. 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’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14. |
Dividends on Common Stock | Dividends on Common Stock Dividends on PNMR’s common stock are declared by its 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 considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. |
New Accounting Pronouncements | New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606) On May 28, 2014, the FASB issued ASU No. 2014-09. 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. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard was to be effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. On July 9, 2015, the FASB approved a one-year deferral in the effective date of ASU 2014-09, with early adoption as of the original effective date permitted. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is analyzing the impacts of this new standard. Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at June 30, 2015 , amounted to $11.8 million for PNMR, $7.5 million for PNM, and $4.2 million for TNMP. Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a material impact on the financial statements other than the disclosure and presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient. |
Consolidation, Variable Interest Entity | 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. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | Information regarding the computation of earnings per share is as follows: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 31,673 $ 29,141 $ 46,013 $ 41,609 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 99 110 105 146 Average Shares – Basic 79,753 79,764 79,759 79,800 Dilutive Effect of Common Stock Equivalents (1) : Stock options and restricted stock 380 464 384 508 Average Shares – Diluted 80,133 80,228 80,143 80,308 Net Earnings Per Share of Common Stock: Basic $ 0.40 $ 0.37 $ 0.58 $ 0.52 Diluted $ 0.40 $ 0.36 $ 0.57 $ 0.52 (1) Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015 . |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting 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 Consolidated (In thousands) Three Months Ended June 30, 2015 Electric operating revenues $ 275,450 $ 77,437 $ — $ 352,887 Cost of energy 95,728 18,310 — 114,038 Margin 179,722 59,127 — 238,849 Other operating expenses 103,541 20,807 (3,962 ) 120,386 Depreciation and amortization 29,002 13,591 3,456 46,049 Operating income (loss) 47,179 24,729 506 72,414 Interest income 1,946 — (5 ) 1,941 Other income (deductions) 7,446 793 (673 ) 7,566 Net interest charges (19,681 ) (6,856 ) (2,376 ) (28,913 ) Segment earnings (loss) before income taxes 36,890 18,666 (2,548 ) 53,008 Income taxes (benefit) 11,527 6,801 (975 ) 17,353 Segment earnings (loss) 25,363 11,865 (1,573 ) 35,655 Valencia non-controlling interest (3,850 ) — — (3,850 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 21,381 $ 11,865 $ (1,573 ) $ 31,673 Six Months Ended June 30, 2015 Electric operating revenues $ 537,390 $ 148,365 $ — $ 685,755 Cost of energy 193,594 36,089 — 229,683 Margin 343,796 112,276 — 456,072 Other operating expenses 207,557 42,567 (7,546 ) 242,578 Depreciation and amortization 57,405 27,049 7,056 91,510 Operating income 78,834 42,660 490 121,984 Interest income 3,717 — (26 ) 3,691 Other income (deductions) 13,257 2,084 (2,452 ) 12,889 Net interest charges (39,640 ) (13,781 ) (5,765 ) (59,186 ) Segment earnings (loss) before income taxes 56,168 30,963 (7,753 ) 79,378 Income taxes (benefit) 17,302 11,404 (2,836 ) 25,870 Segment earnings (loss) 38,866 19,559 (4,917 ) 53,508 Valencia non-controlling interest (7,231 ) — — (7,231 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 31,371 $ 19,559 $ (4,917 ) $ 46,013 At June 30, 2015: Total Assets $ 4,544,279 $ 1,268,862 $ 113,877 $ 5,927,018 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other Consolidated (In thousands) Three Months Ended June 30, 2014 Electric operating revenues $ 275,704 $ 70,456 $ — $ 346,160 Cost of energy 92,642 16,777 — 109,419 Margin 183,062 53,679 — 236,741 Other operating expenses 106,233 20,411 (3,362 ) 123,282 Depreciation and amortization 27,023 12,003 3,137 42,163 Operating income 49,806 21,265 225 71,296 Interest income 2,065 — (25 ) 2,040 Other income (deductions) 5,512 514 (316 ) 5,710 Net interest charges (20,023 ) (6,655 ) (3,294 ) (29,972 ) Segment earnings (loss) before income taxes 37,360 15,124 (3,410 ) 49,074 Income taxes (benefit) 13,106 5,590 (2,803 ) 15,893 Segment earnings (loss) 24,254 9,534 (607 ) 33,181 Valencia non-controlling interest (3,908 ) — — (3,908 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 20,214 $ 9,534 $ (607 ) $ 29,141 Six Months Ended June 30, 2014 Electric operating revenues $ 538,441 $ 136,616 $ — $ 675,057 Cost of energy 189,268 32,765 — 222,033 Margin 349,173 103,851 — 453,024 Other operating expenses 213,957 41,481 (6,593 ) 248,845 Depreciation and amortization 54,105 23,844 6,181 84,130 Operating income 81,111 38,526 412 120,049 Interest income 4,193 — (35 ) 4,158 Other income (deductions) 7,180 702 (958 ) 6,924 Net interest charges (39,835 ) (13,252 ) (6,419 ) (59,506 ) Segment earnings (loss) before income taxes 52,649 25,976 (7,000 ) 71,625 Income taxes (benefit) 17,189 9,640 (4,516 ) 22,313 Segment earnings (loss) 35,460 16,336 (2,484 ) 49,312 Valencia non-controlling interest (7,439 ) — — (7,439 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 27,757 $ 16,336 $ (2,484 ) $ 41,609 At June 30, 2014: Total Assets $ 4,290,529 $ 1,208,517 $ 105,146 $ 5,604,192 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 |
Accumulated Other Comprehensi27
Accumulated Other Comprehensive Income (Loss) (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2015 and 2014 is as follows: Accumulated Other Comprehensive Income (Loss) PNM TNMP PNMR Unrealized Fair Value Gain on Pension Adjustment Available-for- Liability for Cash Flow Sale Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2014 $ 28,008 $ (89,763 ) $ (61,755 ) $ — $ (61,755 ) Amounts reclassified from AOCI (pre-tax) (12,537 ) 2,976 (9,561 ) — (9,561 ) Income tax impact of amounts reclassified 4,913 (1,166 ) 3,747 — 3,747 Other OCI changes (pre-tax) 6,157 — 6,157 — 6,157 Income tax impact of other OCI changes (2,413 ) — (2,413 ) — (2,413 ) Net change after income taxes (3,880 ) 1,810 (2,070 ) — (2,070 ) Balance at June 30, 2015 $ 24,128 $ (87,953 ) $ (63,825 ) $ — $ (63,825 ) Balance at December 31, 2013 $ 25,748 $ (83,625 ) $ (57,877 ) $ (263 ) $ (58,140 ) Amounts reclassified from AOCI (pre-tax) (8,857 ) 2,576 (6,281 ) 176 (6,105 ) Income tax impact of amounts reclassified 3,488 (1,016 ) 2,472 (61 ) 2,411 Other OCI changes (pre-tax) 9,855 — 9,855 (153 ) 9,702 Income tax impact of other OCI changes (3,809 ) — (3,809 ) 53 (3,756 ) Net change after income taxes 677 1,560 2,237 15 2,252 Balance at June 30, 2014 $ 26,425 $ (82,065 ) $ (55,640 ) $ (248 ) $ (55,888 ) |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Variable Interest Entity [Line Items] | |
Noncontrolling Interest Summarized Financial Information | Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (In thousands) Operating revenues $ 5,251 $ 5,307 $ 10,155 $ 10,238 Operating expenses (1,401 ) (1,399 ) (2,924 ) (2,799 ) Earnings attributable to non-controlling interest $ 3,850 $ 3,908 $ 7,231 $ 7,439 Financial Position June 30, December 31, 2015 2014 (In thousands) Current assets $ 3,284 $ 2,513 Net property, plant, and equipment 71,180 72,321 Total assets 74,464 74,834 Current liabilities 1,301 1,288 Owners’ equity – non-controlling interest $ 73,163 $ 73,546 |
Fair Value of Derivative and 29
Fair Value of Derivative and Other Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value of Derivative and Other Financial Instruments [Line Items] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges June 30, December 31, PNMR and PNM (In thousands) Current assets $ 4,550 $ 11,232 4,550 11,232 Current liabilities (1,153 ) (1,209 ) Long-term liabilities — (477 ) (1,153 ) (1,686 ) Net $ 3,397 $ 9,546 |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 PNMR and PNM (In thousands) Electric operating revenues $ 1,003 $ (324 ) $ 531 $ (4,475 ) Cost of energy (99 ) 57 (149 ) 245 Total gain (loss) $ 904 $ (267 ) $ 382 $ (4,230 ) |
Schedule of Notional Amounts of Outstanding Derivative Positions | The table below presents PNMR’s and PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh PNMR and PNM June 30, 2015 865,000 (968,305 ) December 31, 2014 650,000 (1,919,000 ) |
Schedule of Collateral Related to Derivative | The table below presents information about the Company’s 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. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. Contingent Feature – Credit Rating Downgrade Contractual Liability Existing Cash Collateral Net Exposure (In thousands) PNMR and PNM June 30, 2015 $ 1,143 $ — $ 83 December 31, 2014 $ 1,686 $ — $ 167 |
Available-for-sale Securities | At June 30, 2015 and December 31, 2014 , the fair value of available-for-sale securities included $247.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. June 30, 2015 December 31, 2014 Unrealized Gains Fair Value Unrealized Gains Fair Value PNMR and PNM (In thousands) Cash and cash equivalents $ — $ 3,940 $ — $ 8,276 Equity securities: Domestic value 15,015 45,750 17,418 45,340 Domestic growth 19,850 78,515 21,354 74,053 International and other 1,147 17,057 156 16,599 Fixed income securities: U.S. Government 276 30,421 903 22,563 Municipals 3,098 58,986 5,851 68,973 Corporate and other 411 18,881 666 14,341 $ 39,797 $ 253,550 $ 46,348 $ 250,145 The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM 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 change in realized impairment losses of $(1.2) million and $(0.8) million for the three and six months ended June 30, 2015 and $0.1 million and $0.6 million for the three and six months ended June 30, 2014. Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Proceeds from sales $ 62,670 $ 30,316 $ 94,522 $ 53,119 Gross realized gains $ 8,329 $ 5,364 $ 13,465 $ 8,482 Gross realized (losses) $ (1,578 ) $ (755 ) $ (3,119 ) $ (1,794 ) |
Investments Classified by Contractual Maturity Date | At June 30, 2015 , the available-for-sale and held-to-maturity debt securities had the following final maturities: Fair Value Available-for-Sale Held-to-Maturity PNMR and PNM PNMR PNM (In thousands) Within 1 year $ 4,656 $ 17,230 $ 17,230 After 1 year through 5 years 21,533 639 — After 5 years through 10 years 22,577 — — After 10 years through 15 years 10,137 — — After 15 years through 20 years 10,727 — — After 20 years 38,658 — — $ 108,288 $ 17,869 $ 17,230 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at June 30, 2015 and December 31, 2014 for items recorded at fair value. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) June 30, 2015 (In thousands) PNMR and PNM Available-for-sale securities Cash and cash equivalents $ 3,940 $ 3,940 $ — Equity securities: Domestic value 45,750 45,750 — Domestic growth 78,515 78,515 — International and other 17,057 17,057 — Fixed income securities: U.S. Government 30,421 29,131 1,290 Municipals 58,986 — 58,986 Corporate and other 18,881 4,119 14,762 $ 253,550 $ 178,512 $ 75,038 Commodity derivative assets $ 4,550 $ — $ 4,550 Commodity derivative liabilities (1,153 ) — (1,153 ) Net $ 3,397 $ — $ 3,397 December 31, 2014 PNMR and PNM Available-for-sale securities Cash and cash equivalents $ 8,276 $ 8,276 $ — Equity securities: Domestic value 45,340 45,340 — Domestic growth 74,053 74,053 — International and other 16,599 16,599 — Fixed income securities: U.S. Government 22,563 20,808 1,755 Municipals 68,973 — 68,973 Corporate and other 14,341 4,843 9,498 $ 250,145 $ 169,919 $ 80,226 Commodity derivative assets $ 11,232 $ — $ 11,232 Commodity derivative liabilities (1,686 ) — (1,686 ) Net $ 9,546 $ — $ 9,546 |
Fair Value, by Balance Sheet Grouping | The carrying amounts and fair values of investments in PVNGS lessor notes, 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 June 30, 2015 (In thousands) PNMR Long-term debt $ 2,031,158 $ 2,205,847 $ — $ 2,205,847 $ — Investment in PVNGS lessor notes $ 16,568 $ 17,230 $ — $ — $ 17,230 Other investments $ 507 $ 1,146 $ 507 $ — $ 639 PNM Long-term debt $ 1,515,676 $ 1,644,887 $ — $ 1,644,887 $ — Investment in PVNGS lessor notes $ 16,568 $ 17,230 $ — $ — $ 17,230 Other investments $ 265 $ 265 $ 265 $ — $ — TNMP Long-term debt $ 365,482 $ 410,961 $ — $ 410,961 $ — Other investments $ 242 $ 242 $ 242 $ — $ — December 31, 2014 PNMR Long-term debt $ 1,975,090 $ 2,173,117 $ — $ 2,173,117 $ — Investment in PVNGS lessor notes $ 31,232 $ 32,836 $ — $ — $ 32,836 Other investments $ 1,762 $ 2,375 $ 639 $ — $ 1,736 PNM Long-term debt $ 1,490,657 $ 1,624,222 $ — $ 1,624,222 $ — Investment in PVNGS lessor notes $ 31,232 $ 32,836 $ — $ — $ 32,836 Other investments $ 397 $ 397 $ 397 $ — $ — TNMP Long-term debt $ 365,667 $ 427,356 $ — $ 427,356 $ — Other investments $ 242 $ 242 $ 242 $ — $ — |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: Six Months Ended June 30, Restricted Stock 2015 2014 Weighted-average grant date fair value $ 20.34 $ 21.27 Total fair value of restricted shares that vested (in thousands) $ 6,470 $ 4,854 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) $ 1,759 $ 1,779 The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Six Months Ended June 30, Restricted Shares and Performance Based Shares 2015 2014 Expected quarterly dividends per share $ 0.200 $ 0.185 Risk-free interest rate 0.92 % 0.62 % Market-Based Shares Dividend yield 2.87 % 2.82 % Expected volatility 18.73 % 25.11 % Risk-free interest rate 1.00 % 0.64 % The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the six months ended June 30, 2015 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2014 258,770 $ 22.31 920,505 $ 20.39 Granted 340,020 $ 20.34 — $ — Exercised (348,095 ) $ 18.59 (210,945 ) $ 20.07 Forfeited — $ — (1,000 ) $ 30.50 Expired — $ — (66,201 ) $ 27.90 Outstanding at June 30, 2015 250,695 $ 24.82 642,359 $ 19.51 |
Financing (Tables)
Financing (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Short-term Debt | Short-term debt outstanding consisted of: June 30, December 31, Short-term Debt 2015 2014 (In thousands) PNM: Revolving credit facility $ 31,100 $ — PNM New Mexico Credit Facility 20,000 — TNMP – Revolving credit facility 29,000 5,000 PNMR: Revolving credit facility 7,500 600 PNMR Term Loan Agreement 100,000 100,000 $ 187,600 $ 105,600 |
Pension and Other Postretirem32
Pension and Other Postretirement Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Public Service Company of New Mexico [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Net Benefit Costs | The following tables present the components of the PNM Plans’ net periodic benefit cost: Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 51 $ 45 $ — $ — Interest cost 7,064 7,541 1,023 1,159 190 205 Expected return on plan assets (9,831 ) (9,511 ) (1,403 ) (1,410 ) — — Amortization of net (gain) loss 3,705 3,255 491 556 81 52 Amortization of prior service cost (241 ) (241 ) (160 ) (336 ) — — Net periodic benefit cost $ 697 $ 1,044 $ 2 $ 14 $ 271 $ 257 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 102 $ 91 $ — $ — Interest cost 14,127 15,082 2,045 2,315 380 411 Expected return on plan assets (19,662 ) (19,022 ) (2,805 ) (2,819 ) — — Amortization of net (gain) loss 7,410 6,510 983 1,113 162 105 Amortization of prior service cost (483 ) (483 ) (321 ) (672 ) — — Net periodic benefit cost $ 1,392 $ 2,087 $ 4 $ 28 $ 542 $ 516 |
Texas-New Mexico Power Company [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Net Benefit Costs | The following tables present the components of the TNMP Plans’ net periodic benefit cost (income): Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost (Income) Service cost $ — $ — $ 62 $ 59 $ — $ — Interest cost 761 798 152 155 9 10 Expected return on plan assets (1,105 ) (1,132 ) (130 ) (133 ) — — Amortization of net (gain) loss 195 166 — (31 ) 1 — Amortization of prior service cost — — — 8 — — Net Periodic Benefit Cost (Income) $ (149 ) $ (168 ) $ 84 $ 58 $ 10 $ 10 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2015 2014 2015 2014 2015 2014 (In thousands) Components of Net Periodic Benefit Cost (Income) Service cost $ — $ — $ 124 $ 119 $ — $ — Interest cost 1,521 1,597 304 309 18 20 Expected return on plan assets (2,210 ) (2,263 ) (260 ) (267 ) — — Amortization of net (gain) loss 391 333 — (61 ) 2 — Amortization of prior service cost — — — 16 — — Net Periodic Benefit Cost (Income) $ (298 ) $ (333 ) $ 168 $ 116 $ 20 $ 20 |
Regulatory and Rate Matters (Ta
Regulatory and Rate Matters (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Regulated Operations [Abstract] | |
Schedule of Rate Increases for Transmission Costs | The following sets forth TNMP’s most recent interim transmission cost rate increases: Effective Date Approved Increase in Rate Base Annual Increase in Revenue (in millions) September 17, 2013 $ 18.1 $ 2.8 March 13, 2014 18.2 2.9 September 8, 2014 25.2 4.2 March 16, 2015 27.1 4.4 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (In thousands) Services billings: PNMR to PNM $ 21,340 $ 22,190 $ 44,067 $ 43,256 PNMR to TNMP 6,591 6,963 13,680 14,224 PNM to TNMP 184 133 288 242 TNMP to PNMR — — — — Interest billings: PNMR to TNMP 54 83 133 180 PNMR to PNM 22 — 28 54 PNM to PNMR 26 25 55 51 Income tax sharing payments: PNMR to PNM — — 1,450 — PNMR to TNMP — — — — |
Significant Accounting Polici35
Significant Accounting Policies and Responsibility for Financial Statements - Narrative (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||||
Jul. 31, 2015 | Jun. 30, 2015 | Jul. 31, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Common Stock, Dividends, Per Share, Declared | $ 0.185 | $ 0.200 | $ 0.185 | $ 0.400 | $ 0.37 | ||
Dividends, Common Stock, Cash | $ 15,931,000 | ||||||
Adjustments for New Accounting Pronouncement [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Unamortized Debt Issuance Expense | $ 11,800,000 | $ 11,800,000 | 11,800,000 | ||||
Public Service Company of New Mexico [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Dividends, Common Stock, Cash | 20,000,000 | $ 0 | |||||
Public Service Company of New Mexico [Member] | Adjustments for New Accounting Pronouncement [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Unamortized Debt Issuance Expense | 7,500,000 | 7,500,000 | 7,500,000 | ||||
Texas-New Mexico Power Company [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Dividends, Common Stock, Cash | 7,700,000 | $ 6,800,000 | |||||
Texas-New Mexico Power Company [Member] | Adjustments for New Accounting Pronouncement [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Unamortized Debt Issuance Expense | $ 4,200,000 | $ 4,200,000 | $ 4,200,000 | ||||
Subsequent Event [Member] | |||||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||||||
Common Stock, Dividends, Per Share, Declared | $ 0.200 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Earnings Per Share [Abstract] | |||||
Net Earnings Attributable to PNMR | $ 31,673 | $ 29,141 | $ 46,013 | $ 41,609 | |
Average Number of Common Shares: | |||||
Outstanding during period | 79,654,000 | 79,654,000 | 79,654,000 | 79,654,000 | |
Vested awards of restricted stock | 99,000 | 110,000 | 105,000 | 146,000 | |
Average Shares – Basic | 79,753,000 | 79,764,000 | 79,759,000 | 79,800,000 | |
Dilutive Effect of Common Stock Equivalents: | |||||
Stock options and restricted stock | [1] | 380,000 | 464,000 | 384,000 | 508,000 |
Average Shares – Diluted | 80,133,000 | 80,228,000 | 80,143,000 | 80,308,000 | |
Net Earnings Per Share of Common Stock: | |||||
Basic (dollars per share) | $ 0.40 | $ 0.37 | $ 0.58 | $ 0.52 | |
Diluted (dollars per share) | $ 0.40 | $ 0.36 | $ 0.57 | $ 0.52 | |
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares) | 245,950 | ||||
[1] | Excludes the effect of out-of-the-money options for 245,950 shares of common stock at June 30, 2015. |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | $ 352,887 | $ 346,160 | $ 685,755 | $ 675,057 | |
Cost of energy | 114,038 | 109,419 | 229,683 | 222,033 | |
Margin | 238,849 | 236,741 | 456,072 | 453,024 | |
Other operating expenses | 120,386 | 123,282 | 242,578 | 248,845 | |
Depreciation and amortization | 46,049 | 42,163 | 91,510 | 84,130 | |
Operating income | 72,414 | 71,296 | 121,984 | 120,049 | |
Interest income | 1,941 | 2,040 | 3,691 | 4,158 | |
Other income (deductions) | 7,566 | 5,710 | 12,889 | 6,924 | |
Net interest charges | (28,913) | (29,972) | (59,186) | (59,506) | |
Earnings before Income Taxes | 53,008 | 49,074 | 79,378 | 71,625 | |
Income taxes (benefit) | 17,353 | 15,893 | 25,870 | 22,313 | |
Net Earnings | 35,655 | 33,181 | 53,508 | 49,312 | |
Valencia non-controlling interest | (3,850) | (3,908) | (7,231) | (7,439) | |
Subsidiary preferred stock dividends | (132) | (132) | (264) | (264) | |
Net Earnings Available for PNM Common Stock | 31,673 | 29,141 | 46,013 | 41,609 | |
Total Assets | 5,927,018 | 5,604,192 | 5,927,018 | 5,604,192 | $ 5,829,325 |
Goodwill | 278,297 | 278,297 | 278,297 | 278,297 | 278,297 |
Public Service Company of New Mexico [Member] | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 275,450 | 275,704 | 537,390 | 538,441 | |
Cost of energy | 95,728 | 92,642 | 193,594 | 189,268 | |
Margin | 179,722 | 183,062 | 343,796 | 349,173 | |
Other operating expenses | 103,541 | 106,233 | 207,557 | 213,957 | |
Depreciation and amortization | 29,002 | 27,023 | 57,405 | 54,105 | |
Operating income | 47,179 | 49,806 | 78,834 | 81,111 | |
Interest income | 1,946 | 2,065 | 3,717 | 4,193 | |
Other income (deductions) | 7,446 | 5,512 | 13,257 | 7,180 | |
Net interest charges | (19,681) | (20,023) | (39,640) | (39,835) | |
Earnings before Income Taxes | 36,890 | 37,360 | 56,168 | 52,649 | |
Income taxes (benefit) | 11,527 | 13,106 | 17,302 | 17,189 | |
Net Earnings | 25,363 | 24,254 | 38,866 | 35,460 | |
Valencia non-controlling interest | (3,850) | (3,908) | (7,231) | (7,439) | |
Subsidiary preferred stock dividends | (132) | (132) | (264) | (264) | |
Net Earnings Available for PNM Common Stock | 21,381 | 20,214 | 31,371 | 27,757 | |
Total Assets | 4,544,279 | 4,290,529 | 4,544,279 | 4,290,529 | 4,473,652 |
Goodwill | 51,632 | 51,632 | 51,632 | 51,632 | 51,632 |
Texas-New Mexico Power Company [Member] | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 77,437 | 70,456 | 148,365 | 136,616 | |
Cost of energy | 18,310 | 16,777 | 36,089 | 32,765 | |
Margin | 59,127 | 53,679 | 112,276 | 103,851 | |
Other operating expenses | 20,807 | 20,411 | 42,567 | 41,481 | |
Depreciation and amortization | 13,591 | 12,003 | 27,049 | 23,844 | |
Operating income | 24,729 | 21,265 | 42,660 | 38,526 | |
Interest income | 0 | 0 | 0 | 0 | |
Other income (deductions) | 793 | 514 | 2,084 | 702 | |
Net interest charges | (6,856) | (6,655) | (13,781) | (13,252) | |
Earnings before Income Taxes | 18,666 | 15,124 | 30,963 | 25,976 | |
Income taxes (benefit) | 6,801 | 5,590 | 11,404 | 9,640 | |
Net Earnings | 11,865 | 9,534 | 19,559 | 16,336 | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | 11,865 | 9,534 | 19,559 | 16,336 | |
Total Assets | 1,268,862 | 1,208,517 | 1,268,862 | 1,208,517 | 1,240,241 |
Goodwill | 226,665 | 226,665 | 226,665 | 226,665 | $ 226,665 |
Corporate and Other [Member] | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 0 | 0 | 0 | 0 | |
Cost of energy | 0 | 0 | 0 | 0 | |
Margin | 0 | 0 | 0 | 0 | |
Other operating expenses | (3,962) | (3,362) | (7,546) | (6,593) | |
Depreciation and amortization | 3,456 | 3,137 | 7,056 | 6,181 | |
Operating income | 506 | 225 | 490 | 412 | |
Interest income | (5) | (25) | (26) | (35) | |
Other income (deductions) | (673) | (316) | (2,452) | (958) | |
Net interest charges | (2,376) | (3,294) | (5,765) | (6,419) | |
Earnings before Income Taxes | (2,548) | (3,410) | (7,753) | (7,000) | |
Income taxes (benefit) | (975) | (2,803) | (2,836) | (4,516) | |
Net Earnings | (1,573) | (607) | (4,917) | (2,484) | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | (1,573) | (607) | (4,917) | (2,484) | |
Total Assets | 113,877 | 105,146 | 113,877 | 105,146 | |
Goodwill | $ 0 | $ 0 | $ 0 | $ 0 |
Accumulated Other Comprehensi38
Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Equity [Abstract] | ||||
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process | 23.00% | 23.00% | ||
Percentage of Pension Liability Adjustment Capitalized into Other Accounts | 2.70% | 2.10% | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | $ (61,755) | |||
Net change after income taxes | $ (4,595) | $ 1,461 | (2,070) | $ 2,252 |
Ending Balance | (63,825) | (63,825) | ||
PNMR and PNM [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | 28,008 | 25,748 | ||
Amounts reclassified from AOCI (pre-tax) | (12,537) | (8,857) | ||
Income tax impact of amounts reclassified | 4,913 | 3,488 | ||
Other OCI changes (pre-tax) | 6,157 | 9,855 | ||
Income tax impact of other OCI changes | (2,413) | (3,809) | ||
Net change after income taxes | (3,880) | 677 | ||
Ending Balance | 24,128 | 26,425 | 24,128 | 26,425 |
PNMR and PNM [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (89,763) | (83,625) | ||
Amounts reclassified from AOCI (pre-tax) | 2,976 | 2,576 | ||
Income tax impact of amounts reclassified | (1,166) | (1,016) | ||
Net change after income taxes | 1,810 | 1,560 | ||
Ending Balance | (87,953) | (82,065) | (87,953) | (82,065) |
PNM [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (61,755) | (57,877) | ||
Amounts reclassified from AOCI (pre-tax) | (9,561) | (6,281) | ||
Income tax impact of amounts reclassified | 3,747 | 2,472 | ||
Other OCI changes (pre-tax) | 6,157 | 9,855 | ||
Income tax impact of other OCI changes | (2,413) | (3,809) | ||
Net change after income taxes | (2,070) | 2,237 | ||
Ending Balance | (63,825) | (55,640) | (63,825) | (55,640) |
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (263) | |||
Amounts reclassified from AOCI (pre-tax) | 176 | |||
Income tax impact of amounts reclassified | (61) | |||
Other OCI changes (pre-tax) | (153) | |||
Income tax impact of other OCI changes | 53 | |||
Net change after income taxes | 15 | |||
Ending Balance | (248) | (248) | ||
PNMR [Member] | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (61,755) | (58,140) | ||
Amounts reclassified from AOCI (pre-tax) | (9,561) | (6,105) | ||
Income tax impact of amounts reclassified | 3,747 | 2,411 | ||
Other OCI changes (pre-tax) | 6,157 | 9,702 | ||
Income tax impact of other OCI changes | (2,413) | (3,756) | ||
Net change after income taxes | (2,070) | 2,252 | ||
Ending Balance | $ (63,825) | $ (55,888) | $ (63,825) | $ (55,888) |
Variable Interest Entities (Det
Variable Interest Entities (Details) | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015USD ($)MW | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)MW | Jun. 30, 2014USD ($) | Dec. 31, 2014USD ($) | Oct. 08, 2013USD ($) | |
Variable Interest Entity, Statement Of Operation [Abstract] | ||||||
Earnings attributable to non-controlling interest | $ 3,850,000 | $ 3,908,000 | $ 7,231,000 | $ 7,439,000 | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Current assets | 410,065,000 | 410,065,000 | $ 432,817,000 | |||
Total assets | 5,927,018,000 | 5,604,192,000 | 5,927,018,000 | 5,604,192,000 | 5,829,325,000 | |
Current liabilities | 701,104,000 | 701,104,000 | 704,282,000 | |||
Owners’ equity – non-controlling interest | 73,163,000 | 73,163,000 | 73,546,000 | |||
Net earnings | 31,673,000 | 29,141,000 | $ 46,013,000 | 41,609,000 | ||
Public Service Company of New Mexico [Member] | ||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Operating Leases, Renewal Options After Original Lease Term (in years) | 2 years | |||||
Operating Leases, Extended Lease Term Option (in years) | 6 years | |||||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | ||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Operating Leases, Future Minimum Payments Due, Next Six Months | 18,400,000 | $ 18,400,000 | 26,000,000 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Property Lease Guarantee [Member] | Maximum [Member] | ||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Loss Contingency, Range of Possible Loss, Portion Not Accrued | 217,300,000 | 217,300,000 | ||||
Valencia [Member] | Public Service Company of New Mexico [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Long Term Contract For Purchase of Electric Power Fixed Costs | 4,800,000 | 4,800,000 | 9,600,000 | 9,600,000 | ||
Long Term Contract For Purchase of Electric Power Variable Charges | 500,000 | 500,000 | 600,000 | 700,000 | ||
Variable Interest Entity, Statement Of Operation [Abstract] | ||||||
Operating revenues | 5,251,000 | 5,307,000 | 10,155,000 | 10,238,000 | ||
Operating expenses | (1,401,000) | (1,399,000) | (2,924,000) | (2,799,000) | ||
Earnings attributable to non-controlling interest | 3,850,000 | 3,908,000 | 7,231,000 | 7,439,000 | ||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Current assets | 3,284,000 | 3,284,000 | 2,513,000 | |||
Net property, plant, and equipment | 71,180,000 | 71,180,000 | 72,321,000 | |||
Total assets | 74,464,000 | 74,464,000 | 74,834,000 | |||
Current liabilities | 1,301,000 | 1,301,000 | 1,288,000 | |||
Owners’ equity – non-controlling interest | $ 73,163,000 | $ 73,163,000 | $ 73,546,000 | |||
Long term contract option to purchase, ownership percentage | 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% | |||||
Long term contract option to purchase, number of days to set FMV | 60 days | |||||
Long term contract option to purchase, estimated purchase price | $ 85,000,000 | |||||
Long term contract option to purchase, approximate approval period | 15 months | |||||
Valencia [Member] | Public Service Company of New Mexico [Member] | Purchased Through May 30, 2028 [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Number of mega watts purchased (in megawatts) | MW | 158 | 158 | ||||
Variable Interest Entity, Not Primary Beneficiary [Member] | Public Service Company of New Mexico [Member] | ||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Operating leases, future minimum payments due, renewal term | $ 150,500,000 | $ 150,500,000 | ||||
Delta [Member] | Public Service Company of New Mexico [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Long Term Contract For Purchase of Electric Power Fixed Costs | 1,600,000 | 3,200,000 | ||||
Long Term Contract For Purchase of Electric Power Variable Charges | 300,000 | 500,000 | ||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Period of Long Term Contract For Purchase of Electric Power Fixed Costs | 20 years | |||||
Delta [Member] | Public Service Company of New Mexico [Member] | Delta [Member] | ||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||
Revenues | 2,500,000 | 4,300,000 | ||||
Net earnings | $ 300,000 | $ 600,000 |
Lease Commitments (Details)
Lease Commitments (Details) $ in Millions | 6 Months Ended | |||
Jun. 30, 2015USD ($)MW | Jan. 14, 2016USD ($) | Jun. 01, 2014USD ($) | May. 01, 2014MW | |
Public Service Company of New Mexico [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Public Utilities, Option to Purchase Leased Capacity At Fair Value | $ 7.7 | |||
Public Service Company of New Mexico [Member] | TGP Granada, LLC and its affiliate Complaint [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Public Utilities, Lease ownership percentage in EIP | 60.00% | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 31.2494 MW [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Purchase Price of Leased Asset to be paid | $ 78.1 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Leased Capacity to be Purchased | MW | 32.76 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Leased Capacity to be Purchased | MW | 31.25 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Purchase Price of Leased Asset to be paid | $ 85.2 | |||
Early Purchase Price of Leased Asset, Period 1 | $ 79.9 | |||
Early Purchase Price of Leased Asset | 83.4 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Maximum [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Additional consideration for early purchase of leased asset, Period 1 | $ 5.8 | |||
Additional consideration for early purchase of leased asset, Period 2 | $ 2.8 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Subsequent Event [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Purchase Price of Leased Asset, Period 3 | $ 85.2 | |||
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Subsequent Event [Member] | Minimum [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Additional consideration for early purchase of leased asset effective June 1, 2014 | $ 1.2 | |||
Tortoise Capital Resources Corporation [Member] | TGP Granada, LLC and its affiliate Complaint [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Public Utilities, Lease ownership percentage in EIP | 40.00% |
Fair Value of Derivative and 41
Fair Value of Derivative and Other Financial Instruments - Derivative Balance Sheet Information (Details) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Current assets | $ 4,550,000 | $ 11,232,000 |
Commodity derivative instruments, Current liabilities | (1,153,000) | (1,209,000) |
Commodity derivative instruments, Long-term liabilities | 0 | (477,000) |
Assets, Current | 410,065,000 | 432,817,000 |
PNMR and PNM [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative, Collateral, Right to Reclaim Cash | 0 | 0 |
Margin Deposit Assets | 1,600,000 | 3,800,000 |
Derivative, Collateral, Obligation to Return Cash | 200,000 | 200,000 |
Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 4,550,000 | 11,232,000 |
Commodity derivative instruments, Assets | 4,550,000 | 11,232,000 |
Commodity derivative instruments, Current liabilities | (1,153,000) | (1,209,000) |
Commodity derivative instruments, Long-term liabilities | 0 | (477,000) |
Commodity derivative instruments, Liabilities | (1,153,000) | (1,686,000) |
Commodity derivative instruments, Net | 3,397,000 | 9,546,000 |
Fair Value Hedging [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Assets, Current | 100,000 | 0 |
Fair Value Hedging [Member] | Commodity Contract [Member] | Palo Verde Nuclear Generating Station [Member] | PNMR and PNM [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | $ 1,500,000 | $ 3,000,000 |
Fair Value of Derivative and 42
Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNMR and PNM [Member] - Commodity Contract [Member] - Fair Value Hedging [Member] - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) | $ 904 | $ (267) | $ 382 | $ (4,230) |
Electric operating revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) | 1,003 | (324) | 531 | (4,475) |
Cost of energy [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) | $ (99) | $ 57 | $ (149) | $ 245 |
Fair Value of Derivative and 43
Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNMR and PNM [Member] $ in Thousands | Jun. 30, 2015USD ($)dthmwh | Dec. 31, 2014USD ($)dthmwh |
Derivative [Line Items] | ||
Contractual Liability | $ 1,143 | $ 1,686 |
Existing Cash Collateral | 0 | 0 |
Net Exposure | $ 83 | $ 167 |
Gas related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member] | ||
Derivative [Line Items] | ||
Volume positions (Decatherms / MWh) | dth | 865,000 | 650,000 |
Power related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Short Position [Member] | ||
Derivative [Line Items] | ||
Volume positions (Decatherms / MWh) | mwh | 968,305 | 1,919,000 |
Fair Value of Derivative and 44
Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details) | Jun. 30, 2015MW | Dec. 31, 2014$ / MWh |
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Public Utilities, Number of Megawatts Nuclear Generation | MW | 134 | |
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Commodity Contract [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative, Average Forward Price | 37 | |
Palo Verde Nuclear Generating Station [Member] | Firm Contract [Member] | Public Service Company of New Mexico [Member] | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Percentage of Electric Power Plant Output Sold for 2014 and 2015 | 100.00% |
Fair Value of Derivative and 45
Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Schedule of Available-for-sale Securities [Line Items] | |||||
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net, Available-for-sale Securities | $ 1,200 | $ (100) | $ 800 | $ (600) | |
PNMR and PNM [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 253,550 | 253,550 | $ 250,145 | ||
Available-for-sale Securities, Gross Unrealized Gain | 39,797 | 39,797 | 46,348 | ||
Proceeds from sales | 62,670 | 30,316 | 94,522 | 53,119 | |
Gross realized gains | 8,329 | 5,364 | 13,465 | 8,482 | |
Gross realized (losses) | (1,578) | $ (755) | (3,119) | $ (1,794) | |
PNMR and PNM [Member] | Cash and equivalents [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 3,940 | 3,940 | 8,276 | ||
Available-for-sale Securities, Gross Unrealized Gain | 0 | 0 | 0 | ||
PNMR and PNM [Member] | Domestic value [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 45,750 | 45,750 | 45,340 | ||
Available-for-sale Securities, Gross Unrealized Gain | 15,015 | 15,015 | 17,418 | ||
PNMR and PNM [Member] | Domestic growth [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 78,515 | 78,515 | 74,053 | ||
Available-for-sale Securities, Gross Unrealized Gain | 19,850 | 19,850 | 21,354 | ||
PNMR and PNM [Member] | International and other [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 17,057 | 17,057 | 16,599 | ||
Available-for-sale Securities, Gross Unrealized Gain | 1,147 | 1,147 | 156 | ||
PNMR and PNM [Member] | U.S. Government [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 30,421 | 30,421 | 22,563 | ||
Available-for-sale Securities, Gross Unrealized Gain | 276 | 276 | 903 | ||
PNMR and PNM [Member] | Municipals [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 58,986 | 58,986 | 68,973 | ||
Available-for-sale Securities, Gross Unrealized Gain | 3,098 | 3,098 | 5,851 | ||
PNMR and PNM [Member] | Corporate and other [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 18,881 | 18,881 | 14,341 | ||
Available-for-sale Securities, Gross Unrealized Gain | 411 | 411 | 666 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 253,550 | 253,550 | 250,145 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Nuclear Decommissioning Trust [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 247,800 | 247,800 | 244,600 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Mine Reclamation Trust [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 5,700 | 5,700 | 5,500 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 3,940 | 3,940 | 8,276 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 45,750 | 45,750 | 45,340 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 78,515 | 78,515 | 74,053 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 17,057 | 17,057 | 16,599 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 30,421 | 30,421 | 22,563 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | 58,986 | 58,986 | 68,973 | ||
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities, Fair value | $ 18,881 | $ 18,881 | $ 14,341 |
Fair Value of Derivative and 46
Fair Value of Derivative and Other Financial Instruments - Debt Maturities (Details) $ in Thousands | Jun. 30, 2015USD ($) |
PNMR and PNM [Member] | |
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | |
Available-for-sale debt securities, Within 1 year | $ 4,656 |
Available-for-sale debt securities, After 1 year through 5 years | 21,533 |
Available-for-sale debt securities, After 5 years through 10 years | 22,577 |
Available-for-sale debt securities, After 10 years through 15 years | 10,137 |
Available-for-sale debt securities, After 15 years through 20 years | 10,727 |
Available-for-sale debt securities, After 20 years | 38,658 |
Available-for-sale debt securities | 108,288 |
PNM Resources [Member] | |
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | |
Held-to-maturity debt securities, Due within 1 year | 17,230 |
Held-to-maturity debt securities, After 1 year through 5 years | 639 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | 17,869 |
Public Service Company of New Mexico [Member] | |
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | |
Held-to-maturity debt securities, Due within 1 year | 17,230 |
Held-to-maturity debt securities, After 1 year through 5 years | 0 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | $ 17,230 |
Fair Value of Derivative and 47
Fair Value of Derivative and Other Financial Instruments - Recurring (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | $ 253,550 | $ 250,145 |
PNM Resources [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 2,205,847 | 2,173,117 |
Investment in PVNGS lessor notes | 17,230 | 32,836 |
Other investments | 1,146 | 2,375 |
PNM Resources [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Investment in PVNGS lessor notes | 0 | 0 |
Other investments | 507 | 639 |
PNM Resources [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 2,205,847 | 2,173,117 |
Investment in PVNGS lessor notes | 0 | 0 |
Other investments | 0 | 0 |
PNM Resources [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Investment in PVNGS lessor notes | 17,230 | 32,836 |
Other investments | 639 | 1,736 |
Public Service Company of New Mexico [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 1,644,887 | 1,624,222 |
Investment in PVNGS lessor notes | 17,230 | 32,836 |
Other investments | 265 | 397 |
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Investment in PVNGS lessor notes | 0 | 0 |
Other investments | 265 | 397 |
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 1,644,887 | 1,624,222 |
Investment in PVNGS lessor notes | 0 | 0 |
Other investments | 0 | 0 |
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Investment in PVNGS lessor notes | 17,230 | 32,836 |
Other investments | 0 | 0 |
Texas-New Mexico Power Company [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 410,961 | 427,356 |
Other investments | 242 | 242 |
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 242 | 242 |
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 410,961 | 427,356 |
Other investments | 0 | 0 |
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 0 | 0 |
Reported Value Measurement [Member] | PNM Resources [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 2,031,158 | 1,975,090 |
Investment in PVNGS lessor notes | 16,568 | 31,232 |
Other investments | 507 | 1,762 |
Reported Value Measurement [Member] | Public Service Company of New Mexico [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 1,515,676 | 1,490,657 |
Investment in PVNGS lessor notes | 16,568 | 31,232 |
Other investments | 265 | 397 |
Reported Value Measurement [Member] | Texas-New Mexico Power Company [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 365,482 | 365,667 |
Other investments | 242 | 242 |
Cash and equivalents [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,940 | 8,276 |
Domestic value [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 45,750 | 45,340 |
Domestic growth [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 78,515 | 74,053 |
International and other [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 17,057 | 16,599 |
U.S. Government [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 30,421 | 22,563 |
Municipals [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 58,986 | 68,973 |
Corporate and other [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 18,881 | 14,341 |
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 253,550 | 250,145 |
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 178,512 | 169,919 |
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 75,038 | 80,226 |
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 4,550 | 11,232 |
Commodity derivative liabilities | (1,153) | (1,686) |
Commodity derivative instruments, Net | 3,397 | 9,546 |
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 0 | 0 |
Commodity derivative liabilities | 0 | 0 |
Commodity derivative instruments, Net | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 4,550 | 11,232 |
Commodity derivative liabilities | (1,153) | (1,686) |
Commodity derivative instruments, Net | 3,397 | 9,546 |
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,940 | 8,276 |
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,940 | 8,276 |
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 45,750 | 45,340 |
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 45,750 | 45,340 |
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 78,515 | 74,053 |
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 78,515 | 74,053 |
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 17,057 | 16,599 |
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 17,057 | 16,599 |
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 30,421 | 22,563 |
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 29,131 | 20,808 |
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 1,290 | 1,755 |
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 58,986 | 68,973 |
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 58,986 | 68,973 |
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 18,881 | 14,341 |
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 4,119 | 4,843 |
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | $ 14,762 | $ 9,498 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 7,800,000 | $ 6,500,000 | |
Options, Outstanding at end of period, No intrinsic value | 245,950 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Options, Outstanding at beginning of period, Shares | 920,505 | ||
Options, Granted, Shares | 0 | ||
Options, Exercised, Shares | (210,945) | ||
Options, Forfeited, Shares | (1,000) | ||
Options, Expired, Shares | (66,201) | ||
Options, Outstanding at end of period, Shares | 642,359 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract] | |||
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share) | $ 20.39 | ||
Options, Granted, Weighted-Average Exercise Price (in dollars per share) | 0 | ||
Options, Exercised, Weighted-Average Exercise Price (in dollars per share) | 20.07 | ||
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share) | 30.50 | ||
Options, Expired, Weighted-Average Exercise Price (in dollars per share) | 27.90 | ||
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share) | 19.51 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||
Weighted-average grant date fair value of options granted | $ 0 | $ 0 | |
Total fair value of options that vested (in thousands) | $ 0 | $ 0 | |
Total intrinsic value of options exercised (in thousands) | $ 1,759,000 | $ 1,779,000 | |
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Expected quarterly dividends per share | $ 0.200 | $ 0.185 | |
Risk-free interest rate | 0.92% | 0.62% | |
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward] | |||
Restricted Stock, Outstanding at beginning of period, Shares | 258,770 | ||
Restricted Stock, Outstanding at end of period, Shares | 250,695 | ||
Restricted Stock, Granted, Shares | 340,020 | ||
Restricted Stock, Exercised, Shares | (348,095) | ||
Restricted Stock, Forfeited, Shares | 0 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Restricted Stock, Outstanding at beginning of period, Weighted-Average Grant Date Fair Value (in dollars per share) | $ 22.31 | ||
Restricted Stock, Granted, Weighted-Average Grant Date Fair Value (in dollars per share) | 20.34 | $ 21.27 | |
Restricted Stock, Exercised, Weighted-Average Grant Date Fair Value (in dollars per share) | 18.59 | ||
Restricted Stock, Forfeited, Weighted-Average Grant Date Fair Value (in dollars per share) | 0 | ||
Restricted Stock, Outstanding at end of period, Weighted-Average Grant Date Fair Value (in dollars per share) | 24.82 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||
Weighted-average grant date fair value | $ 20.34 | $ 21.27 | |
Total fair value of restricted shares that vested (in thousands) | $ 6,470,000 | $ 4,854,000 | |
Market-Based Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Risk-free interest rate | 1.00% | 0.64% | |
Dividend yield | 2.87% | 2.82% | |
Expected volatility | 18.73% | 25.11% | |
Stock Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options, Outstanding at end of period, Aggregate Intrinsic Value | $ 4,700,000 | ||
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years) | 2 years 7 months 13 days | ||
Executive [Member] | Performance Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Included from Shares Outstanding, Number | 179,845 | ||
Share based Compensation, weighted percentage assigned to achieving market targets | 60.00% | ||
Share based Compensation, weighted percentage assigned to achieving performance targets | 40.00% | ||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One | 180,970 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two | 165,628 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three | 168,258 | ||
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares received if achieves specified improvement in total shareholders return | 135,000 | ||
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares received if achieves specified improvement in total shareholders return | 35,000 | ||
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2019 and she remains an employee [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares received if achieves specified improvement in total shareholders return | 53,859 | ||
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2017 and she remains an employee [Member] [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares received if achieves specified improvement in total shareholders return | 17,953 | ||
Executive Vice President and Chief Financial Officer [Member] | Achieved performance target for 2015 and 2016 [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, Purchase price of common stock | $ 100,000 | ||
Executive Vice President and Chief Financial Officer [Member] | Achieved performance target for 2015, 2016 and 2017 [Member] | Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation arrangement by share-based payment award, Purchase price of common stock | $ 275,000 | ||
Performance Equity Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate | 100.00% |
Financing - Financing Activitie
Financing - Financing Activities (Details) - USD ($) $ in Thousands | May. 08, 2015 | Dec. 31, 2014 | Jun. 30, 2015 | Jun. 01, 2015 | Mar. 09, 2015 | Dec. 22, 2014 | Mar. 05, 2014 | Apr. 22, 2013 |
Debt Instrument [Line Items] | ||||||||
Short-term debt | $ 105,600 | $ 187,600 | ||||||
PNMR 2015 Term Loan Agreement [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term Debt | $ 150,000 | |||||||
Debt Instrument, Interest Rate at Period End | 1.19% | |||||||
Public Service Company of New Mexico [Member] | PNM 2014 Term Loan Agreement [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term Debt | $ 175,000 | |||||||
Debt Instrument, Interest Rate at Period End | 1.14% | |||||||
Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Long-term Debt | $ 125,000 | $ 125,000 | ||||||
Debt Instrument, Interest Rate at Period End | 0.77% | |||||||
Proceeds from (Repayments of) Debt | $ 25,000 | 100,000 | ||||||
PNM Term Loan Agreement [Member] | Notes Payable to Banks [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Short-term debt | $ 75,000 | |||||||
Senior unsecured note, due 2015, at 9 point 25 percent [Member] | Unsecured Debt [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Unsecured Long-term Debt, Noncurrent | $ 118,800 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 9.25% | |||||||
Senior unsecured note, PCRB Due 2043, at 4 percent [Member] | Public Service Company of New Mexico [Member] | Unsecured notes, Pollution control revenue bonds [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Unsecured Long-term Debt, Noncurrent | $ 39,300 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.40% | |||||||
Senior unsecured note, PCRB Due 2043, at 2 point 4 percent [Member] | Public Service Company of New Mexico [Member] | Unsecured notes, Pollution control revenue bonds [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Unsecured Long-term Debt, Noncurrent | $ 39,300 |
Financing - Short-term Debt (De
Financing - Short-term Debt (Details) - USD ($) | Jul. 24, 2015 | Jun. 30, 2015 | Dec. 31, 2014 | Jan. 08, 2014 |
Short-term Debt [Line Items] | ||||
Short-term debt | $ 187,600,000 | $ 105,600,000 | ||
Subsequent Event [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 719,700,000 | |||
PNMR Term Loan Agreement [Member] | ||||
Short-term Debt [Line Items] | ||||
Short-term Debt, Weighted Average Interest Rate | 1.04% | |||
Short-term debt | $ 100,000,000 | 100,000,000 | ||
PNM Resources [Member] | Subsequent Event [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Remaining Borrowing Capacity | 293,200,000 | |||
Restricted Cash and Investments | 1,900,000 | |||
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Remaining Borrowing Capacity | 353,600,000 | |||
Restricted Cash and Investments | 0 | |||
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | Affiliated Entity [Member] | ||||
Short-term Debt [Line Items] | ||||
Short-term debt – affiliate | 18,700,000 | |||
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | ||||
Short-term Debt [Line Items] | ||||
Debt Instruments, NMPRC Approved credit facility | $ 50,000,000 | |||
Short-term debt | 20,000,000 | 0 | ||
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | Subsequent Event [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Remaining Borrowing Capacity | 30,000,000 | |||
Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Remaining Borrowing Capacity | 42,900,000 | |||
Restricted Cash and Investments | 0 | |||
Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Affiliated Entity [Member] | ||||
Short-term Debt [Line Items] | ||||
Short-term debt – affiliate | $ 13,200,000 | |||
Texas-New Mexico Power Company [Member] | Intercompany loan agreements [Member] | ||||
Short-term Debt [Line Items] | ||||
Short-term debt - affiliate | 4,100,000 | |||
Revolving Credit Facility [Member] | PNM Resources [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 300,000,000 | |||
Short-term Debt, Weighted Average Interest Rate | 1.69% | |||
Short-term debt | $ 7,500,000 | 600,000 | ||
Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400,000,000 | |||
Short-term Debt, Weighted Average Interest Rate | 1.44% | |||
Short-term debt | $ 31,100,000 | 0 | ||
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member] | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 75,000,000 | |||
Short-term Debt, Weighted Average Interest Rate | 1.19% | |||
Short-term debt | $ 29,000,000 | $ 5,000,000 | ||
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | ||||
Short-term Debt [Line Items] | ||||
Debt Instrument, Collateral Amount | $ 75,000,000 | |||
Local Lines of Credit [Member] | Public Service Company of New Mexico [Member] | ||||
Short-term Debt [Line Items] | ||||
Short-term Debt, Weighted Average Interest Rate | 1.44% |
Pension and Other Postretirem51
Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Public Service Company of New Mexico [Member] | Pension Plan [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | $ 0 | $ 0 | $ 0 | $ 0 |
Interest cost | 7,064 | 7,541 | 14,127 | 15,082 |
Expected return on plan assets | (9,831) | (9,511) | (19,662) | (19,022) |
Amortization of net (gain) loss | 3,705 | 3,255 | 7,410 | 6,510 |
Amortization of prior service cost | (241) | (241) | (483) | (483) |
Net Periodic Benefit Cost (Income) | 697 | 1,044 | 1,392 | 2,087 |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | 30,000 | 0 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 0 | 0 | ||
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 22,000 | $ 22,000 | ||
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 4.80% | |||
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 5.50% | |||
Public Service Company of New Mexico [Member] | OPEB [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | 51 | 45 | $ 102 | 91 |
Interest cost | 1,023 | 1,159 | 2,045 | 2,315 |
Expected return on plan assets | (1,403) | (1,410) | (2,805) | (2,819) |
Amortization of net (gain) loss | 491 | 556 | 983 | 1,113 |
Amortization of prior service cost | (160) | (336) | (321) | (672) |
Net Periodic Benefit Cost (Income) | 2 | 14 | 4 | 28 |
Defined Benefit Plan, Contributions by Employer | 800 | 800 | 1,600 | 1,600 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 3,500 | 3,500 | ||
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 14,000 | 14,000 | ||
Public Service Company of New Mexico [Member] | Other Pension Plan [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 190 | 205 | 380 | 411 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 81 | 52 | 162 | 105 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | 271 | 257 | 542 | 516 |
Defined Benefit Plan, Contributions by Employer | 400 | 400 | 900 | 700 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 1,500 | 1,500 | ||
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 761 | 798 | 1,521 | 1,597 |
Expected return on plan assets | (1,105) | (1,132) | (2,210) | (2,263) |
Amortization of net (gain) loss | 195 | 166 | 391 | 333 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | (149) | (168) | (298) | (333) |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | 0 | 0 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 0 | 0 | ||
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | $ 0 | 0 | ||
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 4.80% | |||
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 5.50% | |||
Texas-New Mexico Power Company [Member] | OPEB [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | $ 62 | 59 | 124 | 119 |
Interest cost | 152 | 155 | 304 | 309 |
Expected return on plan assets | (130) | (133) | (260) | (267) |
Amortization of net (gain) loss | 0 | (31) | 0 | (61) |
Amortization of prior service cost | 0 | 8 | 0 | 16 |
Net Periodic Benefit Cost (Income) | 84 | 58 | 168 | 116 |
Defined Benefit Plan, Contributions by Employer | 0 | 300 | 0 | 300 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 300 | 300 | ||
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 1,400 | 1,400 | ||
Texas-New Mexico Power Company [Member] | Other Pension Plan [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 9 | 10 | 18 | 20 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 1 | 0 | 2 | 0 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | 10 | 10 | 20 | 20 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 100 | 100 | ||
Texas-New Mexico Power Company [Member] | Other Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Contributions by Employer | $ 100 | $ 100 | $ 100 | $ 100 |
Commitments and Contingencies -
Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - Palo Verde Nuclear Generating Station [Member] - Public Service Company of New Mexico [Member] - USD ($) | Oct. 07, 2014 | Mar. 31, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Dec. 31, 2014 |
Nuclear Spent Fuel And Waste Disposal [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Loss Contingency, Estimate of Possible Loss | $ 58,000,000 | ||||
Revised Annual Fee, Nuclear Waste Disposal | $ 0 | ||||
Nuclear Spent Fuel And Waste Disposal [Member] | Other Deferred Credits [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Loss Contingency Accrual | $ 12,500,000 | $ 12,300,000 | |||
Nuclear Spent Fuel And Waste Disposal [Member] | Settled Litigation [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Lawsuit settlement, third party receipt | $ 57,400,000 | ||||
PNMs share of lawsuit settlement, third party receipt | $ 5,900,000 | ||||
Department of energy, spent nuclear fuel removal July 2011 - June 2014 [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Lawsuit settlement, third party receipt | $ 42,000,000 | ||||
PNMs share of third party settlement claim | 4,300,000 | ||||
Litigation Settlement, Portion credited to customers | $ 3,100,000 |
Commitments and Contingencies53
Commitments and Contingencies - The Clean Air Act (Details) $ in Millions | Oct. 01, 2014USD ($)$ / kwMW | Dec. 20, 2013USD ($)$ / kwMW | Jun. 30, 2015USD ($)T / yrstateMW | May. 19, 2015MW | Jun. 26, 2014MW | Oct. 31, 2012USD ($) |
Clean Air Act related to Regional Haze [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Number of States To Address Regional Haze | state | 50 | |||||
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum | T / yr | 250 | |||||
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 46.30% | |||||
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Overall Reduction Of Ownership, in Megawatts | MW | 340 | |||||
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated Total Capital Cost If Requirement Occurred | $ 824 | |||||
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated Installation Capital Costs | 85 | |||||
Estimated Portion of Total Capital Costs if Requirement Occured | 105 | |||||
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated Total Capital Cost If Requirement Occurred | 910 | |||||
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated Installation Capital Costs | 90 | |||||
Estimated Portion of Total Capital Costs if Requirement Occured | $ 110 | |||||
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Requested Time Period to Recover Retired Units NBV | 20 years | 20 years | ||||
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts, December2013 | MW | 177 | |||||
Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013 | MW | 40 | |||||
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts | MW | 187 | |||||
San Juan Generating Station Units 2 and 3 [Member] | Pnm Electric [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units | $ 212.5 | |||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw | 1,650 | |||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Number of Megawatts Nuclear Generation | MW | 134 | |||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Number of Megawatts Nuclear Generation | MW | 134 | 134 | ||||
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw | 2,500 | |||||
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Estimated Installation Capital Costs | $ 90.6 | $ 82 | ||||
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW | 132 | 78 | 132 | 132 | 132 | |
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Public Utilities, Ownership To Be Exchanged, in Megawatts | MW | 78 |
Commitments and Contingencies54
Commitments and Contingencies - Stipulation Filed with the NMPRC (Details) $ in Millions | Apr. 08, 2015USD ($)MW | Oct. 01, 2014USD ($)$ / kwMW | Dec. 20, 2013USD ($)$ / kwMW | Jun. 30, 2015USD ($)MW | May. 19, 2015MW | Jan. 15, 2015MW | Jun. 26, 2014MW |
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW | 132 | 78 | 132 | 132 | 132 | ||
Public Utilities, Estimated rate base value at 1/1/2018 | $ 26 | ||||||
Public Utilities, Ownership in Megawatts PNM has agreed not to obtain | MW | 65 | ||||||
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | MW | 132 | ||||||
Period of time to accept or reject modifications in recommendation | 7 days | ||||||
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Proposed reduction in carrying value | 26 | ||||||
Public Utilities, Estimated unrecoverable increase in operations and maintenance | 20 | ||||||
San Juan Generating Station Unit 3 [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Estimated pre-tax regulatory disallowance | $ 155 | 70 | |||||
San Juan Generating Station Unit 3 [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Estimated pre-tax regulatory disallowance | 145 | $ 60 | |||||
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Net book value | $ 278 | ||||||
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Recovery Percentage of Estimated undepreciated value at 12/31/17 | 50.00% | ||||||
Public Utilities, Estimated undepreciated value at 12/31/17 | $ 128.5 | $ 231 | |||||
Public Utilities, Requested Time Period to Recover Retired Units NBV | 20 years | 20 years | |||||
Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17 | 50.00% | 50.00% | |||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Net book value | $ 147 | ||||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Estimated rate base value at 1/1/2018 | $ 221.1 | ||||||
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw | 1,650 | ||||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Number of Megawatts Nuclear Generation | MW | 134 | ||||||
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Number of Megawatts Nuclear Generation | MW | 134 | 134 | |||||
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | $ / kw | 2,500 | ||||||
Public Utilities, Percentage capacity factor 7-year performance threshold | 75.00% | ||||||
Public Utilities, Period over which to measure capacity performance | 7 years | ||||||
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Estimated Installation Capital Costs | $ 90.6 | $ 82 |
Commitments and Contingencies55
Commitments and Contingencies - SJGS Matters (Details) | Jul. 31, 2015MW | Jun. 30, 2015MW | May. 19, 2015MW | Apr. 08, 2015MW | Jan. 22, 2015USD ($) | Jan. 07, 2015MW | Oct. 01, 2014MW | Jun. 27, 2014USD ($) | Jun. 26, 2014USD ($)MW | Mar. 11, 2014USD ($) | Dec. 20, 2013MW |
Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Public Utilities, Unsubscribed Ownership in Megawatts | 65 | ||||||||||
Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share | 64.50% | ||||||||||
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share | 58.70% | ||||||||||
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 3 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Percentage of ownership held by exiting owners | 50.00% | ||||||||||
Public Utilities, Ownership Percentage | 50.00% | ||||||||||
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Percentage of ownership held by exiting owners | 38.80% | ||||||||||
Public Utilities, Ownership Percentage | 38.50% | ||||||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | 132 | 132 | 132 | 132 | 78 | ||||||
Public Utilities, Costs to obtain additional ownership | $ | $ 0 | ||||||||||
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Requested Expenditure, Installation Capital Costs | $ | $ 76,600,000 | $ 1,900,000 | |||||||||
Requested Additional Expenditure, Installation Capital Costs | $ | $ 6,400,000 | ||||||||||
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | 132 | ||||||||||
PNMR Development [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Public Utilities, Potential Acquisition of Ownership in Megawatts | 65 | 65 | 65 | ||||||||
Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member] | San Juan Generating Station Unit 4 [Member] | |||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | 132 |
Commitments and Contingencies56
Commitments and Contingencies - Four Corners (Details) $ in Millions | Jun. 30, 2015USD ($)lbsofnox / mmbtu | Dec. 31, 2013 | Aug. 06, 2012compliance_alternative |
Four Corners [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage | 48.00% | ||
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Public Utilities, Number of Compliance alternatives | 2 | ||
Public Utilities, Plant Requirement to Meet NOx emissions Limit | lbsofnox / mmbtu | 0.015 | ||
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage | 20.00% | ||
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations | 20.00% | ||
Loss Contingency, Estimate of Possible Loss | $ | $ 91.8 | ||
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Public Utilities, Ownership Percentage | 13.00% |
Commitments and Contingencies57
Commitments and Contingencies - National Ambient Air Quality Standards (Details) - Public Service Company of New Mexico [Member] | Mar. 02, 2015lb / MMBTUT | Jun. 30, 2015opp | Nov. 25, 2014opp | Nov. 08, 2013lb / MMBTU | Jan. 31, 2010opp |
National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Period of time to act on settlement | 16 months | ||||
Public Utilities, Emissions Tons of SO2 per year | T | 16,000 | ||||
San Juan Generating Station [Member] | National Ambient Air Quality Standards [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Public Utilities, Revised SO2 Emissions Agreed Upon | lb / MMBTU | 0.10 | ||||
Minimum [Member] | National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Public Utilities, Emissions Tons of SO2 per year | T | 2,600 | ||||
Public Utilities, 1-hour SO2 Emissions Rate | lb / MMBTU | 0.45 | ||||
Minimum [Member] | San Juan Generating Station And Four Corners [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Public Utilities, Proposed Government Standard Emission Limit | 65 | 60 | |||
Maximum [Member] | San Juan Generating Station And Four Corners [Member] | |||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||
Public Utilities, Proposed Government Standard Emission Limit | 70 | 70 | |||
Public Utilities, Government Standard Emission Limit | 75 |
Commitments and Contingencies58
Commitments and Contingencies - Litigation and Rulemaking (Details) $ in Millions | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Dec. 21, 2011mw | |
Public Utilities, Commitments And Contingencies [Line Items] | |||
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards | mw | 25 | ||
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Mercury Removal Rate, Percentage | 99.00% | 99.00% | |
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Mercury Control [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Current Annual Mercury Control Costs | $ 0.7 | ||
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Maximum [Member] | Mercury Control [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Contingent Estimated Annual Mercury Control Cost | $ 6.6 | ||
Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member] | Clean Air Act Lawsuit [Member] | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Litigation Settlement, Amount | $ 1.5 | ||
Litigation settlement, expected capital spend, environmental | $ 6.2 | ||
Public Utilities, Ownership Percentage | 13.00% | 13.00% |
Commitments and Contingencies59
Commitments and Contingencies - Coal Supply (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Other current assets | $ 71,482 | $ 58,471 | ||
Public Service Company of New Mexico [Member] | Surface [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Regulatory Assets | 100,000 | |||
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Public Utilities, Annual Funding | 1,000 | $ 300 | $ 3,500 | |
Public Service Company of New Mexico [Member] | Mine Reclamation Trust [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Reclamation Trust Funding, Current fiscal year | 4,000 | |||
Reclamation Trust Funding, Next fiscal year | 5,000 | |||
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Loss Contingency Accrual | 25,400 | 25,700 | ||
Final Reclamation, capped amount to be collected | 100,000 | |||
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Loss Contingency Accrual | 9,100 | 8,600 | ||
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Loss Contingency, Estimate of Possible Loss | 56,500 | |||
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Loss Contingency, Estimate of Possible Loss | 93,300 | |||
San Juan Generating Station [Member] | Coal Supply [Member] | Public Service Company of New Mexico [Member] | ||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||
Other current assets | $ 41,900 | $ 37,300 | ||
Public Utilities, Estimated Increase in Coal Cost, Percentage | 30.00% |
Commitments and Contingencies60
Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details) $ in Millions | Jul. 13, 2015a | Jun. 30, 2015USD ($) | Jan. 22, 2015Allotment_Parcel | Apr. 02, 2014Allotment_Parcel | Apr. 01, 2014USD ($) | Jan. 06, 2014Allotment_Parcel | Sep. 30, 2012Allotment_Parcel |
Continuous Highwall Mining [Member] | San Juan Generating Station [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Proposed Retroactive Surface Mining Royalty Rate | 12.50% | ||||||
Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003 | 8.00% | ||||||
Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change | $ 5 | ||||||
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change | 46.30% | ||||||
NMTRD Coal Severance Tax [Member] | Four Corners [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest | $ 30 | ||||||
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Ownership Percentage in Nuclear Reactor | 10.20% | ||||||
Public Utilities, Maximum Potential Assessment Per Incident | $ 38.9 | ||||||
Public Utilities, Annual Payment Limitation Related to Incident | 5.7 | ||||||
Public Utilities, Aggregate Amount of All Risk Insurance | 2,750 | ||||||
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited | 5.4 | ||||||
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member] | Maximum [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Liability Insurance Coverage | 13,400 | ||||||
Public Utilities, Liability Insurance Coverage Sublimit | $ 2,250 | ||||||
Public Service Company of New Mexico [Member] | Commercial Providers [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Liability Insurance Coverage | 375 | ||||||
Public Service Company of New Mexico [Member] | Industry Wide Retrospective Assessment Program [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, Liability Insurance Coverage | $ 13,000 | ||||||
Public Service Company of New Mexico [Member] | NMTRD Coal Severance Tax [Member] | Four Corners [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC | 9.40% | ||||||
Public Service Company of New Mexico [Member] | Navajo Nation Allottee Matters [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Number of landowners claiming to be Navajo allottees | Allotment_Parcel | 43 | ||||||
Number of allotment parcels' appraisal requested for review | Allotment_Parcel | 58 | ||||||
Number of allotments where landowners are revoking rights of way renewal consents | Allotment_Parcel | 10 | 6 | |||||
Public Service Company of New Mexico [Member] | Navajo Nation Allottee Matters [Member] | Subsequent Event [Member] | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Area of Land | a | 15.49 |
Regulatory and Rate Matters - E
Regulatory and Rate Matters - Electric Rate Case (Details) - 2014 Electric Rate Case [Member] - Public Service Company of New Mexico [Member] $ in Millions | May. 27, 2015 | Jun. 30, 2015USD ($) | Jun. 25, 2015 |
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 107.4 | ||
Public Utilities, Requested Return on Equity, Percentage | 10.50% | ||
Public Utilities, Average customer bill increase percentage | 7.69% | ||
Public Utilities, Percentage of requested rate increase pertaining to infrastructure investments | 92.00% | ||
Future test year period, Number of days following the filing of application for rate increase | 45 days | 13 months | |
Public Utilities, Number of other utilities filing appeals | 2 | ||
Public Utilities, Number of other parties filing cross appeals | 1 |
Regulatory and Rate Matters - R
Regulatory and Rate Matters - Renewable Portfolio Standard and Energy Rider (Details) - Public Service Company of New Mexico [Member] | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2015USD ($)MWhMW | Dec. 31, 2014USD ($) | Jun. 30, 2015USD ($)MW | Dec. 31, 2014USD ($)$ / MWh | Dec. 31, 2013USD ($) | Feb. 27, 2015USD ($) | |
Renewable Portfolio Standard [Member] | Required Percentage by 2011 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales | 10.00% | 10.00% | ||||
Renewable Portfolio Standard [Member] | Required Percentage by 2015 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales | 15.00% | 15.00% | ||||
Renewable Portfolio Standard [Member] | Required Percentage by 2020 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales | 20.00% | 20.00% | ||||
Renewable Portfolio Standard [Member] | Minimum [Member] | Wind Energy [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Diversification | 30.00% | 30.00% | ||||
Renewable Portfolio Standard [Member] | Minimum [Member] | Solar Energy [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Diversification | 20.00% | 20.00% | ||||
Renewable Portfolio Standard [Member] | Minimum [Member] | Renewable Technologies [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Diversification | 5.00% | 5.00% | ||||
Renewable Portfolio Standard [Member] | Minimum [Member] | Distributed Generation [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Required Percentage of Diversification | 3.00% | 3.00% | ||||
Renewable Portfolio Standard [Member] | Maximum [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Reasonable Cost Threshold | 3.00% | 3.00% | ||||
2014 Wind generated Renewable Energy Credits [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Mega Watt Hours of Wind Generation | MWh | 50,000 | |||||
Renewable Portfolio Standard 2014 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity | MW | 23 | 23 | ||||
Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity | $ 46,700,000 | |||||
Public Utilities, Wind Capacity Planned Purchase Agreement Term | 20 years | |||||
Public Utilities, Number of Mega Watts of Wind Energy Capacity | MW | 102 | |||||
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement | $ 5,800,000 | |||||
Public Utilities, Final Cost of Solar Photovoltaic Capacity | $ 46,500,000 | |||||
Public Utilities, Cost of renewable resources procured | $ 100,000 | $ 100,000 | ||||
2015 Wind generated Renewable Energy Credits [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Mega Watt Hours of Wind Generation | MWh | 120,000 | |||||
Renewable Portfolio Standard 2015 [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity | MW | 40 | 40 | ||||
Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity | $ 79,300,000 | |||||
Public Utilities, Approved Revised cost per MWh for additional necessary procurements to comply with RPS | $ / MWh | 3 | |||||
Renewable Energy Rider [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Revenue from Renewable energy rider | $ 34,300,000 | |||||
Renewable Energy Rider [Member] | Maximum [Member] | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013 | 10.50% | 10.50% | ||||
Public Utilities, Annual Revenue To be Collected Under 2015 Rider Rate | $ 44,700,000 | $ 44,700,000 | ||||
Public Utilities, Revised Annual Revenue To be Collected Under 2015 Rider Rate | $ 43,000,000 | |||||
Public Utilities, Annual Revenue To be Collected Under 2016 Rider Rate | $ 42,400,000 |
Regulatory and Rate Matters -63
Regulatory and Rate Matters - Energy Efficiency and Load Management (Details) - Public Service Company of New Mexico [Member] - USD ($) $ in Millions | Oct. 06, 2014 | Jun. 30, 2015 | Dec. 31, 2014 |
Energy Efficiency and Load Management [Member] | Disincentives / Incentives Adder [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Program Costs Related To Energy Efficiency | $ 25.8 | ||
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program, Percentage of Program Costs | 7.60% | ||
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program | $ 1.7 | ||
Public Utilities, Proposed Profit Incentive Adder Revenues Related To 2015 Energy Efficiency Program | $ 2.1 | ||
2014 Energy Efficiency and Load Management Program [Member] | Disincentives / Incentives Adder [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Anticipated future profit incentive 2015 | $ 1.7 | ||
Public Utilities, Anticipated future profit incentive 2016 | $ 1.8 | ||
Maximum [Member] | Renewable Portfolio Standard [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Reasonable Cost Threshold | 3.00% |
Regulatory and Rate Matters - I
Regulatory and Rate Matters - Integrated Resource Plan, Four Corners Right of First Refusal and Application for Certificate (Details) - Public Service Company of New Mexico [Member] $ in Millions | 1 Months Ended | 3 Months Ended | 4 Months Ended | |
Jul. 31, 2011 | Jun. 30, 2015USD ($)MW | Jun. 17, 2015 | Feb. 17, 2015 | |
Four Corners [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities | 7.00% | |||
Period of time to file a waiver of rights of first refusal | 120 days | |||
San Juan Generating Station Units 2 and 3 [Member] | Clean Air Act, SNCR [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts | MW | 187 | |||
Public Utilities, Cost of replacement gas-generation | $ 133.2 | |||
Integrated Resource Plan, 2011 [Member] | ||||
Public Utilities, General Disclosures [Line Items] | ||||
Public Utilities, Frequency of IRP filings | 3 years | |||
Public Utilities, Planning Period Covered of IRP | 20 years |
Regulatory and Rate Matters - F
Regulatory and Rate Matters - Formula Transmission Rate Case (Details) - Formula Transmission Rate Case [Member] - Public Service Company of New Mexico [Member] $ in Millions | May. 02, 2014USD ($) | Jun. 03, 2013USD ($) | Jun. 30, 2015USD ($) | Mar. 20, 2015party |
Public Utilities, General Disclosures [Line Items] | ||||
Amount of Regulatory Costs Not yet Approved | $ 3.2 | |||
Public Utilities, Return on Equity | 10.81% | 10.00% | ||
Percentage ownership of EIP transmission line | 60.00% | |||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 0.5 | $ 1.3 | ||
Number of other parties to settlement | party | 5 | |||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 1.3 |
Regulatory and Rate Matters -66
Regulatory and Rate Matters - Firm-Requirements Wholesale Customers (Details) - Public Service Company of New Mexico [Member] $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended |
Jun. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2014USD ($)MW | |
Firm Requirements Wholesale Power Rate Case, Navopache [Member] [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 5.3 | ||
Public Utilities, Average monthly usage in megawatts | MW | 55 | ||
Public Utilities, Revenue For Power Sold Under Specific Contract | $ 28.4 | ||
Firm Requirements Wholesale Power Rate Case [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Contract Extension | 10 years | ||
City of Gallup, New Mexico Contract [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Revenue For Power Sold Under Specific Contract | $ 6.1 | ||
Public Utilities, Gain on sale of substation | $ 1.1 |
Regulatory and Rate Matters - T
Regulatory and Rate Matters - TNMP Narrative (Details) - Texas-New Mexico Power Company [Member] | 1 Months Ended | ||
Jul. 30, 2011USD ($) | Jul. 24, 2015customer | Jun. 30, 2015USD ($)customer | |
Advanced Meter System Deployment and Surcharge Request [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Deployment Costs | $ 113,400,000 | ||
Public Utilities, Collection of Deployment Costs Through Surcharge Period | 12 years | ||
Public Utilities, Completion Period of Advanced Meter Deployment | 5 years | ||
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers | $ 200,000 | ||
Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers | 500,000 | ||
Public Utilities, Approved Non-standard metering ongoing expenses monthly charge | $ 36.78 | ||
Presumed number of customers that will elect non-standard meter service | customer | 1,081 | ||
Advanced Meter System Deployment and Surcharge Request [Member] | Subsequent Event [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Current number of customers that have elected non-standard meter service | customer | 96 | ||
Advanced Meter System Deployment and Surcharge Request [Member] | Minimum [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Non-standard metering service cost initial fee range | $ 63.97 | ||
Advanced Meter System Deployment and Surcharge Request [Member] | Maximum [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved Non-standard metering service cost initial fee range | 168.61 | ||
Energy Efficiency [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Public Utilities, Approved 2014 Program Implementation Costs | 5,600,000 | ||
Public Utilities, Unapproved 2015 Program Implementation Costs, Bonus | 700,000 | ||
Public Utilities, Unapproved 2015 Program Implementation Costs | 5,700,000 | ||
Public Utilities, Approved 2014 Incentive Portion of Program Implementation Costs | 1,500,000 | ||
Public Utilities, Requested 2016 Program Implementation Costs | 5,900,000 | ||
Public Utilities, Unapproved 2016 Program Implementation Costs, Bonus | $ 600,000 |
Regulatory and Rate Matters -68
Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - Transmission Cost of Service Rates [Member] - Texas-New Mexico Power Company [Member] - USD ($) $ in Millions | Jul. 17, 2015 | Sep. 15, 2015 | Mar. 15, 2015 | Sep. 07, 2014 | Mar. 12, 2014 |
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 25.2 | $ 18.2 | $ 18.1 | ||
Annual Increase in Revenue | $ 4.2 | $ 2.9 | $ 2.8 | ||
Subsequent Event [Member] | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 27.1 | ||||
Annual Increase in Revenue | $ 1.4 | $ 4.4 | |||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015 | Mar. 31, 2015 | Jun. 30, 2014 | Mar. 31, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Tax Contingency [Line Items] | ||||||
Decrease in regulatory liabilities due to change in state corporate tax rate | $ 2,000 | $ 4,600 | ||||
Decrease in deferred tax asset due to change in state corporate tax rate | $ 200 | |||||
Income Taxes | $ 17,353 | $ 15,893 | $ 25,870 | $ 22,313 | ||
State Net Operating Loss Carryforward, Impairment | 1,000 | |||||
Public Service Company of New Mexico [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Increase in deferred tax asset not related to regulatory activity, as a result of tax rate change | 700 | |||||
Decrease in income tax expense due to tax rate change | 500 | |||||
Income Taxes | 11,527 | 13,106 | 17,302 | 17,189 | ||
State Net Operating Loss Carryforward, Impairment | 700 | |||||
Corporate and Other [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Decrease in income tax expense due to tax rate change | 200 | |||||
Income Taxes | $ (975) | (2,803) | $ (2,836) | (4,516) | ||
State Net Operating Loss Carryforward, Impairment | $ 300 | |||||
Internal Revenue Service (IRS) [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Income Taxes | 1,300 | |||||
PNM Resources [Member] | Internal Revenue Service (IRS) [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | 2,000 | $ 2,000 | ||||
Income Taxes | 200 | |||||
Public Service Company of New Mexico [Member] | Internal Revenue Service (IRS) [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Income Taxes | 1,100 | |||||
Texas-New Mexico Power Company [Member] | Internal Revenue Service (IRS) [Member] | ||||||
Income Tax Contingency [Line Items] | ||||||
Income Taxes | $ 0 |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Service billings [Member] | PNMR to PNM [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 21,340 | $ 22,190 | $ 44,067 | $ 43,256 |
Service billings [Member] | PNMR to TNMP [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 6,591 | 6,963 | 13,680 | 14,224 |
Service billings [Member] | PNM to TNMP [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 184 | 133 | 288 | 242 |
Service billings [Member] | TNMP to PNMR [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 0 | 0 | 0 |
Interest charges [Member] | PNMR to PNM [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 22 | 0 | 28 | 54 |
Interest charges [Member] | PNMR to TNMP [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 54 | 83 | 133 | 180 |
Interest charges [Member] | PNM to PNMR [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 26 | 25 | 55 | 51 |
Income tax sharing payments [Member] | PNMR to PNM [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 0 | 1,450 | 0 |
Income tax sharing payments [Member] | PNMR to TNMP [Member] | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 0 | $ 0 | $ 0 | $ 0 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Apr. 01, 2015 | Dec. 31, 2014 | Jun. 30, 2014 | Apr. 01, 2014 | Apr. 01, 2012 |
Goodwill [Line Items] | ||||||
Goodwill | $ 278,297 | $ 278,297 | $ 278,297 | |||
Public Service Company of New Mexico [Member] | ||||||
Goodwill [Line Items] | ||||||
Goodwill | $ 51,600 | $ 51,600 | ||||
Percentage of fair value in excess of carrying amount | 25.00% | 30.00% | ||||
Texas-New Mexico Power Company [Member] | ||||||
Goodwill [Line Items] | ||||||
Goodwill | $ 226,700 | |||||
Percentage of fair value in excess of carrying amount | 26.00% |