Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2017 | Oct. 20, 2017 | |
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 | Sep. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 79,653,624 | |
PNM | ||
Document Information [Line Items] | ||
Entity Registrant Name | PUBLIC SERVICE CO OF NEW MEXICO | |
Entity Central Index Key | 81,023 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 39,117,799 | |
Texas-New Mexico Power Company | ||
Document Information [Line Items] | ||
Entity Registrant Name | TEXAS NEW MEXICO POWER CO | |
Entity Central Index Key | 22,767 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 6,358 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Earnings - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Electric Operating Revenues | $ 419,900 | $ 400,374 | $ 1,112,398 | $ 1,026,726 |
Operating Expenses: | ||||
Cost of energy | 103,748 | 108,766 | 310,818 | 282,498 |
Administrative and general | 46,268 | 46,942 | 138,923 | 139,214 |
Energy production costs | 31,970 | 31,460 | 98,150 | 112,026 |
Regulatory disallowances and restructuring costs | 0 | 16,451 | 0 | 17,225 |
Depreciation and amortization | 58,821 | 53,017 | 172,829 | 153,801 |
Transmission and distribution costs | 16,801 | 16,056 | 50,309 | 49,965 |
Taxes other than income taxes | 19,808 | 19,611 | 57,820 | 57,598 |
Total operating expenses | 277,416 | 292,303 | 828,849 | 812,327 |
Operating income | 142,484 | 108,071 | 283,549 | 214,399 |
Other Income and Deductions: | ||||
Interest income | 3,582 | 4,604 | 12,348 | 18,420 |
Gains on available-for-sale securities | 5,406 | 4,531 | 17,730 | 15,380 |
Other income | 6,275 | 4,884 | 14,626 | 13,413 |
Other (deductions) | (4,571) | (3,764) | (10,958) | (10,866) |
Net other income and deductions | 10,692 | 10,255 | 33,746 | 36,347 |
Interest Charges | 32,106 | 32,467 | 96,137 | 97,179 |
Earnings before Income Taxes | 121,070 | 85,859 | 221,158 | 153,567 |
Income Taxes | 42,743 | 27,303 | 75,154 | 50,094 |
Net Earnings | 78,327 | 58,556 | 146,004 | 103,473 |
(Earnings) Attributable to Valencia Non-controlling Interest | (4,456) | (4,006) | (11,452) | (11,037) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Net Earnings Attributable to PNMR | 73,739 | 54,418 | 134,156 | 92,040 |
Net Earnings Available for PNM Common Stock | $ 73,739 | $ 54,418 | $ 134,156 | $ 92,040 |
Net Earnings Attributable to PNMR per Common Share: | ||||
Basic (dollars per share) | $ 0.92 | $ 0.68 | $ 1.68 | $ 1.15 |
Diluted (dollars per share) | 0.92 | 0.68 | 1.67 | 1.15 |
Dividends Declared per Common Share (dollars per share) | $ 0.2425 | $ 0.22 | $ 0.7275 | $ 0.66 |
PNM | ||||
Electric Operating Revenues | $ 327,254 | $ 311,276 | $ 854,909 | $ 780,228 |
Operating Expenses: | ||||
Cost of energy | 82,367 | 88,565 | 246,635 | 222,376 |
Administrative and general | 42,026 | 41,370 | 127,012 | 122,553 |
Energy production costs | 31,970 | 31,460 | 98,150 | 112,026 |
Regulatory disallowances and restructuring costs | 0 | 16,451 | 0 | 17,225 |
Depreciation and amortization | 36,764 | 33,312 | 109,228 | 97,778 |
Transmission and distribution costs | 10,207 | 9,311 | 30,301 | 29,868 |
Taxes other than income taxes | 10,668 | 10,750 | 32,837 | 33,289 |
Total operating expenses | 214,002 | 231,219 | 644,163 | 635,115 |
Operating income | 113,252 | 80,057 | 210,746 | 145,113 |
Other Income and Deductions: | ||||
Interest income | 1,782 | 1,509 | 6,457 | 8,549 |
Gains on available-for-sale securities | 5,406 | 4,531 | 17,730 | 15,380 |
Other income | 3,762 | 3,239 | 10,270 | 9,578 |
Other (deductions) | (2,826) | (2,790) | (8,076) | (7,653) |
Net other income and deductions | 8,124 | 6,489 | 26,381 | 25,854 |
Interest Charges | 20,451 | 22,213 | 62,393 | 66,494 |
Earnings before Income Taxes | 100,925 | 64,333 | 174,734 | 104,473 |
Income Taxes | 35,642 | 19,343 | 58,865 | 32,131 |
Net Earnings | 65,283 | 44,990 | 115,869 | 72,342 |
(Earnings) Attributable to Valencia Non-controlling Interest | (4,456) | (4,006) | (11,452) | (11,037) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Net Earnings Attributable to PNMR | 60,827 | 40,984 | 104,417 | 61,305 |
Net Earnings Available for PNM Common Stock | 60,695 | 40,852 | 104,021 | 60,909 |
Texas-New Mexico Power Company | ||||
Electric Operating Revenues | 92,646 | 89,098 | 257,489 | 246,498 |
Operating Expenses: | ||||
Cost of energy | 21,381 | 20,201 | 64,183 | 60,122 |
Administrative and general | 10,765 | 9,588 | 30,402 | 29,382 |
Depreciation and amortization | 16,424 | 16,354 | 47,392 | 45,760 |
Transmission and distribution costs | 6,594 | 6,745 | 20,008 | 20,097 |
Taxes other than income taxes | 8,008 | 7,851 | 21,778 | 20,849 |
Total operating expenses | 63,172 | 60,739 | 183,763 | 176,210 |
Operating income | 29,474 | 28,359 | 73,726 | 70,288 |
Other Income and Deductions: | ||||
Other income | 2,258 | 1,376 | 3,621 | 2,999 |
Other (deductions) | (1,030) | (521) | (1,229) | (860) |
Net other income and deductions | 1,228 | 855 | 2,392 | 2,139 |
Interest Charges | 7,704 | 7,308 | 22,619 | 22,150 |
Earnings before Income Taxes | 22,998 | 21,906 | 53,499 | 50,277 |
Income Taxes | 8,271 | 8,053 | 18,964 | 18,460 |
Net Earnings Attributable to PNMR | $ 14,727 | $ 13,853 | $ 34,535 | $ 31,817 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Net Earnings | $ 78,327 | $ 58,556 | $ 146,004 | $ 103,473 |
Unrealized Gains on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | 4,528 | 2,933 | 13,648 | 1,899 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (2,526) | (3,101) | (6,786) | (6,180) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit) | 987 | 839 | 2,961 | 2,517 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Change in fair market value, net of income tax (expense) benefit of $(4), $(172), $108, and $509 | 6 | 269 | (170) | (796) |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(62), $(79), $(187), and $(224) | 99 | 123 | 297 | 349 |
Total Other Comprehensive Income (Loss) | 3,094 | 1,063 | 9,950 | (2,211) |
Comprehensive Income | 81,421 | 59,619 | 155,954 | 101,262 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (4,456) | (4,006) | (11,452) | (11,037) |
Preferred Stock Dividend Requirements of Subsidiary | (132) | (132) | (396) | (396) |
Comprehensive Income Attributable to PNMR | 76,833 | 55,481 | 144,106 | 89,829 |
PNM | ||||
Net Earnings | 65,283 | 44,990 | 115,869 | 72,342 |
Unrealized Gains on Available-for-Sale Securities: | ||||
Unrealized holding gains arising during the period, net of income tax (expense) | 4,528 | 2,933 | 13,648 | 1,899 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | (2,526) | (3,101) | (6,786) | (6,180) |
Pension Liability Adjustment: | ||||
Reclassification adjustment for amortization of experience losses recognized as net periodic benefit cost, net of income tax expense (benefit) | 987 | 839 | 2,961 | 2,517 |
Fair Value Adjustment for Cash Flow Hedges: | ||||
Total Other Comprehensive Income (Loss) | 2,989 | 671 | 9,823 | (1,764) |
Comprehensive Income | 68,272 | 45,661 | 125,692 | 70,578 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (4,456) | (4,006) | (11,452) | (11,037) |
Comprehensive Income Attributable to PNMR | $ 63,816 | $ 41,655 | $ 114,240 | $ 59,541 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | $ (2,871) | $ (1,877) | $ (8,654) | $ (1,216) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 1,601 | 1,985 | 4,302 | 3,955 |
Pension liability adjustment, income tax expense (benefit) | (626) | (537) | (1,878) | (1,611) |
Change in fair market value, income tax (expense) benefit | (4) | (172) | 108 | 509 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | (62) | (79) | (187) | (224) |
PNM | ||||
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit | (2,871) | (1,877) | (8,654) | (1,216) |
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit) | 1,601 | 1,985 | 4,302 | 3,955 |
Pension liability adjustment, income tax expense (benefit) | $ (626) | $ (537) | $ (1,878) | $ (1,611) |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Cash Flows From Operating Activities: | ||
Net Earnings | $ 146,004 | $ 103,473 |
Net earnings | 134,156 | 92,040 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 200,286 | 178,137 |
Deferred income tax expense | 75,224 | 50,302 |
Net unrealized (gains) losses on commodity derivatives | 968 | 2,179 |
Realized (gains) on available-for-sale securities | (17,730) | (15,380) |
Stock based compensation expense | 5,322 | 4,401 |
Regulatory disallowances and restructuring costs | 0 | 17,225 |
Allowance for equity funds used during construction | (6,217) | (3,058) |
Other, net | 1,409 | 2,104 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (21,077) | (1,145) |
Materials, supplies, and fuel stock | (203) | (4,629) |
Other current assets | 22,761 | (11,819) |
Other assets | (5,981) | 1,916 |
Accounts payable | 3,729 | 6,192 |
Accrued interest and taxes | 20,722 | 20,816 |
Other current liabilities | (1,588) | (19,431) |
Other liabilities | (6,292) | (10,297) |
Net cash flows from operating activities | 417,337 | 320,986 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (353,423) | (502,530) |
Proceeds from sales of available-for-sale securities | 456,577 | 280,989 |
Purchases of available-for-sale securities | (461,126) | (284,706) |
Return of principal on PVNGS lessor notes | 0 | 8,547 |
Investment in Westmoreland Loan | 0 | (122,250) |
Principal repayments on Westmoreland Loan | 28,770 | 15,000 |
Other, net | 160 | 179 |
Net cash flows from investing activities | (329,042) | (604,771) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | (20,600) | 105,300 |
Long-term borrowings | 317,000 | 503,500 |
Repayment of long-term debt | (263,323) | (288,157) |
Proceeds from stock option exercise | 1,739 | 6,668 |
Awards of common stock | (13,816) | (14,920) |
Dividends paid | (58,344) | (52,967) |
Valencia’s transactions with its owner | (12,963) | (12,327) |
Amounts received under transmission interconnection arrangements | 11,879 | 3,262 |
Refunds paid under transmission interconnection arrangements | (9,368) | (2,246) |
Other, net | (1,872) | (2,698) |
Net cash flows from financing activities | (49,668) | 245,415 |
Change in Cash and Cash Equivalents | 38,627 | (38,370) |
Cash and Cash Equivalents at Beginning of Period | 4,522 | 46,051 |
Cash and Cash Equivalents at End of Period | 43,149 | 7,681 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 75,356 | 75,537 |
Income taxes paid (refunded), net | 625 | 850 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | (4,499) | 30,208 |
PNM | ||
Cash Flows From Operating Activities: | ||
Net Earnings | 115,869 | 72,342 |
Net earnings | 104,417 | 61,305 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 134,541 | 122,344 |
Deferred income tax expense | 59,866 | 33,175 |
Net unrealized (gains) losses on commodity derivatives | 968 | 2,179 |
Realized (gains) on available-for-sale securities | (17,730) | (15,380) |
Regulatory disallowances and restructuring costs | 0 | 17,225 |
Allowance for equity funds used during construction | (5,908) | (2,654) |
Other, net | 1,705 | 2,091 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (13,881) | 8,283 |
Materials, supplies, and fuel stock | 1,385 | (7,731) |
Other current assets | 24,488 | (4,005) |
Other assets | 6,925 | 10,117 |
Accounts payable | 123 | 6,819 |
Accrued interest and taxes | 16,221 | 16,146 |
Other current liabilities | (17,988) | (18,908) |
Other liabilities | (8,792) | (13,401) |
Net cash flows from operating activities | 297,792 | 228,642 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (206,499) | (377,637) |
Proceeds from sales of available-for-sale securities | 456,577 | 280,989 |
Purchases of available-for-sale securities | (461,126) | (284,706) |
Return of principal on PVNGS lessor notes | 0 | 8,547 |
Other, net | 150 | 171 |
Net cash flows from investing activities | (210,898) | (372,636) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | (61,000) | 42,400 |
Long-term borrowings | 257,000 | 321,000 |
Repayment of long-term debt | (232,000) | (271,000) |
Equity contribution from parent | 0 | 28,142 |
Dividends paid | (396) | (4,538) |
Valencia’s transactions with its owner | (12,963) | (12,327) |
Amounts received under transmission interconnection arrangements | 11,879 | 3,262 |
Refunds paid under transmission interconnection arrangements | 9,368 | 2,246 |
Other, net | (1,000) | (1,944) |
Net cash flows from financing activities | (47,848) | 102,749 |
Change in Cash and Cash Equivalents | 39,046 | (41,245) |
Cash and Cash Equivalents at Beginning of Period | 324 | 43,138 |
Cash and Cash Equivalents at End of Period | 39,370 | 1,893 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 48,627 | 53,791 |
Income taxes paid (refunded), net | 0 | 0 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | (9,399) | 20,200 |
Texas-New Mexico Power Company | ||
Cash Flows From Operating Activities: | ||
Net earnings | 34,535 | 31,817 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ||
Depreciation and amortization | 48,754 | 47,055 |
Deferred income tax expense | 8,578 | (739) |
Allowance for equity funds used during construction | (309) | (405) |
Other, net | (296) | 14 |
Changes in certain assets and liabilities: | ||
Accounts receivable and unbilled revenues | (7,196) | (9,428) |
Materials, supplies, and fuel stock | (1,588) | 3,102 |
Other current assets | (1,674) | (3,570) |
Other assets | (13,799) | (8,415) |
Accounts payable | 669 | (6,758) |
Accrued interest and taxes | 13,550 | 22,896 |
Other current liabilities | 945 | (363) |
Other liabilities | 1,633 | 399 |
Net cash flows from operating activities | 83,802 | 75,605 |
Cash Flows From Investing Activities: | ||
Additions to utility and non-utility plant | (106,914) | (93,048) |
Net cash flows from investing activities | (106,914) | (93,048) |
Cash Flows From Financing Activities: | ||
Revolving credit facilities borrowings (repayments), net | 0 | (59,000) |
Short-term borrowings (repayments) - affiliate, net | (4,600) | (11,800) |
Long-term borrowings | 60,000 | 60,000 |
Equity contribution from parent | 0 | 50,000 |
Dividends paid | (29,663) | (17,965) |
Other, net | (874) | (775) |
Net cash flows from financing activities | 24,863 | 20,460 |
Change in Cash and Cash Equivalents | 1,751 | 3,017 |
Cash and Cash Equivalents at Beginning of Period | 671 | 1 |
Cash and Cash Equivalents at End of Period | 2,422 | 3,018 |
Supplemental Cash Flow Disclosures: | ||
Interest paid, net of amounts capitalized | 16,721 | 15,642 |
Income taxes paid (refunded), net | 750 | 850 |
Supplemental schedule of noncash investing activities: | ||
(Increase) decrease in accrued plant additions | $ (251) | $ (10) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Current Assets: | ||
Cash and cash equivalents | $ 43,149 | $ 4,522 |
Accounts receivable, net of allowance for uncollectible accounts | 107,428 | 87,012 |
Unbilled revenues | 57,241 | 58,284 |
Other receivables | 16,567 | 28,245 |
Current portion of Westmoreland Loan | 12,272 | 38,360 |
Materials, supplies, and fuel stock | 68,179 | 73,027 |
Regulatory assets | 3,424 | 3,855 |
Commodity derivative instruments | 3,093 | 5,224 |
Income taxes receivable | 6,761 | 6,066 |
Other current assets | 56,421 | 73,444 |
Total current assets | 374,535 | 378,039 |
Other Property and Investments: | ||
Long-term portion of Westmoreland Loan | 53,958 | 56,640 |
Available-for-sale securities | 306,444 | 272,977 |
Other investments | 386 | 547 |
Non-utility property | 3,404 | 3,404 |
Total other property and investments | 364,192 | 333,568 |
Utility Plant: | ||
Plant in service, held for future use, and to be abandoned | 7,133,646 | 6,944,534 |
Less accumulated depreciation and amortization | 2,431,695 | 2,334,938 |
Net plant in service and plant held for future use | 4,701,951 | 4,609,596 |
Construction work in progress | 301,466 | 208,206 |
Nuclear fuel, net of accumulated amortization | 88,702 | 86,913 |
Net utility plant | 5,092,119 | 4,904,715 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 489,416 | 501,223 |
Goodwill | 278,297 | 278,297 |
Commodity derivative instruments | 3,846 | 0 |
Other deferred charges | 94,849 | 75,238 |
Total deferred charges and other assets | 866,408 | 854,758 |
Total assets | 6,697,254 | 6,471,080 |
Current Liabilities: | ||
Short-term debt | 266,500 | 287,100 |
Current installments of long-term debt | 165,312 | 273,348 |
Accounts payable | 89,882 | 86,705 |
Customer deposits | 10,951 | 11,374 |
Accrued interest and taxes | 83,288 | 61,871 |
Regulatory liabilities | 7,156 | 3,609 |
Commodity derivative instruments | 1,279 | 2,339 |
Dividends declared | 19,448 | 19,448 |
Transmission interconnection arrangement liabilities | 12,167 | 522 |
Other current liabilities | 67,069 | 59,314 |
Total current liabilities | 710,885 | 805,108 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 2,282,390 | 2,119,364 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 1,015,967 | 940,650 |
Regulatory liabilities | 456,740 | 455,649 |
Asset retirement obligations | 133,841 | 127,519 |
Accrued pension liability and postretirement benefit cost | 116,812 | 125,844 |
Commodity derivative instruments | 3,846 | 0 |
Other deferred credits | 132,098 | 140,545 |
Total deferred credits and other liabilities | 1,859,304 | 1,790,207 |
Total liabilities | 4,852,579 | 4,714,679 |
Commitments and Contingencies (See Note 11) | ||
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 |
Company common stockholders’ equity: | ||
Common stock | 1,156,906 | 1,163,661 |
Accumulated other comprehensive income (loss), net of income taxes | (82,501) | (92,451) |
Retained earnings | 691,332 | 604,742 |
Total stockholders' equity | 1,765,737 | 1,675,952 |
Non-controlling interest in Valencia | 67,409 | 68,920 |
Total equity | 1,833,146 | 1,744,872 |
Total liabilities and stockholders' equity | 6,697,254 | 6,471,080 |
PNM | ||
Current Assets: | ||
Cash and cash equivalents | 39,370 | 324 |
Accounts receivable, net of allowance for uncollectible accounts | 79,668 | 65,003 |
Unbilled revenues | 45,800 | 48,289 |
Other receivables | 13,510 | 25,514 |
Affiliate receivables | 8,944 | 8,886 |
Materials, supplies, and fuel stock | 63,016 | 64,401 |
Regulatory assets | 2,526 | 3,442 |
Commodity derivative instruments | 3,093 | 5,224 |
Income taxes receivable | 26,808 | 25,807 |
Other current assets | 48,883 | 67,355 |
Total current assets | 331,618 | 314,245 |
Other Property and Investments: | ||
Available-for-sale securities | 306,444 | 272,977 |
Other investments | 166 | 316 |
Non-utility property | 96 | 96 |
Total other property and investments | 306,706 | 273,389 |
Utility Plant: | ||
Plant in service, held for future use, and to be abandoned | 5,463,764 | 5,359,211 |
Less accumulated depreciation and amortization | 1,881,371 | 1,809,528 |
Net plant in service and plant held for future use | 3,582,393 | 3,549,683 |
Construction work in progress | 223,677 | 158,122 |
Nuclear fuel, net of accumulated amortization | 88,702 | 86,913 |
Net utility plant | 3,894,772 | 3,794,718 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 349,453 | 365,413 |
Goodwill | 51,632 | 51,632 |
Commodity derivative instruments | 3,846 | 0 |
Other deferred charges | 85,789 | 68,149 |
Total deferred charges and other assets | 490,720 | 485,194 |
Total assets | 5,023,816 | 4,867,546 |
Current Liabilities: | ||
Short-term debt | 0 | 61,000 |
Current installments of long-term debt | 0 | 231,880 |
Accounts payable | 65,088 | 55,566 |
Affiliate payables | 9,738 | 23,183 |
Customer deposits | 10,951 | 11,374 |
Accrued interest and taxes | 52,041 | 34,819 |
Regulatory liabilities | 7,138 | 3,517 |
Commodity derivative instruments | 1,279 | 2,339 |
Dividends declared | 132 | 132 |
Other current liabilities | 32,532 | 33,029 |
Total current liabilities | 191,066 | 457,361 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 1,657,396 | 1,399,489 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 810,995 | 748,666 |
Regulatory liabilities | 423,477 | 423,701 |
Asset retirement obligations | 132,878 | 126,601 |
Accrued pension liability and postretirement benefit cost | 106,742 | 114,427 |
Commodity derivative instruments | 3,846 | 0 |
Other deferred credits | 106,762 | 118,980 |
Total deferred credits and other liabilities | 1,584,700 | 1,532,375 |
Total liabilities | 3,433,162 | 3,389,225 |
Commitments and Contingencies (See Note 11) | ||
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 |
Company common stockholders’ equity: | ||
Common stock | 1,264,918 | 1,264,918 |
Accumulated other comprehensive income (loss), net of income taxes | (82,605) | (92,428) |
Retained earnings | 329,403 | 225,382 |
Total stockholders' equity | 1,511,716 | 1,397,872 |
Non-controlling interest in Valencia | 67,409 | 68,920 |
Total equity | 1,579,125 | 1,466,792 |
Total liabilities and stockholders' equity | 5,023,816 | 4,867,546 |
Texas-New Mexico Power Company | ||
Current Assets: | ||
Cash and cash equivalents | 2,422 | 671 |
Accounts receivable, net of allowance for uncollectible accounts | 27,760 | 22,009 |
Unbilled revenues | 11,441 | 9,995 |
Other receivables | 2,698 | 2,090 |
Materials, supplies, and fuel stock | 5,163 | 8,626 |
Regulatory assets | 898 | 413 |
Other current assets | 1,609 | 1,031 |
Total current assets | 51,991 | 44,835 |
Other Property and Investments: | ||
Other investments | 220 | 231 |
Non-utility property | 2,240 | 2,240 |
Total other property and investments | 2,460 | 2,471 |
Utility Plant: | ||
Plant in service, held for future use, and to be abandoned | 1,433,901 | 1,380,584 |
Less accumulated depreciation and amortization | 449,476 | 429,397 |
Net plant in service and plant held for future use | 984,425 | 951,187 |
Construction work in progress | 53,545 | 16,978 |
Net utility plant | 1,037,970 | 968,165 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 139,963 | 135,810 |
Goodwill | 226,665 | 226,665 |
Other deferred charges | 6,170 | 5,277 |
Total deferred charges and other assets | 372,798 | 367,752 |
Total assets | 1,465,219 | 1,383,223 |
Current Liabilities: | ||
Short-term debt – affiliate | 0 | 4,600 |
Accounts payable | 12,578 | 16,709 |
Affiliate payables | 3,736 | 3,793 |
Accrued interest and taxes | 59,131 | 45,581 |
Regulatory liabilities | 18 | 92 |
Other current liabilities | 3,210 | 2,134 |
Total current liabilities | 78,673 | 72,909 |
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | 480,589 | 420,875 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 254,525 | 245,785 |
Regulatory liabilities | 33,263 | 31,948 |
Asset retirement obligations | 789 | 754 |
Accrued pension liability and postretirement benefit cost | 10,070 | 11,417 |
Other deferred credits | 9,203 | 6,300 |
Total deferred credits and other liabilities | 307,850 | 296,204 |
Total liabilities | 867,112 | 789,988 |
Commitments and Contingencies (See Note 11) | ||
Company common stockholders’ equity: | ||
Common stock | 64 | 64 |
Paid-in-capital | 454,166 | 454,166 |
Retained earnings | 143,877 | 139,005 |
Total stockholders' equity | 598,107 | 593,235 |
Total liabilities and stockholders' equity | $ 1,465,219 | $ 1,383,223 |
Condensed Consolidated Balance7
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Allowance for uncollectible accounts | $ 1,063 | $ 1,209 |
Accumulated depreciation, nuclear fuel | $ 49,895 | $ 43,905 |
Cumulative preferred stock of subsidiary, stated value (in dollars per share) | $ 100 | $ 100 |
Cumulative preferred stock of subsidiary, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Cumulative preferred stock of subsidiary, shares issued (in shares) | 115,293 | 115,293 |
Cumulative preferred stock of subsidiary, shares outstanding (in shares) | 115,293 | 115,293 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 120,000,000 | 120,000,000 |
Common stock, shares issued (in shares) | 79,653,624 | 79,653,624 |
Common stock, shares outstanding (in shares) | 79,653,624 | 79,653,624 |
PNM | ||
Allowance for uncollectible accounts | $ 1,063 | $ 1,209 |
Accumulated depreciation, nuclear fuel | $ 49,895 | $ 43,905 |
Cumulative preferred stock, stated value (in dollars per share) | $ 100 | $ 100 |
Cumulative preferred stock, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Cumulative preferred stock, shares issued (in shares) | 115,293 | 115,293 |
Cumulative preferred stock, shares outstanding (in shares) | 115,293 | 115,293 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 40,000,000 | 40,000,000 |
Common stock, shares issued (in shares) | 39,117,799 | 39,117,799 |
Common stock, shares outstanding (in shares) | 39,117,799 | 39,117,799 |
Texas-New Mexico Power Company | ||
Common stock, par value (in dollars per share) | $ 10 | $ 10 |
Common stock, shares authorized (in shares) | 12,000,000 | 12,000,000 |
Common stock, shares issued (in shares) | 6,358 | 6,358 |
Common stock, shares outstanding (in shares) | 6,358 | 6,358 |
Condensed Consolidated Stateme8
Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Thousands | Total | Total PNMR Common Stockholders’ Equity | Common Stock | AOCI | Retained Earnings | Non- controlling Interest in Valencia | PNM | PNMTotal PNMR Common Stockholders’ Equity | PNMCommon Stock | PNMAOCI | PNMRetained Earnings | PNMNon- controlling Interest in Valencia | Texas-New Mexico Power Company | Texas-New Mexico Power CompanyCommon Stock | Texas-New Mexico Power CompanyPaid-in Capital | Texas-New Mexico Power CompanyRetained Earnings |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Cumulative effect adjustment (Note 8) | $ 10,382 | $ 10,382 | $ 0 | $ 0 | $ 10,382 | $ 0 | ||||||||||
Balance, as adjusted | 1,755,254 | 1,686,334 | 1,163,661 | (92,451) | 615,124 | 68,920 | ||||||||||
Beginning balance at Dec. 31, 2016 | 1,744,872 | 1,675,952 | 1,163,661 | (92,451) | 604,742 | 68,920 | $ 1,466,792 | $ 1,397,872 | $ 1,264,918 | $ (92,428) | $ 225,382 | $ 68,920 | ||||
Beginning balance TNMP at Dec. 31, 2016 | 1,675,952 | 1,397,872 | $ 593,235 | $ 64 | $ 454,166 | $ 139,005 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net Earnings | 146,004 | 134,552 | 134,552 | 11,452 | 115,869 | 104,417 | 0 | 104,417 | 11,452 | |||||||
Net earnings | 134,156 | 104,417 | 34,535 | 34,535 | ||||||||||||
Total other comprehensive income | 9,950 | 9,950 | 9,950 | 9,823 | 9,823 | 9,823 | 0 | |||||||||
Subsidiary preferred stock dividends | (396) | (396) | (396) | |||||||||||||
Dividends declared on preferred stock | (396) | (396) | 0 | (396) | ||||||||||||
Dividends declared on common stock | (57,948) | (57,948) | (57,948) | (29,663) | (29,663) | |||||||||||
Proceeds from stock option exercise | 1,739 | 1,739 | 1,739 | |||||||||||||
Awards of common stock | (13,816) | (13,816) | (13,816) | |||||||||||||
Stock based compensation expense | 5,322 | 5,322 | 5,322 | |||||||||||||
Valencia’s transactions with its owner | (12,963) | (12,963) | (12,963) | (12,963) | ||||||||||||
Ending balance at Sep. 30, 2017 | 1,833,146 | $ 1,765,737 | $ 1,156,906 | $ (82,501) | $ 691,332 | $ 67,409 | 1,579,125 | $ 1,511,716 | $ 1,264,918 | $ (82,605) | $ 329,403 | $ 67,409 | ||||
Ending balance TNMP at Sep. 30, 2017 | $ 1,765,737 | $ 1,511,716 | $ 598,107 | $ 64 | $ 454,166 | $ 143,877 |
Significant Accounting Policies
Significant Accounting Policies and Responsibility for Financial Statements | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies and Responsibility for Financial Statements | Significant Accounting Policies and Responsibility for Financial Statements Financial Statement Preparation In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2017 and December 31, 2016 , the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2017 and 2016, and the consolidated cash flows for the nine months ended September 30, 2017 and 2016 . 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 2016 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2017 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 2016 Annual Reports on Form 10-K. GAAP defines subsequent events as events or transactions that occur after the balance sheet date, but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP. Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 5) and, through January 15, 2016, the PVNGS Capital Trust. 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. Certain PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, 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 the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends 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 $0.2425 per share in July 2017 and $0.22 in July 2016, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.2425 per share in September 2017 and $0.22 per share in September 2016, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statement of Earnings. TNMP declared and paid cash dividends on common stock to PNMR of $29.7 million in the nine months ended September 30, 2017. PNM and TNMP declared and paid cash dividends on common stock to PNMR of $4.1 million and $18.0 million in the nine months ended September 30, 2016. In the nine months ended September 30, 2016, PNMR made equity contributions of $28.1 million to PNM and $50.0 million to TNMP. New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606) In May 2014, the FASB issued ASU 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. ASU 2014-09 also revises the disclosure requirements regarding revenue. Since the issuance of ASU 2014-09, the FASB issued a one -year deferral of the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. ASU 2014-09 can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company anticipates adopting ASU 2014-09 on January 1, 2018, its required effective date, using the modified retrospective method of adoption. The Company has substantially completed its assessment of ASU 2014-09, but, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding certain industry specific issues. These industry specific issues include the impacts of the new guidance on its accounting for CIAC and the presentation of revenues associated with “alternative revenue programs,” which primarily result from the Company’s approved rate rider programs. Although conclusions have not been finalized, the Company does not anticipate a material change in revenue recognition under the new requirements. The Company continues to analyze the financial statement presentation and disclosure requirements of ASU 2014-09. Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. ASU 2016-01 also revises certain presentation and disclosure requirements. Under ASU 2016-01, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available-for-sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt ASU 2016-01 on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and future changes in the value of equity securities will be recorded in earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $9.8 million at September 30, 2017. Accounting Standards Update 2016-02 – Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 will require that a liability be recorded on the balance sheet for all leases, based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings or cash flows, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. Although early adoption of the standard is permitted, the Company does not plan to adopt this standard prior to January 1, 2019, its required effective date. At adoption of ASU 2016-02, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. This approach requires all periods presented to be restated under the new guidance, but allows entities to apply certain practical expedients to arrangements that exist upon adoption or expired during the periods presented. As further discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, and equipment. The Company also routinely enters into land easements and right-of-way agreements, but only a limited number of these agreements are considered leases under the current guidance. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification, including the treatment of land easements under ASU 2016-02. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under ASU 2016-02. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company is also evaluating the practical expedients, if any, it will elect upon adoption. The Company anticipates this process will continue into 2018. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 on January 1, 2020 although early adoption is permitted beginning on January 1, 2019. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230): Restricted Cash In November 2016, the FASB issued ASU 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not provide a definition of what should be considered restricted cash. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for each period presented. The Company continues to analyze the impacts of ASU 2016-18, but does not believe the new standard will have a significant impact on its financial statements. The Company will adopt ASU 2016-18 on January 1, 2018, its required effective date. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. The amendments in ASU 2017-07 require the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net benefit cost (the “non-service cost components”) are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the non-service cost components have been presented. ASU 2017-07 also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s benefit plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net benefit costs as regulatory assets to the extent attributable to regulated operations and does not anticipate ASU 2017-07 will have a significant impact on its financial statements. The Company will adopt the standard on January 1, 2018, its required effective date. Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019 although early adoption is permitted beginning on January 1, 2018. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 9, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 7, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | Earnings Per Share In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 73,739 $ 54,418 $ 134,156 $ 92,040 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 284 96 215 99 Average Shares – Basic 79,938 79,750 79,869 79,753 Dilutive Effect of Common Stock Equivalents: Stock options and restricted stock 216 367 263 377 Average Shares – Diluted 80,154 80,117 80,132 80,130 Net Earnings Per Share of Common Stock: Basic $ 0.92 $ 0.68 $ 1.68 $ 1.15 Diluted $ 0.92 $ 0.68 $ 1.67 $ 1.15 |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. PNM PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates. TNMP TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. Corporate and Other The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development and NM Capital are also included in Corporate and Other. 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 September 30, 2017 Electric operating revenues $ 327,254 $ 92,646 $ — $ 419,900 Cost of energy 82,367 21,381 — 103,748 Utility margin 244,887 71,265 — 316,152 Other operating expenses 94,871 25,367 (5,391 ) 114,847 Depreciation and amortization 36,764 16,424 5,633 58,821 Operating income (loss) 113,252 29,474 (242 ) 142,484 Interest income 1,782 — 1,800 3,582 Other income (deductions) 6,342 1,228 (460 ) 7,110 Interest charges (20,451 ) (7,704 ) (3,951 ) (32,106 ) Segment earnings (loss) before income taxes 100,925 22,998 (2,853 ) 121,070 Income taxes (benefit) 35,642 8,271 (1,170 ) 42,743 Segment earnings (loss) 65,283 14,727 (1,683 ) 78,327 Valencia non-controlling interest (4,456 ) — — (4,456 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 60,695 $ 14,727 $ (1,683 ) $ 73,739 Nine Months Ended September 30, 2017 Electric operating revenues $ 854,909 $ 257,489 $ — $ 1,112,398 Cost of energy 246,635 64,183 — 310,818 Utility margin 608,274 193,306 — 801,580 Other operating expenses 288,300 72,188 (15,286 ) 345,202 Depreciation and amortization 109,228 47,392 16,209 172,829 Operating income (loss) 210,746 73,726 (923 ) 283,549 Interest income 6,457 — 5,891 12,348 Other income (deductions) 19,924 2,392 (918 ) 21,398 Interest charges (62,393 ) (22,619 ) (11,125 ) (96,137 ) Segment earnings (loss) before income taxes 174,734 53,499 (7,075 ) 221,158 Income taxes (benefit) 58,865 18,964 (2,675 ) 75,154 Segment earnings (loss) 115,869 34,535 (4,400 ) 146,004 Valencia non-controlling interest (11,452 ) — — (11,452 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 104,021 $ 34,535 $ (4,400 ) $ 134,156 At September 30, 2017: Total Assets $ 5,023,816 $ 1,465,219 $ 208,219 $ 6,697,254 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other Consolidated (In thousands) Three Months Ended September 30, 2016 Electric operating revenues $ 311,276 $ 89,098 $ — $ 400,374 Cost of energy 88,565 20,201 — 108,766 Utility margin 222,711 68,897 — 291,608 Other operating expenses 109,342 24,184 (3,006 ) 130,520 Depreciation and amortization 33,312 16,354 3,351 53,017 Operating income (loss) 80,057 28,359 (345 ) 108,071 Interest income 1,509 — 3,095 4,604 Other income (deductions) 4,980 855 (184 ) 5,651 Interest charges (22,213 ) (7,308 ) (2,946 ) (32,467 ) Segment earnings (loss) before income taxes 64,333 21,906 (380 ) 85,859 Income taxes 19,343 8,053 (93 ) 27,303 Segment earnings (loss) 44,990 13,853 (287 ) 58,556 Valencia non-controlling interest (4,006 ) — — (4,006 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 40,852 $ 13,853 $ (287 ) $ 54,418 Nine Months Ended September 30, 2016 Electric operating revenues $ 780,228 $ 246,498 $ — $ 1,026,726 Cost of energy 222,376 60,122 — 282,498 Utility margin 557,852 186,376 — 744,228 Other operating expenses 314,961 70,328 (9,261 ) 376,028 Depreciation and amortization 97,778 45,760 10,263 153,801 Operating income (loss) 145,113 70,288 (1,002 ) 214,399 Interest income 8,549 — 9,871 18,420 Other income (deductions) 17,305 2,139 (1,517 ) 17,927 Interest charges (66,494 ) (22,150 ) (8,535 ) (97,179 ) Segment earnings (loss) before income taxes 104,473 50,277 (1,183 ) 153,567 Income taxes (benefit) 32,131 18,460 (497 ) 50,094 Segment earnings (loss) 72,342 31,817 (686 ) 103,473 Valencia non-controlling interest (11,037 ) — — (11,037 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 60,909 $ 31,817 $ (686 ) $ 92,040 At September 30, 2016: Total Assets $ 4,799,012 $ 1,366,840 $ 237,818 $ 6,403,670 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2017 and 2016 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2016 $ 4,320 $ (96,748 ) $ (92,428 ) $ (23 ) $ (92,451 ) Amounts reclassified from AOCI (pre-tax) (11,088 ) 4,839 (6,249 ) 484 (5,765 ) Income tax impact of amounts reclassified 4,302 (1,878 ) 2,424 (187 ) 2,237 Other OCI changes (pre-tax) 22,302 — 22,302 (278 ) 22,024 Income tax impact of other OCI changes (8,654 ) — (8,654 ) 108 (8,546 ) Net after-tax change 6,862 2,961 9,823 127 9,950 Balance at September 30, 2017 $ 11,182 $ (93,787 ) $ (82,605 ) $ 104 $ (82,501 ) Balance at December 31, 2015 $ 17,346 $ (88,822 ) $ (71,476 ) $ 44 $ (71,432 ) Amounts reclassified from AOCI (pre-tax) (10,135 ) 4,128 (6,007 ) 573 (5,434 ) Income tax impact of amounts reclassified 3,955 (1,611 ) 2,344 (224 ) 2,120 Other OCI changes (pre-tax) 3,115 — 3,115 (1,305 ) 1,810 Income tax impact of other OCI changes (1,216 ) — (1,216 ) 509 (707 ) Net after-tax change (4,281 ) 2,517 (1,764 ) (447 ) (2,211 ) Balance at September 30, 2016 $ 13,065 $ (86,305 ) $ (73,240 ) $ (403 ) $ (73,643 ) Pre-tax amounts reclassified from AOCI related to “Unrealized Gains 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. 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 is included in capitalized interest. 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 | 9 Months Ended |
Sep. 30, 2017 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | Variable Interest Entities GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. Additional information concerning PNM’s VIEs is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Valencia PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2017 , PNM paid $4.9 million and $14.7 million for fixed charges and $0.9 million and $1.2 million for variable charges. For the three and nine months ended September 30, 2016 , PNM paid $4.9 million and $14.5 million for fixed charges and $0.5 million and $1.1 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of 50% of book value reduced by related indebtedness or 50% of fair market value. PNM has concluded that the third-party entity that owns Valencia is a VIE and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates Valencia in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the Condensed Consolidated Financial Statements of PNM although PNM has no legal ownership interest or voting control of the VIE. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest. Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Operating revenues $ 5,859 $ 5,356 $ 15,880 $ 15,541 Operating expenses (1,403 ) (1,350 ) (4,428 ) (4,504 ) Earnings attributable to non-controlling interest $ 4,456 $ 4,006 $ 11,452 $ 11,037 Financial Position September 30, December 31, 2017 2016 (In thousands) Current assets $ 3,498 $ 2,551 Net property, plant, and equipment 64,818 66,947 Total assets 68,316 69,498 Current liabilities 907 578 Owners’ equity – non-controlling interest $ 67,409 $ 68,920 Westmoreland San Juan LLC (“WSJ”) and SJCC As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, on January 31, 2016, as well as a $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to possible loss in the event of a default by WSJ under the Westmoreland Loan and/or performance was required under the letter of credit support. Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016. At September 30, 2017 , the amount outstanding under the Westmoreland Loan was $66.2 million . In addition, interest receivable of $1.2 million is included in Other receivables. The Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. A principal payment of $9.6 million plus interest of $1.8 million is due on November 1, 2017. As of October 20, 2017, $11.4 million was held in a SJCC bank account that is restricted solely to be used to service the Westmoreland Loan. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations. In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. The acquisition of SJCC for approximately $125.0 million on January 31, 2016 was an arm’s-length negotiated transaction between Westmoreland and BHP, which amount should approximate the fair value of SJCC at the date of acquisition. If WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations. Both WSJ and SJCC are considered to be VIEs. PNMR’s analysis of these arrangements concluded that Westmoreland, as the parent of WSJ, has the ability to direct the SJCC mining operations, which is the factor that most significantly impacts the economic performance of WSJ and SJCC. NM Capital’s rights under the Westmoreland Loan are the typical protective rights of a lender, but do not give NM Capital any oversight over mining operations unless there is a default under the loan agreement. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of Westmoreland and its subsidiaries, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation. Therefore, PNM’s involvement through the CSA is a protective right rather than a participating right and Westmoreland has the power to direct the activities that most significantly impact the economic performance of SJCC. The CSA requires SJCC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation. If SJCC is able to mine more efficiently than anticipated, its economic performance will be improved. Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted. Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the Westmoreland Loan and the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs. |
Lease Commitments
Lease Commitments | 9 Months Ended |
Sep. 30, 2017 | |
Leases [Abstract] | |
Lease Commitments | Lease Commitments The Company leases office buildings, vehicles, and other equipment. In addition, PNM leases interests in Units 1 and 2 of PVNGS and certain right-of-way agreements are classified as leases. All of the Company’s leases are currently accounted for as operating leases. See New Accounting Pronouncements in Note 1. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, including PNM’s actions with regard to renewal and purchase options under the PVNGS leases. The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM exercised its fair market value options to purchase the assets underlying those leases on the expiration date of the original leases. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.3 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.8 MW of the entitlement from PVNGS Unit 2. See Note 12 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors, and take title to the leased interests. If such an event had occurred as of September 30, 2017 , amounts due to the lessors under the circumstances described above would be up to $169.9 million , payable on January 15, 2018 in addition to the scheduled lease payments due on January 15, 2018. |
Fair Value of Derivative and Ot
Fair Value of Derivative and Other Financial Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value of Derivative and Other Financial Instruments [Abstract] | |
Fair Value of Derivative and Other Financial Instruments | Fair Value of Derivative and Other Financial Instruments Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique. Energy Related Derivative Contracts Overview The primary objective for the use of commodity derivative instruments, including energy contracts, options, swaps, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. Beginning January 1, 2018, PNM will be exposed to market risk for the 65 MW of SJGS Unit 4 that will be transferred to PNM from PNMR Development (Note 11) on December 31, 2017. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022, subject to certain conditions. Under these agreements, PNM is obligated to deliver 36 MW of power only when SJGS Unit 4 is operating. These agreements are not considered derivatives because there is no notional amount due to the unit-contingent nature of the transactions. Therefore, these agreements are not recorded at fair value. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. TNMP does not enter into energy related derivative contracts. Commodity Risk Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts 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, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the nine months ended September 30, 2017 and the year ended December 31, 2016, PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The derivative contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. PNM has no trading transactions. Commodity Derivatives PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges September 30, December 31, (In thousands) Current assets $ 3,093 $ 5,224 Deferred charges 3,846 — 6,939 5,224 Current liabilities (1,279 ) (2,339 ) Long-term liabilities (3,846 ) — (5,125 ) (2,339 ) Net $ 1,814 $ 2,885 Included in the above table are $0.7 million and $2.7 million of current assets at September 30, 2017 and December 31, 2016 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 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. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives. Included in the above table are equal amounts of assets and liabilities aggregating $4.9 million at September 30, 2017 and $0.5 million at December 31, 2016 , which result from PNM’s hazard sharing arrangements with Tri-State (Note 12). The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial. At September 30, 2017 and December 31, 2016 , PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2017 and December 31, 2016 , amounts posted as cash collateral under margin arrangements were $1.2 million and $2.6 million . 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 $0.1 million of current assets and $0.2 million of current liabilities at September 30, 2017 and $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. The following table presents the effect of mark-to-market commodity derivative instruments on PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Electric operating revenues $ (2,237 ) $ 1,652 $ 5,697 $ 214 Cost of energy (14 ) (1 ) (5,289 ) (1,113 ) Total gain (loss) $ (2,251 ) $ 1,651 $ 408 $ (899 ) Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh September 30, 2017 100,000 (630,933 ) December 31, 2016 254,100 (2,471,600 ) PNM has contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral. At September 30, 2017 and December 31, 2016, PNM had no such contracts in a net liability position. 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. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of September 30, 2017 , PNM had contracted to sell substantially all of PVNGS Unit 3 output through 2017 at market price plus a premium. Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of the sales through 2017, which average approximately $29 per MWh. 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 consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At September 30, 2017 and December 31, 2016 , the fair value of available-for-sale securities included $283.0 million and $253.9 million for the NDT and $23.4 million and $19.1 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. September 30, 2017 December 31, 2016 Unrealized Gains Fair Value Unrealized Gains Fair Value (In thousands) Cash and cash equivalents $ — $ 8,151 $ — $ 23,683 Equity securities: Domestic value 5,252 72,162 1,135 34,796 Domestic growth 5,775 73,345 3,032 47,595 International and other 4,865 43,167 2,029 27,481 Fixed income securities: U.S. Government 307 28,960 115 40,962 Municipals 998 41,131 585 43,789 Corporate and other 1,434 39,528 553 54,671 $ 18,631 $ 306,444 $ 7,449 $ 272,977 The proceeds and gross realized gains and losses on the disposition of available-for-sale securities are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $0.1 million and $1.1 million for the three and nine months ended September 30, 2017 and $0.1 million and $1.0 million for the three and nine months ended September 30, 2016. Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Proceeds from sales $ 98,532 $ 86,975 $ 456,577 $ 280,989 Gross realized gains $ 8,128 $ 7,026 $ 24,745 $ 27,273 Gross realized (losses) $ (2,829 ) $ (2,565 ) $ (8,150 ) $ (12,913 ) Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At September 30, 2017 and December 31, 2016, PNMR’s held-to-maturity securities consist of the Westmoreland Loan. The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings. At September 30, 2017 , 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 (In thousands) Within 1 year $ 3,913 $ — After 1 year through 5 years 22,766 76,353 After 5 years through 10 years 25,456 — After 10 years through 15 years 5,178 — After 15 years through 20 years 10,692 — After 20 years 41,614 — $ 109,619 $ 76,353 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 nine months ended September 30, 2017 or the year ended December 31, 2016 . 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 Westmoreland Loan, 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 by PNM 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 September 30, 2017 and December 31, 2016 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) (In thousands) September 30, 2017 Available-for-sale securities Cash and cash equivalents $ 8,151 $ 8,151 $ — Equity securities: Domestic value 72,162 72,162 — Domestic growth 73,345 73,345 — International and other 43,167 39,931 3,236 Fixed income securities: U.S. Government 28,960 28,273 687 Municipals 41,131 — 41,131 Corporate and other 39,528 — 39,528 $ 306,444 $ 221,862 $ 84,582 Commodity derivative assets $ 6,939 $ — $ 6,939 Commodity derivative liabilities (5,125 ) — (5,125 ) Net $ 1,814 $ — $ 1,814 December 31, 2016 Available-for-sale securities Cash and cash equivalents $ 23,683 $ 23,683 $ — Equity securities: Domestic value 34,796 34,796 — Domestic growth 47,595 47,595 — International and other 27,481 27,481 — Fixed income securities: U.S. Government 40,962 39,723 1,239 Municipals 43,789 — 43,789 Corporate and other 54,671 23,158 31,513 $ 272,977 $ 196,436 $ 76,541 Commodity derivative assets $ 5,224 $ — $ 5,224 Commodity derivative liabilities (2,339 ) — (2,339 ) Net $ 2,885 $ — $ 2,885 The carrying amounts and fair values of investments in the Westmoreland Loan, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 September 30, 2017 (In thousands) PNMR Long-term debt $ 2,447,702 $ 2,564,887 $ — $ 2,564,887 $ — Westmoreland Loan $ 66,230 $ 76,353 $ — $ — $ 76,353 Other investments $ 386 $ 386 $ 386 $ — $ — PNM Long-term debt $ 1,657,396 $ 1,736,026 $ — $ 1,736,026 $ — Other investments $ 166 $ 166 $ 166 $ — $ — TNMP Long-term debt $ 480,589 $ 517,977 $ — $ 517,977 $ — Other investments $ 220 $ 220 $ 220 $ — $ — December 31, 2016 PNMR Long-term debt $ 2,392,712 $ 2,540,693 $ — $ 2,540,693 $ — Westmoreland Loan $ 95,000 $ 100,893 $ — $ — $ 100,893 Other investments $ 547 $ 1,164 $ 547 $ — $ 617 PNM Long-term debt $ 1,631,369 $ 1,730,157 $ — $ 1,730,157 $ — Other investments $ 316 $ 316 $ 316 $ — $ — TNMP Long-term debt $ 420,875 $ 468,329 $ — $ 468,329 $ — Other investments $ 231 $ 231 $ 231 $ — $ — |
Stock-Based Compensation
Stock-Based Compensation | 9 Months Ended |
Sep. 30, 2017 | |
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 2016 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, 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. Beginning with 2017 awards, the vesting period for awards of restricted stock to non-employee members of the Board is one year. The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized 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 September 30, 2017 and December 31, 2016 , PNMR had unrecognized expense related to stock awards of $4.8 million and $4.5 million , which are expected to be recognized over an average of 2.0 and 1.8 years. PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date. The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (collectively, “excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR had not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. PNMR adopted ASU 2016-09 as of January 1, 2017 and recorded excess tax benefits of $0.2 million and $2.3 million in the three and nine months ended September 30, 2017 of which $0.1 million and $1.7 million was allocated to PNM and $0.1 million and $0.6 million was allocated to TNMP. As required by ASU 2016-09, PNMR recorded the excess tax benefits that were not recognized in prior years, due to its net operating loss position, as a cumulative effect adjustment of $10.4 million on January 1, 2017, increasing retained earnings and decreasing accumulated deferred income taxes on the Condensed Consolidated Balance Sheets. When excess tax benefits are used to reduce income taxes payable, the benefit will be reflected in cash flows from operating activities. The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period. The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Nine Months Ended September 30, Restricted Shares and Performance Based Shares 2017 2016 Expected quarterly dividends per share $ 0.2425 $ 0.2200 Risk-free interest rate 1.50 % 0.94 % Market-Based Shares Dividend yield 2.67 % 2.74 % Expected volatility 20.80 % 20.44 % Risk-free interest rate 1.54 % 0.97 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months ended September 30, 2017 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2016 218,316 $ 27.59 305,874 $ 12.29 Granted 248,271 $ 23.06 — $ — Exercised (270,855 ) $ 20.92 (109,433 ) $ 15.89 Forfeited (4,012 ) $ 29.96 — $ — Expired — $ — (3,000 ) $ 30.50 Outstanding at September 30, 2017 191,720 $ 31.10 193,441 $ 9.98 PNMR’s stock-based compensation program provides for performance and market targets through 2019. Included as granted and as exercised in the above table are 49,682 previously awarded shares that were earned for the 2014 through 2016 performance measurement period and ratified by the Board in February 2017 (based upon achieving market targets at “target” levels, weighted at 60% , and not meeting performance targets, weighted at 40% ). Excluded from the above table are maximums of 163,712 , 137,036 , and 133,632 shares for the three -year performance periods ending in 2017, 2018, and 2019 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 was to receive 135,000 shares of PNMR’s common stock if PNMR met specific market targets at the end of 2016 and she remained an employee of the Company. Under the agreement, she received 35,000 of the total shares in 2015 since PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the remaining 100,000 shares, which are included in the above table, in February 2017. The retention award was made under the PEP and was approved by the Board on February 28, 2012. 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 achieved the specific performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 based on a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares, which are included in the above table. 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. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include the restricted stock shares that remain unvested under this retention award agreement. In March 2015, the Company entered into an additional 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 September 30, 2017 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $5.9 million with a weighted-average remaining contract life of 1.8 years. At September 30, 2017 , no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date. The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Nine Months Ended September 30, Restricted Stock 2017 2016 Weighted-average grant date fair value $ 23.06 $ 26.49 Total fair value of restricted shares that vested (in thousands) $ 5,666 $ 5,011 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) $ 2,234 $ 1,208 |
Financing
Financing | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Financing | Financing The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities and term loans contains a single financial covenant, which requires the maintenance of a debt-to-capital ratio of less than or equal to 65% , and generally also include customary covenants, events of default, cross default provisions, and change of control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Financing Activities As discussed in Note 11, NM Capital, a wholly-owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent, as of February 1, 2016. The BTMU Term Loan Agreement has a maturity of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 4.06% at September 30, 2017 . PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The BTMU Term Loan Agreement and the guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65% , and customary events of default, a cross default provision, and a change of control provision consistent with PNMR’s other term loan agreements. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million (the “Westmoreland Loan”) to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance Westmoreland’s purchase of SJCC. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $60.9 million at September 30, 2017 . Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $15.7 million on the BTMU Term Loan Agreement in the twelve months ended September 30, 2018. On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 11). At December 31, 2016, PNM had $37.0 million of outstanding PCRBs, which have a final maturity of June 1, 2040, and $20.0 million of outstanding PCRBs which have a final maturity of June 1, 2042. These PCRBs were subject to mandatory tender for remarketing on June 1, 2017 and were successfully remarketed on that date. The $37.0 million of PCRBs now bear interest at 2.125% and the $20.0 million of PCRBs now bear interest at 2.45% . Both series are now subject to mandatory tender for remarketing on June 1, 2022. On June 14, 2017, TNMP entered into an agreement (the “TNMP 2017 Bond Purchase Agreement”), which provided TNMP would issue $60.0 million aggregate principal amount of 3.22% first mortgage bonds, due 2027 (the “2017 Series A Bonds”) on or about August 25, 2017, subject to satisfaction of certain conditions. TNMP issued the 2017 Series A Bonds on August 24, 2017 and used the proceeds to reduce short-term and intercompany debt and for general corporate purposes. On July 20, 2017, PNM entered into a $200.0 million term loan agreement (the “PNM 2017 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent, and U.S. Bank National Association, as lender. The PNM 2017 Term Loan Agreement bears interest at a variable rate and must be repaid on or before January 18, 2019. PNM used the proceeds of the PNM 2017 Term Loan Agreement to prepay without penalty the $175.0 million PNM 2016 Term Loan Agreement, which was to mature on November 17, 2017, and to reduce short-term borrowings. The PNM 2017 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum debt-to-capital ratio of 65% , and customary events of default, a cross default provision, and a change of control provision consistent with PNM’s other term loan agreements. On July 28, 2017, PNM entered into an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principal amount of Senior Unsecured Notes (the “PNM 2018 SUNs”) offered in private placement transactions. Under the PNM 2017 Senior Unsecured Note Agreement, PNM has agreed to issue $350.0 million of the PNM 2018 SUNs on or about May 15, 2018 and $100.0 million of the PNM 2018 SUNs on or about August 1, 2018. The issuances of the PNM 2018 SUNs are subject to the satisfaction of customary conditions. PNM will use the gross proceeds from the PNM 2018 SUNs to repay $350.0 million of PNM’s 7.95% Senior Unsecured Notes that mature on May 15, 2018 and $100.0 million of PNM’s 7.50% Senior Unsecured Notes that mature on August 1, 2018. The terms of the PNM 2017 Senior Unsecured Note Agreement include customary covenants, including a covenant that requires the maintenance of a debt-to-capital ratio of less than or equal to 65% , customary events of default, including a cross default provision, and covenants regarding parity of financial covenants, liens and guarantees with respect to PNM’s material credit facilities. In the event of a change of control, PNM will be required to offer to prepay the PNM 2018 SUNs at par. PNM will have the right to redeem any or all of the PNM 2018 SUNs prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, aggregate borrowings of $450.0 million under PNM’s Senior Unsecured Notes due on May 15, 2018 and August 1, 2018, are reflected as being long-term in the Condensed Consolidated Balance Sheet at September 30, 2017 since the PNM 2017 Senior Unsecured Note Agreement demonstrates PNM’s ability and intent to re-finance the aggregate $450.0 million Senior Unsecured Notes on a long-term basis. Information concerning the maturities and interest rates on the PNM 2018 SUNs to be issued in May 2018 and August 2018 is as follows: Scheduled Funding Maturity Principal Interest Date Date Amount Rate (In millions) May 15, 2018 May 15, 2023 $ 55.0 3.15 % May 15, 2018 May 15, 2025 104.0 3.45 % May 15, 2018 May 15, 2028 88.0 3.68 % May 15, 2018 May 15, 2033 38.0 3.93 % May 15, 2018 May 15, 2038 45.0 4.22 % May 15, 2018 May 15, 2048 20.0 4.50 % 350.0 August 1, 2018 August 1, 2028 15.0 3.78 % August 1, 2018 August 1, 2048 85.0 4.60 % 100.0 $ 450.0 On September 25, 2017, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from September 18, 2018 to September 23, 2022 and to provide for two one -year extension options, subject to approval by a majority of the lenders. In March 2015, PNMR entered into a $150.0 million Term Loan Agreement (the “PNMR 2015 Term Loan Agreement”), which bears interest at a variable rate and must be repaid by March 9, 2018. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927% , subject to change if there is a change in PNMR’s credit rating, for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. In 2017, PNMR entered into three separate four -year hedging agreements whereby it effectively established fixed interest rates of 1.926% , 1.823% , and 1.629% , plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million , of its variable rate debt. These hedge agreements are accounted for as cash flow hedges. The fair value of the hedge related to the PNMR 2015 Term Loan Agreement was a gain of $0.3 million at September 30, 2017 and is included in Other current assets on the Condensed Consolidated Balance Sheets and a loss of less than $0.1 million at December 31, 2016. At September 30, 2017 , one of the remaining hedge agreements had a fair value gain of $0.1 million , which is included in Other current assets, and the other two had fair value losses aggregating $0.5 million , which are included in Other current liabilities, on the Condensed Consolidated Balance Sheets. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement. At September 30, 2017, variable interest rates were 2.14% on the $150.0 million PNMR 2015 Term Loan Agreement, 2.19% on the $100.0 million PNMR 2016 Two -Year Term Loan, and 1.97% on the $200.0 million PNM 2017 Term Loan Agreement. Short-term Debt and Liquidity Currently, the PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million . In November 2016, PNMR and PNM entered into agreements to extend the maturity of both facilities from October 31, 2020 to October 31, 2021. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitments beyond October, 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021. 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 23, 2022. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. Short-term debt outstanding consisted of: September 30, December 31, Short-term Debt 2017 2016 (In thousands) PNM: PNM Revolving Credit Facility $ — $ 35,000 PNM New Mexico Credit Facility — 26,000 TNMP Revolving Credit Facility — — PNMR: PNMR Revolving Credit Facility 166,500 126,100 PNMR 2016 One-Year Term Loan 100,000 100,000 $ 266,500 $ 287,100 At September 30, 2017 , the weighted average interest rate was 2.49% for the PNMR Revolving Credit Facility and 2.09% for the PNMR 2016 One -Year Term Loan, which matures in December 2017. In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.4 million , $2.5 million , and $0.1 million at September 30, 2017 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of September 30, 2017, PNM and TNMP had no intercompany borrowings from PNMR. At October 20, 2017 , PNMR, PNM, and TNMP had $118.5 million , $397.5 million , and $69.0 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 20, 2017 , on a consolidated basis, was $635.0 million for PNMR. As of October 20, 2017 , PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. At October 20, 2017 , PNMR, PNM, and TNMP had invested cash of $1.5 million , $50.5 million , and none . As described above, PNM entered into the PNM 2017 Senior Unsecured Note Agreement on July 28, 2017 to issue $450.0 million of the PNM 2018 SUNs on May 15, 2018 and August 1, 2018, proceeds from which will be used to repay like amounts of PNM Senior Unsecured Notes maturing on those dates. PNM has no other long-term debt due through December 31, 2018. The $50.0 million PNM New Mexico Credit Facility expires in January 2018. PNMR has maturities and other repayments of short-term and long-term debt aggregating $265.7 million in the period from October 1, 2017 through September 30, 2018 and $102.3 million in the remainder of 2018, including anticipated repayments on the BTMU Term Loan Agreement. TNMP has no required principal payments on its long-term debt through 2018. Additional information on debt maturities is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. |
Pension and Other Postretiremen
Pension and Other Postretirement Benefit Plans | 9 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
Pension and Other Postretirement Benefit Plans | Pension and Other Postretirement Benefit Plans PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Annual net periodic benefit cost for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. See New Accounting Pronouncements in Note 1. PNM Plans The following tables present the components of the PNM Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 24 $ 35 $ — $ — Interest cost 6,727 7,577 1,006 1,087 174 203 Expected return on plan assets (8,451 ) (8,854 ) (1,308 ) (1,371 ) — — Amortization of net (gain) loss 4,001 3,455 921 286 78 64 Amortization of prior service cost (241 ) (241 ) (416 ) (7 ) — — Net periodic benefit cost $ 2,036 $ 1,937 $ 227 $ 30 $ 252 $ 267 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 72 $ 105 $ — $ — Interest cost 20,181 22,731 3,019 3,260 523 609 Expected return on plan assets (25,352 ) (26,562 ) (3,923 ) (4,113 ) — — Amortization of net (gain) loss 12,004 10,365 2,762 858 235 192 Amortization of prior service cost (724 ) (724 ) (1,248 ) (22 ) — — Net periodic benefit cost $ 6,109 $ 5,810 $ 682 $ 88 $ 758 $ 801 PNM did not make any contributions to its pension plan trust in the three and nine months ended September 30, 2017 and 2016 and does not anticipate making any contributions to the pension plan in 2017 -2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9% . Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made no contributions to the OPEB trust in the three and nine months ended September 30, 2017 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2016. PNM does not expect to make any contributions to the OPEB trust in 2017-2021. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2017 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2016 and are expected to total $1.5 million during 2017 and $5.8 million for 2018-2021. TNMP Plans The following tables present the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 36 $ 46 $ — $ — Interest cost 722 826 139 169 8 10 Expected return on plan assets (945 ) (986 ) (114 ) (122 ) — — Amortization of net (gain) loss 231 175 (20 ) (10 ) 2 1 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ 8 $ 15 $ 41 $ 83 $ 10 $ 11 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 107 $ 139 $ — $ — Interest cost 2,165 2,478 417 508 25 30 Expected return on plan assets (2,834 ) (2,957 ) (342 ) (367 ) — — Amortization of net (gain) loss 692 525 (60 ) (30 ) 7 1 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ 23 $ 46 $ 122 $ 250 $ 32 $ 31 TNMP did not make any contributions to its pension plan trust in the three and nine months ended September 30, 2017 and 2016 and does not anticipate making any contributions in 2017 -2021, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.1% to 4.9% . Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions of none and $0.7 million to the OPEB trust in the three and nine months ended September 30, 2017 and no contribution in the three and nine months ended September 30, 2016. TNMP does not expect to make any additional contributions to the OPEB trust in 2017 and expects to make contributions totaling $1.4 million for 2018-2021. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and nine months ended September 30, 2017 and 2016 and are expected to total $0.1 million during 2017 and $0.4 million in 2018-2021. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
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, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows. Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. Commitments and Contingencies Related to the Environment Nuclear Spent Fuel and Waste Disposal Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the DC Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high-level waste from PVNGS. In August 2014, APS and DOE entered into a settlement agreement, which established a process for the payment of claims for costs incurred through December 31, 2016. The settlement agreement has been extended to December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations. PNM estimates that it will incur approximately $57.7 million (in 2016 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2017 and December 31, 2016 , PNM had a liability for interim storage costs of $12.1 million and $12.1 million included in other deferred credits. PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation. On June 8, 2012, the DC 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 DC 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 DC 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, which was issued in September 2013. 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. The NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the DC Circuit issued its June 2012 decision although PVNGS had not been involved in any licensing actions affected by that decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged, in the DC Circuit, 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. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval, as ordered by the DC Circuit. 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. On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule to provide certain clarifications to reflect interpretations of the 1999 rule. EPA also provided a companion draft guidance document for public comment. The new rule shifted the due date for the next cycle of SIPs that are designed to cover the second compliance period from 2019 to 2028, changed the schedule and process for states to file 5 -year progress reports, and revised certain aspects of the visibility impairment provisions. EPA’s final rule was challenged by numerous parties. The DC Circuit has granted unopposed requests extending the deadline for briefing proposals to December 21, 2017. PNM is currently evaluating the potential impacts of this rule on SJGS. SJGS BART Compliance – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K contains detailed information concerning the BART compliance process, including interactions with governmental agencies responsible for environmental oversight and the NMPRC approval process. In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS. Under the approved plan, the installation of selective non-catalytic reduction technology (“SNCR”) was required on SJGS Units 1 and 4, which installation was completed in early 2016, and Units 2 and 3 are to be retired by the end of 2017. In addition to the required SNCR equipment, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). PNM’s share of the total costs for SNCRs and BDT equipment was $77.7 million . See Note 12 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 have increased with the installation of SNCR and BDT equipment. On December 16, 2015, the NMPRC issued an order regarding SJGS. As provided in that order: • PNM will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) by December 31, 2017 and recover, over 20 years, 50% of their undepreciated net book value at that date and earn a regulated return on those costs • PNM is granted a CCN to acquire an additional 132 MW in SJGS Unit 4, effective January 1, 2018, with an initial book value of zero , plus the costs of SNCR and other capital additions • PNM is granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (currently estimated to aggregate approximately $155 million ) • No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position and supporting testimony in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties to the stipulation agree to support this case being decided within six months (see Other SJGS Matters below and Note 12) • PNM is authorized to acquire 65 MW of SJGS Unit 4 as excluded utility plant; PNM and PNMR commit that no further coal-fired merchant plant will be acquired at any time by PNM, PNMR, or any PNM affiliate; PNM is not precluded from seeking a CCN to include the 65 MW or other coal capacity in rate base • Beginning January 1, 2020, for every MWh produced by 197 MW of coal-fired generation from PNM’s ownership share of SJGS, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO 2 emission attribute compliant with EPA’s Clean Power Plan; this REC retirement is in addition to what is required to meet the RPS; the cost of these RECs are to be capped at $7.0 million per year and will be recovered in rates; PNM should purchase EPA-compliant RECs from New Mexico renewable generation unless those RECs are more costly • PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project is discussed in Note 12) • PNM will not recover approximately $20 million of other costs incurred in connection with CAA compliance • The NMPRC will issue a Notice of Proposed Dismissal in PNM’s 2014 IRP At December 31, 2015, PNM recorded losses for regulatory disallowances and restructuring costs, aggregating $165.7 million , reflecting a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered, the other unrecoverable costs, and the $16.5 million increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). The ultimate amount of the regulatory disallowance will be dependent on the actual December 31, 2017 net undepreciated book values of SJGS Units 2 and 3. Accordingly, the amount recorded will be adjusted to reflect changes to the December 31, 2017 net book values. Additional information about the CSA is discussed under Coal Supply below and in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million , including a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation from the new coal mine reclamation arrangement. PNM recorded an expense of $0.8 million during the three months ended March 31, 2016, an expense of $5.2 million in the three months ended September 30, 2016, and a reduction of expense of $2.3 million in the three months ended December 31, 2016, which are reflected in regulatory disallowances and restructuring costs on the Condensed Consolidated Statement of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in the three months ended March 31, 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Condensed Consolidated Statement of Earnings. At September 30, 2017, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $211.6 million for a net undepreciated book value of $260.2 million , offset by 50% (which equals $128.6 million ) of the anticipated December 31, 2017 undepreciated net book value of SJGS Units 2 and 3 that will not be recovered, resulting in the net carrying value for SJGS Units 2 and 3 being $131.6 million at September 30, 2017. On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious. Answer briefs refuting NEE’s claims were filed on November 2, 2016 by PNM, the NMPRC, and certain intervenors. Reply briefs were filed by NEE on January 9, 2017 and the parties presented oral argument to the court on January 25, 2017. The court has not rendered a decision on the appeal and there is no required time frame for a decision. In addition, on March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC (see Coal Supply below). The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter. PNM cannot currently predict the outcome of these matters. SJGS Ownership Restructuring Matters – As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, SJGS currently is jointly owned by PNM and eight other entities. In connection with the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and owns 38.5% of SJGS Unit 4. Following mediated negotiations, the SJGS participants executed the San Juan Project Restructuring Agreement (“RA”) on July 31, 2015. The RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit. PNMR Development became a party to the RA and agreed to acquire a 65 MW ownership interest in SJGS Unit 4 on the December 31, 2017 exit date, but has obligations related to Unit 4 before then. On the exit date, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million . PNMR Development has assigned the rights and obligations related to the 65 MW to PNM effective on December 31, 2017, which will facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM will treat the 65 MW as merchant utility plant that will be excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022 (Note 7). Reflecting the additions of the 132 MW and 65 MW, PNM’s ownership share would be 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4. The RA became effective contemporaneously with the effectiveness of the new CSA. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Coal Supply below, occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and is suppling coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement provides economic benefits that are being passed on to PNM’s customers through the FPPAC. Other SJGS Matters – Although the RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant. PNM’s 2017 IRP (Note 12) filed with the NMPRC on July 3, 2017 presented resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assumed SJGS will cease operations after mid-2022. The 2017 IRP data shows that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers. Four Corners On August 6, 2012, EPA issued its Four Corners FIP with a final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lbs/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations. PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $89.2 million , including amounts incurred through September 30, 2017 and PNM’s AFUDC. PNM is seeking recovery from its ratepayers of these costs in its NM 2016 Rate Case discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and Note 12. PNM is unable to predict the ultimate outcome of this matter. The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners. Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016. The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs have until November 13, 2017 to file an appeal of this dismissal order. PNM cannot predict whether the plaintiffs will appeal the order or whether such appeal, if filed, will be successful. Carbon Dioxide Emissions On August 3, 2015, EPA established final standards to limit CO 2 emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the DC Circuit. The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and establishes deadlines for states to submit initial plans to EPA by September 6, 2016, with a potential two -year extension, and final plans by 2018. The September 2016 deadline passed with no action and the 2018 deadline could be adjusted due to the stay of the Clean Power Plan issued by the US Supreme Court and pending litigation described below. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan. On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court issued a 5-4 decision granting the stay pending judicial review of the rule by the DC Circuit. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan, but has not rendered a decision. The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation if the Clean Power Plan is sustained under the current administration. In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate CO 2 emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA was to determine that it was not necessary or appropriate, the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners. PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation. On June 30, 2016, EPA published in the Federal Register the design details of its voluntary Clean Energy Incentive Program under the Clean Power Plan. Comments were due to EPA on November 1, 2016. On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, (4) the Legal Memorandum supporting the Clean Power Plan, and (5) the New Source Performance Standards for Oil & Natural Gas Sector. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In connection with its review, EPA filed a petition with the DC Circuit requesting that the court hold the consolidated cases challenging the Clean Power Plan in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking. The DC Circuit issued an order to hold the consolidated cases in abeyance. The DC Circuit issued a similar order in connection with a motion filed by EPA to hold consolidated cases challenging the NSPS in abeyance. EPA also signed a Federal Register notice announcing that EPA is initiating its review of the Clean Power Plan and providing advance notice of forthcoming rulemaking proceedings. On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the Federal Register on October 16, 2017, starting a 60 -day public comment period. Any final rule will be subject to legal challenge and judicial review. EPA also noted that it is still evaluating whether to adopt a replacement rule to regulate GHG from existing electric utility generating units and may issue a proposed rulemaking if it determines that a replacement rule would be appropriate. PNM’s review of the CO 2 emission reductions standards under the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, litigation of the final rule, and other actions the Trump Administration is taking through judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any. National Ambient Air Quality Standards (“NAAQS”) The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO 2 , ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO 2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO 2 and the 24-hour SO 2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO 2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO 2 sources to identify maximum 1-hour SO 2 concentrations. The proposed rule also describes |
Regulatory and Rate Matters
Regulatory and Rate Matters | 9 Months Ended |
Sep. 30, 2017 | |
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 2016 Annual Reports on Form 10-K. PNM New Mexico General Rate Cases New Mexico 2015 General Rate Case (“NM 2015 Rate Case”) On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates. The application proposed a revenue increase of $123.5 million , including base non-fuel revenues of $121.7 million . PNM’s application was based on a future test year (“FTY”) period beginning October 1, 2015 and proposed a ROE of 10.5% . The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and economic factors. The application included several proposed changes in rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included higher customer and demand charges, a revenue decoupling pilot program applicable to residential and small commercial customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 6). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“CSA”). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current CSA (Note 11), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million . On August 4, 2016, the Hearing Examiner in the case issued a recommended decision (“RD”). The RD proposed an increase in non-fuel revenues of $41.3 million compared to the $121.5 million increase requested by PNM. Major components of the difference in the increase in non-fuel revenues proposed in the RD, included: • A ROE of 9.575% compared to the 10.5% requested by PNM • Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 6); the RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases • Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 6) and related property taxes, which were $1.5 million per year at that time; the RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes • Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 11); PNM’s share of the costs of installing the BDT equipment was $52.3 million of which $40.0 million was included in rate base in PNM’s rate request • Disallowing recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges The RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. In addition, the RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The RD proposed approving PNM’s proposals for revised depreciation rates (except for requiring depreciation on Four Corners be calculated based on a 2041 life rather than the 2031 life proposed by PNM), the inclusion of construction work in progress in rate base, and ratemaking treatment of the “prepaid pension asset.” The RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the RD. The NMPRC issued an order on September 28, 2016 that authorized PNM to implement an increase in non-fuel rates of $61.2 million , effective for bills sent to customers after September 30, 2016. The order generally approved the RD, but with certain significant modifications. The modifications to the RD included: • Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million ; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued • Full recovery of the rent expense and property taxes associated with the extended leases for capacity, aggregating 114.6 MW, in Palo Verde Units 1 and 2 • Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases • Recovery of assumed operating and maintenance expense savings of $0.3 million annually related to BDT On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. Specifically, PNM’s statement indicated it is appealing the following elements of the NMPRC’s order: • Disallowance of recovery of the full purchase price, representing fair market value, of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016 • Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM • Disallowance of recovery of future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases • Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT The issues that are being appealed by the various cross-appellants include: • The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2 • The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners • The revised method to collect PNM’s fuel and purchased power costs under the FPPAC • The final rate design • The NMPRC allowing PNM to include the “prepaid pension asset” in rate base NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court is scheduled for October 30, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals. GAAP requires that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM continues to estimate that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss continues to be 15 months of capital cost recovery, which the order disallowed for PNM’s investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss is a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million in September 2016 for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM can no longer assert that those assets are probable of being recovered through the ratemaking process. Additional losses will be recorded if the currently estimated 15 month time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is extended. The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounting to $2.1 million was reflected as a reduction of income tax expense in September 2016. PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recorded in future periods. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of September 30, 2017, such losses could include: • The remaining costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity in excess of the recovery permitted under the NMPRC’s order; the net book value of such excess amount was $76.9 million , after considering the loss recorded in 2016 • The undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity in PVNGS Unit 2 purchased by PNM in January 2016 was being leased by PNM; the net book value of these improvements was $ 39.9 million , after considering the loss recorded in 2016 • The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $50.0 million , after considering the loss recorded in 2016 Also, PNM has evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $153.4 million (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) at September 30, 2017, after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and “prepaid pension asset” in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM. PNM is unable to predict the outcome of this matter. New Mexico 2016 General Rate Case (“NM 2016 Rate Case”) On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request are: • An increase in base non-fuel revenues of $99.2 million • Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application) • ROE of 10.125% • Drivers of revenue deficiency ◦ Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 11) ◦ Infrastructure investments, including environmental upgrades at Four Corners ◦ Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors ◦ Updates in the FERC/retail jurisdictional allocations • Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation ◦ Increased customer and demand charges ◦ A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions were held, but no agreements were reached by March 27, 2017. PNM and several intervenors filed an unopposed motion with the NMPRC to extend by one month the procedural schedule, including the date for filing a stipulation. On April 12, 2017, the NMPRC issued an order modifying the procedural schedule to allow for additional settlement discussion. Under the revised schedule, any settlement stipulation was to be filed by April 27, 2017. On April 27, 2017, PNM and several intervenors filed a motion with the NMPRC to extend the deadline for filing a stipulation. The motion was granted by the Hearing Examiners and in May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form, but allowed the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed the issues raised by the Hearing Examiners in their order. NEE is the sole party opposing the revised stipulation. The terms of the revised stipulation include: • A revenue increase totaling $62.3 million , with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019 • A ROE of 9.575% • Full recovery of the investment in SCRs at Four Corners with a debt-only return • An agreement not to adjust non-fuel base rate changes to be effective prior to January 1, 2020 • An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws enacted prior to November 1, 2018 and effective and applicable to PNM by January 1, 2019 • Returning to customers over a three -year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 13) to the extent attributable to PNM’s retail operations • PNM will withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket On May 24, 2017, the NMPRC issued an order, which resulted in the tolling of the statutory suspension period for two months and extending the suspension of the rate increase until January 6, 2018. The NMPRC can further extend the suspension period for an additional two months. A hearing on the revised stipulation was held in August 2017. The revised stipulation requires the approval of the NMPRC in order to take effect. If the NMPRC approves the revised stipulation as filed, GAAP would require PNM to recognize a loss to reflect that PNM will not earn an equity return on its investments in SCRs at Four Corners. The loss would be recorded as a regulatory disallowance as of the date of NMPRC approval. The amount of the loss would be calculated by determining the present value of disallowed cash flows, which would equal the difference between the cash flows resulting from recovery of those investments with a debt only return and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC. Such amount would depend on the final costs of the SCRs and other factors and assumptions at the date of NMPRC approval. Based on the stipulation and PNM’s current assumptions, PNM estimates the regulatory disallowance would be approximately $21 million . PNM cannot predict the outcome of this matter. Investigation/Rulemaking Concerning NMPRC Ratemaking Policies On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method should be established for determining ROE; should the ROE be subject to reward or penalty based on utilities meeting or failing to meet certain metrics, which could include customer complaints, outages, peak demand reductions, and RPS and energy efficiency compliance; whether recovery of utility rate case expenses should be limited to 50% unless the case is settled; whether intervenors should be allowed to recover their expenses if the NMPRC accepts their position; whether parties should have access to software used by utilities to support their positions; and how regulatory assets should be authorized and recovered. Initial comments were filed in July 2017 and a public workshop was held in September 2017. Additional public workshops are scheduled in November 2017. PNM cannot predict the outcome of this proceeding. Renewable Portfolio Standard The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 30% wind, 20% solar, 3% distributed generation, and 5% other. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. PNM makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Included in PNM’s approved procurement plans are the following renewable energy resources: • 107 MW of PNM-owned solar PV facilities, including 40 MW constructed in 2015 that were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; and an additional procurement of 1.5 MW of PNM-owned solar PV facilities to supply the energy sold under PNM’s voluntary renewable energy tariff • A PPA through 2027 for the output of New Mexico Wind, having an aggregate capacity of 204 MW and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW • A PPA for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current capacity of the facility is 4 MW • Solar distributed generation, aggregating 81.6 MW at September 30, 2017, owned by customers or third parties from whom PNM purchases any net excess output and RECs • Solar and wind RECs as needed to meet the RPS requirements PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome. PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan met RPS and diversity requirements for 2017 and 2018 using existing resources and PNM did not propose any significant new procurements. PNM projected that its plan would slightly exceed the RCT in 2017 and would be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determined a variance was necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a recommended decision recommending that the plan be approved as filed and also found that a variance from the RCT was not required. The NMPRC approved the recommended decision on November 23, 2016. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM is requesting approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018; and various other requests, including the continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. PNM’s proposed procurement cost for 2018 and 2019 will be within the RCT. The plan is also seeking a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. PNM also requested to adjust its annual renewable energy rate rider to collect the costs of renewable resources. On June 14, 2017, the NMPRC issued an initial order appointing a Hearing Examiner and suspending the proposed rate rider adjustment. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that the 50 MW solar projects not be approved and that PNM be required to issue another all-renewables RFP within 10 days of the issuance of a final order allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagrees with the Hearing Examiner’s recommendations and believes they are unlawful and against the weight of evidence. Exceptions to the recommended decision are due on October 27, 2017. PNM will file its exceptions timely and will vigorously contest the Hearing Examiner’s proposals regarding Lightning Dock Geothermal and the requirement that PNM allow developers to construct renewable facilities on PNM-owned sites. PNM cannot predict the outcome of this matter. Renewable Energy Rider The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $11.8 million and $10.7 million in the three months ended September 30, 2017 and 2016 and $32.4 million and $27.3 million in the nine months ended September 30, 2017 and 2016. In its 2016 renewable energy procurement plan case, PNM proposed to collect $42.4 million in 2016. The 2016 rider adjustment was approved as part of the order issued February 3, 2016 approving the 2016 renewable energy plan. In its 2017 renewable energy procurement plan, PNM proposed to collect $50.0 million through the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, was due to recovering the costs of energy from New Mexico Wind through the rider, rather than through the FPPAC in compliance with the NMPRC’s order in PNM’s NM 2015 Rate Case. The 2017 rider adjustment was approved in the November 23, 2016 order that approved the 2017 renewable energy plan. On February 28, 2017, PNM filed a reconciliation of 2017 revenue requirement and proposed a revision to the rider that would recover $42.7 million during 2017. In its 2018 renewable energy procurement plan case, PNM proposes to collect $43.5 million . Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5% , PNM is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016. Energy Efficiency and Load Management Program Costs and Incentives 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. The act sets 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. On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consisted of ten programs with a total budget of $28.0 million . The application also sought approval of an incentive of $2.4 million based on targeted savings of 75 GWh. The actual incentive would be based on actual savings achieved. On January 11, 2017, the NMPRC approved an unopposed stipulation that established a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million , and approved a sliding scale profit incentive with a base level of 7.1% of program costs, equal to $1.8 million , if PNM achieves a minimum proscribed level of energy savings, increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million . The application also seeks approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve saving of 53 GWh in 2018. As proposed, PNM would have earned an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. PNM |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes In 2013, New Mexico House Bill 641 reduced the New Mexico corporate income tax rate from 7.6% to 5.9% . The rate reduction is being phased-in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes during the period that includes the date of enactment, which was in the year ended December 31, 2013, to reflect the tax rate at which the balances are expected to reverse. At that time, 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 would be required to return the benefit to customers over time. In addition, 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, 2017 and 2016, PNM’s regulatory liability was reduced by $4.8 million and $7.1 million , which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: reduced by $0.1 million in the three months ended March 31, 2017, increasing income tax expense by less than $0.1 million for PNM and $0.1 million for the Corporate and Other segment; and decreased by $0.7 million in the three months ended March 31, 2016, increasing income tax expense by $0.8 million for PNM and reducing income tax expense by $0.1 million for the Corporate and Other segment. In the stipulation filed in PNM’s NM 2016 Rate Case (Note 12), it is proposed that the benefit of the lower New Mexico corporate income tax rate be returned to customers over a three -year period beginning January 1, 2018. In 2008, fifty percent bonus tax depreciation was enacted as a temporary two -year stimulus measure as part of the Economic Stimulus Act of 2008. Bonus tax depreciation in various forms has been continuously extended since that time. As a result of the net operating loss carryforwards for income tax purposes created by bonus depreciation, and reduced future income taxes payable resulting from New Mexico House Bill 641, certain tax carryforwards are not expected to be utilized before their expiration. In accordance with GAAP, PNMR and PNM have impaired the tax carryforwards which were not expected to be utilized prior to their expiration. The Company has not recorded any impairments in 2016 or 2017. The NMPRC’s final order in PNM’s NM 2015 Rate Case (Note 12) approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from the extension of bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million , which is reflected as a reduction of income tax expense on the Condensed Consolidated Statement of Earnings in the three months ended September 30, 2016. The Company undertook an analysis of interest income and interest expense applicable to federal income tax matters. The analysis encompassed the impacts of IRS examinations, amended income tax returns, and filings for carrybacks of tax matters to previous taxable years applicable to all years not closed under the IRS rules. As a result of this effort, PNMR received net refunds from the IRS of $6.5 million in the three months ended June 30, 2016. Of the refunds, $2.1 million was recorded as a reduction of interest receivable and $5.1 million was recorded as interest income, which was partially offset by $0.7 million of interest expense. In addition, PNMR incurred $0.9 million in professional fees related to the analysis. Of the net pre-tax impacts aggregating $3.5 million , $2.6 million is reflected in the PNM segment, $0.3 million in the TNMP segment, and $0.6 million in the Corporate and Other segment. See Note 8 for a discussion of the impacts on income tax expense resulting from the adoption of Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718). |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions PNMR, PNM, and TNMP are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Services billings: PNMR to PNM $ 23,451 $ 22,189 $ 71,044 $ 67,192 PNMR to TNMP 7,828 6,593 23,771 20,881 PNM to TNMP 115 105 302 347 TNMP to PNMR 35 10 106 30 TNMP to PNM 8 84 154 171 Interest billings: PNMR to TNMP 66 13 126 112 PNMR to PNM 3 3 14 8 PNM to PNMR 71 38 163 110 Income tax sharing payments: PNMR to PNM — — — — PNMR to TNMP — — — — |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. PNMR’s reporting units that currently have goodwill are PNM and TNMP. Additional information concerning the Company’s goodwill is contained in Note 18 of Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K. GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price has occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required if, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, GAAP currently requires the entity to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how a goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis. For its annual evaluations performed as of April 1, 2016, PNMR performed quantitative analyses for both the PNM and TNMP reporting units. For the quantitative analyses, 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 April 1, 2016 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% . The April 1, 2016 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million , exceeded its carrying value by approximately 32% . For its annual evaluations performed as of April 1, 2017, PNMR performed qualitative analyses for both the PNM and TNMP reporting units. The qualitative analysis was performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2016 quantitative analysis. This analysis considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including the estimated impacts of the proposed revised stipulation in PNM’s NM 2016 Rate Case, the impacts of potential outcomes of the matters appealed to the NM Supreme Court under the NM 2015 Rate Case, and the impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. This evaluation also considered changes in TNMP’s regulatory environment such as the PUCT’s proposed amendments to the interim transmission cost of service filing rule, as well as potential outcomes associated with TNMP’s general rate case filing, which the Company anticipates filing in 2018. The qualitative analysis also considered market and macroeconomic factors including changes in anticipated growth rates, anticipated changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it is not more likely than not that the April 1, 2017 carrying values of PNM or TNMP exceed their fair values. As indicated above, the annual evaluations performed as of April 1, 2017 and 2016 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 2017 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below their carrying values. |
Significant Accounting Polici24
Significant Accounting Policies and Responsibility for Financial Statements (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 5) and, through January 15, 2016, the PVNGS Capital Trust. 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. Certain PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. |
Dividends on Common Stock | Dividends on Common Stock Dividends on PNMR’s common stock are declared by the Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends 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. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606) In May 2014, the FASB issued ASU 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. ASU 2014-09 also revises the disclosure requirements regarding revenue. Since the issuance of ASU 2014-09, the FASB issued a one -year deferral of the effective date and has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. ASU 2014-09 can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company anticipates adopting ASU 2014-09 on January 1, 2018, its required effective date, using the modified retrospective method of adoption. The Company has substantially completed its assessment of ASU 2014-09, but, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding certain industry specific issues. These industry specific issues include the impacts of the new guidance on its accounting for CIAC and the presentation of revenues associated with “alternative revenue programs,” which primarily result from the Company’s approved rate rider programs. Although conclusions have not been finalized, the Company does not anticipate a material change in revenue recognition under the new requirements. The Company continues to analyze the financial statement presentation and disclosure requirements of ASU 2014-09. Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU 2016-01, which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. ASU 2016-01 also revises certain presentation and disclosure requirements. Under ASU 2016-01, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available-for-sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt ASU 2016-01 on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and future changes in the value of equity securities will be recorded in earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains on equity securities, net of income taxes, recorded in AOCI of $9.8 million at September 30, 2017. Accounting Standards Update 2016-02 – Leases (Topic 842) In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 will require that a liability be recorded on the balance sheet for all leases, based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings or cash flows, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. Although early adoption of the standard is permitted, the Company does not plan to adopt this standard prior to January 1, 2019, its required effective date. At adoption of ASU 2016-02, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. This approach requires all periods presented to be restated under the new guidance, but allows entities to apply certain practical expedients to arrangements that exist upon adoption or expired during the periods presented. As further discussed in Note 7 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K, the Company has operating leases of office buildings, vehicles, and equipment. The Company also routinely enters into land easements and right-of-way agreements, but only a limited number of these agreements are considered leases under the current guidance. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024. The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification, including the treatment of land easements under ASU 2016-02. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under ASU 2016-02. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company is also evaluating the practical expedients, if any, it will elect upon adoption. The Company anticipates this process will continue into 2018. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 on January 1, 2020 although early adoption is permitted beginning on January 1, 2019. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230): Restricted Cash In November 2016, the FASB issued ASU 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not provide a definition of what should be considered restricted cash. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for each period presented. The Company continues to analyze the impacts of ASU 2016-18, but does not believe the new standard will have a significant impact on its financial statements. The Company will adopt ASU 2016-18 on January 1, 2018, its required effective date. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. The amendments in ASU 2017-07 require the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net benefit cost (the “non-service cost components”) are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the non-service cost components have been presented. ASU 2017-07 also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s benefit plans is discussed in Note 12 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 10. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net benefit costs as regulatory assets to the extent attributable to regulated operations and does not anticipate ASU 2017-07 will have a significant impact on its financial statements. The Company will adopt the standard on January 1, 2018, its required effective date. Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019 although early adoption is permitted beginning on January 1, 2018. As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 9, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8 of the Notes to Consolidated Financial Statements in the 2016 Annual Reports on Form 10-K and in Note 7, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements. The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (collectively, “excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR had not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. |
Variable Interest Entities | GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Computation of Earnings Per Share | Information regarding the computation of earnings per share is as follows: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands, except per share amounts) Net Earnings Attributable to PNMR $ 73,739 $ 54,418 $ 134,156 $ 92,040 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 284 96 215 99 Average Shares – Basic 79,938 79,750 79,869 79,753 Dilutive Effect of Common Stock Equivalents: Stock options and restricted stock 216 367 263 377 Average Shares – Diluted 80,154 80,117 80,132 80,130 Net Earnings Per Share of Common Stock: Basic $ 0.92 $ 0.68 $ 1.68 $ 1.15 Diluted $ 0.92 $ 0.68 $ 1.67 $ 1.15 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Summary of Financial Information by Segment | The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION PNM TNMP Corporate and Other Consolidated (In thousands) Three Months Ended September 30, 2017 Electric operating revenues $ 327,254 $ 92,646 $ — $ 419,900 Cost of energy 82,367 21,381 — 103,748 Utility margin 244,887 71,265 — 316,152 Other operating expenses 94,871 25,367 (5,391 ) 114,847 Depreciation and amortization 36,764 16,424 5,633 58,821 Operating income (loss) 113,252 29,474 (242 ) 142,484 Interest income 1,782 — 1,800 3,582 Other income (deductions) 6,342 1,228 (460 ) 7,110 Interest charges (20,451 ) (7,704 ) (3,951 ) (32,106 ) Segment earnings (loss) before income taxes 100,925 22,998 (2,853 ) 121,070 Income taxes (benefit) 35,642 8,271 (1,170 ) 42,743 Segment earnings (loss) 65,283 14,727 (1,683 ) 78,327 Valencia non-controlling interest (4,456 ) — — (4,456 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 60,695 $ 14,727 $ (1,683 ) $ 73,739 Nine Months Ended September 30, 2017 Electric operating revenues $ 854,909 $ 257,489 $ — $ 1,112,398 Cost of energy 246,635 64,183 — 310,818 Utility margin 608,274 193,306 — 801,580 Other operating expenses 288,300 72,188 (15,286 ) 345,202 Depreciation and amortization 109,228 47,392 16,209 172,829 Operating income (loss) 210,746 73,726 (923 ) 283,549 Interest income 6,457 — 5,891 12,348 Other income (deductions) 19,924 2,392 (918 ) 21,398 Interest charges (62,393 ) (22,619 ) (11,125 ) (96,137 ) Segment earnings (loss) before income taxes 174,734 53,499 (7,075 ) 221,158 Income taxes (benefit) 58,865 18,964 (2,675 ) 75,154 Segment earnings (loss) 115,869 34,535 (4,400 ) 146,004 Valencia non-controlling interest (11,452 ) — — (11,452 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 104,021 $ 34,535 $ (4,400 ) $ 134,156 At September 30, 2017: Total Assets $ 5,023,816 $ 1,465,219 $ 208,219 $ 6,697,254 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other Consolidated (In thousands) Three Months Ended September 30, 2016 Electric operating revenues $ 311,276 $ 89,098 $ — $ 400,374 Cost of energy 88,565 20,201 — 108,766 Utility margin 222,711 68,897 — 291,608 Other operating expenses 109,342 24,184 (3,006 ) 130,520 Depreciation and amortization 33,312 16,354 3,351 53,017 Operating income (loss) 80,057 28,359 (345 ) 108,071 Interest income 1,509 — 3,095 4,604 Other income (deductions) 4,980 855 (184 ) 5,651 Interest charges (22,213 ) (7,308 ) (2,946 ) (32,467 ) Segment earnings (loss) before income taxes 64,333 21,906 (380 ) 85,859 Income taxes 19,343 8,053 (93 ) 27,303 Segment earnings (loss) 44,990 13,853 (287 ) 58,556 Valencia non-controlling interest (4,006 ) — — (4,006 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 40,852 $ 13,853 $ (287 ) $ 54,418 Nine Months Ended September 30, 2016 Electric operating revenues $ 780,228 $ 246,498 $ — $ 1,026,726 Cost of energy 222,376 60,122 — 282,498 Utility margin 557,852 186,376 — 744,228 Other operating expenses 314,961 70,328 (9,261 ) 376,028 Depreciation and amortization 97,778 45,760 10,263 153,801 Operating income (loss) 145,113 70,288 (1,002 ) 214,399 Interest income 8,549 — 9,871 18,420 Other income (deductions) 17,305 2,139 (1,517 ) 17,927 Interest charges (66,494 ) (22,150 ) (8,535 ) (97,179 ) Segment earnings (loss) before income taxes 104,473 50,277 (1,183 ) 153,567 Income taxes (benefit) 32,131 18,460 (497 ) 50,094 Segment earnings (loss) 72,342 31,817 (686 ) 103,473 Valencia non-controlling interest (11,037 ) — — (11,037 ) Subsidiary preferred stock dividends (396 ) — — (396 ) Segment earnings (loss) attributable to PNMR $ 60,909 $ 31,817 $ (686 ) $ 92,040 At September 30, 2016: Total Assets $ 4,799,012 $ 1,366,840 $ 237,818 $ 6,403,670 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 |
Accumulated Other Comprehensi27
Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2017 and 2016 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2016 $ 4,320 $ (96,748 ) $ (92,428 ) $ (23 ) $ (92,451 ) Amounts reclassified from AOCI (pre-tax) (11,088 ) 4,839 (6,249 ) 484 (5,765 ) Income tax impact of amounts reclassified 4,302 (1,878 ) 2,424 (187 ) 2,237 Other OCI changes (pre-tax) 22,302 — 22,302 (278 ) 22,024 Income tax impact of other OCI changes (8,654 ) — (8,654 ) 108 (8,546 ) Net after-tax change 6,862 2,961 9,823 127 9,950 Balance at September 30, 2017 $ 11,182 $ (93,787 ) $ (82,605 ) $ 104 $ (82,501 ) Balance at December 31, 2015 $ 17,346 $ (88,822 ) $ (71,476 ) $ 44 $ (71,432 ) Amounts reclassified from AOCI (pre-tax) (10,135 ) 4,128 (6,007 ) 573 (5,434 ) Income tax impact of amounts reclassified 3,955 (1,611 ) 2,344 (224 ) 2,120 Other OCI changes (pre-tax) 3,115 — 3,115 (1,305 ) 1,810 Income tax impact of other OCI changes (1,216 ) — (1,216 ) 509 (707 ) Net after-tax change (4,281 ) 2,517 (1,764 ) (447 ) (2,211 ) Balance at September 30, 2016 $ 13,065 $ (86,305 ) $ (73,240 ) $ (403 ) $ (73,643 ) |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Variable Interest Entities [Abstract] | |
Summarized Financial Information | Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Operating revenues $ 5,859 $ 5,356 $ 15,880 $ 15,541 Operating expenses (1,403 ) (1,350 ) (4,428 ) (4,504 ) Earnings attributable to non-controlling interest $ 4,456 $ 4,006 $ 11,452 $ 11,037 Financial Position September 30, December 31, 2017 2016 (In thousands) Current assets $ 3,498 $ 2,551 Net property, plant, and equipment 64,818 66,947 Total assets 68,316 69,498 Current liabilities 907 578 Owners’ equity – non-controlling interest $ 67,409 $ 68,920 |
Fair Value of Derivative and 29
Fair Value of Derivative and Other Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value of Derivative and Other Financial Instruments [Abstract] | |
Summary of Derivatives | PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: Economic Hedges September 30, December 31, (In thousands) Current assets $ 3,093 $ 5,224 Deferred charges 3,846 — 6,939 5,224 Current liabilities (1,279 ) (2,339 ) Long-term liabilities (3,846 ) — (5,125 ) (2,339 ) Net $ 1,814 $ 2,885 |
Effect of Mark-to-Market on Earnings, Excluding Tax Effects | The following table presents the effect of mark-to-market commodity derivative instruments on PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. Economic Hedges Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Electric operating revenues $ (2,237 ) $ 1,652 $ 5,697 $ 214 Cost of energy (14 ) (1 ) (5,289 ) (1,113 ) Total gain (loss) $ (2,251 ) $ 1,651 $ 408 $ (899 ) |
Schedule of Net Buy (Sell) Volume Positions | The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh September 30, 2017 100,000 (630,933 ) December 31, 2016 254,100 (2,471,600 ) |
Schedule of Fair Value and Gross Unrealized Gains in Available-for-sale Securities | The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. September 30, 2017 December 31, 2016 Unrealized Gains Fair Value Unrealized Gains Fair Value (In thousands) Cash and cash equivalents $ — $ 8,151 $ — $ 23,683 Equity securities: Domestic value 5,252 72,162 1,135 34,796 Domestic growth 5,775 73,345 3,032 47,595 International and other 4,865 43,167 2,029 27,481 Fixed income securities: U.S. Government 307 28,960 115 40,962 Municipals 998 41,131 585 43,789 Corporate and other 1,434 39,528 553 54,671 $ 18,631 $ 306,444 $ 7,449 $ 272,977 |
Schedule of Gross Realized Gains and Losses | The proceeds and gross realized gains and losses on the disposition of available-for-sale securities are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $0.1 million and $1.1 million for the three and nine months ended September 30, 2017 and $0.1 million and $1.0 million for the three and nine months ended September 30, 2016. Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Proceeds from sales $ 98,532 $ 86,975 $ 456,577 $ 280,989 Gross realized gains $ 8,128 $ 7,026 $ 24,745 $ 27,273 Gross realized (losses) $ (2,829 ) $ (2,565 ) $ (8,150 ) $ (12,913 ) |
Investments Classified by Contractual Maturity Date | At September 30, 2017 , 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 (In thousands) Within 1 year $ 3,913 $ — After 1 year through 5 years 22,766 76,353 After 5 years through 10 years 25,456 — After 10 years through 15 years 5,178 — After 15 years through 20 years 10,692 — After 20 years 41,614 — $ 109,619 $ 76,353 |
Schedule of Investments | Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2017 and December 31, 2016 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) (In thousands) September 30, 2017 Available-for-sale securities Cash and cash equivalents $ 8,151 $ 8,151 $ — Equity securities: Domestic value 72,162 72,162 — Domestic growth 73,345 73,345 — International and other 43,167 39,931 3,236 Fixed income securities: U.S. Government 28,960 28,273 687 Municipals 41,131 — 41,131 Corporate and other 39,528 — 39,528 $ 306,444 $ 221,862 $ 84,582 Commodity derivative assets $ 6,939 $ — $ 6,939 Commodity derivative liabilities (5,125 ) — (5,125 ) Net $ 1,814 $ — $ 1,814 December 31, 2016 Available-for-sale securities Cash and cash equivalents $ 23,683 $ 23,683 $ — Equity securities: Domestic value 34,796 34,796 — Domestic growth 47,595 47,595 — International and other 27,481 27,481 — Fixed income securities: U.S. Government 40,962 39,723 1,239 Municipals 43,789 — 43,789 Corporate and other 54,671 23,158 31,513 $ 272,977 $ 196,436 $ 76,541 Commodity derivative assets $ 5,224 $ — $ 5,224 Commodity derivative liabilities (2,339 ) — (2,339 ) Net $ 2,885 $ — $ 2,885 |
Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value | The carrying amounts and fair values of investments in the Westmoreland Loan, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 September 30, 2017 (In thousands) PNMR Long-term debt $ 2,447,702 $ 2,564,887 $ — $ 2,564,887 $ — Westmoreland Loan $ 66,230 $ 76,353 $ — $ — $ 76,353 Other investments $ 386 $ 386 $ 386 $ — $ — PNM Long-term debt $ 1,657,396 $ 1,736,026 $ — $ 1,736,026 $ — Other investments $ 166 $ 166 $ 166 $ — $ — TNMP Long-term debt $ 480,589 $ 517,977 $ — $ 517,977 $ — Other investments $ 220 $ 220 $ 220 $ — $ — December 31, 2016 PNMR Long-term debt $ 2,392,712 $ 2,540,693 $ — $ 2,540,693 $ — Westmoreland Loan $ 95,000 $ 100,893 $ — $ — $ 100,893 Other investments $ 547 $ 1,164 $ 547 $ — $ 617 PNM Long-term debt $ 1,631,369 $ 1,730,157 $ — $ 1,730,157 $ — Other investments $ 316 $ 316 $ 316 $ — $ — TNMP Long-term debt $ 420,875 $ 468,329 $ — $ 468,329 $ — Other investments $ 231 $ 231 $ 231 $ — $ — |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Activity | The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Nine Months Ended September 30, Restricted Stock 2017 2016 Weighted-average grant date fair value $ 23.06 $ 26.49 Total fair value of restricted shares that vested (in thousands) $ 5,666 $ 5,011 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) $ 2,234 $ 1,208 The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Nine Months Ended September 30, Restricted Shares and Performance Based Shares 2017 2016 Expected quarterly dividends per share $ 0.2425 $ 0.2200 Risk-free interest rate 1.50 % 0.94 % Market-Based Shares Dividend yield 2.67 % 2.74 % Expected volatility 20.80 % 20.44 % Risk-free interest rate 1.54 % 0.97 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the nine months ended September 30, 2017 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2016 218,316 $ 27.59 305,874 $ 12.29 Granted 248,271 $ 23.06 — $ — Exercised (270,855 ) $ 20.92 (109,433 ) $ 15.89 Forfeited (4,012 ) $ 29.96 — $ — Expired — $ — (3,000 ) $ 30.50 Outstanding at September 30, 2017 191,720 $ 31.10 193,441 $ 9.98 |
Financing (Tables)
Financing (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Maturities and Interest Rates | Information concerning the maturities and interest rates on the PNM 2018 SUNs to be issued in May 2018 and August 2018 is as follows: Scheduled Funding Maturity Principal Interest Date Date Amount Rate (In millions) May 15, 2018 May 15, 2023 $ 55.0 3.15 % May 15, 2018 May 15, 2025 104.0 3.45 % May 15, 2018 May 15, 2028 88.0 3.68 % May 15, 2018 May 15, 2033 38.0 3.93 % May 15, 2018 May 15, 2038 45.0 4.22 % May 15, 2018 May 15, 2048 20.0 4.50 % 350.0 August 1, 2018 August 1, 2028 15.0 3.78 % August 1, 2018 August 1, 2048 85.0 4.60 % 100.0 $ 450.0 |
Schedule of Short-term Debt | Short-term debt outstanding consisted of: September 30, December 31, Short-term Debt 2017 2016 (In thousands) PNM: PNM Revolving Credit Facility $ — $ 35,000 PNM New Mexico Credit Facility — 26,000 TNMP Revolving Credit Facility — — PNMR: PNMR Revolving Credit Facility 166,500 126,100 PNMR 2016 One-Year Term Loan 100,000 100,000 $ 266,500 $ 287,100 |
Pension and Other Postretirem32
Pension and Other Postretirement Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
Schedule of Net Benefit Costs | The following tables present the components of the PNM Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 24 $ 35 $ — $ — Interest cost 6,727 7,577 1,006 1,087 174 203 Expected return on plan assets (8,451 ) (8,854 ) (1,308 ) (1,371 ) — — Amortization of net (gain) loss 4,001 3,455 921 286 78 64 Amortization of prior service cost (241 ) (241 ) (416 ) (7 ) — — Net periodic benefit cost $ 2,036 $ 1,937 $ 227 $ 30 $ 252 $ 267 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 72 $ 105 $ — $ — Interest cost 20,181 22,731 3,019 3,260 523 609 Expected return on plan assets (25,352 ) (26,562 ) (3,923 ) (4,113 ) — — Amortization of net (gain) loss 12,004 10,365 2,762 858 235 192 Amortization of prior service cost (724 ) (724 ) (1,248 ) (22 ) — — Net periodic benefit cost $ 6,109 $ 5,810 $ 682 $ 88 $ 758 $ 801 The following tables present the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 36 $ 46 $ — $ — Interest cost 722 826 139 169 8 10 Expected return on plan assets (945 ) (986 ) (114 ) (122 ) — — Amortization of net (gain) loss 231 175 (20 ) (10 ) 2 1 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ 8 $ 15 $ 41 $ 83 $ 10 $ 11 Nine Months Ended September 30, Pension Plan OPEB Plan Executive Retirement Program 2017 2016 2017 2016 2017 2016 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 107 $ 139 $ — $ — Interest cost 2,165 2,478 417 508 25 30 Expected return on plan assets (2,834 ) (2,957 ) (342 ) (367 ) — — Amortization of net (gain) loss 692 525 (60 ) (30 ) 7 1 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost $ 23 $ 46 $ 122 $ 250 $ 32 $ 31 |
Regulatory and Rate Matters (Ta
Regulatory and Rate Matters (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Energy/Capacity Transactions | Information about the purchases and sales is as follows: Sales Purchases GWh Amount GWh Amount (In millions) (In millions) Three months ended September 30, 2017 202.4 $ 7.2 215.1 $ 7.6 Three months ended September 30, 2016 208.2 6.2 216.4 6.4 Nine months ended September 30, 2017 615.0 17.7 632.5 18.2 Nine months ended September 30, 2016 268.5 7.8 278.8 8.1 |
Schedule of Rate Increases for Transmission Costs | The following sets forth TNMP’s recent interim transmission cost rate increases: Effective Date Approved Increase in Rate Base Annual Increase in Revenue (In millions) September 10, 2015 $ 7.0 $ 1.4 March 23, 2016 25.8 4.3 September 8, 2016 9.5 1.8 March 14, 2017 30.2 4.8 September 13, 2017 27.5 4.7 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
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 Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (In thousands) Services billings: PNMR to PNM $ 23,451 $ 22,189 $ 71,044 $ 67,192 PNMR to TNMP 7,828 6,593 23,771 20,881 PNM to TNMP 115 105 302 347 TNMP to PNMR 35 10 106 30 TNMP to PNM 8 84 154 171 Interest billings: PNMR to TNMP 66 13 126 112 PNMR to PNM 3 3 14 8 PNM to PNMR 71 38 163 110 Income tax sharing payments: PNMR to PNM — — — — PNMR to TNMP — — — — |
Significant Accounting Polici35
Significant Accounting Policies and Responsibility for Financial Statements (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2017 | Jul. 31, 2017 | Sep. 30, 2016 | Jul. 31, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Accounting Policies [Abstract] | ||||||||
Payment defaults under agreements | $ 0 | $ 0 | $ 0 | |||||
Unrealized gains, net of income taxes, recorded in AOCI | $ 9,800,000 | $ 9,800,000 | $ 9,800,000 | |||||
Dividends Payable [Line Items] | ||||||||
Declared dividends on common stock (dollars per share) | $ 0.2425 | $ 0.2425 | $ 0.22 | $ 0.22 | $ 0.2425 | $ 0.22 | $ 0.7275 | $ 0.66 |
Dividends declared and paid | $ 57,948,000 | |||||||
PNM | ||||||||
Dividends Payable [Line Items] | ||||||||
Equity contribution | $ 28,100,000 | |||||||
Dividends declared and paid | 4,100,000 | |||||||
Texas-New Mexico Power Company | ||||||||
Dividends Payable [Line Items] | ||||||||
Equity contribution | 50,000,000 | |||||||
Dividends declared and paid | $ 29,663,000 | $ 18,000,000 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Earnings Per Share [Abstract] | ||||
Net Earnings Attributable to PNMR | $ 73,739 | $ 54,418 | $ 134,156 | $ 92,040 |
Average Number of Common Shares: | ||||
Outstanding during period (in shares) | 79,654 | 79,654 | 79,654 | 79,654 |
Vested awards of restricted stock (in shares) | 284 | 96 | 215 | 99 |
Average Shares – Basic (in shares) | 79,938 | 79,750 | 79,869 | 79,753 |
Dilutive Effect of Common Stock Equivalents: | ||||
Stock options and restricted stock (in shares) | 216 | 367 | 263 | 377 |
Average Shares – Diluted (in shares) | 80,154 | 80,117 | 80,132 | 80,130 |
Net Earnings Per Share of Common Stock: | ||||
Basic (in dollars per share) | $ 0.92 | $ 0.68 | $ 1.68 | $ 1.15 |
Diluted (in dollars per share) | $ 0.92 | $ 0.68 | $ 1.67 | $ 1.15 |
Segment Information - Summarize
Segment Information - Summarized Financial Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | $ 419,900 | $ 400,374 | $ 1,112,398 | $ 1,026,726 | |
Cost of energy | 103,748 | 108,766 | 310,818 | 282,498 | |
Utility margin | 316,152 | 291,608 | 801,580 | 744,228 | |
Other operating expenses | 114,847 | 130,520 | 345,202 | 376,028 | |
Depreciation and amortization | 58,821 | 53,017 | 172,829 | 153,801 | |
Operating income | 142,484 | 108,071 | 283,549 | 214,399 | |
Interest income | 3,582 | 4,604 | 12,348 | 18,420 | |
Other income (deductions) | 7,110 | 5,651 | 21,398 | 17,927 | |
Interest charges | (32,106) | (32,467) | (96,137) | (97,179) | |
Earnings before Income Taxes | 121,070 | 85,859 | 221,158 | 153,567 | |
Income taxes (benefit) | 42,743 | 27,303 | 75,154 | 50,094 | |
Net Earnings | 78,327 | 58,556 | 146,004 | 103,473 | |
Valencia non-controlling interest | (4,456) | (4,006) | (11,452) | (11,037) | |
Subsidiary preferred stock dividends | (132) | (132) | (396) | (396) | |
Net Earnings Available for PNM Common Stock | 73,739 | 54,418 | 134,156 | 92,040 | |
Total Assets | 6,697,254 | 6,403,670 | 6,697,254 | 6,403,670 | $ 6,471,080 |
Goodwill | 278,297 | 278,297 | 278,297 | 278,297 | $ 278,297 |
PNM | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 327,254 | 311,276 | 854,909 | 780,228 | |
Cost of energy | 82,367 | 88,565 | 246,635 | 222,376 | |
Utility margin | 244,887 | 222,711 | 608,274 | 557,852 | |
Other operating expenses | 94,871 | 109,342 | 288,300 | 314,961 | |
Depreciation and amortization | 36,764 | 33,312 | 109,228 | 97,778 | |
Operating income | 113,252 | 80,057 | 210,746 | 145,113 | |
Interest income | 1,782 | 1,509 | 6,457 | 8,549 | |
Other income (deductions) | 6,342 | 4,980 | 19,924 | 17,305 | |
Interest charges | (20,451) | (22,213) | (62,393) | (66,494) | |
Earnings before Income Taxes | 100,925 | 64,333 | 174,734 | 104,473 | |
Income taxes (benefit) | 35,642 | 19,343 | 58,865 | 32,131 | |
Net Earnings | 65,283 | 44,990 | 115,869 | 72,342 | |
Valencia non-controlling interest | (4,456) | (4,006) | (11,452) | (11,037) | |
Subsidiary preferred stock dividends | (132) | (132) | (396) | (396) | |
Net Earnings Available for PNM Common Stock | 60,695 | 40,852 | 104,021 | 60,909 | |
Total Assets | 5,023,816 | 4,799,012 | 5,023,816 | 4,799,012 | |
Goodwill | 51,632 | 51,632 | 51,632 | 51,632 | |
TNMP | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 92,646 | 89,098 | 257,489 | 246,498 | |
Cost of energy | 21,381 | 20,201 | 64,183 | 60,122 | |
Utility margin | 71,265 | 68,897 | 193,306 | 186,376 | |
Other operating expenses | 25,367 | 24,184 | 72,188 | 70,328 | |
Depreciation and amortization | 16,424 | 16,354 | 47,392 | 45,760 | |
Operating income | 29,474 | 28,359 | 73,726 | 70,288 | |
Interest income | 0 | 0 | 0 | 0 | |
Other income (deductions) | 1,228 | 855 | 2,392 | 2,139 | |
Interest charges | (7,704) | (7,308) | (22,619) | (22,150) | |
Earnings before Income Taxes | 22,998 | 21,906 | 53,499 | 50,277 | |
Income taxes (benefit) | 8,271 | 8,053 | 18,964 | 18,460 | |
Net Earnings | 14,727 | 13,853 | 34,535 | 31,817 | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | 14,727 | 13,853 | 34,535 | 31,817 | |
Total Assets | 1,465,219 | 1,366,840 | 1,465,219 | 1,366,840 | |
Goodwill | 226,665 | 226,665 | 226,665 | 226,665 | |
Corporate and Other | |||||
Segment Reporting Information, Profit (Loss) [Abstract] | |||||
Electric operating revenues | 0 | 0 | 0 | 0 | |
Cost of energy | 0 | 0 | 0 | 0 | |
Utility margin | 0 | 0 | 0 | 0 | |
Other operating expenses | (5,391) | (3,006) | (15,286) | (9,261) | |
Depreciation and amortization | 5,633 | 3,351 | 16,209 | 10,263 | |
Operating income | (242) | (345) | (923) | (1,002) | |
Interest income | 1,800 | 3,095 | 5,891 | 9,871 | |
Other income (deductions) | (460) | (184) | (918) | (1,517) | |
Interest charges | (3,951) | (2,946) | (11,125) | (8,535) | |
Earnings before Income Taxes | (2,853) | (380) | (7,075) | (1,183) | |
Income taxes (benefit) | (1,170) | (93) | (2,675) | (497) | |
Net Earnings | (1,683) | (287) | (4,400) | (686) | |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | |
Net Earnings Available for PNM Common Stock | (1,683) | (287) | (4,400) | (686) | |
Total Assets | 208,219 | 237,818 | 208,219 | 237,818 | |
Goodwill | $ 0 | $ 0 | $ 0 | $ 0 |
Accumulated Other Comprehensi38
Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | $ (92,451) | $ (71,432) | ||
Amounts reclassified from AOCI (pre-tax) | (5,765) | (5,434) | ||
Income tax impact of amounts reclassified | 2,237 | 2,120 | ||
Other OCI changes (pre-tax) | 22,024 | 1,810 | ||
Income tax impact of other OCI changes | (8,546) | (707) | ||
Total Other Comprehensive Income (Loss) | $ 3,094 | $ 1,063 | 9,950 | (2,211) |
Ending Balance | (82,501) | (73,643) | (82,501) | (73,643) |
Fair Value Adjustment for Cash Flow Hedges | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (23) | 44 | ||
Amounts reclassified from AOCI (pre-tax) | 484 | 573 | ||
Income tax impact of amounts reclassified | (187) | (224) | ||
Other OCI changes (pre-tax) | (278) | (1,305) | ||
Income tax impact of other OCI changes | 108 | 509 | ||
Total Other Comprehensive Income (Loss) | 127 | (447) | ||
Ending Balance | 104 | (403) | 104 | (403) |
PNM | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (92,428) | (71,476) | ||
Amounts reclassified from AOCI (pre-tax) | (6,249) | (6,007) | ||
Income tax impact of amounts reclassified | 2,424 | 2,344 | ||
Other OCI changes (pre-tax) | 22,302 | 3,115 | ||
Income tax impact of other OCI changes | (8,654) | (1,216) | ||
Total Other Comprehensive Income (Loss) | 2,989 | 671 | 9,823 | (1,764) |
Ending Balance | (82,605) | (73,240) | (82,605) | (73,240) |
PNM | Unrealized Gains on Available-for-Sale Securities | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | 4,320 | 17,346 | ||
Amounts reclassified from AOCI (pre-tax) | (11,088) | (10,135) | ||
Income tax impact of amounts reclassified | 4,302 | 3,955 | ||
Other OCI changes (pre-tax) | 22,302 | 3,115 | ||
Income tax impact of other OCI changes | (8,654) | (1,216) | ||
Total Other Comprehensive Income (Loss) | 6,862 | (4,281) | ||
Ending Balance | 11,182 | 13,065 | 11,182 | 13,065 |
PNM | Pension Liability Adjustment | ||||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||||
Beginning Balance | (96,748) | (88,822) | ||
Amounts reclassified from AOCI (pre-tax) | 4,839 | 4,128 | ||
Income tax impact of amounts reclassified | (1,878) | (1,611) | ||
Total Other Comprehensive Income (Loss) | 2,961 | 2,517 | ||
Ending Balance | $ (93,787) | $ (86,305) | $ (93,787) | $ (86,305) |
Variable Interest Entities (Det
Variable Interest Entities (Details) | Jan. 31, 2016USD ($) | Sep. 30, 2017USD ($)MW | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($)MW | Sep. 30, 2016USD ($) | Oct. 20, 2017USD ($) | Dec. 31, 2016USD ($) |
Results of Operations | |||||||
Earnings attributable to non-controlling interest | $ 4,456,000 | $ 4,006,000 | $ 11,452,000 | $ 11,037,000 | |||
Financial Position | |||||||
Current assets | 374,535,000 | 374,535,000 | $ 378,039,000 | ||||
Total assets | 6,697,254,000 | 6,403,670,000 | 6,697,254,000 | 6,403,670,000 | 6,471,080,000 | ||
Current liabilities | 710,885,000 | 710,885,000 | 805,108,000 | ||||
Owners’ equity – non-controlling interest | 67,409,000 | 67,409,000 | 68,920,000 | ||||
PNM | |||||||
Results of Operations | |||||||
Earnings attributable to non-controlling interest | 4,456,000 | 4,006,000 | 11,452,000 | 11,037,000 | |||
Financial Position | |||||||
Current assets | 331,618,000 | 331,618,000 | 314,245,000 | ||||
Total assets | 5,023,816,000 | 5,023,816,000 | 4,867,546,000 | ||||
Current liabilities | 191,066,000 | 191,066,000 | 457,361,000 | ||||
Owners’ equity – non-controlling interest | 67,409,000 | 67,409,000 | 68,920,000 | ||||
PNM | Valencia | |||||||
Variable Interest Entity [Line Items] | |||||||
Payment for fixed costs | 4,900,000 | 4,900,000 | 14,700,000 | 14,500,000 | |||
Payment for variable costs | 900,000 | 500,000 | $ 1,200,000 | 1,100,000 | |||
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% | ||||||
Results of Operations | |||||||
Operating revenues | 5,859,000 | 5,356,000 | $ 15,880,000 | 15,541,000 | |||
Operating expenses | (1,403,000) | (1,350,000) | (4,428,000) | (4,504,000) | |||
Earnings attributable to non-controlling interest | 4,456,000 | $ 4,006,000 | 11,452,000 | $ 11,037,000 | |||
Financial Position | |||||||
Current assets | 3,498,000 | 3,498,000 | 2,551,000 | ||||
Net property, plant, and equipment | 64,818,000 | 64,818,000 | 66,947,000 | ||||
Total assets | 68,316,000 | 68,316,000 | 69,498,000 | ||||
Current liabilities | 907,000 | 907,000 | 578,000 | ||||
Owners’ equity – non-controlling interest | $ 67,409,000 | $ 67,409,000 | $ 68,920,000 | ||||
PNM | Valencia | Purchased through May 2028 | |||||||
Variable Interest Entity [Line Items] | |||||||
Number of megawatts purchased (in megawatts) | MW | 158 | 158 | |||||
NM Capital | San Juan Generating Station | Coal supply | |||||||
Variable Interest Entity [Line Items] | |||||||
Loan agreement among several entities | $ 125,000,000 | ||||||
Cash used to support bank letter or credit arrangement | 30,300,000 | $ 30,300,000 | $ 30,300,000 | ||||
NM Capital | San Juan Coal Company, Westmoreland | Coal supply | |||||||
Variable Interest Entity [Line Items] | |||||||
Loan receivable | $ 125,000,000 | 66,200,000 | 66,200,000 | ||||
Interest receivable | 1,200,000 | 1,200,000 | |||||
Scheduled principal payment proceeds | 9,600,000 | 9,600,000 | |||||
Scheduled interest payment proceeds | $ 1,800,000 | $ 1,800,000 | |||||
Unaffiliated third party | San Juan Coal Company, Westmoreland | Coal supply | Subsequent event | |||||||
Variable Interest Entity [Line Items] | |||||||
Amount held in a restricted bank account | $ 11,400,000 |
Lease Commitments (Details)
Lease Commitments (Details) - PNM $ in Millions | Jan. 15, 2016USD ($)leaseMW | Sep. 30, 2017USD ($)lease | Jan. 31, 2016lease | Jan. 15, 2015lease |
Palo Verde Nuclear Generating Station, Unit 1 Leases | ||||
Operating Leased Assets [Line Items] | ||||
Number of leases, expiring | 4 | |||
Number of leases under which lease term was extended | 4 | |||
Palo Verde Nuclear Generating Station, Unit 2 Leases | ||||
Operating Leased Assets [Line Items] | ||||
Number of leases, expiring | 4 | |||
Number of leases under which lease term was extended | 1 | |||
Number of leases under which assets were purchased | 3 | 3 | 3 | |
Leased capacity to be purchased (in megawatts) | MW | 32.8 | |||
Palo Verde Nuclear Generating Station, Unit 2 Leases, 31.25 MW | ||||
Operating Leased Assets [Line Items] | ||||
Number of leases under which assets were purchased | 1 | |||
Payment to lessors | $ | $ 78.1 | |||
Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 | ||||
Operating Leased Assets [Line Items] | ||||
Leased capacity to be purchased (in megawatts) | MW | 31.3 | |||
Palo Verde Nuclear Generating Station, Unit 2 Leases, 32.76 MW | ||||
Operating Leased Assets [Line Items] | ||||
Number of leases under which assets were purchased | 2 | |||
Payment to lessors | $ | $ 85.2 | |||
Palo Verde Nuclear Generating Station | ||||
Operating Leased Assets [Line Items] | ||||
Loss contingency, lease arrangements (up to) | $ | $ 169.9 |
Fair Value of Derivative and 41
Fair Value of Derivative and Other Financial Instruments - Overview and Commodity Derivatives (Details) | Sep. 30, 2017USD ($)MW | Dec. 31, 2016USD ($) |
Derivatives, Fair Value [Line Items] | ||
Current assets | $ 3,093,000 | $ 5,224,000 |
Deferred charges | 3,846,000 | 0 |
Current liabilities | (1,279,000) | (2,339,000) |
Long-term liabilities | $ (3,846,000) | 0 |
PNM | ||
Derivatives, Fair Value [Line Items] | ||
Expected exposure to market risk (in megawatts) | MW | 65 | |
Power to be sold to third party (in megawatts) | MW | 36 | |
Current assets | $ 3,093,000 | 5,224,000 |
Deferred charges | 3,846,000 | 0 |
Current liabilities | (1,279,000) | (2,339,000) |
Long-term liabilities | (3,846,000) | 0 |
Amounts recognized for the right to reclaim cash collateral | 0 | 0 |
Amounts posted as cash collateral under margin arrangements | 1,200,000 | 2,600,000 |
PNM | Designated as Hedging Instrument | Commodity derivatives | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 3,093,000 | 5,224,000 |
Deferred charges | 3,846,000 | 0 |
Derivative Asset | 6,939,000 | 5,224,000 |
Current liabilities | (1,279,000) | (2,339,000) |
Long-term liabilities | (3,846,000) | 0 |
Derivative Liability | (5,125,000) | (2,339,000) |
Net | 1,814,000 | 2,885,000 |
PNM | Designated as Hedging Instrument | Commodity derivatives | Fuel and purchased power costs | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 100,000 | 200,000 |
Current liabilities | (200,000) | (100,000) |
PNM | Designated as Hedging Instrument | Commodity derivatives | Palo Verde Nuclear Generating Station | ||
Derivatives, Fair Value [Line Items] | ||
Current assets | 700,000 | 2,700,000 |
PNM | Designated as Hedging Instrument | Commodity derivatives | Hazard sharing arrangement | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset | 4,900,000 | 500,000 |
Derivative Liability | $ (5,200,000) | $ (500,000) |
Fair Value of Derivative and 42
Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - PNM - Designated as Hedging Instrument - Commodity derivatives - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) | $ (2,251) | $ 1,651 | $ 408 | $ (899) |
Electric operating revenues | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) | (2,237) | 1,652 | 5,697 | 214 |
Cost of energy | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain (loss) | $ (14) | $ (1) | $ (5,289) | $ (1,113) |
Fair Value of Derivative and 43
Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) - PNM | 9 Months Ended | 12 Months Ended |
Sep. 30, 2017USD ($)MMBTUMWh | Dec. 31, 2016USD ($)MMBTUMWh | |
Derivative [Line Items] | ||
Net exposure | $ | $ 0 | $ 0 |
Commodity derivatives | Fair value hedging | Buy | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MMBTU | 100,000 | 254,100 |
Commodity derivatives | Fair value hedging | Sell | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MWh | 630,933 | 2,471,600 |
Fair Value of Derivative and 44
Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details) - Palo Verde Nuclear Generating Station Unit 3 - PNM | Sep. 30, 2017$ / MWhMW |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Number of megawatts nuclear generation (in megawatts) | MW | 134 |
Commodity derivatives | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Derivative, average forward price (in dollars per MWh) | $ / MWh | 29 |
Fair Value of Derivative and 45
Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Schedule of Available-for-sale Securities [Line Items] | |||||
Available-for-sale securities for which carrying value exceeds fair value | $ 0 | $ 0 | |||
Held-to-maturity securities for which carrying value exceeds fair value | 0 | 0 | |||
Impairments considered to be other than temporary | 0 | ||||
PNM | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 306,444,000 | 306,444,000 | $ 272,977,000 | ||
Unrealized Gains | 18,631,000 | 18,631,000 | 7,449,000 | ||
(Increase)/decrease in other than temporary losses of available-for-sale securities, net portion recognized in earnings | 100,000 | $ 100,000 | 1,100,000 | $ 1,000,000 | |
Proceeds from sales | 98,532,000 | 86,975,000 | 456,577,000 | 280,989,000 | |
Gross realized gains | 8,128,000 | 7,026,000 | 24,745,000 | 27,273,000 | |
Gross realized (losses) | (2,829,000) | $ (2,565,000) | (8,150,000) | $ (12,913,000) | |
PNM | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 306,444,000 | 306,444,000 | 272,977,000 | ||
PNM | Nuclear Decommissioning Trust | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 283,000,000 | 283,000,000 | 253,900,000 | ||
PNM | Mine Reclamation Trust | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 23,400,000 | 23,400,000 | 19,100,000 | ||
PNM | Cash and cash equivalents | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 8,151,000 | 8,151,000 | 23,683,000 | ||
Unrealized Gains | 0 | 0 | 0 | ||
PNM | Cash and cash equivalents | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 8,151,000 | 8,151,000 | 23,683,000 | ||
PNM | Domestic value | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 72,162,000 | 72,162,000 | 34,796,000 | ||
Unrealized Gains | 5,252,000 | 5,252,000 | 1,135,000 | ||
PNM | Domestic value | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 72,162,000 | 72,162,000 | 34,796,000 | ||
PNM | Domestic growth | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 73,345,000 | 73,345,000 | 47,595,000 | ||
Unrealized Gains | 5,775,000 | 5,775,000 | 3,032,000 | ||
PNM | Domestic growth | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 73,345,000 | 73,345,000 | 47,595,000 | ||
PNM | International and other | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 43,167,000 | 43,167,000 | 27,481,000 | ||
Unrealized Gains | 4,865,000 | 4,865,000 | 2,029,000 | ||
PNM | International and other | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 43,167,000 | 43,167,000 | 27,481,000 | ||
PNM | U.S. Government | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 28,960,000 | 28,960,000 | 40,962,000 | ||
Unrealized Gains | 307,000 | 307,000 | 115,000 | ||
PNM | U.S. Government | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 28,960,000 | 28,960,000 | 40,962,000 | ||
PNM | Municipals | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 41,131,000 | 41,131,000 | 43,789,000 | ||
Unrealized Gains | 998,000 | 998,000 | 585,000 | ||
PNM | Municipals | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 41,131,000 | 41,131,000 | 43,789,000 | ||
PNM | Corporate and other | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | 39,528,000 | 39,528,000 | 54,671,000 | ||
Unrealized Gains | 1,434,000 | 1,434,000 | 553,000 | ||
PNM | Corporate and other | Fair Value, Measurements, Recurring | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Fair Value | $ 39,528,000 | $ 39,528,000 | $ 54,671,000 |
Fair Value of Derivative and 46
Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) $ in Thousands | Sep. 30, 2017USD ($) |
Held-to-Maturity | |
Within 1 year | $ 0 |
After 1 year through 5 years | 76,353 |
After 5 years through 10 years | 0 |
Held-to-maturity debt securities | 76,353 |
PNMR and PNM | |
Available-for-Sale | |
Within 1 year | 3,913 |
After 1 year through 5 years | 22,766 |
After 5 years through 10 years | 25,456 |
After 10 years through 15 years | 5,178 |
After 15 years through 20 years | 10,692 |
After 20 years | 41,614 |
Available-for-sale debt securities | $ 109,619 |
Fair Value of Derivative and 47
Fair Value of Derivative and Other Financial Instruments - Items Recorded and Presented by Level of Hierarchy (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | $ 2,564,887 | $ 2,540,693 |
Westmoreland Loan | 76,353 | 100,893 |
Other investments | 386 | 1,164 |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Westmoreland Loan | 0 | 0 |
Other investments | 386 | 547 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 2,564,887 | 2,540,693 |
Westmoreland Loan | 0 | 0 |
Other investments | 0 | 0 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Westmoreland Loan | 76,353 | 100,893 |
Other investments | 0 | 617 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 2,447,702 | 2,392,712 |
Westmoreland Loan | 66,230 | 95,000 |
Other investments | 386 | 547 |
PNM | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 306,444 | 272,977 |
Long-term debt | 1,736,026 | 1,730,157 |
Other investments | 166 | 316 |
PNM | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 166 | 316 |
PNM | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 1,736,026 | 1,730,157 |
Other investments | 0 | 0 |
PNM | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 0 | 0 |
PNM | Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 1,657,396 | 1,631,369 |
Other investments | 166 | 316 |
PNM | Cash and cash equivalents | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 8,151 | 23,683 |
PNM | Domestic value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 72,162 | 34,796 |
PNM | Domestic growth | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 73,345 | 47,595 |
PNM | International and other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 43,167 | 27,481 |
PNM | U.S. Government | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 28,960 | 40,962 |
PNM | Municipals | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 41,131 | 43,789 |
PNM | Corporate and other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 39,528 | 54,671 |
TNMP | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 517,977 | 468,329 |
Other investments | 220 | 231 |
TNMP | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 220 | 231 |
TNMP | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 517,977 | 468,329 |
Other investments | 0 | 0 |
TNMP | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 0 | 0 |
Other investments | 0 | 0 |
TNMP | Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt | 480,589 | 420,875 |
Other investments | 220 | 231 |
Fair Value, Measurements, Recurring | PNM | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 306,444 | 272,977 |
Fair Value, Measurements, Recurring | PNM | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 221,862 | 196,436 |
Fair Value, Measurements, Recurring | PNM | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 84,582 | 76,541 |
Fair Value, Measurements, Recurring | PNM | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 6,939 | 5,224 |
Commodity derivative liabilities | (5,125) | (2,339) |
Net | 1,814 | 2,885 |
Fair Value, Measurements, Recurring | PNM | Commodity derivatives | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 0 | 0 |
Commodity derivative liabilities | 0 | 0 |
Net | 0 | 0 |
Fair Value, Measurements, Recurring | PNM | Commodity derivatives | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivative assets | 6,939 | 5,224 |
Commodity derivative liabilities | (5,125) | (2,339) |
Net | 1,814 | 2,885 |
Fair Value, Measurements, Recurring | PNM | Cash and cash equivalents | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 8,151 | 23,683 |
Fair Value, Measurements, Recurring | PNM | Cash and cash equivalents | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 8,151 | 23,683 |
Fair Value, Measurements, Recurring | PNM | Cash and cash equivalents | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring | PNM | Domestic value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 72,162 | 34,796 |
Fair Value, Measurements, Recurring | PNM | Domestic value | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 72,162 | 34,796 |
Fair Value, Measurements, Recurring | PNM | Domestic value | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring | PNM | Domestic growth | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 73,345 | 47,595 |
Fair Value, Measurements, Recurring | PNM | Domestic growth | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 73,345 | 47,595 |
Fair Value, Measurements, Recurring | PNM | Domestic growth | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring | PNM | International and other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 43,167 | 27,481 |
Fair Value, Measurements, Recurring | PNM | International and other | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 39,931 | 27,481 |
Fair Value, Measurements, Recurring | PNM | International and other | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 3,236 | 0 |
Fair Value, Measurements, Recurring | PNM | U.S. Government | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 28,960 | 40,962 |
Fair Value, Measurements, Recurring | PNM | U.S. Government | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 28,273 | 39,723 |
Fair Value, Measurements, Recurring | PNM | U.S. Government | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 687 | 1,239 |
Fair Value, Measurements, Recurring | PNM | Municipals | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 41,131 | 43,789 |
Fair Value, Measurements, Recurring | PNM | Municipals | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 0 |
Fair Value, Measurements, Recurring | PNM | Municipals | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 41,131 | 43,789 |
Fair Value, Measurements, Recurring | PNM | Corporate and other | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 39,528 | 54,671 |
Fair Value, Measurements, Recurring | PNM | Corporate and other | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | 0 | 23,158 |
Fair Value, Measurements, Recurring | PNM | Corporate and other | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investments | $ 39,528 | $ 31,513 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) | Mar. 03, 2017 | Sep. 30, 2017 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | Feb. 28, 2017 | Dec. 31, 2015 | Mar. 31, 2015 | Jan. 01, 2015 | Mar. 31, 2012 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Number of shares granted (in shares) | 0 | |||||||||
Vesting period | 1 year | |||||||||
Unrecognized expense related to stock awards | $ 4,800,000 | $ 4,800,000 | $ 4,500,000 | |||||||
Excess tax benefits | $ 200,000 | $ 2,300,000 | ||||||||
Cumulative effect adjustment | $ 10,382,000 | |||||||||
Restricted Stock, Shares | ||||||||||
Expired (in shares) | (3,000) | |||||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | ||||||||||
Expired (in dollars per share) | $ 30.50 | |||||||||
Stock Options, Shares | ||||||||||
Outstanding at beginning of period (in shares) | 305,874 | |||||||||
Granted (in shares) | 0 | |||||||||
Exercised (in shares) | (109,433) | |||||||||
Forfeited (in shares) | 0 | |||||||||
Expired (in shares) | (3,000) | |||||||||
Outstanding at end of period (in shares) | 193,441 | 193,441 | 305,874 | |||||||
Stock Options, Weighted- Average Exercise Price | ||||||||||
Outstanding at beginning of period (in dollars per share) | $ 12.29 | |||||||||
Granted (in dollars per share) | 0 | |||||||||
Exercised (in dollars per share) | 15.89 | |||||||||
Forfeited (in dollars per share) | 0 | |||||||||
Expired (in dollars per share) | 30.50 | |||||||||
Outstanding at end of period (in dollars per share) | $ 9.98 | 9.98 | $ 12.29 | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | ||||||||||
Weighted-average grant date fair value of options granted (in dollars per share) | $ 0 | $ 0 | ||||||||
Total fair value of options that vested | $ 0 | $ 0 | ||||||||
Total intrinsic value of options exercised | 2,234,000 | $ 1,208,000 | ||||||||
Chairman, President, and Chief Executive Officer | Common stock | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 135,000 | |||||||||
Chairman, President, and Chief Executive Officer | Common stock | Achieves specified improvement in total shareholder return at end of 2014 compared to 2011 and she remains employee | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 35,000 | |||||||||
Chairman, President, and Chief Executive Officer | Common stock | Achieves specified improvement In total shareholder return at end of 2015 compared to 2011 and she remains employee | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 100,000 | |||||||||
Chairman, President, and Chief Executive Officer | Common stock | Achieves a specific performance target by the end of 2019 and she remains an employee | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 53,859 | |||||||||
Chairman, President, and Chief Executive Officer | Common stock | Achieves a specific performance target by the end of 2017 and she remains an employee | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares received if achieves specified improvement in total shareholders return (in shares) | 17,953 | |||||||||
Executive Vice President and Chief Financial Officer | Common stock | Achieved performance target for 2015 and 2016 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Share-based compensation arrangement by share-based payment award, purchase price of common stock | $ 100,000 | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 100,000 | |||||||||
Restricted Stock, Shares | ||||||||||
Granted (in shares) | 2,754 | |||||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | ||||||||||
Granted (in dollars per share) | $ 36.30 | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | ||||||||||
Weighted-average grant date fair value (in dollars per share) | $ 36.30 | |||||||||
Executive Vice President and Chief Financial Officer | Common stock | Achieved performance target for 2015, 2016 and 2017 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Share-based compensation arrangement by share-based payment award, purchase price of common stock | $ 275,000 | |||||||||
Retained Earnings | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Cumulative effect adjustment | $ 10,382,000 | |||||||||
Accounting Standards Update 2016-09 | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Accumulated deferred income taxes | (10,400,000) | |||||||||
Accounting Standards Update 2016-09 | Retained Earnings | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Cumulative effect adjustment | $ 10,400,000 | |||||||||
PNM | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Excess tax benefits | $ 100,000 | 1,700,000 | ||||||||
TNMP | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Excess tax benefits | $ 100,000 | $ 600,000 | ||||||||
Restricted Shares and Performance Based Shares | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Period of time stock expense is expected to be recognized | 2 years | 1 year 9 months 26 days | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | ||||||||||
Expected quarterly dividends per share (in dollars per share) | $ 0.2425 | $ 0.2200 | ||||||||
Risk-free interest rate | 1.50% | 0.94% | ||||||||
Restricted Stock | ||||||||||
Restricted Stock, Shares | ||||||||||
Outstanding at beginning of period (in shares) | 218,316 | |||||||||
Granted (in shares) | 248,271 | |||||||||
Exercised (in shares) | (270,855) | |||||||||
Forfeited (in shares) | (4,012) | |||||||||
Expired (in shares) | 0 | |||||||||
Outstanding at end of period (in shares) | 191,720 | 191,720 | 218,316 | |||||||
Restricted Stock, Weighted- Average Grant Date Fair Value | ||||||||||
Outstanding at beginning of period (in dollars per share) | $ 27.59 | |||||||||
Granted (in dollars per share) | 23.06 | $ 26.49 | ||||||||
Exercised (in dollars per share) | 20.92 | |||||||||
Forfeited (in dollars per share) | 29.96 | |||||||||
Expired (in dollars per share) | 0 | |||||||||
Outstanding at end of period (in dollars per share) | $ 31.10 | $ 31.10 | $ 27.59 | |||||||
Stock Options, Shares | ||||||||||
Expired (in shares) | 0 | |||||||||
Stock Options, Weighted- Average Exercise Price | ||||||||||
Expired (in dollars per share) | $ 0 | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | ||||||||||
Weighted-average grant date fair value (in dollars per share) | $ 23.06 | $ 26.49 | ||||||||
Total fair value of restricted shares that vested | $ 5,666,000 | $ 5,011,000 | ||||||||
Performance Shares | Executive | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Shares granted (in shares) | 49,682 | 49,682 | ||||||||
Shares exercised (in shares) | 49,682 | 49,682 | ||||||||
Weighted percentage assigned to achieving market targets | 60.00% | 60.00% | ||||||||
Weighted percentage assigned to achieving performance targets | 40.00% | 40.00% | ||||||||
Maximum number of shares awarded in year 1 (in shares) | 163,712 | 163,712 | ||||||||
Maximum number of shares awarded in year 2 (in shares) | 137,036 | 137,036 | ||||||||
Maximum number of shares awarded in year 3 (in shares) | 133,632 | 133,632 | ||||||||
Performance period | 3 years | |||||||||
Market-Based Shares | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | ||||||||||
Risk-free interest rate | 1.54% | 0.97% | ||||||||
Dividend yield | 2.67% | 2.74% | ||||||||
Expected volatility | 20.80% | 20.44% | ||||||||
Stock options | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Aggregate intrinsic value of stock options outstanding | $ 5,900,000 | $ 5,900,000 | ||||||||
Weighted-average remaining contract life | 1 year 9 months 18 days | |||||||||
Number of outstanding stock options with an exercise price greater than the closing price (in shares) | 0 | 0 | ||||||||
Performance Equity Plan | ||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||
Vesting period | 3 years | |||||||||
Vesting rate | 100.00% |
Financing - Financing Activitie
Financing - Financing Activities (Details) | Jul. 28, 2017USD ($) | Jul. 20, 2017USD ($) | Feb. 01, 2016USD ($) | Sep. 30, 2017USD ($)derivative | Sep. 30, 2017USD ($)Extensionderivative | Dec. 31, 2016USD ($) | Jun. 14, 2017USD ($) | Oct. 21, 2016USD ($) | Sep. 30, 2015 | Mar. 09, 2015USD ($) |
Debt Instrument [Line Items] | ||||||||||
Estimated principal payments | $ 265,700,000 | $ 265,700,000 | ||||||||
Fixed interest rate | 1.927% | |||||||||
Interest rate contract | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Number of hedging agreements (in derivatives) | derivative | 3 | 3 | ||||||||
PNMR 2016 One-Year Term Loan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term of loan | 1 year | |||||||||
Weighted-average interest rate for short-term debt | 2.09% | 2.09% | ||||||||
PNMR 2015 Term Loan Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate at period end | 2.14% | 2.14% | ||||||||
PNMR 2016 Two-Year Term Loan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term loans | $ 100,000,000 | $ 100,000,000 | ||||||||
Variable interest rate | 2.19% | 2.19% | ||||||||
Term of loan | 2 years | |||||||||
Variable rate short-term debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 50,000,000 | $ 50,000,000 | ||||||||
Term of hedging agreement | 4 years | |||||||||
Variable rate short-term debt | Interest rate contract, 1 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fixed interest rate | 1.926% | 1.926% | ||||||||
Variable rate short-term debt | Interest rate contract, 2 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fixed interest rate | 1.823% | 1.823% | ||||||||
Variable rate short-term debt | Interest rate contract, 3 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fixed interest rate | 1.629% | 1.629% | ||||||||
Cash flow hedge | Level 2 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fair value gain (loss) (less than) | $ 300,000 | $ (100,000) | ||||||||
Cash flow hedge | Level 2 | Interest rate contract, 3 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fair value gain (loss) (less than) | 100,000 | |||||||||
Cash flow hedge | Level 2 | Interest rate contracts, 1 and 2 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fair value gain (loss) (less than) | $ (500,000) | |||||||||
PNM | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity term over which financings require regulator approval (more than) | 18 months | |||||||||
NM Capital | Coal supply | San Juan Coal Company, Westmoreland | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Payments to fund long-term loans to unaffiliated third party | $ 125,000,000 | |||||||||
Line of credit | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Ratio of debt to capital (less than or equal to) | 65.00% | |||||||||
PNMR 2015 Term Loan Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term loans | $ 150,000,000 | |||||||||
PNM 2016 Term Loan Agreement | PNM | JPMorgan Chase Bank, N.A. and U.S. Bank National Association | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | 175,000,000 | |||||||||
BTMU Term Loan Agreement | NM Capital | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Term loans | $ 125,000,000 | $ 60,900,000 | $ 60,900,000 | |||||||
Estimated principal payments | $ 15,700,000 | $ 15,700,000 | ||||||||
Letter of credit | PNMR | JPM LOC Facility | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 30,300,000 | |||||||||
First mortgage bonds | TNMP | Interest Rate of 3.22%, Due 2027 | Plan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.22% | |||||||||
Aggregate principal amount | $ 60,000,000 | |||||||||
Pollution Control Revenue Bonds | PNM | Pollution Control Revenue Bonds due June 1, 2040 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 2.125% | 2.125% | ||||||||
Outstanding balance | $ 37,000,000 | $ 37,000,000 | 37,000,000 | |||||||
Pollution Control Revenue Bonds | PNM | Pollution Control Revenue Bonds due June 1, 2042 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 2.45% | 2.45% | ||||||||
Outstanding balance | $ 20,000,000 | $ 20,000,000 | $ 20,000,000 | |||||||
Term loan agreement with banks | PNM | PNM 2017 Term Loan Agreement | JPMorgan Chase Bank, N.A. and U.S. Bank National Association | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Covenant that requires the maintenance of a debt-to-capital ratio (less than or equal to) | 65.00% | |||||||||
Aggregate principal amount | $ 200,000,000 | |||||||||
Senior Unsecured Notes | PNM | Senior Unsecured Note Agreement (SUNs) | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Covenant that requires the maintenance of a debt-to-capital ratio (less than or equal to) | 65.00% | |||||||||
Aggregate principal amount | $ 450,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018 | Plan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | 350,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018 | Plan | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Aggregate principal amount | $ 100,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.15% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.15% | |||||||||
Aggregate principal amount | $ 55,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.45% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.45% | |||||||||
Aggregate principal amount | $ 104,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.68% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.68% | |||||||||
Aggregate principal amount | $ 88,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 3.93% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.93% | |||||||||
Aggregate principal amount | $ 38,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 4.22% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.22% | |||||||||
Aggregate principal amount | $ 45,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in May 2018, Interest rate of 4.50% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.50% | |||||||||
Aggregate principal amount | $ 20,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018, Interest rate of 3.78% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.78% | |||||||||
Aggregate principal amount | $ 15,000,000 | |||||||||
Senior Unsecured Notes | PNM | SUNs, Issuance in August 2018, Interest rate of 4.60% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.60% | |||||||||
Aggregate principal amount | $ 85,000,000 | |||||||||
Unsecured debt | PNM | Senior Unsecured Notes, Maturity in May 2018, 7.95% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 7.95% | 7.95% | ||||||||
Amount of senior unsecured notes to be repaid with SUN proceeds | $ 350,000,000 | |||||||||
Senior Unsecured Notes | $ 450,000,000 | $ 450,000,000 | ||||||||
Unsecured debt | PNM | Senior Unsecured Notes, Maturity in August 2018, 7.50% | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 7.50% | 7.50% | ||||||||
Senior Unsecured Notes | $ 100,000,000 | $ 100,000,000 | ||||||||
PNM 2017 Term Loan Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Interest rate at period end | 1.97% | 1.97% | ||||||||
PNMR Revolving Credit Facility | PNMR | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Weighted-average interest rate for short-term debt | 2.49% | 2.49% | ||||||||
LIBOR | BTMU Term Loan Agreement | NM Capital | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.06% | 4.06% | ||||||||
Revolving credit facility | TNMP | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Number of extension options | Extension | 2 | |||||||||
Extension option on term | 1 year |
Financing - Short-term Debt and
Financing - Short-term Debt and Liquidity (Details) | 9 Months Ended | |||||
Sep. 30, 2017USD ($)Extension | Nov. 01, 2020USD ($) | Oct. 20, 2017USD ($) | Jul. 28, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 30, 2016USD ($) | |
Short-term Debt [Line Items] | ||||||
Short-term debt | $ 266,500,000 | $ 287,100,000 | ||||
Letters of credit outstanding | 6,400,000 | |||||
Maturities and other repayments due in next 12 months | 265,700,000 | |||||
Maturities and other repayments due in the remainder of year two | $ 102,300,000 | |||||
Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Remaining borrowing capacity | $ 635,000,000 | |||||
PNMR | Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Remaining borrowing capacity | 118,500,000 | |||||
Short-term debt – affiliate | 0 | |||||
Consolidated invested cash | 1,500,000 | |||||
PNMR 2016 One-Year Term Loan | ||||||
Short-term Debt [Line Items] | ||||||
Weighted-average interest rate for short-term debt | 2.09% | |||||
Term of loan | 1 year | |||||
Short-term debt | $ 100,000,000 | 100,000,000 | ||||
PNMR Revolving Credit Facility | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | $ 10,000,000 | |||||
PNMR Revolving Credit Facility | PNMR | ||||||
Short-term Debt [Line Items] | ||||||
Weighted-average interest rate for short-term debt | 2.49% | |||||
PNMR Revolving Credit Facility | Forecast | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | $ 290,000,000 | |||||
PNM | ||||||
Short-term Debt [Line Items] | ||||||
Short-term debt | $ 0 | 61,000,000 | ||||
Letters of credit outstanding | 2,500,000 | |||||
PNM | Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Remaining borrowing capacity | 397,500,000 | |||||
Consolidated invested cash | 50,500,000 | |||||
PNM | Lines of credit | ||||||
Short-term Debt [Line Items] | ||||||
NMPRC approved credit facility | 50,000,000 | |||||
Short-term debt | 0 | 26,000,000 | ||||
Maturities and other repayments due | 50,000,000 | |||||
PNM | Lines of credit | Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Remaining borrowing capacity | 50,000,000 | |||||
PNM | Senior Unsecured Note Agreement (SUNs) | Senior Unsecured Notes | ||||||
Short-term Debt [Line Items] | ||||||
Debt issued | $ 450,000,000 | |||||
PNM | PNM Revolving Credit Facility | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | $ 40,000,000 | |||||
PNM | PNM Revolving Credit Facility | Forecast | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | $ 360,000,000 | |||||
TNMP | ||||||
Short-term Debt [Line Items] | ||||||
Letters of credit outstanding | 100,000 | |||||
Intercompany borrowings | 0 | |||||
Short-term debt – affiliate | 0 | 4,600,000 | ||||
Maturities and other repayments due in 2018 | 0 | |||||
TNMP | Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Remaining borrowing capacity | 69,000,000 | |||||
Consolidated invested cash | 0 | |||||
Revolving credit facility | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | 300,000,000 | |||||
Short-term debt | 166,500,000 | 126,100,000 | ||||
Revolving credit facility | PNM | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | 400,000,000 | |||||
Short-term debt | 0 | 35,000,000 | ||||
Revolving credit facility | TNMP | ||||||
Short-term Debt [Line Items] | ||||||
Financing capacity | $ 75,000,000 | |||||
Number of extension options | Extension | 2 | |||||
Extension option on term | 1 year | |||||
Short-term debt | $ 0 | $ 0 | ||||
Revolving credit facility | TNMP | First mortgage bonds | ||||||
Short-term Debt [Line Items] | ||||||
Collateral amount | $ 75,000,000 | |||||
Affiliated entity | TNMP | Subsequent event | ||||||
Short-term Debt [Line Items] | ||||||
Short-term debt – affiliate | $ 0 |
Pension and Other Postretirem51
Pension and Other Postretirement Benefit Plans (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
PNM | Pension Plan | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | $ 0 | $ 0 | $ 0 | $ 0 |
Interest cost | 6,727,000 | 7,577,000 | 20,181,000 | 22,731,000 |
Expected return on plan assets | (8,451,000) | (8,854,000) | (25,352,000) | (26,562,000) |
Amortization of net (gain) loss | 4,001,000 | 3,455,000 | 12,004,000 | 10,365,000 |
Amortization of prior service cost | (241,000) | (241,000) | (724,000) | (724,000) |
Net Periodic Benefit Cost | 2,036,000 | 1,937,000 | 6,109,000 | 5,810,000 |
Contributions by employer | 0 | 0 | 0 | 0 |
Total expected employer contributions for future fiscal years | 0 | $ 0 | ||
PNM | Pension Plan | Minimum | ||||
Components of Net Periodic Benefit Cost | ||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.10% | |||
PNM | Pension Plan | Maximum | ||||
Components of Net Periodic Benefit Cost | ||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.90% | |||
PNM | OPEB Plan | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 24,000 | 35,000 | $ 72,000 | 105,000 |
Interest cost | 1,006,000 | 1,087,000 | 3,019,000 | 3,260,000 |
Expected return on plan assets | (1,308,000) | (1,371,000) | (3,923,000) | (4,113,000) |
Amortization of net (gain) loss | 921,000 | 286,000 | 2,762,000 | 858,000 |
Amortization of prior service cost | (416,000) | (7,000) | (1,248,000) | (22,000) |
Net Periodic Benefit Cost | 227,000 | 30,000 | 682,000 | 88,000 |
Contributions by employer | 0 | 800,000 | 0 | 2,400,000 |
Total expected employer contributions for future fiscal years | 0 | 0 | ||
PNM | Executive Retirement Program | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 174,000 | 203,000 | 523,000 | 609,000 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 78,000 | 64,000 | 235,000 | 192,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | 252,000 | 267,000 | 758,000 | 801,000 |
Contributions by employer | 400,000 | 400,000 | 1,200,000 | 1,200,000 |
Total expected employer contributions for future fiscal years | 5,800,000 | 5,800,000 | ||
Total expected employer contributions for fiscal year | 1,500,000 | 1,500,000 | ||
Texas-New Mexico Power Company | Pension Plan | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 722,000 | 826,000 | 2,165,000 | 2,478,000 |
Expected return on plan assets | (945,000) | (986,000) | (2,834,000) | (2,957,000) |
Amortization of net (gain) loss | 231,000 | 175,000 | 692,000 | 525,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | 8,000 | 15,000 | 23,000 | 46,000 |
Contributions by employer | 0 | 0 | 0 | 0 |
Total expected employer contributions for future fiscal years | 0 | $ 0 | ||
Texas-New Mexico Power Company | Pension Plan | Minimum | ||||
Components of Net Periodic Benefit Cost | ||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.10% | |||
Texas-New Mexico Power Company | Pension Plan | Maximum | ||||
Components of Net Periodic Benefit Cost | ||||
Assumptions used calculating net periodic benefit cost, discount rate | 4.90% | |||
Texas-New Mexico Power Company | OPEB Plan | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 36,000 | 46,000 | $ 107,000 | 139,000 |
Interest cost | 139,000 | 169,000 | 417,000 | 508,000 |
Expected return on plan assets | (114,000) | (122,000) | (342,000) | (367,000) |
Amortization of net (gain) loss | (20,000) | (10,000) | (60,000) | (30,000) |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | 41,000 | 83,000 | 122,000 | 250,000 |
Contributions by employer | 0 | 0 | 700,000 | 0 |
Total expected employer contributions for future fiscal years | 1,400,000 | 1,400,000 | ||
Total expected employer contributions for fiscal year | 0 | 0 | ||
Texas-New Mexico Power Company | Executive Retirement Program | ||||
Components of Net Periodic Benefit Cost | ||||
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 8,000 | 10,000 | 25,000 | 30,000 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 2,000 | 1,000 | 7,000 | 1,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | 10,000 | 11,000 | 32,000 | 31,000 |
Total expected employer contributions for future fiscal years | 400,000 | 400,000 | ||
Total expected employer contributions for fiscal year | 100,000 | 100,000 | ||
Texas-New Mexico Power Company | Executive Retirement Program | Maximum | ||||
Components of Net Periodic Benefit Cost | ||||
Contributions by employer | $ 100,000 | $ 100,000 | $ 100,000 | $ 100,000 |
Commitments and Contingencies -
Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) | May 16, 2014 | Sep. 30, 2017 | Dec. 31, 2016 |
Public Utilities, Commitments And Contingencies [Line Items] | |||
Estimate of possible loss | $ 57,700,000 | ||
Revised annual fee, nuclear waste disposal | $ 0 | ||
Other deferred credits | |||
Public Utilities, Commitments And Contingencies [Line Items] | |||
Loss contingency accrual | $ 12,100,000 | $ 12,100,000 |
Commitments and Contingencies53
Commitments and Contingencies - The Clean Air Act (Details) | Feb. 25, 2016 | Dec. 31, 2015USD ($) | Dec. 16, 2015USD ($)MWhMW | Jul. 31, 2015USD ($)MW | Mar. 02, 2015lb / MMBTUT | Dec. 31, 2015USD ($) | Sep. 30, 2017USD ($)lbsofnox / mmbtujoint_ownerrequirementMW | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Sep. 30, 2017USD ($)lbsofnox / mmbtujoint_ownerrequirementMW | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Jan. 26, 2016state | Oct. 01, 2015parts_per_billion | Sep. 30, 2015parts_per_billion | May 14, 2015lb / MMBTU | Dec. 30, 2013 | Apr. 30, 2013well | Feb. 28, 2013lawsuitstatemine | Aug. 06, 2012compliance_alternative | Jan. 31, 2010parts_per_billion | Jul. 31, 2005T | Dec. 31, 1999state |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ 0 | $ 16,451,000 | $ 0 | $ 17,225,000 | ||||||||||||||||||||
Plant in service, held for future use, and to be abandoned | 7,133,646,000 | $ 6,944,534,000 | 7,133,646,000 | $ 6,944,534,000 | ||||||||||||||||||||
Accumulated depreciation and amortization | $ 2,431,695,000 | 2,334,938,000 | $ 2,431,695,000 | 2,334,938,000 | ||||||||||||||||||||
Clean Air Act related to regional haze | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of states to address regional haze (in states) | state | 50 | |||||||||||||||||||||||
Potential to emit tons per year of visibility impairing pollution (in tons, more than) | T | 250 | |||||||||||||||||||||||
Clean Power Plan | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Period of potential extension to meet environmental targets | 2 years | |||||||||||||||||||||||
Number of states that filed a petition against the Clean Power Plan | state | 29 | |||||||||||||||||||||||
San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of other joint owners | joint_owner | 8 | 8 | ||||||||||||||||||||||
PNM | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ 0 | 16,451,000 | $ 0 | $ 17,225,000 | ||||||||||||||||||||
Plant in service, held for future use, and to be abandoned | 5,463,764,000 | 5,359,211,000 | 5,463,764,000 | 5,359,211,000 | ||||||||||||||||||||
Accumulated depreciation and amortization | $ 1,881,371,000 | 1,809,528,000 | $ 1,881,371,000 | 1,809,528,000 | ||||||||||||||||||||
Power to be sold to third party (in megawatts) | MW | 36 | 36 | ||||||||||||||||||||||
PNM | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Estimated costs to remain unrecovered | $ 20,000,000 | |||||||||||||||||||||||
PNM | Increase in coal mine decommissioning liability | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Expense reflected in regulatory disallowances and restructuring costs | 4,800,000 | 4,500,000 | ||||||||||||||||||||||
PNM | National Ambient Air Quality Standards, 2015 EPA Legal Settlement | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Period of time to act on settlement | 16 months | |||||||||||||||||||||||
Emissions tons of SO2 per year (more than) | T | 16,000 | |||||||||||||||||||||||
PNM | National Ambient Air Quality Standards, 2015 EPA Legal Settlement | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Period of time from state designation, to provide implementation plans | 36 months | |||||||||||||||||||||||
PNM | WEG v OSM lawsuit | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of mines impacted | mine | 7 | |||||||||||||||||||||||
Number of states impacted | state | 4 | |||||||||||||||||||||||
Number of claims for relief, filed (in lawsuits) | lawsuit | 15 | |||||||||||||||||||||||
PNM | Santa Fe generating station | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of wells with elevated levels of nitrates | well | 3 | |||||||||||||||||||||||
PNM | San Juan Generating Station Units 2 and 3 | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Plant in service, held for future use, and to be abandoned | $ 471,800,000 | $ 471,800,000 | ||||||||||||||||||||||
Accumulated depreciation and amortization | 211,600,000 | 211,600,000 | ||||||||||||||||||||||
Net book value | $ 260,200,000 | $ 260,200,000 | ||||||||||||||||||||||
PNM | San Juan Generating Station Units 2 and 3 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Current ownership interest (in megawatts) | MW | 418 | |||||||||||||||||||||||
Time period to recover retired units' remaining net book value | 20 years | |||||||||||||||||||||||
Recovery percentage of estimated undepreciated value at 12/31/17 | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | |||||||||||||||||||
Regulatory disallowances and restructuring costs | $ 127,600,000 | |||||||||||||||||||||||
Expense reflected in regulatory disallowances and restructuring costs | $ (2,300,000) | $ 5,200,000 | $ 800,000 | $ 3,700,000 | ||||||||||||||||||||
Accumulated plant write-off, disallowance | $ 128,600,000 | $ 128,600,000 | ||||||||||||||||||||||
Net carrying value of utility plant | $ 131,600,000 | $ 131,600,000 | ||||||||||||||||||||||
PNM | San Juan Generating Station | WEG v OSM lawsuit | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of claims for relief, filed (in lawsuits) | lawsuit | 2 | |||||||||||||||||||||||
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Additional ownership to be obtained (in megawatts) | MW | 65 | 132 | ||||||||||||||||||||||
Estimated rate base value | $ 0 | |||||||||||||||||||||||
Coal-fired generation (in megawatts) | MW | 197 | |||||||||||||||||||||||
Number of megawatt hours of Renewable Energy Certificates to be acquired and retired (in megawatt hours) | MWh | 1 | |||||||||||||||||||||||
Percentage of ownership held by exiting owners | 38.80% | 38.80% | ||||||||||||||||||||||
Ownership percentage | 38.50% | 38.50% | ||||||||||||||||||||||
PNM | San Juan Generating Station Unit 4 | Clean Air Act, Post-2022 coal supply future rate case | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Period of time agreed to by all parties to settle rate case | 6 months | |||||||||||||||||||||||
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR Hearing Examiner, Recommended Denial | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Additional ownership to be obtained (in megawatts) | MW | 132 | |||||||||||||||||||||||
PNM | San Juan Generating Station Unit 3 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Percentage of ownership held by exiting owners | 50.00% | 50.00% | ||||||||||||||||||||||
Ownership percentage | 50.00% | 50.00% | ||||||||||||||||||||||
PNM | Palo Verde Nuclear Generating Station Unit 3 | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of megawatts nuclear generation (in megawatts) | MW | 134 | 134 | ||||||||||||||||||||||
PNM | Palo Verde Nuclear Generating Station Unit 3 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of megawatts nuclear generation (in megawatts) | MW | 134 | |||||||||||||||||||||||
Estimated undepreciated value at 12/31/17 | $ 155,000,000 | |||||||||||||||||||||||
PNM | Four Corners | Clean Air Act related to post combustion controls | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Number of compliance alternatives | compliance_alternative | 2 | |||||||||||||||||||||||
Plant requirement to meet NOx emissions limit (in pounds of NOx per MMBTU) | lbsofnox / mmbtu | 0.015 | 0.015 | ||||||||||||||||||||||
Plant requirement to meet opacity limit | 20.00% | 20.00% | ||||||||||||||||||||||
Rule imposes opacity limitation on certain fugitive dust emissions from coal and material handling operations | 20.00% | 20.00% | ||||||||||||||||||||||
Estimate of possible loss | $ 89,200,000 | $ 89,200,000 | ||||||||||||||||||||||
PNM | Four Corners Units 4 and 5 (Coal) | Clean Air Act related to post combustion controls | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Ownership percentage | 13.00% | 13.00% | ||||||||||||||||||||||
PNM | Four Corners Units 1, 2 and 3 (Coal) | Clean Air Act related to post combustion controls | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Ownership percentage | 0.00% | |||||||||||||||||||||||
PNM | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | San Juan Generating Station Units 1 and 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Installation costs | $ 77,700,000 | |||||||||||||||||||||||
PNMR Development | San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Additional ownership to be obtained (in megawatts) | MW | 65 | |||||||||||||||||||||||
Expense reflected in regulatory disallowances and restructuring costs | $ 600,000 | |||||||||||||||||||||||
Potential acquisition of ownership (in megawatts) | MW | 65 | |||||||||||||||||||||||
Maximum | PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Annual cost of Renewable Energy Credits | $ 7,000,000 | |||||||||||||||||||||||
Maximum | PNM | San Juan Generating Station and Four Corners | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Proposed government standard emission limit (in ozone parts per million) | parts_per_billion | 70 | |||||||||||||||||||||||
Government standard emission limit (in ozone parts per million) | parts_per_billion | 70 | 75 | ||||||||||||||||||||||
Minimum | PNM | National Ambient Air Quality Standards, 2015 EPA Legal Settlement | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Emissions tons of SO2 per year (more than) | T | 2,600 | |||||||||||||||||||||||
One-hour SO2 emissions rate (in pounds per MMBTU) | lb / MMBTU | 0.45 | |||||||||||||||||||||||
Minimum | PNM | San Juan Generating Station and Four Corners | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Proposed government standard emission limit (in ozone parts per million) | parts_per_billion | 60 | |||||||||||||||||||||||
Increase in coal mine decommissioning liability | PNM | San Juan Generating Station Units 2 and 3 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | 165,700,000 | |||||||||||||||||||||||
Surface | Loss on long-term purchase commitment | PNM | San Juan Generating Station | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Regulatory disallowances and restructuring costs | $ 16,500,000 | |||||||||||||||||||||||
Estimate of possible loss | $ 100,900,000 | $ 100,900,000 | ||||||||||||||||||||||
Energy equipment | PNMR Development | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Costs of installing equipment | $ 7,600,000 | |||||||||||||||||||||||
Plan | PNM | San Juan Generating Station Units 1 and 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Ownership percentage | 66.30% | |||||||||||||||||||||||
Plan | PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Ownership percentage | 77.30% | |||||||||||||||||||||||
San Juan Generating Station | PNM | National Ambient Air Quality Standards | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Revised SO2 emissions (in pounds per MMBTU) | lb / MMBTU | 0.10 | |||||||||||||||||||||||
Reeves Station | PNM | ||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||
Requirements to be implemented | requirement | 0 | 0 |
Commitments and Contingencies54
Commitments and Contingencies - Coal Supply (Details) | Feb. 01, 2016USD ($) | Jan. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Oct. 20, 2017USD ($) | Jun. 30, 2017 | Feb. 01, 2017 | Aug. 01, 2016payment |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Other current assets | $ 56,421,000 | $ 56,421,000 | $ 73,444,000 | |||||||||
Regulatory disallowances and restructuring costs | 0 | $ 16,451,000 | 0 | $ 17,225,000 | ||||||||
PNM | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Other current assets | 48,883,000 | 48,883,000 | 67,355,000 | |||||||||
Regulatory disallowances and restructuring costs | 0 | 16,451,000 | 0 | $ 17,225,000 | ||||||||
PNM | Surface | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Regulatory assets | 100,000,000 | 100,000,000 | ||||||||||
PNM | Loss on long-term purchase commitment | Surface | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Loss contingency accrual | 41,400,000 | 41,400,000 | 41,000,000 | |||||||||
Final reclamation, capped amount to be collected | 100,000,000 | |||||||||||
PNM | Loss on long-term purchase commitment | Underground | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Loss contingency accrual | 14,700,000 | 14,700,000 | 14,000,000 | |||||||||
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Surface | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Regulatory disallowances and restructuring costs | $ 16,500,000 | |||||||||||
Estimate of possible loss | 100,900,000 | 100,900,000 | ||||||||||
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Underground | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Estimate of possible loss | 127,400,000 | 127,400,000 | ||||||||||
Coal supply | PNM | San Juan Generating Station | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Other current assets | 31,900,000 | 31,900,000 | 48,700,000 | |||||||||
Estimated increase in coal cost | 51.00% | |||||||||||
Coal supply | NM Capital | San Juan Generating Station | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Payments to fund long-term loans to unaffiliated third party | $ 125,000,000 | |||||||||||
Loan agreement among several entities | $ 125,000,000 | |||||||||||
Interest rate | 7.25% | 9.25% | ||||||||||
Requirement to post reclamation bonds | 118,700,000 | 118,700,000 | ||||||||||
Cash used to support bank letter or credit arrangement | $ 30,300,000 | 30,300,000 | 30,300,000 | |||||||||
Coal supply | NM Capital | San Juan Coal Company, Westmoreland | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Payments to fund long-term loans to unaffiliated third party | $ 125,000,000 | |||||||||||
Loan receivable | $ 125,000,000 | 66,200,000 | 66,200,000 | |||||||||
Scheduled principal payment proceeds | 9,600,000 | 9,600,000 | ||||||||||
Scheduled interest payment proceeds | 1,800,000 | 1,800,000 | ||||||||||
Prepayment penalty | 0 | 0 | ||||||||||
BTMU Term Loan Agreement | NM Capital | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Long-term Debt | $ 125,000,000 | 60,900,000 | 60,900,000 | |||||||||
Subsequent event | Coal supply | Unaffiliated third party | San Juan Coal Company, Westmoreland | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Amount held in a restricted bank account | $ 11,400,000 | |||||||||||
Increase in coal mine decommissioning liability | PNM | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Expense reflected in regulatory disallowances and restructuring costs | $ 4,800,000 | $ 4,500,000 | ||||||||||
Mine Reclamation Trust | PNM | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Required contribution to Reclamation Trust, current fiscal year | 5,800,000 | 5,800,000 | ||||||||||
Reclamation Trust Funding, Year 2 | 8,300,000 | 8,300,000 | ||||||||||
Reclamation Trust Funding, Year 3 | 8,700,000 | 8,700,000 | ||||||||||
Four Corners | Mine Reclamation Trust | PNM | ||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||
Required contribution to Reclamation Trust, current fiscal year | 2,300,000 | 2,300,000 | ||||||||||
Reclamation Trust Funding, Year 2 | 2,100,000 | 2,100,000 | ||||||||||
Reclamation Trust Funding, Year 3 | $ 2,100,000 | $ 2,100,000 | ||||||||||
Number of annual installment payments | payment | 13 |
Commitments and Contingencies55
Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details) | Oct. 23, 2017Allotment_Parcel | Mar. 28, 2017 | Apr. 30, 2010city | Sep. 30, 2017USD ($) | Sep. 30, 2017USD ($)generating_unit | Dec. 01, 2015Allotment_Parcel | Jul. 13, 2015a | Jan. 22, 2015Allotment_Parcel | Apr. 02, 2014landownerAllotment_Parcel | Feb. 27, 2014lawsuit | Jan. 06, 2014Allotment_Parcel | Aug. 31, 2013 | Sep. 30, 2012landowner |
Continuous highwall mining | San Juan Generating Station | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Proposed retroactive surface mining royalty rate | 12.50% | ||||||||||||
Surface mining royalty rate applied | 8.00% | 8.00% | |||||||||||
Estimated underpaid surface mining royalties under proposed rate change | $ 5,000,000 | $ 5,000,000 | |||||||||||
PNM's share estimated underpaid surface mining royalties under proposed rate change | 46.30% | 46.30% | |||||||||||
PNM | Navajo Nation Allottee Matters | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Number of landowners claiming to be Navajo allottees (in landowners) | landowner | 43 | 43 | |||||||||||
Number of allotment parcels' appraisal requested for review (in allotment parcels) | Allotment_Parcel | 58 | ||||||||||||
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel | 10 | 6 | |||||||||||
Area of land (in acres) | a | 15.49 | ||||||||||||
Number of allotment parcels at issue that are not to be condemned | Allotment_Parcel | 2 | ||||||||||||
Number of allotment parcels at issue | Allotment_Parcel | 5 | ||||||||||||
PNM | Palo Verde Nuclear Generating Station | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Number of cities to provide cooling water | city | 5 | ||||||||||||
Term of agreement for cooling water | 40 years | ||||||||||||
PNM | Palo Verde Nuclear Generating Station | Nuclear plant | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Ownership percentage in nuclear reactor | 10.20% | 10.20% | |||||||||||
Number of units | generating_unit | 3 | ||||||||||||
Maximum potential assessment per incident | $ 38,900,000 | $ 38,900,000 | |||||||||||
Annual payment limitation related to incident | 5,800,000 | 5,800,000 | |||||||||||
Aggregate amount of all risk insurance | 2,750,000,000 | 2,750,000,000 | |||||||||||
Maximum amount under Nuclear Electric Insurance Limited | 5,400,000 | 5,400,000 | |||||||||||
PNM | Maximum | Palo Verde Nuclear Generating Station | Nuclear plant | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Liability insurance coverage | 13,400,000,000 | 13,400,000,000 | |||||||||||
Liability insurance coverage sublimit | 2,250,000,000 | 2,250,000,000 | |||||||||||
First Choice | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Additional tax due plus penalties and interest | 5,000,000 | ||||||||||||
Commercial providers | PNM | Palo Verde Nuclear Generating Station | Nuclear plant | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Liability insurance coverage | 450,000,000 | 450,000,000 | |||||||||||
Industry Wide Retrospective Assessment Program | PNM | Palo Verde Nuclear Generating Station | Nuclear plant | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Liability insurance coverage | $ 13,000,000,000 | $ 13,000,000,000 | |||||||||||
Pending litigation | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Number of pending claims | lawsuit | 2 | ||||||||||||
Written notification to terminate agreement, minimum period of time required | 30 days | ||||||||||||
Settled litigation | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Number of pending claims | lawsuit | 1 | ||||||||||||
Subsequent event | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Unopposed motion filed for extension of procedural schedule | 90 days | ||||||||||||
Subsequent event | PNM | Navajo Nation Allottee Matters | |||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||||||||
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel | 2 |
Regulatory and Rate Matters - P
Regulatory and Rate Matters - PNM (Details) $ in Millions | Oct. 23, 2017 | Jul. 26, 2017USD ($)GWh | Jul. 03, 2017 | Jun. 01, 2017USD ($)GWhMW | May 23, 2017USD ($) | May 10, 2017 | Apr. 14, 2017USD ($)GWhprogram | Mar. 27, 2017 | Feb. 28, 2017USD ($) | Jan. 11, 2017USD ($) | Dec. 07, 2016USD ($) | Sep. 28, 2016USD ($)MW | Aug. 04, 2016USD ($)MW | Jun. 01, 2016MW | May 04, 2016 | Apr. 15, 2016USD ($)GWhprogram | Jan. 15, 2016USD ($)leaseMW | Nov. 30, 2015 | Aug. 27, 2015USD ($) | Jan. 15, 2015 | Jul. 01, 2014 | Sep. 30, 2016USD ($) | Dec. 31, 2015USD ($)MW | Sep. 30, 2017USD ($)GWhleaseMW | Sep. 30, 2016USD ($)GWh | Sep. 30, 2017USD ($)GWhleaseMW | Sep. 30, 2016USD ($)GWh | Dec. 31, 2015MW | Oct. 17, 2017MW | May 12, 2017USD ($) | May 05, 2017signatory | Dec. 31, 2016USD ($) | Oct. 26, 2016MW | Jul. 08, 2016service_rateMW | Jun. 30, 2016meeting | Apr. 26, 2016MW | Feb. 26, 2016USD ($) | Jan. 31, 2016leaseMW |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Excess return on jurisdictional equity that would require refund | 0.50% | 0.50% | ||||||||||||||||||||||||||||||||||||
Application filed for new electric service rates | service_rate | 2 | |||||||||||||||||||||||||||||||||||||
PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Planning period covered of IRP | 20 years | |||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | |||||||||||||||||||||||||||||||||||||
Number of statewide meetings hosted | meeting | 17 | |||||||||||||||||||||||||||||||||||||
PNMR Development | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 30 | |||||||||||||||||||||||||||||||||||||
Construction of solar generation capacity (in megawatts) | MW | 10 | |||||||||||||||||||||||||||||||||||||
2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ 123.5 | |||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) of non-fuel revenue | $ 121.5 | $ 121.7 | $ 121.5 | |||||||||||||||||||||||||||||||||||
Hearing examiner's recommended return on equity | 9.575% | |||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended rate increase (decrease) of non-fuel revenue | $ 41.3 | |||||||||||||||||||||||||||||||||||||
Requested return on equity | 10.50% | |||||||||||||||||||||||||||||||||||||
Estimate of possible loss | $ 153.4 | 153.4 | ||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) for fuel related costs | (42.9) | |||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) for non-fuel related revenues | $ (0.2) | |||||||||||||||||||||||||||||||||||||
Approved rate increase (decrease) | $ 61.2 | |||||||||||||||||||||||||||||||||||||
Estimated period of time for supreme court appeal decision | 15 months | |||||||||||||||||||||||||||||||||||||
Approved recovery of net operating loss carryforward | $ 2.1 | |||||||||||||||||||||||||||||||||||||
2014 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Future test year period | 12 months | |||||||||||||||||||||||||||||||||||||
Period of time after the filing of a rate case application | 13 months | |||||||||||||||||||||||||||||||||||||
Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of megawatts of Solar PV facilities | MW | 40 | 107 | 107 | 40 | ||||||||||||||||||||||||||||||||||
Current output in the geothermal facility (in megawatts) | MW | 4 | 4 | ||||||||||||||||||||||||||||||||||||
Solar generation capacity (in megawatts) | MW | 81.6 | 81.6 | ||||||||||||||||||||||||||||||||||||
Renewable Energy Rider | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Recorded revenues from renewable rider | $ 11.8 | $ 10.7 | $ 32.4 | $ 27.3 | ||||||||||||||||||||||||||||||||||
Renewable Portfolio Standard Supplemental Procurement | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of megawatts of Solar PV facilities | MW | 1.5 | 1.5 | ||||||||||||||||||||||||||||||||||||
Renewable Portfolio Standard 2014 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of megawatts for wind energy | MW | 204 | 102 | ||||||||||||||||||||||||||||||||||||
Integrated Resource Plan, 2011 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Frequency of IRP filings | 3 years | |||||||||||||||||||||||||||||||||||||
Planning period covered of IRP | 20 years | |||||||||||||||||||||||||||||||||||||
Advanced Metering Infrastructure Costs | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Estimated costs to be recovered | $ 95.1 | $ 87.2 | ||||||||||||||||||||||||||||||||||||
Estimated future investment | $ 33 | |||||||||||||||||||||||||||||||||||||
Firm Requirements Wholesale Power Rate Case, Navopache | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of megawatts served under a short-term coordination tariff | MW | 10 | |||||||||||||||||||||||||||||||||||||
Revenue for power sold under PSA | $ 1.1 | $ 4.8 | $ 3.3 | $ 14.8 | ||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 2 Leases | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of megawatts purchased (in megawatts) | MW | 64.1 | 64.1 | 64.1 | 64.1 | ||||||||||||||||||||||||||||||||||
Net book value of capitalized improvements | $ 39.9 | $ 39.9 | ||||||||||||||||||||||||||||||||||||
Net book value | $ 76.9 | $ 76.9 | ||||||||||||||||||||||||||||||||||||
Number of leases under which assets were purchased | lease | 3 | 3 | 3 | 3 | ||||||||||||||||||||||||||||||||||
Estimated annual property tax expense | $ 0.8 | |||||||||||||||||||||||||||||||||||||
Number of leases under which lease term was extended | lease | 1 | |||||||||||||||||||||||||||||||||||||
Lease term extension period | 8 years | |||||||||||||||||||||||||||||||||||||
Number of megawatts nuclear generation (in megawatts) | MW | 114.6 | 114.6 | 114.6 | |||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 2 Leases | 2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Disallowance of the recovery underpreciated costs of capitalized leasehold improvements | $ 43.8 | |||||||||||||||||||||||||||||||||||||
Initial rate base value | 83.7 | |||||||||||||||||||||||||||||||||||||
Hearing examiner's proposed disallowance of recovery | $ 163.3 | |||||||||||||||||||||||||||||||||||||
Period of time for which capital improvements were disallowed | 15 months | |||||||||||||||||||||||||||||||||||||
Pre-tax regulatory disallowance | $ 6.8 | |||||||||||||||||||||||||||||||||||||
Alvarado square | 2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended amount to not be recovered from retail customers | 4.5 | |||||||||||||||||||||||||||||||||||||
Pre-tax regulatory disallowance of costs recorded as regulatory assets and deferred charges | $ 4.5 | |||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 1 Leases, extended | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Estimated annual property tax expense | $ 1.5 | |||||||||||||||||||||||||||||||||||||
Estimated annual rent expense | 18.1 | |||||||||||||||||||||||||||||||||||||
Number of leases under which lease term was extended | lease | 4 | |||||||||||||||||||||||||||||||||||||
Lease term extension period | 8 years | |||||||||||||||||||||||||||||||||||||
Palo Verde Nuclear Generating Station, Unit 1 Leases, extended | 2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Recovery of assumed operating and maintenance expense savings annually | $ 0.3 | |||||||||||||||||||||||||||||||||||||
San Juan Generating Station Units 2 and 3 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Net book value | $ 260.2 | $ 260.2 | ||||||||||||||||||||||||||||||||||||
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Net book value | 50 | 50 | ||||||||||||||||||||||||||||||||||||
Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | 2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested base rate increase (decrease) | 40 | |||||||||||||||||||||||||||||||||||||
Clean Air Act, SNCR | San Juan Generating Station Units 2 and 3 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Newly identified replacement gas-fired generation (in megawatts) | MW | 80 | |||||||||||||||||||||||||||||||||||||
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, Balanced Draft Technology | San Juan Generating Station Units 1 and 4 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Installation Capital Costs | $ 52.3 | |||||||||||||||||||||||||||||||||||||
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other Costs | Clean Air Act, SNCR | San Juan Generating Station Units 1 and 4 | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Installation Capital Costs | $ 77.7 | |||||||||||||||||||||||||||||||||||||
Refined coal | San Juan Generating Station | 2015 Electric Rate Case | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Hearing examiner's recommended percentage of revenue to be credited to customers | 100.00% | |||||||||||||||||||||||||||||||||||||
NMPRC | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ 99.2 | |||||||||||||||||||||||||||||||||||||
Requested return on equity | 10.125% | |||||||||||||||||||||||||||||||||||||
Unopposed motion filed for extension of procedural schedule | 1 month | |||||||||||||||||||||||||||||||||||||
Number of additional signatories | signatory | 13 | |||||||||||||||||||||||||||||||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years | |||||||||||||||||||||||||||||||||||||
Return on equity, regulatory disallowance | $ 21 | $ 21 | ||||||||||||||||||||||||||||||||||||
Proposed revision to rider that will allow for recovery | $ 43.5 | $ 42.7 | ||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | |||||||||||||||||||||||||||||||||||||
NMPRC | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested rate increase (decrease) | $ 62.3 | |||||||||||||||||||||||||||||||||||||
Requested initial rate increase (decrease) | $ 32.3 | |||||||||||||||||||||||||||||||||||||
Requested return on equity | 9.575% | |||||||||||||||||||||||||||||||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years | |||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 1 | GWh | 80 | |||||||||||||||||||||||||||||||||||||
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW | 50 | |||||||||||||||||||||||||||||||||||||
Action plan, covered period | 4 years | |||||||||||||||||||||||||||||||||||||
Notice of Proposed Dismissal, period to show good cause | 30 days | |||||||||||||||||||||||||||||||||||||
Required Percentage by 2011 | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 10.00% | 10.00% | ||||||||||||||||||||||||||||||||||||
Required Percentage by 2015 | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 15.00% | 15.00% | ||||||||||||||||||||||||||||||||||||
Required Percentage by 2020 | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of renewable energy in portfolio to electric sales | 20.00% | 20.00% | ||||||||||||||||||||||||||||||||||||
Minimum | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Profit incentive sliding scale multiplier | 7.10% | |||||||||||||||||||||||||||||||||||||
Minimum | Wind | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 30.00% | 30.00% | ||||||||||||||||||||||||||||||||||||
Minimum | Solar | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 20.00% | 20.00% | ||||||||||||||||||||||||||||||||||||
Minimum | Distributed generation | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 3.00% | 3.00% | ||||||||||||||||||||||||||||||||||||
Minimum | Other | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Required percentage of diversification | 5.00% | 5.00% | ||||||||||||||||||||||||||||||||||||
Maximum | Renewable Portfolio Standard | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Reasonable cost threshold | 3.00% | 3.00% | 3.00% | |||||||||||||||||||||||||||||||||||
Profit incentive sliding scale multiplier | 9.00% | |||||||||||||||||||||||||||||||||||||
Maximum | Renewable Energy Rider | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Proposal to collect funds under renewable energy procurement plan | $ 42.4 | |||||||||||||||||||||||||||||||||||||
Annual revenue to be collected under rider rate | $ 50 | $ 50 | ||||||||||||||||||||||||||||||||||||
New Mexico Wind | NMPRC | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 2 | GWh | 105 | |||||||||||||||||||||||||||||||||||||
Lightning Dock Geothermal | NMPRC | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 1 | GWh | 55 | |||||||||||||||||||||||||||||||||||||
Requested approval to procure additional gigawatt hours in year 2 | GWh | 77 | |||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | 2017 Energy Efficiency and Load Management Program | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | |||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 26 | $ 28 | ||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 2.4 | |||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 75 | |||||||||||||||||||||||||||||||||||||
Profit incentive | $ 1.8 | |||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | Proposed 2018 Portfolio | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | |||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 25.1 | |||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 1.9 | |||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 53 | |||||||||||||||||||||||||||||||||||||
Projected incentive earnings | $ 1.9 | $ 2.1 | ||||||||||||||||||||||||||||||||||||
Targeted savings (in gigawatt hours) | GWh | 69 | 70 | ||||||||||||||||||||||||||||||||||||
Disincentives/Incentives Adder | Proposed 2019 Portfolio | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Number of programs in the proposed program portfolio | program | 10 | |||||||||||||||||||||||||||||||||||||
Program portfolio's total budget | $ 28.2 | |||||||||||||||||||||||||||||||||||||
Incentive based on target savings | $ 1.7 | $ 2.1 | ||||||||||||||||||||||||||||||||||||
Tri-State | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Term of hazard sharing agreement | 5 years | 1 year | ||||||||||||||||||||||||||||||||||||
Each party will sell the other party capacity (in megawatts) | MW | 100 | |||||||||||||||||||||||||||||||||||||
Number of hours sold (in GWh) | GWh | 202,400,000 | 208,200,000 | 615,000,000 | 268,500,000 | ||||||||||||||||||||||||||||||||||
Hours sold (in dollars) | $ 7.2 | $ 6.2 | $ 17.7 | $ 7.8 | ||||||||||||||||||||||||||||||||||
Number of hours purchased (in GWh) | GWh | 215,100,000 | 216,400,000 | 632,500,000 | 278,800,000 | ||||||||||||||||||||||||||||||||||
Hours purchased (in dollars) | $ 7.6 | $ 6.4 | $ 18.2 | $ 8.1 | ||||||||||||||||||||||||||||||||||
Subsequent event | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Unopposed motion filed for extension of procedural schedule | 90 days | |||||||||||||||||||||||||||||||||||||
Subsequent event | NMPRC | PNM | ||||||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||
Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW | 50 |
Regulatory and Rate Matters - T
Regulatory and Rate Matters - TNMP Narrative (Details) - Texas-New Mexico Power Company | May 25, 2017USD ($) | Mar. 13, 2017USD ($) | Jul. 30, 2011USD ($) | Sep. 30, 2017USD ($)customer | Oct. 20, 2017customer | Dec. 31, 2016advanced_meter |
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Adjustment of the most recent annual CTC funding amount (greater than or equal to) | 15.00% | |||||
Requested increase (decrease) adjustment to reduce collection of amortization | $ (1,100,000) | |||||
Energy efficiency cost recovery factor, total amount requested | $ 6,000,000 | |||||
Energy efficiency cost recovery factor, performance bonus requested | $ 1,100,000 | |||||
Advanced Meter System Deployment and Surcharge Request | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Approved deployment costs | $ 113,400,000 | |||||
Collection of deployment costs through surcharge period | 12 years | |||||
Number of advanced meters installed (more than) | advanced_meter | 242,000 | |||||
Recovery in cost through initial fees | $ 200,000 | |||||
Ongoing annual expenses | 500,000 | |||||
Approved non-standard metering ongoing expenses monthly charge | $ 36.78 | |||||
Presumed number of customers that will elect non-standard meter service (in customers) | customer | 1,081 | |||||
Minimum | Advanced Meter System Deployment and Surcharge Request | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Approved non-standard metering service cost, initial fee range | $ 63.97 | |||||
Maximum | Advanced Meter System Deployment and Surcharge Request | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Approved non-standard metering service cost, initial fee range | $ 168.61 | |||||
Subsequent event | Advanced Meter System Deployment and Surcharge Request | ||||||
Public Utilities, Commitments And Contingencies [Line Items] | ||||||
Current number of customers that have elected non-standard meter service (in customers) | customer | 99 |
Regulatory and Rate Matters -58
Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - Texas-New Mexico Power Company - USD ($) $ in Millions | Jul. 19, 2017 | Mar. 14, 2017 | Sep. 08, 2016 | Mar. 23, 2016 | Sep. 10, 2015 |
Transmission Cost of Service Rates | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 30.2 | $ 9.5 | $ 25.8 | $ 7 | |
Annual Increase in Revenue | $ 4.8 | $ 1.8 | $ 4.3 | $ 1.4 | |
PUCT | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Requested rate increase (decrease) | $ 27.5 | ||||
Proposed increase (decrease) in revenues | $ 4.7 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | May 23, 2017 | Mar. 31, 2017 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Income Tax Contingency [Line Items] | ||||||||
New Mexico Corporate tax rate before change in 2013 | 7.60% | |||||||
New Mexico Corporate tax rate, effective by 2018 | 5.90% | |||||||
Increase (decrease) in deferred tax assets as a result of tax rate changes | $ (0.7) | |||||||
Increase (decrease) in tax expense due to tax rate change (less than for 2017) | 0.8 | |||||||
Operating loss carryforward | $ 2.1 | |||||||
Corporate and Other | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Increase (decrease) in tax expense due to tax rate change (less than for 2017) | $ 0.1 | (0.1) | ||||||
Internal Revenue Service (IRS) | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Net refunds received from the IRS | $ 6.5 | |||||||
Increase (decrease) in interest receivable | $ (2.1) | |||||||
Interest income | 5.1 | |||||||
Interest expense | 0.7 | |||||||
Professional fees | $ 0.9 | |||||||
Net pre-tax impacts, liability (refund) | (3.5) | |||||||
Internal Revenue Service (IRS) | Corporate and Other | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Net pre-tax impacts, liability (refund) | (0.6) | |||||||
Internal Revenue Service (IRS) | PNM | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Net pre-tax impacts, liability (refund) | (2.6) | |||||||
Internal Revenue Service (IRS) | Texas-New Mexico Power Company | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Net pre-tax impacts, liability (refund) | $ 0.3 | |||||||
NMPRC | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years | |||||||
PNM | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Increase (decrease) in regulatory liability | (4.8) | $ (7.1) | ||||||
Increase (decrease) in deferred tax assets as a result of tax rate changes | (0.1) | |||||||
Increase (decrease) in tax expense due to tax rate change (less than for 2017) | $ 0.1 | |||||||
PNM | NMPRC | ||||||||
Income Tax Contingency [Line Items] | ||||||||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Services billings: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 23,451 | $ 22,189 | $ 71,044 | $ 67,192 |
Services billings: | PNMR to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 7,828 | 6,593 | 23,771 | 20,881 |
Services billings: | PNM to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 115 | 105 | 302 | 347 |
Services billings: | TNMP to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 35 | 10 | 106 | 30 |
Services billings: | TNMP to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 8 | 84 | 154 | 171 |
Interest billings: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 3 | 3 | 14 | 8 |
Interest billings: | PNMR to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 66 | 13 | 126 | 112 |
Interest billings: | PNM to PNMR | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 71 | 38 | 163 | 110 |
Income tax sharing payments: | PNMR to PNM | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 0 | 0 | 0 |
Income tax sharing payments: | PNMR to TNMP | ||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 0 | $ 0 | $ 0 | $ 0 |
Goodwill (Details)
Goodwill (Details) - USD ($) | Apr. 01, 2017 | Apr. 01, 2016 | Sep. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2016 |
Goodwill [Line Items] | |||||
Goodwill | $ 278,297,000 | $ 278,297,000 | $ 278,297,000 | ||
Impairments of goodwill | $ 0 | $ 0 | |||
PNM | |||||
Goodwill [Line Items] | |||||
Goodwill | $ 51,600,000 | 51,632,000 | 51,632,000 | ||
Goodwill fair value exceeded by its carrying value | 25.00% | ||||
TNMP | |||||
Goodwill [Line Items] | |||||
Goodwill | $ 226,700,000 | $ 226,665,000 | $ 226,665,000 | ||
Goodwill fair value exceeded by its carrying value | 32.00% |
Uncategorized Items - pnm-20170
Label | Element | Value |
Four Corners [Member] | Public Service Company of New Mexico [Member] | ||
Unrecorded Unconditional Purchase Obligation | us-gaap_UnrecordedUnconditionalPurchaseObligationBalanceSheetAmount | $ 6,500,000 |