Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Oct. 25, 2013 | |
Document Information [Line Items] | ' | ' |
Entity Registrant Name | 'PNM RESOURCES INC | ' |
Entity Central Index Key | '0001108426 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 79,653,624 |
Public Service Company of New Mexico [Member] | ' | ' |
Document Information [Line Items] | ' | ' |
Entity Registrant Name | 'PUBLIC SERVICE CO OF NEW MEXICO | ' |
Entity Central Index Key | '0000081023 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 39,117,799 |
Texas-New Mexico Power Company [Member] | ' | ' |
Document Information [Line Items] | ' | ' |
Entity Registrant Name | 'TEXAS NEW MEXICO POWER CO | ' |
Entity Central Index Key | '0000022767 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 6,358 |
Condensed_Consolidated_Stateme
Condensed Consolidated Statements of Earnings (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
In Thousands, except Per Share data, unless otherwise specified | Jul. 31, 2013 | Jul. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Electric Operating Revenues | ' | ' | $399,730 | $390,411 | $1,064,993 | $1,019,646 |
Operating Expenses: | ' | ' | ' | ' | ' | ' |
Cost of energy | ' | ' | 114,674 | 110,777 | 325,039 | 297,342 |
Administrative and general | ' | ' | 46,915 | 45,283 | 134,744 | 135,371 |
Energy production costs | ' | ' | 41,142 | 40,365 | 131,546 | 131,546 |
Regulatory disallowances | ' | ' | 1,735 | 0 | 1,735 | 0 |
Depreciation and amortization | ' | ' | 42,743 | 42,820 | 125,189 | 122,289 |
Transmission and distribution costs | ' | ' | 17,248 | 17,082 | 50,690 | 50,896 |
Taxes other than income taxes | ' | ' | 17,534 | 15,934 | 49,739 | 45,218 |
Total operating expenses | ' | ' | 281,991 | 272,261 | 818,682 | 782,662 |
Operating income | ' | ' | 117,739 | 118,150 | 246,311 | 236,984 |
Other Income and Deductions: | ' | ' | ' | ' | ' | ' |
Interest income | ' | ' | 2,264 | 3,130 | 7,731 | 9,808 |
Gains on investments held by NDT | ' | ' | 2,190 | 5,716 | 6,995 | 9,376 |
Other income | ' | ' | 3,252 | 2,484 | 7,517 | 6,991 |
Other (deductions) | ' | ' | -5,970 | -3,451 | -13,516 | -10,719 |
Net other income (deductions) | ' | ' | 1,736 | 7,879 | 8,727 | 15,456 |
Interest Charges | ' | ' | 30,365 | 30,515 | 92,279 | 90,280 |
Earnings before Income Taxes | ' | ' | 89,110 | 95,514 | 162,759 | 162,160 |
Income Taxes | ' | ' | 30,296 | 33,538 | 58,600 | 54,609 |
Net Earnings | ' | ' | 58,814 | 61,976 | 104,159 | 107,551 |
(Earnings) Attributable to Valencia Non-controlling Interest | ' | ' | -4,127 | -3,980 | -10,904 | -10,699 |
Preferred Stock Dividend Requirements of Subsidiary | ' | ' | -132 | -132 | -396 | -396 |
Net Earnings Attributable to PNMR | ' | ' | 54,555 | 57,864 | 92,859 | 96,456 |
Net Earnings Attributable to PNMR per Common Share: | ' | ' | ' | ' | ' | ' |
Basic (dollars per share) | ' | ' | $0.68 | $0.73 | $1.16 | $1.21 |
Diluted (dollars per share) | ' | ' | $0.68 | $0.72 | $1.15 | $1.20 |
Dividends Declared per Common Share (dollars per share) | $0.17 | $0.14 | $0.17 | $0.14 | $0.50 | $0.44 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' | ' | ' |
Electric Operating Revenues | ' | ' | 326,026 | 321,731 | 863,609 | 832,242 |
Operating Expenses: | ' | ' | ' | ' | ' | ' |
Cost of energy | ' | ' | 100,200 | 99,217 | 283,715 | 263,009 |
Administrative and general | ' | ' | 40,679 | 41,150 | 116,058 | 120,857 |
Energy production costs | ' | ' | 41,142 | 40,365 | 131,546 | 131,546 |
Regulatory disallowances | ' | ' | 1,735 | 0 | 1,735 | 0 |
Depreciation and amortization | ' | ' | 25,879 | 24,437 | 77,763 | 72,017 |
Transmission and distribution costs | ' | ' | 11,686 | 11,172 | 33,420 | 33,679 |
Taxes other than income taxes | ' | ' | 9,488 | 8,417 | 28,613 | 25,386 |
Total operating expenses | ' | ' | 230,809 | 224,758 | 672,850 | 646,494 |
Operating income | ' | ' | 95,217 | 96,973 | 190,759 | 185,748 |
Other Income and Deductions: | ' | ' | ' | ' | ' | ' |
Interest income | ' | ' | 2,298 | 3,173 | 7,839 | 9,938 |
Gains on investments held by NDT | ' | ' | 2,190 | 5,716 | 6,995 | 9,376 |
Other income | ' | ' | 2,396 | 1,176 | 5,269 | 4,378 |
Other (deductions) | ' | ' | -2,375 | -1,682 | -5,287 | -4,553 |
Net other income (deductions) | ' | ' | 4,509 | 8,383 | 14,816 | 19,139 |
Interest Charges | ' | ' | 20,124 | 19,230 | 59,971 | 56,652 |
Earnings before Income Taxes | ' | ' | 79,602 | 86,126 | 145,604 | 148,235 |
Income Taxes | ' | ' | 27,652 | 31,235 | 49,184 | 51,929 |
Net Earnings | ' | ' | 51,950 | 54,891 | 96,420 | 96,306 |
(Earnings) Attributable to Valencia Non-controlling Interest | ' | ' | -4,127 | -3,980 | -10,904 | -10,699 |
Net Earnings Attributable to PNMR | ' | ' | 47,823 | 50,911 | 85,516 | 85,607 |
Preferred Stock Dividends Requirements | ' | ' | -132 | -132 | -396 | -396 |
Net Earnings Available for PNM Common Stock | ' | ' | 47,691 | 50,779 | 85,120 | 85,211 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' | ' | ' |
Electric Operating Revenues | ' | ' | 73,704 | 68,680 | 201,384 | 187,404 |
Operating Expenses: | ' | ' | ' | ' | ' | ' |
Cost of energy | ' | ' | 14,474 | 11,560 | 41,324 | 34,333 |
Administrative and general | ' | ' | 10,641 | 10,130 | 32,446 | 30,700 |
Depreciation and amortization | ' | ' | 13,850 | 13,819 | 37,810 | 37,173 |
Transmission and distribution costs | ' | ' | 5,562 | 5,910 | 17,270 | 17,217 |
Taxes other than income taxes | ' | ' | 6,923 | 6,291 | 17,558 | 16,322 |
Total operating expenses | ' | ' | 51,450 | 47,710 | 146,408 | 135,745 |
Operating income | ' | ' | 22,254 | 20,970 | 54,976 | 51,659 |
Other Income and Deductions: | ' | ' | ' | ' | ' | ' |
Interest income | ' | ' | 0 | 0 | 0 | 1 |
Other income | ' | ' | 820 | 771 | 1,765 | 1,708 |
Other (deductions) | ' | ' | -104 | -405 | -356 | -464 |
Net other income (deductions) | ' | ' | 716 | 366 | 1,409 | 1,245 |
Interest Charges | ' | ' | 6,655 | 7,047 | 20,661 | 21,214 |
Earnings before Income Taxes | ' | ' | 16,315 | 14,289 | 35,724 | 31,690 |
Income Taxes | ' | ' | 6,209 | 5,205 | 13,554 | 11,577 |
Net Earnings Attributable to PNMR | ' | ' | $10,106 | $9,084 | $22,170 | $20,113 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Comprehensive Income (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Net Earnings | $54,555 | $57,864 | $92,859 | $96,456 |
Net Earnings | 58,814 | 61,976 | 104,159 | 107,551 |
Unrealized Gain on Investment Securities: | ' | ' | ' | ' |
Unrealized holding gains arising during the period, net of income tax (expense) benefit | 6,322 | 7,587 | 11,512 | 23,511 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | -1,411 | -6,481 | -5,551 | -19,509 |
Pension Liability Adjustment: | ' | ' | ' | ' |
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 960 | 727 | 2,880 | 2,181 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Change in fair market value, net of income tax (expense) benefit | -238 | -92 | -236 | -270 |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) | 35 | 29 | 99 | 85 |
Total Other Comprehensive Income (Loss) | 5,668 | 1,770 | 8,704 | 5,998 |
Comprehensive Income | 64,482 | 63,746 | 112,863 | 113,549 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | -4,127 | -3,980 | -10,904 | -10,699 |
Preferred Stock Dividend Requirements of Subsidiary | -132 | -132 | -396 | -396 |
Comprehensive Income Attributable to PNMR | 60,223 | 59,634 | 101,563 | 102,454 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Net Earnings | 47,823 | 50,911 | 85,516 | 85,607 |
Net Earnings | 51,950 | 54,891 | 96,420 | 96,306 |
Unrealized Gain on Investment Securities: | ' | ' | ' | ' |
Unrealized holding gains arising during the period, net of income tax (expense) benefit | 6,322 | 7,587 | 11,512 | 23,511 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense | -1,411 | -6,481 | -5,551 | -19,509 |
Pension Liability Adjustment: | ' | ' | ' | ' |
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 960 | 727 | 2,880 | 2,181 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Total Other Comprehensive Income (Loss) | 5,871 | 1,833 | 8,841 | 6,183 |
Comprehensive Income | 57,821 | 56,724 | 105,261 | 102,489 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | -4,127 | -3,980 | -10,904 | -10,699 |
Comprehensive Income Attributable to PNMR | 53,694 | 52,744 | 94,357 | 91,790 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Net Earnings | 10,106 | 9,084 | 22,170 | 20,113 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Change in fair market value, net of income tax (expense) benefit | -238 | -92 | -236 | -270 |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) | 35 | 29 | 99 | 85 |
Total Other Comprehensive Income (Loss) | -203 | -63 | -137 | -185 |
Comprehensive Income Attributable to PNMR | $9,903 | $9,021 | $22,033 | $19,928 |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Unrealized holding gains (losses) arising during the period, income tax (expense) | ($4,143) | ($4,972) | ($7,544) | ($15,409) |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense | 925 | 4,248 | 3,639 | 12,786 |
Pension liability adjustment, income tax (expense) benefit | -631 | -476 | -1,893 | -1,428 |
Change in fair market value, income tax (expense) | 128 | 51 | 127 | 150 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | -19 | -16 | -54 | -47 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Unrealized holding gains (losses) arising during the period, income tax (expense) | -4,143 | -4,972 | -7,544 | -15,409 |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense | 925 | 4,248 | 3,639 | 12,786 |
Pension liability adjustment, income tax (expense) benefit | -631 | -476 | -1,893 | -1,428 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Change in fair market value, income tax (expense) | 128 | 51 | 127 | 150 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | ($19) | ($16) | ($54) | ($47) |
Condensed_Consolidated_Stateme3
Condensed Consolidated Statements of Cash Flows (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Cash Flows From Operating Activities: | ' | ' |
Net Earnings | $104,159 | $107,551 |
Net Earnings | 92,859 | 96,456 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 157,856 | 153,992 |
Deferred income tax expense | 57,878 | 55,141 |
Net unrealized (gains) losses on commodity derivatives | -5,858 | 3,076 |
Realized (gains) losses on investments held by NDT | -6,995 | -9,376 |
Stock based compensation expense | 4,315 | 2,748 |
Regulatory disallowances | 1,735 | 0 |
Other, net | 1,444 | -2,037 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -23,731 | -31,550 |
Materials, supplies, and fuel stock | -724 | -6,769 |
Other current assets | -6,667 | -4,225 |
Other assets | 21,656 | -9,499 |
Accounts payable | -17,786 | 3,973 |
Accrued interest and taxes | 126,218 | 22,336 |
Other current liabilities | -32,111 | -21,681 |
Proceeds from governmental grants | 0 | 21,567 |
Other liabilities | -70,379 | -80,248 |
Net cash flows from operating activities | 311,010 | 204,999 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -233,928 | -214,743 |
Proceeds from sales of investments held by NDT | 179,336 | 136,305 |
Purchases of investments held by NDT | -181,401 | -138,658 |
Proceeds from sale of First Choice | 0 | 4,034 |
Return of principal on PVNGS lessor notes | 23,357 | 23,455 |
Other, net | 1,210 | 1,627 |
Net cash flows from investing activities | -211,426 | -187,980 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), net | -46,700 | 30,700 |
Long-term borrowings | 75,000 | 20,000 |
Repayment of long-term debt | -26,037 | -20,000 |
Cash paid in debt exchange | -13,048 | 0 |
Proceeds from stock option exercise | 3,500 | 10,301 |
Purchases to satisfy awards of common stock | -12,429 | -21,930 |
Dividends paid | -38,233 | -33,454 |
Valencia's transactions with its owner | -13,477 | -12,034 |
Other, net | -3,706 | -337 |
Net cash flows from financing activities | -75,130 | -26,754 |
Change in Cash and Cash Equivalents | 24,454 | -9,735 |
Cash and Cash Equivalents at Beginning of Period | 8,985 | 15,091 |
Cash and Cash Equivalents at End of Period | 33,439 | 5,356 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of capitalized interest | 71,824 | 64,040 |
Income taxes paid (refunded), net | -95,472 | 5,302 |
Supplemental schedule of noncash financing activities: | ' | ' |
Premium on long-term debt incurred in connection with debt exchange | 23,249 | 'Â Â |
Public Service Company of New Mexico [Member] | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net Earnings | 96,420 | 96,306 |
Net Earnings | 85,516 | 85,607 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 104,161 | 97,086 |
Deferred income tax expense | 49,870 | 52,558 |
Net unrealized (gains) losses on commodity derivatives | -5,858 | 3,076 |
Realized (gains) losses on investments held by NDT | -6,995 | -9,376 |
Regulatory disallowances | 1,735 | 0 |
Other, net | -1,282 | -1,005 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -14,123 | -26,183 |
Materials, supplies, and fuel stock | -744 | -6,404 |
Other current assets | -5,187 | -6,942 |
Other assets | 21,977 | -9,425 |
Accounts payable | -4,953 | 2,353 |
Accrued interest and taxes | 66,090 | 80,418 |
Other current liabilities | -43,935 | -9,850 |
Proceeds from governmental grants | 0 | 21,567 |
Other liabilities | -67,062 | -75,629 |
Net cash flows from operating activities | 190,114 | 208,550 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -164,669 | -144,571 |
Proceeds from sales of investments held by NDT | 179,336 | 136,305 |
Purchases of investments held by NDT | -181,401 | -138,658 |
Return of principal on PVNGS lessor notes | 23,357 | 23,455 |
Other, net | 1,212 | -720 |
Net cash flows from investing activities | -142,165 | -124,189 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), net | -21,100 | -66,000 |
Long-term borrowings | 75,000 | 20,000 |
Repayment of long-term debt | 0 | -20,000 |
Dividends paid | -68,424 | -18,076 |
Valencia's transactions with its owner | -13,477 | -12,034 |
Other, net | -1,727 | -337 |
Net cash flows from financing activities | -29,728 | -96,447 |
Change in Cash and Cash Equivalents | 18,221 | -12,086 |
Cash and Cash Equivalents at Beginning of Period | 3,958 | 12,307 |
Cash and Cash Equivalents at End of Period | 22,179 | 221 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of capitalized interest | 49,984 | 43,167 |
Income taxes paid (refunded), net | -44,999 | -63,114 |
Texas-New Mexico Power Company [Member] | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net Earnings | 22,170 | 20,113 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 40,946 | 41,222 |
Deferred income tax expense | 3,901 | 11,337 |
Other, net | -13 | -275 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -9,608 | -5,367 |
Materials, supplies, and fuel stock | 20 | -365 |
Other current assets | -2,420 | -709 |
Other assets | 36 | -498 |
Accounts payable | -291 | -358 |
Accrued interest and taxes | 14,669 | 4,860 |
Other current liabilities | -1,946 | 1,980 |
Other liabilities | 2,182 | -3,411 |
Net cash flows from operating activities | 69,646 | 68,529 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -67,400 | -59,801 |
Net cash flows from investing activities | -67,400 | -59,801 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), affiliate, net | 12,000 | 0 |
Long-term borrowings | 4,800 | 2,300 |
Cash paid in debt exchange | -13,048 | 0 |
Dividends paid | -3,726 | -11,028 |
Other, net | -2,117 | 0 |
Net cash flows from financing activities | -2,091 | -8,728 |
Change in Cash and Cash Equivalents | 155 | 0 |
Cash and Cash Equivalents at Beginning of Period | 1 | 1 |
Cash and Cash Equivalents at End of Period | 156 | 1 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of capitalized interest | 13,626 | 13,074 |
Income taxes paid (refunded), net | 696 | 1,848 |
Supplemental schedule of noncash financing activities: | ' | ' |
Premium on long-term debt incurred in connection with debt exchange | $23,249 | ' |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current Assets: | ' | ' |
Cash and cash equivalents | $33,439 | $8,985 |
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM | 110,937 | 87,093 |
Unbilled revenues | 55,155 | 57,266 |
Other receivables | 53,681 | 53,332 |
Materials, supplies, and fuel stock | 60,367 | 59,643 |
Regulatory assets | 38,511 | 39,120 |
Commodity derivative instruments | 5,743 | 3,785 |
Income taxes receivable | 5,283 | 101,477 |
Other current assets | 37,404 | 31,490 |
Total current assets | 400,520 | 442,191 |
Other Property and Investments: | ' | ' |
Investment in PVNGS lessor notes | 32,542 | 54,325 |
Investments held by NDT | 207,483 | 188,971 |
Other investments | 6,725 | 9,139 |
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR | 4,475 | 4,487 |
Total other property and investments | 251,225 | 256,922 |
Utility Plant: | ' | ' |
Plant in service and plant held for future use | 5,431,680 | 5,313,796 |
Less accumulated depreciation and amortization | 1,839,481 | 1,774,223 |
Net plant in service and plant held for future use | 3,592,199 | 3,539,573 |
Construction work in progress | 175,410 | 125,287 |
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644 for PNMR and PNM | 79,458 | 81,627 |
Net utility plant | 3,847,067 | 3,746,487 |
Deferred Charges and Other Assets: | ' | ' |
Regulatory assets | 551,607 | 555,577 |
Goodwill | 278,297 | 278,297 |
Commodity derivative instruments | 4,284 | 352 |
Other deferred charges | 95,814 | 92,757 |
Total deferred charges and other assets | 930,002 | 926,983 |
Assets | 5,428,814 | 5,372,583 |
Current Liabilities: | ' | ' |
Short-term debt | 112,000 | 158,700 |
Current installments of long-term debt | 52,530 | 2,530 |
Accounts payable | 76,309 | 99,177 |
Customer deposits | 14,171 | 18,176 |
Accrued interest and taxes | 82,801 | 52,003 |
Regulatory liabilities | 1,218 | 15,173 |
Commodity derivative instruments | 1,017 | 1,000 |
Dividends declared | 13,271 | 11,679 |
Current portion of accumulated deferred income taxes | 258 | 258 |
Other current liabilities | 62,018 | 75,407 |
Total current liabilities | 415,593 | 434,103 |
Long-term Debt | 1,696,311 | 1,669,760 |
Deferred Credits and Other Liabilities: | ' | ' |
Accumulated deferred income taxes | 743,828 | 701,545 |
Accumulated deferred investment tax credits | 12,598 | 14,242 |
Regulatory liabilities | 456,634 | 423,460 |
Asset retirement obligations | 93,519 | 85,893 |
Accrued pension liability and postretirement benefit cost | 147,442 | 224,565 |
Commodity derivative instruments | 1,347 | 1,933 |
Other deferred credits | 106,554 | 116,523 |
Total deferred credits and other liabilities | 1,561,922 | 1,568,161 |
Total liabilities | 3,673,826 | 3,672,024 |
Commitments and Contingencies (See Note 10) | 'Â Â | 'Â Â |
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, Value, Issued | 1,177,686 | 1,182,819 |
Accumulated other comprehensive income (loss), net of income taxes | -72,926 | -81,630 |
Retained earnings | 560,429 | 506,998 |
Total Company common stockholders' equity | 1,665,189 | 1,608,187 |
Non-controlling interest in Valencia | 78,270 | 80,843 |
Total equity | 1,743,459 | 1,689,030 |
Total liabilities and stockholders' equity | 5,428,814 | 5,372,583 |
Public Service Company of New Mexico [Member] | ' | ' |
Current Assets: | ' | ' |
Cash and cash equivalents | 22,179 | 3,958 |
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM | 84,613 | 69,876 |
Unbilled revenues | 46,473 | 49,085 |
Other receivables | 52,328 | 50,975 |
Affiliate receivables | 8,827 | 9,050 |
Materials, supplies, and fuel stock | 57,534 | 56,790 |
Regulatory assets | 34,315 | 36,490 |
Commodity derivative instruments | 5,743 | 3,785 |
Income taxes receivable | 35,910 | 80,223 |
Other current assets | 32,294 | 27,457 |
Total current assets | 380,216 | 387,689 |
Other Property and Investments: | ' | ' |
Investment in PVNGS lessor notes | 32,542 | 54,325 |
Investments held by NDT | 207,483 | 188,971 |
Other investments | 4,380 | 4,034 |
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR | 976 | 976 |
Total other property and investments | 245,381 | 248,306 |
Utility Plant: | ' | ' |
Plant in service and plant held for future use | 4,217,120 | 4,133,532 |
Less accumulated depreciation and amortization | 1,409,042 | 1,355,240 |
Net plant in service and plant held for future use | 2,808,078 | 2,778,292 |
Construction work in progress | 136,679 | 102,329 |
Nuclear fuel, net of accumulated amortization of $52,876 and $42,644 for PNMR and PNM | 79,458 | 81,627 |
Net utility plant | 3,024,215 | 2,962,248 |
Deferred Charges and Other Assets: | ' | ' |
Regulatory assets | 402,040 | 431,956 |
Goodwill | 51,632 | 51,632 |
Commodity derivative instruments | 4,284 | 352 |
Other deferred charges | 84,702 | 81,724 |
Total deferred charges and other assets | 542,658 | 565,664 |
Assets | 4,192,470 | 4,163,907 |
Current Liabilities: | ' | ' |
Short-term debt | 0 | 21,100 |
Accounts payable | 60,049 | 73,914 |
Customer deposits | 14,171 | 18,176 |
Affiliate payables | 13,462 | 25,340 |
Accrued interest and taxes | 52,735 | 30,320 |
Regulatory liabilities | 1,218 | 15,172 |
Commodity derivative instruments | 1,017 | 1,000 |
Dividends declared | 132 | 132 |
Current portion of accumulated deferred income taxes | 3,447 | 3,447 |
Other current liabilities | 40,041 | 54,150 |
Total current liabilities | 186,272 | 242,751 |
Long-term Debt | 1,290,608 | 1,215,579 |
Deferred Credits and Other Liabilities: | ' | ' |
Accumulated deferred income taxes | 608,366 | 573,881 |
Accumulated deferred investment tax credits | 12,598 | 14,242 |
Regulatory liabilities | 409,444 | 379,841 |
Asset retirement obligations | 92,614 | 85,042 |
Accrued pension liability and postretirement benefit cost | 134,009 | 208,618 |
Commodity derivative instruments | 1,347 | 1,933 |
Other deferred credits | 87,417 | 95,585 |
Total deferred credits and other liabilities | 1,345,795 | 1,359,142 |
Total liabilities | 2,822,675 | 2,817,472 |
Commitments and Contingencies (See Note 10) | 'Â Â | 'Â Â |
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements | 11,529 | 11,529 |
Company common stockholders’ equity: | ' | ' |
Common Stock, Value, Issued | 1,061,776 | 1,061,776 |
Accumulated other comprehensive income (loss), net of income taxes | -72,573 | -81,414 |
Retained earnings | 290,793 | 273,701 |
Total Company common stockholders' equity | 1,279,996 | 1,254,063 |
Non-controlling interest in Valencia | 78,270 | 80,843 |
Total equity | 1,358,266 | 1,334,906 |
Total liabilities and stockholders' equity | 4,192,470 | 4,163,907 |
Texas-New Mexico Power Company [Member] | ' | ' |
Current Assets: | ' | ' |
Cash and cash equivalents | 156 | 1 |
Accounts receivable, net of allowance for uncollectible accounts of $1,391 and $1,751 for PNMR and PNM | 26,324 | 17,217 |
Unbilled revenues | 8,682 | 8,181 |
Other receivables | 1,728 | 2,359 |
Materials, supplies, and fuel stock | 2,833 | 2,853 |
Regulatory assets | 4,196 | 2,630 |
Current portion of accumulated deferred income taxes | 1,131 | 1,131 |
Other current assets | 1,816 | 1,107 |
Total current assets | 46,866 | 35,479 |
Other Property and Investments: | ' | ' |
Other investments | 281 | 281 |
Non-utility property, net of accumulated depreciation of $143 and $131 for PNMR | 2,240 | 2,240 |
Total other property and investments | 2,521 | 2,521 |
Utility Plant: | ' | ' |
Plant in service and plant held for future use | 1,048,474 | 1,009,108 |
Less accumulated depreciation and amortization | 347,228 | 339,315 |
Net plant in service and plant held for future use | 701,246 | 669,793 |
Construction work in progress | 27,112 | 19,801 |
Net utility plant | 728,358 | 689,594 |
Deferred Charges and Other Assets: | ' | ' |
Regulatory assets | 149,567 | 123,621 |
Goodwill | 226,665 | 226,665 |
Other deferred charges | 8,610 | 8,349 |
Total deferred charges and other assets | 384,842 | 358,635 |
Assets | 1,162,587 | 1,086,229 |
Current Liabilities: | ' | ' |
Short-term debt – affiliate | 33,100 | 28,300 |
Short-term debt | 12,000 | 0 |
Current installments of long-term debt | 50,000 | 0 |
Accounts payable | 7,114 | 8,848 |
Affiliate payables | 2,138 | 4,381 |
Accrued interest and taxes | 45,160 | 30,491 |
Other current liabilities | 9,614 | 8,854 |
Total current liabilities | 159,126 | 80,874 |
Long-term Debt | 286,128 | 311,589 |
Deferred Credits and Other Liabilities: | ' | ' |
Accumulated deferred income taxes | 167,674 | 163,710 |
Regulatory liabilities | 46,754 | 43,619 |
Asset retirement obligations | 778 | 732 |
Accrued pension liability and postretirement benefit cost | 13,433 | 15,947 |
Other deferred credits | 6,573 | 5,944 |
Total deferred credits and other liabilities | 235,212 | 229,952 |
Total liabilities | 680,466 | 622,415 |
Commitments and Contingencies (See Note 10) | 'Â Â | 'Â Â |
Company common stockholders’ equity: | ' | ' |
Common Stock, Value, Issued | 64 | 64 |
Paid-in-capital | 390,366 | 390,366 |
Accumulated other comprehensive income (loss), net of income taxes | -353 | -216 |
Retained earnings | 92,044 | 73,600 |
Total Company common stockholders' equity | 482,121 | 463,814 |
Total liabilities and stockholders' equity | $1,162,587 | $1,086,229 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, except Share data, unless otherwise specified | ||
Allowance for uncollectible accounts | $1,391 | $1,751 |
Accumulated depreciation, non-utility property | 143 | 131 |
Accumulated depreciation, nuclear fuel | 52,876 | 42,644 |
Cumulative preferred stock of subsidiary, stated value | $100 | $100 |
Cumulative preferred stock of subsidiary, shares authorized | 10,000,000 | 10,000,000 |
Cumulative preferred stock of subsidiary, shares issued | 115,293 | 115,293 |
Cumulative preferred stock of subsidiary, shares authorized | 115,293 | 115,293 |
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 120,000,000 | 120,000,000 |
Common stock, shares issued | 79,653,624 | 79,653,624 |
Common stock, shares outstanding | 79,653,624 | 79,653,624 |
Public Service Company of New Mexico [Member] | ' | ' |
Allowance for uncollectible accounts | 1,339 | 1,751 |
Accumulated depreciation, nuclear fuel | $52,876 | $42,644 |
Cumulative preferred stock, stated value | $100 | $100 |
Cumulative preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Cumulative preferred stock, shares issued | 115,293 | 115,293 |
Cumulative preferred stock, shares outstanding | 115,293 | 115,293 |
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares issued | 39,117,799 | 39,117,799 |
Common stock, shares outstanding | 39,117,799 | 39,117,799 |
Texas-New Mexico Power Company [Member] | ' | ' |
Common stock, par value | $10 | $10 |
Common stock, shares authorized | 12,000,000 | 12,000,000 |
Common stock, shares issued | 6,358 | 6,358 |
Common stock, shares outstanding | 6,358 | 6,358 |
Condensed_Consolidated_Stateme4
Condensed Consolidated Statements of Changes in Equity (USD $) | Total | Common Stock [Member] | AOCI [Member] | Retained Earnings [Member] | Total Company Common Stockholders' Equity [Member] | Non-controlling Interest in Valencia [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] |
In Thousands, unless otherwise specified | Common Stock [Member] | AOCI [Member] | Retained Earnings [Member] | Total Company Common Stockholders' Equity [Member] | Non-controlling Interest in Valencia [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | AOCI [Member] | Retained Earnings [Member] | ||||||||
Balance at Dec. 31, 2012 | $1,689,030 | $1,182,819 | ($81,630) | $506,998 | $1,608,187 | $80,843 | $1,334,906 | $1,061,776 | ($81,414) | $273,701 | $1,254,063 | $80,843 | ' | ' | ' | ' | ' |
Balance TNMP at Dec. 31, 2012 | 1,608,187 | ' | ' | ' | ' | ' | 1,254,063 | ' | ' | ' | ' | ' | 463,814 | 64 | 390,366 | -216 | 73,600 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from stock option exercise | 3,500 | 3,500 | 0 | 0 | 3,500 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Awards of common stock | -12,429 | -12,429 | 0 | 0 | -12,429 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Excess tax (shortfall) from stock-based payment arrangements | -519 | -519 | 0 | 0 | -519 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock based compensation expense | 4,315 | 4,315 | 0 | 0 | 4,315 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Valencia's transactions with its owner | -13,477 | 0 | 0 | 0 | 0 | -13,477 | -13,477 | 0 | 0 | 0 | 0 | -13,477 | ' | ' | ' | ' | ' |
Net Earnings | 92,859 | ' | ' | ' | ' | ' | 85,516 | ' | ' | ' | ' | ' | 22,170 | 0 | 0 | 0 | 22,170 |
Net earnings before subsidiary preferred stock dividends | 104,159 | 0 | 0 | 93,255 | 93,255 | 10,904 | 96,420 | 0 | 0 | 85,516 | 85,516 | 10,904 | ' | ' | ' | ' | ' |
Subsidiary preferred stock dividends | -396 | 0 | 0 | -396 | -396 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total other comprehensive income (loss) | 8,704 | 0 | 8,704 | 0 | 8,704 | 0 | 8,841 | 0 | 8,841 | 0 | 8,841 | 0 | -137 | 0 | 0 | -137 | 0 |
Dividends declared on preferred stock | ' | ' | ' | ' | ' | ' | -396 | 0 | 0 | -396 | -396 | 0 | ' | ' | ' | ' | ' |
Dividends declared on common stock | -39,428 | 0 | 0 | -39,428 | -39,428 | 0 | -68,028 | 0 | 0 | -68,028 | -68,028 | 0 | -3,726 | 0 | 0 | 0 | -3,726 |
Balance TNMP at Sep. 30, 2013 | 1,665,189 | ' | ' | ' | ' | ' | 1,279,996 | ' | ' | ' | ' | ' | 482,121 | 64 | 390,366 | -353 | 92,044 |
Balance at Sep. 30, 2013 | 1,743,459 | 1,177,686 | -72,926 | 560,429 | 1,665,189 | 78,270 | 1,358,266 | 1,061,776 | -72,573 | 290,793 | 1,279,996 | 78,270 | ' | ' | ' | ' | ' |
Balance at Jun. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Earnings | 54,555 | ' | ' | ' | ' | ' | 47,823 | ' | ' | ' | ' | ' | 10,106 | ' | ' | ' | ' |
Net earnings before subsidiary preferred stock dividends | 58,814 | ' | ' | ' | ' | ' | 51,950 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Subsidiary preferred stock dividends | -132 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total other comprehensive income (loss) | 5,668 | ' | ' | ' | ' | ' | 5,871 | ' | ' | ' | ' | ' | -203 | ' | ' | ' | ' |
Balance TNMP at Sep. 30, 2013 | 1,665,189 | ' | ' | ' | ' | ' | 1,279,996 | ' | ' | ' | ' | ' | 482,121 | ' | ' | ' | ' |
Balance at Sep. 30, 2013 | $1,743,459 | ' | ' | ' | ' | ' | $1,358,266 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Significant_Accounting_Policie
Significant Accounting Policies and Responsibility for Financial Statements | 9 Months Ended |
Sep. 30, 2013 | |
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, 2013 and December 31, 2012, the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2013 and 2012, and the consolidated cash flows for the nine months ended September 30, 2013 and 2012. 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 2012 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2013 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 2012 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 the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. | |
PNMR shared services' administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12. | |
Dividends on Common Stock | |
Dividends on PNMR's common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.165 per share in July 2013 and $0.145 in July 2012, 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 $0.165 per share in September 2013 and $0.145 in September 2012, which are reflected as being in the third quarter within "Dividends Declared per Common Share" on the PNMR Condensed Consolidated Statements of Earnings. | |
PNM declared and paid cash dividends on its common stock to PNMR of $68.0 million in the nine months ended September 30, 2013. PNM declared a cash dividend on its common stock to PNMR of $16.8 million in September 2012, which was paid in October 2012, and declared and paid a dividend of $17.7 million in June 2012. TNMP declared and paid cash dividends to PNMR of $3.7 million and $11.0 million in the nine months ended September 30, 2013 and 2012. TNMP dividends paid in 2012 were recorded as reductions of paid-in-capital. | |
New Accounting Pronouncements | |
Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. | |
Accounting Standards Update 2013-11 - Income Taxes: Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists | |
The FASB released guidance that requires entities to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for net operating losses in certain circumstances. The guidance is to be applied prospectively and is effective for annual and interim reporting periods beginning after December 15, 2013, with early adoption permitted. The Company is still analyzing the impacts of this new standard and when to adopt it. However, it appears that the new standard will result in substantially all of the Company's liability for unrecognized tax benefits being reclassified from being reflected in liability accounts to being reflected as reductions of deferred tax assets. Adoption of this standard is not expected to impact earnings. |
Segment_Information
Segment Information | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Segment Information | ' | |||||||||||||||
Segment Information | ||||||||||||||||
The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. | ||||||||||||||||
PNM | ||||||||||||||||
PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the general wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM's jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale and transmission rates. | ||||||||||||||||
TNMP | ||||||||||||||||
TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP's operations are subject to traditional rate regulation by the PUCT. | ||||||||||||||||
Corporate and Other | ||||||||||||||||
The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. | ||||||||||||||||
The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. | ||||||||||||||||
PNMR SEGMENT INFORMATION | ||||||||||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
Three Months Ended September 30, 2013 | (In thousands) | |||||||||||||||
Electric operating revenues | $ | 326,026 | $ | 73,704 | $ | — | $ | 399,730 | ||||||||
Cost of energy | 100,200 | 14,474 | — | 114,674 | ||||||||||||
Margin | 225,826 | 59,230 | — | 285,056 | ||||||||||||
Other operating expenses | 104,730 | 23,126 | (3,282 | ) | 124,574 | |||||||||||
Depreciation and amortization | 25,879 | 13,850 | 3,014 | 42,743 | ||||||||||||
Operating income | 95,217 | 22,254 | 268 | 117,739 | ||||||||||||
Interest income | 2,298 | — | (34 | ) | 2,264 | |||||||||||
Other income (deductions) | 2,211 | 716 | (3,455 | ) | (528 | ) | ||||||||||
Net interest charges | (20,124 | ) | (6,655 | ) | (3,586 | ) | (30,365 | ) | ||||||||
Segment earnings (loss) before income taxes | 79,602 | 16,315 | (6,807 | ) | 89,110 | |||||||||||
Income taxes (benefit) | 27,652 | 6,209 | (3,565 | ) | 30,296 | |||||||||||
Segment earnings (loss) | 51,950 | 10,106 | (3,242 | ) | 58,814 | |||||||||||
Valencia non-controlling interest | (4,127 | ) | — | — | (4,127 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 47,691 | $ | 10,106 | $ | (3,242 | ) | $ | 54,555 | |||||||
Nine Months Ended September 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 863,609 | $ | 201,384 | $ | — | $ | 1,064,993 | ||||||||
Cost of energy | 283,715 | 41,324 | — | 325,039 | ||||||||||||
Margin | 579,894 | 160,060 | — | 739,954 | ||||||||||||
Other operating expenses | 311,372 | 67,274 | (10,192 | ) | 368,454 | |||||||||||
Depreciation and amortization | 77,763 | 37,810 | 9,616 | 125,189 | ||||||||||||
Operating income | 190,759 | 54,976 | 576 | 246,311 | ||||||||||||
Interest income | 7,839 | — | (108 | ) | 7,731 | |||||||||||
Other income (deductions) | 6,977 | 1,409 | (7,390 | ) | 996 | |||||||||||
Net interest charges | (59,971 | ) | (20,661 | ) | (11,647 | ) | (92,279 | ) | ||||||||
Segment earnings (loss) before income taxes | 145,604 | 35,724 | (18,569 | ) | 162,759 | |||||||||||
Income taxes (benefit) | 49,184 | 13,554 | (4,138 | ) | 58,600 | |||||||||||
Segment earnings (loss) | 96,420 | 22,170 | (14,431 | ) | 104,159 | |||||||||||
Valencia non-controlling interest | (10,904 | ) | — | — | (10,904 | ) | ||||||||||
Subsidiary preferred stock dividends | (396 | ) | — | — | (396 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 85,120 | $ | 22,170 | $ | (14,431 | ) | $ | 92,859 | |||||||
At September 30, 2013: | ||||||||||||||||
Total Assets | $ | 4,192,470 | $ | 1,162,587 | $ | 73,757 | $ | 5,428,814 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Additions to utility and non-utility plant included in accounts payable | $ | 15,995 | $ | 544 | $ | 1,668 | $ | 18,207 | ||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
Three Months Ended September 30, 2012 | (In thousands) | |||||||||||||||
Electric operating revenues | $ | 321,731 | $ | 68,680 | $ | — | $ | 390,411 | ||||||||
Cost of energy | 99,217 | 11,560 | — | 110,777 | ||||||||||||
Margin | 222,514 | 57,120 | — | 279,634 | ||||||||||||
Other operating expenses | 101,104 | 22,331 | (4,771 | ) | 118,664 | |||||||||||
Depreciation and amortization | 24,437 | 13,819 | 4,564 | 42,820 | ||||||||||||
Operating income | 96,973 | 20,970 | 207 | 118,150 | ||||||||||||
Interest income | 3,173 | — | (43 | ) | 3,130 | |||||||||||
Other income (deductions) | 5,210 | 366 | (827 | ) | 4,749 | |||||||||||
Net interest charges | (19,230 | ) | (7,047 | ) | (4,238 | ) | (30,515 | ) | ||||||||
Segment earnings (loss) before income taxes | 86,126 | 14,289 | (4,901 | ) | 95,514 | |||||||||||
Income taxes (benefit) | 31,235 | 5,205 | (2,902 | ) | 33,538 | |||||||||||
Segment earnings (loss) | 54,891 | 9,084 | (1,999 | ) | 61,976 | |||||||||||
Valencia non-controlling interest | (3,980 | ) | — | — | (3,980 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 50,779 | $ | 9,084 | $ | (1,999 | ) | $ | 57,864 | |||||||
Nine Months Ended September 30, 2012 | ||||||||||||||||
Electric operating revenues | $ | 832,242 | $ | 187,404 | $ | — | $ | 1,019,646 | ||||||||
Cost of energy | 263,009 | 34,333 | — | 297,342 | ||||||||||||
Margin | 569,233 | 153,071 | — | 722,304 | ||||||||||||
Other operating expenses | 311,468 | 64,239 | (12,676 | ) | 363,031 | |||||||||||
Depreciation and amortization | 72,017 | 37,173 | 13,099 | 122,289 | ||||||||||||
Operating income (loss) | 185,748 | 51,659 | (423 | ) | 236,984 | |||||||||||
Interest income | 9,938 | 1 | (131 | ) | 9,808 | |||||||||||
Other income (deductions) | 9,201 | 1,244 | (4,797 | ) | 5,648 | |||||||||||
Net interest charges | (56,652 | ) | (21,214 | ) | (12,414 | ) | (90,280 | ) | ||||||||
Segment earnings (loss) before income taxes | 148,235 | 31,690 | (17,765 | ) | 162,160 | |||||||||||
Income taxes (benefit) | 51,929 | 11,577 | (8,897 | ) | 54,609 | |||||||||||
Segment earnings (loss) | 96,306 | 20,113 | (8,868 | ) | 107,551 | |||||||||||
Valencia non-controlling interest | (10,699 | ) | — | — | (10,699 | ) | ||||||||||
Subsidiary preferred stock dividends | (396 | ) | — | — | (396 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 85,211 | $ | 20,113 | $ | (8,868 | ) | $ | 96,456 | |||||||
At September 30, 2012: | ||||||||||||||||
Total Assets | $ | 4,073,331 | $ | 1,060,062 | $ | 126,814 | $ | 5,260,207 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Additions to utility and non-utility plant included in accounts payable | $ | 6,056 | $ | 886 | $ | 1,063 | $ | 8,005 | ||||||||
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income (Loss) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
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, 2013 is as follows: | ||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Investment | Liability | for Cash Flow | ||||||||||||||
Securities | Adjustment | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
PNMR | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | (216 | ) | $ | (81,630 | ) | |||||
 Amounts reclassified from AOCI (pre-tax) | (9,190 | ) | 4,773 | 153 | (4,264 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,639 | (1,893 | ) | (54 | ) | 1,692 | ||||||||||
 Other OCI changes (pre-tax) | 19,056 | — | (363 | ) | 18,693 | |||||||||||
Income tax impact of other OCI changes | (7,544 | ) | — | 127 | (7,417 | ) | ||||||||||
Net change after income taxes | 5,961 | 2,880 | (137 | ) | 8,704 | |||||||||||
Balance at September 30, 2013 | $ | 22,367 | $ | (94,940 | ) | $ | (353 | ) | $ | (72,926 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | — | $ | (81,414 | ) | ||||||
 Amounts reclassified from AOCI (pre-tax) | (9,190 | ) | 4,773 | — | (4,417 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,639 | (1,893 | ) | — | 1,746 | |||||||||||
 Other OCI changes (pre-tax) | 19,056 | — | — | 19,056 | ||||||||||||
Income tax impact of other OCI changes | (7,544 | ) | — | — | (7,544 | ) | ||||||||||
Net change after income taxes | 5,961 | 2,880 | — | 8,841 | ||||||||||||
Balance at September 30, 2013 | $ | 22,367 | $ | (94,940 | ) | $ | — | $ | (72,573 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2012 | $ | — | $ | — | $ | (216 | ) | $ | (216 | ) | ||||||
 Amounts reclassified from AOCI (pre-tax) | — | — | 153 | 153 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (54 | ) | (54 | ) | ||||||||||
 Other OCI changes (pre-tax) | — | — | (363 | ) | (363 | ) | ||||||||||
Income tax impact of other OCI changes | — | — | 127 | 127 | ||||||||||||
Net change after income taxes | — | — | (137 | ) | (137 | ) | ||||||||||
Balance at September 30, 2013 | $ | — | $ | — | $ | (353 | ) | $ | (353 | ) | ||||||
Pre-tax amounts reclassified from AOCI related to "Unrealized Gain on Investment Securities" are included in "Gains on investments held by NDT" 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. Approximately 19.6% of the amount reclassified is then capitalized into construction work in process and approximately 1.1% is capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to "Fair Value Adjustment for Cash Flow Hedges" are reclassified to "Interest Charges" in the Condensed Consolidated Statements of Earnings. An insignificant amount is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in "Income Taxes" in the Condensed Consolidated Statements of Earnings. |
Variable_Interest_Entities
Variable Interest Entities | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Variable Interest Entities | ' | |||||||||||||||
Variable Interest Entities | ' | |||||||||||||||
Variable Interest Entities | ||||||||||||||||
GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity, by focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM's variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. | ||||||||||||||||
Valencia | ||||||||||||||||
PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 145 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operations and maintenance charges under this PPA. For the three and nine months ended September 30, 2013, PNM paid $4.8 million and $14.1 million for fixed charges and $0.7 million and $1.0 million for variable charges. For the three and nine months ended September 30, 2012, PNM paid $4.8 million and $14.0 million for fixed charges and $0.6 million and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM's assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner's equity and net income of Valencia are considered attributable to non-controlling interest. | ||||||||||||||||
During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. | ||||||||||||||||
The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process will be initiated if the parties fail to reach agreement on fair market value within 60 days. After the purchase price has been determined, PNM may in its sole discretion determine whether or not it desires to exercise its option to purchase the 50% interest. In that regard, PNM will evaluate all its alternatives with respect to Valencia with the goal of achieving a fair and economical benefit for its customers. Also, PNM is in the process of developing its 2014 IRP (Note 11). Through this process, PNM will evaluate all of its resource options including Valencia to determine the optimal way to serve its customers. If PNM decides to exercise its option, the approval of the NMPRC and FERC would be required, which process could take up to 15 months. Since the purchase price is yet to be established, PNM cannot determine whether or not it will exercise its option or if required regulatory approvals would be received. | ||||||||||||||||
Summarized financial information for Valencia is as follows: | ||||||||||||||||
Results of Operations | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands) | ||||||||||||||||
Operating revenues | $ | 5,453 | $ | 5,358 | $ | 15,150 | $ | 14,916 | ||||||||
Operating expenses | (1,326 | ) | (1,378 | ) | (4,246 | ) | (4,217 | ) | ||||||||
Earnings attributable to non-controlling interest | $ | 4,127 | $ | 3,980 | $ | 10,904 | $ | 10,699 | ||||||||
Financial Position | ||||||||||||||||
September 30, | December 31, | |||||||||||||||
2013 | 2012 | |||||||||||||||
(In thousands) | ||||||||||||||||
Current assets | $ | 3,457 | $ | 3,655 | ||||||||||||
Net property, plant, and equipment | 75,841 | 77,953 | ||||||||||||||
Total assets | 79,298 | 81,608 | ||||||||||||||
Current liabilities | 1,028 | 765 | ||||||||||||||
Owners' equity – non-controlling interest | $ | 78,270 | $ | 80,843 | ||||||||||||
PVNGS Leases    | ||||||||||||||||
PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. As set forth in the leases, PNM has options to renew the leases at fixed rates, which represent 50% of the amounts during the original terms of the leases, for two years beyond the termination of the original lease terms. The option periods on all of the Unit 1 leases and one of the Unit 2 leases, amounting to 14% of the Unit 2 capacity under lease, may be further extended for up to an additional six years (the "Maximum Option Period") if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM notified each of the lessors of the Unit 1 leases that it will extend each Unit 1 lease for the Maximum Option Period upon the expiration of the basic lease term on January 15, 2015. In addition, PNM notified each of the lessors in the Unit 2 leases that PNM will "retain" the assets leased under that lease upon the expiration of the basic lease term on January 15, 2016. PNM will be required to specify by notice to each of the lessors by January 15, 2014, whether on January 15, 2016 it will extend the Unit 2 leases or purchase the leased assets. PNM is unable to predict the outcome or impact of these matters. | ||||||||||||||||
PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes, aggregate $52.6 million as of September 30, 2013 over the remaining original terms of the leases. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2013, PNM could have been required to pay the beneficial owners up to $154.1 million, which would result in PNM taking ownership of the leased assets and termination of the leases. PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM's assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. | ||||||||||||||||
PNM has evaluated the PVNGS lease arrangements, including the notices discussed above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $11.8 million at September 30, 2013 and $26.0 million at December 31, 2012, that are included in other current liabilities on the Condensed Consolidated Balance Sheets. For additional information regarding these leases, see Risk Factors, MD&A – Off Balance Sheet Arrangements and Note 7 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. | ||||||||||||||||
Delta | ||||||||||||||||
PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. PNM makes fixed and variable payments to Delta under the PPA. For the three and nine months ended September 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $4.8 million and variable energy charges of $0.7 million and $1.3 million under the PPA. For the three and nine months ended September 30, 2012, PNM incurred fixed capacity charges of $1.6 million and $4.7 million and variable energy charges of $0.3 million and $0.6 million. PNM's only quantifiable obligation under the PPA is to make the fixed payments, which as of September 30, 2013, aggregated $40.7 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation. | ||||||||||||||||
This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease. | ||||||||||||||||
In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owns Delta. At closing PNM would make a cash payment of $23.0 million, which would be adjusted for actual working capital compared to a targeted working capital and certain prepayments of debt. Delta had project financing debt, which PNM would retire at closing of the purchase, of $16.9 million at September 30, 2013, including $3.2 million due by September 30, 2014. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing is subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. Closing of the purchase is anticipated to occur in early 2014. | ||||||||||||||||
Delta informed PNM that at September 30, 2013, it had total assets of $25.3 million, including net property, plant, and equipment of $21.0 million, and total liabilities of $18.9 million. Delta also indicated its revenue for the three and nine months ended September 30, 2013 was $2.8 million and $6.8 million and its net earnings were $0.6 million and $0.9 million. Consolidation of Delta would be immaterial to the Condensed Consolidated Balance Sheets of PNMR and PNM. Since all of Delta's revenues and expenses are attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would be to reclassify Delta's net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM. |
Fair_Value_of_Derivative_and_O
Fair Value of Derivative and Other Financial Instruments | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Abstract] | ' | |||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments | ' | |||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments | ||||||||||||||||||||
Energy Related Derivative Contracts | ||||||||||||||||||||
Overview | ||||||||||||||||||||
The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company's energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM's operations are managed primarily through a net asset-backed strategy, whereby PNM's aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated, to the extent not covered by the FPPAC. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company's energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. | ||||||||||||||||||||
Commodity Risk | ||||||||||||||||||||
Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies. | ||||||||||||||||||||
Accounting for Derivatives | ||||||||||||||||||||
Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company's intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal sales and purchases exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal sales and purchases are not marked to market and are reflected in results of operations when the underlying transactions physically settle. | ||||||||||||||||||||
During the nine months ended September 30, 2013 and the year ended December 31, 2012, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the economic hedge. The Company does not enter into speculative trading transactions. | ||||||||||||||||||||
Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties' and the Company's credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique. | ||||||||||||||||||||
Commodity Derivatives | ||||||||||||||||||||
Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Current assets | $ | 5,743 | $ | 3,785 | ||||||||||||||||
Deferred charges | 4,284 | 352 | ||||||||||||||||||
10,027 | 4,137 | |||||||||||||||||||
Current liabilities | (1,017 | ) | (1,000 | ) | ||||||||||||||||
Long-term liabilities | (1,347 | ) | (1,933 | ) | ||||||||||||||||
(2,364 | ) | (2,933 | ) | |||||||||||||||||
Net | $ | 7,663 | $ | 1,204 | ||||||||||||||||
Included in the above table are $2.3 million of current assets and $3.8 million of deferred charges related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM's commodity derivative instruments included in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2013 and December 31, 2012. | ||||||||||||||||||||
At September 30, 2013 and December 31, 2012, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at September 30, 2013 and December 31, 2012, amounts posted as cash collateral under margin arrangements were $2.0 million and $1.9 million for both PNMR and PNM. PNMR and PNM had no obligation to return cash collateral at September 30, 2013 and December 31, 2012. Cash collateral amounts are included in other current assets on the Condensed Consolidated Balance Sheets. | ||||||||||||||||||||
  | ||||||||||||||||||||
PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.6 million of current assets, $0.1 million of deferred charges and $0.1 million of current liabilities at September 30, 2013 and less than $0.1 million of current assets at December 31, 2012 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 on earnings, excluding income tax effects and settlements, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented. | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Electric operating revenues | $ | 7,077 | $ | (740 | ) | $ | 5,743 | $ | 897 | |||||||||||
Cost of energy | (72 | ) | 263 | 421 | (278 | ) | ||||||||||||||
   Total gain (loss) | $ | 7,005 | $ | (477 | ) | $ | 6,164 | $ | 619 | |||||||||||
Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR's and PNM's net buy (sell) volume positions: | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
MMBTU | MWh | |||||||||||||||||||
September 30, 2013 | ||||||||||||||||||||
PNMR and PNM | 980,000 | (3,801,738 | ) | |||||||||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR and PNM | 1,127,500 | (2,477,520 | ) | |||||||||||||||||
In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company's credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with "adequate assurance" that the Company will perform; and others have no provision for collateral. | ||||||||||||||||||||
The table below presents information about the Company's contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company's revolving credit facilities that have been issued as | ||||||||||||||||||||
collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. | ||||||||||||||||||||
Contingent Feature – | Contractual Liability | Existing Cash Collateral | Net Exposure | |||||||||||||||||
Credit Rating Downgrade | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
September 30, 2013 | ||||||||||||||||||||
PNMR and PNM | $ | 2,250 | $ | — | $ | 2,224 | ||||||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR and PNM | $ | 2,933 | $ | — | $ | 2,777 | ||||||||||||||
Sale of Power from PVNGS Unit 3 | ||||||||||||||||||||
Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of September 30, 2013, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. PNM has established fixed rates for substantially all of these sales through the end of 2013 through derivative contracts that are accounted for as economic hedges. PNM is also substantially hedged for 2014. | ||||||||||||||||||||
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, which include unrealized gains on securities which have not been recognized in net earnings. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM's share of post-term reclamation | ||||||||||||||||||||
costs related to the coal mines serving SJGS, which investments are included in "other investments" on the Condensed Consolidated Balance Sheet. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. | ||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||
Unrealized Gains | Fair Value | Unrealized Gains | Fair Value | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 24,414 | $ | — | $ | 4,628 | ||||||||||||
Equity securities: | ||||||||||||||||||||
   Domestic value | 10,519 | 34,967 | 5,223 | 30,044 | ||||||||||||||||
   Domestic growth | 23,355 | 67,527 | 15,212 | 51,650 | ||||||||||||||||
International and other | 1,543 | 16,159 | 247 | 14,868 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
   U.S. Government | 262 | 16,711 | 1,305 | 32,592 | ||||||||||||||||
   Municipals | 1,120 | 37,074 | 4,069 | 43,861 | ||||||||||||||||
   Corporate and other | 221 | 14,553 | 1,100 | 14,868 | ||||||||||||||||
$ | 37,020 | $ | 211,405 | $ | 27,156 | $ | 192,511 | |||||||||||||
The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Proceeds from sales | $ | 103,230 | $ | 90,518 | $ | 179,336 | $ | 136,305 | ||||||||||||
Gross realized gains | $ | 2,611 | $ | 6,263 | $ | 8,962 | $ | 11,029 | ||||||||||||
Gross realized (losses) | $ | (1,202 | ) | $ | (5,131 | ) | $ | (2,920 | ) | $ | (7,055 | ) | ||||||||
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments. | ||||||||||||||||||||
At September 30, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities: | ||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Available-for-Sale | Held-to-Maturity | |||||||||||||||||||
PNMR and PNM | PNMR | PNM | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Within 1 year | $ | 1,284 | $ | 4,840 | $ | 1,138 | ||||||||||||||
After 1 year through 5 years | 16,768 | 55,310 | 53,956 | |||||||||||||||||
After 5 years through 10 years | 8,027 | — | — | |||||||||||||||||
After 10 years through 15 years | 3,277 | — | — | |||||||||||||||||
After 15 years through 20 years | 5,512 | — | — | |||||||||||||||||
After 20 years | 33,470 | — | — | |||||||||||||||||
$ | 68,338 | $ | 60,150 | $ | 55,094 | |||||||||||||||
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. | ||||||||||||||||||||
Fair Value Disclosures | ||||||||||||||||||||
The Company determines the fair values of its derivative and other 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 can 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. | ||||||||||||||||||||
For the NDT and reclamation trust investments, 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 long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services. | ||||||||||||||||||||
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, 2013 and 2012. | ||||||||||||||||||||
Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | ||||||||||||||||||
September 30, 2013 | (In thousands) | |||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Decommissioning and reclamation investments: | ||||||||||||||||||||
   Cash and cash equivalents | $ | 24,414 | $ | 24,414 | $ | — | ||||||||||||||
   Equity securities: | ||||||||||||||||||||
     Domestic value | 34,967 | 34,967 | — | |||||||||||||||||
     Domestic growth | 67,527 | 67,527 | — | |||||||||||||||||
International and other | 16,159 | 16,159 | — | |||||||||||||||||
   Fixed income securities: | ||||||||||||||||||||
     U.S. government | 16,711 | 14,949 | 1,762 | |||||||||||||||||
     Municipals | 37,074 | — | 37,074 | |||||||||||||||||
     Corporate and other | 14,553 | — | 14,553 | |||||||||||||||||
          | $ | 211,405 | $ | 158,016 | $ | 53,389 | ||||||||||||||
Commodity derivative assets | $ | 10,027 | $ | — | $ | 10,027 | ||||||||||||||
Commodity derivative liabilities | (2,364 | ) | — | (2,364 | ) | |||||||||||||||
          Net | $ | 7,663 | $ | — | $ | 7,663 | ||||||||||||||
31-Dec-12 | ||||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Decommissioning and reclamation investments: | ||||||||||||||||||||
   Cash and cash equivalents | $ | 4,628 | $ | 4,628 | $ | — | ||||||||||||||
   Equity securities: | ||||||||||||||||||||
     Domestic value | 30,044 | 30,044 | — | |||||||||||||||||
     Domestic growth | 51,650 | 51,650 | — | |||||||||||||||||
     International and other | 14,868 | 14,868 | — | |||||||||||||||||
   Fixed income securities: | ||||||||||||||||||||
     U.S. government | 32,592 | 27,737 | 4,855 | |||||||||||||||||
     Municipals | 43,861 | — | 43,861 | |||||||||||||||||
     Corporate and other | 14,868 | — | 14,868 | |||||||||||||||||
          | $ | 192,511 | $ | 128,927 | $ | 63,584 | ||||||||||||||
Commodity derivative assets | $ | 4,137 | $ | — | $ | 4,137 | ||||||||||||||
Commodity derivative liabilities | (2,933 | ) | — | (2,933 | ) | |||||||||||||||
          Net | $ | 1,204 | $ | — | $ | 1,204 | ||||||||||||||
There were no Level 3 fair value measurements at September 30, 2013 or December 31, 2012. | ||||||||||||||||||||
The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | ||||||||||||||||
September 30, 2013 | (In thousands) | |||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,748,841 | $ | 1,929,828 | $ | — | $ | 1,926,126 | $ | 3,702 | ||||||||||
Investment in PVNGS lessor notes | $ | 53,300 | $ | 55,094 | $ | — | $ | — | $ | 55,094 | ||||||||||
Other investments | $ | 2,803 | $ | 6,941 | $ | 739 | $ | — | $ | 6,202 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,290,608 | $ | 1,400,109 | $ | — | $ | 1,400,109 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 53,300 | $ | 55,094 | $ | — | $ | — | $ | 55,094 | ||||||||||
Other investments | $ | 458 | $ | 458 | $ | 458 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 336,128 | $ | 393,122 | $ | — | $ | 393,122 | $ | — | ||||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — | ||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,672,290 | $ | 1,969,362 | $ | — | $ | 1,966,725 | $ | 2,637 | ||||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | ||||||||||
Other investments | $ | 5,599 | $ | 6,965 | $ | 774 | $ | — | $ | 6,191 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,215,579 | $ | 1,385,433 | $ | — | $ | 1,385,433 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | ||||||||||
Other investments | $ | 494 | $ | 494 | $ | 494 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 311,589 | $ | 418,166 | $ | — | $ | 418,166 | $ | — | ||||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — | ||||||||||
Earnings_Per_Share
Earnings Per Share | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
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, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Net Earnings Attributable to PNMR | $ | 54,555 | $ | 57,864 | $ | 92,859 | $ | 96,456 | ||||||||
Average Number of Common Shares: | ||||||||||||||||
Outstanding during period | 79,654 | 79,654 | 79,654 | 79,654 | ||||||||||||
    Vested awards of restricted stock | 177 | 114 | 194 | 156 | ||||||||||||
Average Shares - Basic | 79,831 | 79,768 | 79,848 | 79,810 | ||||||||||||
Dilutive Effect of Common Stock Equivalents (1): | ||||||||||||||||
Stock options and restricted stock | 503 | 622 | 608 | 600 | ||||||||||||
Average Shares - Diluted | 80,334 | 80,390 | 80,456 | 80,410 | ||||||||||||
Net Earnings Per Share of Common Stock: | ||||||||||||||||
Basic | $ | 0.68 | $ | 0.73 | $ | 1.16 | $ | 1.21 | ||||||||
Diluted | $ | 0.68 | $ | 0.72 | $ | 1.15 | $ | 1.2 | ||||||||
(1) | Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013. |
StockBased_Compensation
Stock-Based Compensation | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
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"). In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2013 or 2012 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and have service requirements. 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 2012 Annual Reports on Form 10-K. | ||||||||||||||
Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in stock awards. | ||||||||||||||
The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the award date is recognized immediately at the award date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2013 and December 31, 2012, PNMR had unrecognized expense related to stock awards of $5.7 million and $3.8 million. | ||||||||||||||
The Company uses the Black Scholes option pricing model to estimate the fair value of stock option awards based on multiple factors, including historical exercise patterns of employees in relatively homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected exercising patterns for these same homogeneous groups, and both the implied and historical volatility of PNMR's stock price. 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 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. | ||||||||||||||
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 | 2013 | 2012 | ||||||||||||
Expected quarterly dividends per share | $ | 0.165 | $ | 0.145 | ||||||||||
Risk-free interest rate | 0.34 | % | 0.65 | % | ||||||||||
Market-Based Shares | ||||||||||||||
Dividend yield | 2.86 | % | 3.45 | % | ||||||||||
Expected volatility | 25.11 | % | 43.98 | % | ||||||||||
Risk-free interest rate | 0.36 | % | 1.04 | % | ||||||||||
The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months ended September 30, 2013: | ||||||||||||||
Stock Option Shares | Weighted- | Restricted Stock | Weighted- | |||||||||||
Average | Average | |||||||||||||
Exercise | Grant Date Fair Value | |||||||||||||
Price | ||||||||||||||
Outstanding at beginning of period | 1,992,700 | $ | 20.72 | 353,722 | $ | 14.03 | ||||||||
Granted | — | $ | — | 249,113 | $ | 20.03 | ||||||||
Exercised | (260,579 | ) | $ | 13.43 | (275,988 | ) | $ | 15.92 | ||||||
Forfeited | — | $ | — | (8,366 | ) | $ | 18.37 | |||||||
Expired | (292,644 | ) | $ | 27.23 | — | $ | — | |||||||
Outstanding at end of period | 1,439,477 | $ | 20.72 | 318,481 | $ | 17.88 | ||||||||
Included as restricted stock granted and exercised in the table above are 100,953 shares that were based upon achieving performance or market targets for 2012. The Board approved these shares in February 2013, including shares with market targets at near maximum levels. | ||||||||||||||
PNMR also has share agreements that provide for performance or market targets through 2015. Excluded from the above table are maximums of 188,129, 198,369, and 179,811 restricted stock shares for periods ending in 2013, 2014, and 2015 that would be awarded if all performance or market criteria are achieved and all executives remain eligible. | ||||||||||||||
In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR's common stock if the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any shares under the retention award agreement. | ||||||||||||||
     | ||||||||||||||
At September 30, 2013, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.7 million with a weighted-average remaining contract life of 3.56 years. At September 30, 2013, the exercise price of 793,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value. | ||||||||||||||
The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: | ||||||||||||||
Nine Months Ended September 30, | ||||||||||||||
Stock Options | 2013 | 2012 | ||||||||||||
Weighted-average grant date fair value of options granted | $ | — | $ | — | ||||||||||
Total fair value of options that vested (in thousands) | $ | 625 | $ | 1,058 | ||||||||||
Total intrinsic value of options exercised (in thousands) | $ | 2,466 | $ | 4,515 | ||||||||||
Restricted Stock | ||||||||||||||
Weighted-average grant date fair value | $ | 20.03 | $ | 15.63 | ||||||||||
Total fair value of restricted shares that vested (in thousands) | $ | 4,395 | $ | 4,755 | ||||||||||
Financing
Financing | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Financing | ' | ||||||||
Financing | |||||||||
Additional information concerning financing activities, including a TNMP cash-flow hedge that establishes a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. | |||||||||
Short-term Debt | |||||||||
PNMR has a revolving credit financing capacity of $300.0 million under the PNMR Revolving Credit Facility. PNM has a revolving credit financing capacity of $400.0 million under the PNM Revolving Credit Facility. Both of these facilities currently expire on October 31, 2018. In December 2012, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement, which matures in December 2013. TNMP has a revolving credit financing capacity of $75.0 million under the TNMP Revolving Credit Facility that is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from December 16, 2015 to September 18, 2018. At September 30, 2013, the weighted average interest rate was 1.31% for borrowings outstanding under the PNMR Term Loan Agreement, 1.44% for the PNM Term Loan Agreement, and 1.30% for the TNMP Revolving Credit Facility. Short-term debt outstanding consisted of: | |||||||||
September 30, | December 31, | ||||||||
Short-term Debt | 2013 | 2012 | |||||||
(In thousands) | |||||||||
PNM – Revolving credit facility | $ | — | $ | 21,100 | |||||
TNMP – Revolving credit facility | 12,000 | — | |||||||
PNMR: | |||||||||
Revolving credit facility | — | 37,600 | |||||||
PNMR Term Loan Agreement | 100,000 | 100,000 | |||||||
$ | 112,000 | $ | 158,700 | ||||||
At October 25, 2013, PNMR, PNM, and TNMP had $291.4 million, $396.8 million, and $67.7 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit. Total availability at October 25, 2013, on a consolidated basis, was $755.9 million for PNMR. As of October 25, 2013, TNMP had $43.0 million in borrowings from PNMR under their intercompany loan agreement. At October 25, 2013, PNMR, PNM and TNMP had consolidated invested cash of $6.5 million, $15.7 million, and none. | |||||||||
Financing Activities | |||||||||
On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP's $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in the recording of a $23.2 million premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. A regulatory asset was recorded offsetting the premium and the cash consideration paid in the exchange. | |||||||||
On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the "PNM Term Loan Agreement") among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. The PNM Term Loan Agreement bears interest at a variable rate, which was 1.44% at September 30, 2013, must be repaid on or before October 21, 2014, and is reflected as long-term debt on the Condensed Consolidated Balance Sheets. The PNM Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Term Loan Agreement has a cross default provision and a change of control provision. | |||||||||
In the nine months ended September 30, 2013, PNMR purchased $23.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, for $26.0 million plus accrued and unpaid interest. | |||||||||
On October 2, 2013, the NMPRC approved PNM's application to enter into a new revolving credit facility of up to $50.0 million with banks operating in New Mexico. PNM anticipates entering into a facility in late 2013. | |||||||||
In October 2013, the second of the two 1-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2018. |
Commitments_and_Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2013 | |
Commitments and Contingencies Disclosure [Abstract] | ' |
Commitments and Contingencies | ' |
Commitments and Contingencies | |
Overview | |
There are various claims and lawsuits pending against the Company. The Company is also 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 occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 11) 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. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. 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 2012 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 under the contract. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE's delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The PVNGS owners previously received a damages award for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE's continuing failure to remove spent nuclear fuel and high level waste from PVNGS. Activities in this legal proceeding are currently limited to review by the government of supporting information for APS's claim. PNM is unable to predict the outcome of this matter. | |
PNM estimates that it will incur approximately $42.8 million (in 2010 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, 2013 and December 31, 2012, PNM had a liability for interim storage costs of $12.4 million and $13.9 million included in other deferred credits. | |
On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC's rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC's 2010 update to the agency's Waste Confidence Decision. The D.C. Circuit found that the agency's 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement or a finding of no significant impact from the agency's actions. The D.C. Circuit found that the NRC's evaluation of the environmental risks from spent nuclear was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. The petitioners had also sought a writ requiring the NRC to comply with the law and resume processing DOE's pending license application for a nuclear waste site at Yucca Mountain in Nevada. On August 13, 2013, the D.C. Circuit granted the writ and held that the NRC must continue reviewing the license application. PNM is unable to predict the impact of these decisions. | |
The Clean Air Act | |
Regional Haze | |
In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018. | |
SJGS | |
BART Determination Process - SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology ("SNCR"). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology ("SCR") with stringent NOx emission limits on all four units by September 21, 2016. | |
PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA's decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA's rule in the Tenth Circuit, seeking to shorten its compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court's order, the parties have filed supplemental information. No decision has been announced and there is no deadline for a court decision. | |
In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico's regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree. | |
Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be refined through an "open book" subcontractor bidding process. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below. | |
PNM previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs. | |
Based upon its current SJGS ownership interest, PNM's share of the costs under either SCRs or SNCRs as described above would be about 46.3%. | |
During 2012 and early 2013, PNM engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by EIB and EPA. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. | |
NMPRC approval of the retirement of SJGS Units 2 and 3 and plans for PNM to acquire power to replace its reduced capacity from SJGS would also be part of implementation. PNM also anticipates requesting approval to recover from ratepayers the unrecovered investment in SJGS Units 2 and 3 and costs incurred to retire those units. PNM anticipates filing for the required NMPRC approvals in December 2013. On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order requires PNM to make monthly presentations to the NMPRC on this matter. At September 30, 2013, PNM's net book value of SJGS Units 2 and 3 was approximately $287 million. | |
In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA action on the revised SIP is projected for late 2014. | |
Due to the long lead times on certain equipment purchases, PNM is taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract. | |
In connection with the implementation of the revised plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners as may be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may seek approvals of their utility commissions or governing boards. | |
This revised plan primarily focuses on how SJGS would meet the regional haze rule, but also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized. PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability. | |
Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the terms agreed to do not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the revised SIP. | |
On February 25, 2013, the parties filed their status reports with the Tenth Circuit. To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes. | |
If the February 15, 2013 plan described above is implemented, PNM currently estimates its share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 would be approximately $60 million to $80 million, including gross receipts taxes, AFUDC, and other PNM costs. This amount is based on the anticipation that PNM's ownership share of SJGS Units 1 and 4 would aggregate to between approximately 52% and 55%. PNM also estimates that the cost of replacing a portion of PNM's share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3 with identified gas-fired or solar peaking capacity would be approximately $299 million. Neither of these amounts is included in PNM's current construction expenditure forecast since approval of the plan is subject to numerous conditions. Additional base load generating capacity may be required to replace a portion of retired SJGS capacity. The nature of additional base load capacity, which has not yet been identified, could come from some combination of PVNGS Unit 3, renewable resources, and/or additional gas-fired generation. 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 would increase with the installation of either SCRs or SNCRs. See Note11 for additional information concerning PNM's filing for NMPRC approvals regarding these matters. | |
PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished at all or within the required timeframes. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would likely seek relief from the compliance deadline from EPA or the Tenth Circuit in order to continue to be able to operate the plant during the completion of the installation process. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM's needs or, if available, what costs would be incurred. | |
PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS. PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, 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. | |
SJGS Ownership Restructuring Matters - As discussed in the 2012 Annual Reports on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The San Juan Project Participation Agreement ("SJPPA") that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. Accordingly, they believe they would be unable to fund the construction of either SCRs or SNCRs at SJGS. Therefore, the California participants have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA and sooner, if possible. One other participant has also expressed a similar intent to exit ownership in the plant. | |
The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. The negotiations have included potential shifts in ownership among participants and between units in order to facilitate the shutdown of SJGS Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could result in the exiting participants' ownership interests in SJGS Unit 4 being shifted to SJGS Unit 3 and certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4. In addition, the discussions regarding such a restructuring have included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. Although discussions are continuing, no agreements have been reached. | |
The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or common property. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements, to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants, but has not reached a decision on how to proceed. PNM cannot predict the outcome of this matter, its impact on SJGS' compliance with the CAA, or the impact on PNM's financial position and results of operations. | |
Four Corners | |
On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control strategy finalized by EPA would require the installation of post-combustion controls, including SCRs, on each of Units 1-5 at Four Corners to reduce NOx emissions. Under the second emission control alternative, the owners of Four Corners would have the option to close permanently 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. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/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. Under the EPA's final BART determination, the Four Corners participants had until July 1, 2013 to notify EPA of which emission control strategy Four Corners would follow. Either alternative would involve substantial investment by the owners in additional post-combustion pollution controls and, accordingly, contemplates the continued operation of Four Corners for a substantial period of time. On September 24, 2013, EPA extended the date by which the Four Corners participants must notify EPA of their chosen BART compliance strategy from July 1 to December 31, 2013. | |
The Four Corners participants' obligations to comply with EPA's final BART determinations, coupled with the financial impact of possible future 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. | |
PNM is continuing to evaluate the impacts of EPA's BART determination for Four Corners. PNM estimates its share of costs, including PNM's AFUDC, to be up to approximately $75 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM has no ownership interest in Four Corners Units 1, 2, and 3. PNM is unable to predict the ultimate outcome of this matter. | |
SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE's 48% interest in each of Units 4 and 5 of Four Corners. A principal remaining condition to closing is the negotiation and execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will shut down Units 1, 2, and 3 at Four Corners. On May 9, 2013, the Arizona Corporation Commission ("ACC"), which regulates APS, voted to re-examine the facilitation of a deregulated retail electric market in Arizona. In connection with this matter, APS announced that it would not be in a position to close the Four Corners purchase transaction with SCE until the ACC's intentions with regard to pursuing deregulation in Arizona became clearer. In September 2013, the ACC closed the deregulation docket. Certain parties have filed motions for rehearing, which are pending before the ACC. Pursuant to the asset purchase agreement, because all of the closing conditions were not originally satisfied by December 31, 2012, either APS or SCE has a right to terminate the agreement, unless the party seeking to terminate is then in breach. Although the ACC closed its deregulation docket, APS has reported that it cannot predict whether the closing conditions will be satisfied such that closing of its planned purchase of SCE's interest in Four Corners can occur. | |
Four Corners BART FIP Challenge | |
On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP. In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA. APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS' motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. This matter is now proceeding in the Tenth Circuit. PNM cannot currently predict the outcome of this matter or the range of its potential impact. | |
Regional Haze Challenges | |
On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO2 and particulate matter emissions elements of EPA's approval of New Mexico's Regional Haze SIP. Â On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA's final approval of the remaining elements of New Mexico's Regional Haze SIP, as well as EPA's approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. This matter is now proceeding in the Tenth Circuit. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes. | |
SJGS Operating Permit Challenge | |
On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS's operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG. EPA's order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has violated any emission limits. | |
In August 2012, NMED issued a response to the EPA order stating that SJGS's operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO2 and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide ("CO") emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved. | |
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, SO2, ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO2 NAAQS. On May 21, 2013, EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO2 sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO2 NAAQS. Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO2 standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO2 standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above. | |
EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist with the plant with compliance with the particulate matter NAAQS. | |
In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and is scheduled to propose a new standard in December 2013 and finalize it by the end of 2014. Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation. | |
Citizen Suit Under the Clean Air Act | |
The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS's emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties' dispute is deemed settled. | |
In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.6 million, to a total of $6.1 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS. The special master issued a report indicating he was unable to make a determination on either of these issues. In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. The parties have provided status updates to the court as required. PNM cannot predict the outcome of this matter. | |
Section 114 Request | |
In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA's request. PNM is currently unable to predict the timing or content of EPA's response, if any, or any resulting actions. | |
Four Corners Clean Air Act Lawsuit | |
In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact. | |
WEG v. OSM NEPA Lawsuit | |
In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC's San Juan mine. WEG's allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act violations against OSM, including, but not limited to, OSM's alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG's petition seeks various forms of relief, including voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC's claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. PNM cannot currently predict the outcome of this matter or the range of its potential impact. | |
Navajo Nation Environmental Issues | |
Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation's authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts. | |
Endangered Species Act | |
In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats. The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA. Neither PNM nor APS was a party to the lawsuit. On March 14, 2012, the Court entered an order dismissing the plaintiffs' lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the Court's order to the Tenth Circuit. On July 8, 2013, the Tenth Circuit entered an order dismissing the appeal, which concludes this matter. | |
Cooling Water Intake Structures | |
EPA issued its proposed cooling water intake structures rule in April 2011, which would provide national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a "structured site-specific analysis" to determine what site-specific controls, if any, should be required. | |
The proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date has been extended to November 4, 2013. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. | |
Effluent Limitation Guidelines | |
On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for steam electric power plants. EPA's proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations. EPA is subject to a consent decree deadline to finalize the revised guidelines by May 22, 2014. PNM is in the process of reviewing the proposed rule to assess the impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. APS is currently assessing the impact to Four Corners. PNM is unable to predict the outcome of this matter or if it will have a material impact on PNM's financial position, results of operations, or cash flows. | |
Santa Fe Generating Station | |
PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of the former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The municipal well continues to operate and meets federal drinking water standards. The City of Santa Fe has recently indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM's groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well. | |
The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM's obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. | |
Coal Combustion Byproducts Waste Disposal | |
CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer's Office. | |
In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA's proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule. | |
On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA's regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary. They also claim that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. | |
PNM advocates for the non-hazardous regulation of CCBs. However, if CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows. | |
Hazardous Air Pollutants ("HAPs") Rulemaking | |
In December 2011, the EPA issued its final Mercury and Air Toxics Standards ("MATS") to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM's assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule. | |
Other Commitments and Contingencies | |
Coal Supply | |
The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2013 and December 31, 2012, prepayments for coal, which are included in other current assets, amounted to $15.8 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017. | |
APS purchases all of Four Corners' coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. The BHP subsidiary would be retained as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and the Four Corners owners. The Four Corners owners must finalize their approvals of the contract. These negotiations, and the related transaction whereby full ownership of the coal mine would be transferred to the Navajo Nation, are proceeding. On April 29, 2013, the Navajo Nation Tribal Council approved the creation of the new commercial enterprise with sufficient power and authority to execute the transaction with BHP. See The Clean Air Act - Regional Haze - Four Corners above. PNM is unable to predict the outcome of this matter. | |
In 2010, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the 2010 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $56.9 million for the surface mines at both SJGS and Four Corners and $19.7 million for the underground mine at SJGS as of September 30, 2013. At September 30, 2013 and December 31, 2012, liabilities, in current dollars, of $23.7 million and $26.8 million for surface mine reclamation and $4.6 million and $4.2 million for underground mine reclamation were recorded in other deferred credits. | |
PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act - Regional Haze - SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. Although the updated coal mine reclamation study has not been finalized, preliminary indications are that reclamation costs for both the surface and underground mines have increased, including significant increases due to the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the surface mine pits thereby increasing the overall reclamation costs. The amount of any increase and the allocation between the surface and underground mines cannot be determined at this time. Furthermore, it has not been decided how costs would be divided among the owners of SJGS, which may be dependent on the final decision regarding how SJGS ownership is restructured. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impact. | |
San Juan Underground Mine Fire Incident | |
On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration ("MSHA") was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time. | |
The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM's filings with the NMPRC reflect an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and has informed PNM that it has settled with its insurance carrier. PNM believes the settlement proceeds obtained by SJCC through its insurance carrier are reimbursable (in whole or in part) to the owners of SJGS through the coal sales agreement. PNM's portion of the insurance recovery, which is estimated to be $18.7 million based on information received from SJCC, will be flowed through PNM's FPPAC to the extent it relates to increased coal costs included in the FPPAC. | |
Continuous Highwall Mining Royalty Rate | |
In August 2013, the DOI Bureau of Land Management ("BLM") issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining ("CHM"). Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule. | |
SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS. In March 2001, SJCC learned that the DOI Minerals Management Service ("MMS") disagreed with the application of the underground royalty rate to CHM. In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal. The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed. PNM's share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM's FPPAC. PNM is unable to predict the outcome of this matter. | |
SJCC Arbitration | |
The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues have been submitted to a panel for binding arbitration. In October 2013, the arbitration panel ruled on one issue and set other issues for hearing. The panel ruled that the SJGS participants owe SJCC $1.5 million for disputed mining costs. PNM's share of this amount is $0.7 million of which $0.5 million will be passed through PNM's FPPAC. The remaining issues going forward to a hearing include: 1) whether the SJGS participants owe SJCC unbilled mining costs of $5.2 million or whether SJCC owes the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $12.9 million as mining costs that SJCC should have considered to be capital improvements, which are not billable under the mining contract. PNM's share of any amounts resulting from the arbitration would be approximately 46.3%. Of PNM's share of the costs, approximately 33% of the first remaining issue as well as approximately 25% of the second remaining issue would be passed through PNM's FPPAC and the rest would impact earnings. A hearing date on the remaining issues has not been set. PNM is unable to predict the outcome of the arbitration hearing. | |
Four Corners Severance Tax Assessment | |
On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM's share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM's FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. Prior to year end, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, intend to file a complaint with the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter. | |
Nuclear Fuel | |
In late August 2012, one of PVNGS's suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The issues have been resolved and the conversion plant has restarted. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short-term impact on nuclear fuel supplies as a result of the force majeure declaration. | |
PVNGS Liability and Insurance Matters | |
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM's 10.2% interest in each of the three PVNGS units, PNM's maximum potential assessment per incident for all three units is $38.9 million, with an annual payment limitation of $5.7 million. | |
The PVNGS participants maintain "all risk" (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited ("NEIL"). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL's losses in any policy year exceed accumulated funds, PNM is subject to retrospective assessments of $4.3 million for each retrospective assessment declared by NEIL's Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions. | |
Water Supply | |
Because of New Mexico's arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time. However, prolonged drought, ESA activities, and a Federal lawsuit by the State of Texas suing the State of New Mexico over water allocations could pose a threat of reduced water availability for these plants. | |
PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future. | |
In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years. | |
PVNGS Water Supply Litigation | |
In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court's jurisdiction over PVNGS' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court's criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows. | |
San Juan River Adjudication | |
In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation's water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees. The court has ordered that settlement of the Navajo Nation's claims under the settlement agreement and entry of the proposed decrees be heard in an expedited proceeding. The court recently issued an order finding that no evidentiary hearing is warranted in the Navajo Nation proceeding, and that it will be issuing an order addressing the issues raised by the parties at some point in the future. This order must be entered no later than December 31, 2013, pursuant to the 2005 settlement. | |
PNM's water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. Therefore, PNM has elected to participate in this proceeding. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss. | |
Complaint Against Southwestern Public Service Company | |
In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices and issues relating to demand cost allocation (the "Golden Spread Proceeding"). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM ("SPS 2006 Rate Proceeding"). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ. FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS' fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated. PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes. | |
Navajo Nation Allottee Matters | |
A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs' case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs ("BIA"), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director's decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director's decision that the allottees had failed to perfect their appeals, and dismissed the allottees' appeals, without prejudice.  PNM continues to participate in this matter in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time. | |
In a separate matter, in September 2012, forty-three landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. PNM is participating in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time. | |
TGP Complaint | |
On March 2, 2012, TGP Granada, LLC and its affiliate (collectively, "TGP") filed a complaint at FERC against PNM and Tortoise Capital Resources Corp. ("TTO"). PNM owns 60% of the EIP and leases the other 40% from TTO. PNM's lease of the portion of the EIP owned by TTO expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease. | |
TGP's filing requested FERC to direct PNM and TTO to identify the party that will immediately assume the obligation of making transmission capacity on the EIP available to customers for use after the April 1, 2015 expiration of the EIP lease agreement. TGP also requested a declaratory order or waiver regarding certain provisions of PNM's Open Access Transmission Tariff to allow its affiliate to change the point-of-receipt associated with a transmission service agreement related to the EIP without losing its transmission service priority. On July 5, 2012, FERC issued an order denying TGP's requests for declaratory order and waiver. In addition, FERC directed PNM, in consultation with TTO, to identify the party that will provide long-term transmission service over the leased portion of the EIP. | |
On November 1, 2012, PNM and TTO entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity. In November 2012, PNM requested the necessary FERC approvals for the definitive agreement. In January 2013, FERC approved PNM's requests. On February 8, 2013, FERC issued an order dismissing as moot a motion filed by TGP for clarification of FERC's July 5, 2012 order. Since no rehearing request or appeal was filed, the February 8, 2013 order is final and non-appealable. |
Pension_and_Other_Postretireme
Pension and Other Postretirement Benefit Plans | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | |||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | |||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | ||||||||||||||||||||||||
PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs ("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 2012 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year. | ||||||||||||||||||||||||
PNM Plans | ||||||||||||||||||||||||
The following tables present the components of the PNM Plans' net periodic benefit cost: | ||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 65 | $ | 54 | $ | — | $ | — | ||||||||||||
Interest cost | 7,035 | 8,058 | 1,029 | 1,324 | 180 | 219 | ||||||||||||||||||
Expected return on plan assets | (10,482 | ) | (10,325 | ) | (1,261 | ) | (1,225 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 3,710 | 2,629 | 1,061 | 972 | 58 | 21 | ||||||||||||||||||
Amortization of prior service cost | 19 | 79 | (336 | ) | (336 | ) | — | — | ||||||||||||||||
Net periodic benefit cost | $ | 282 | $ | 441 | $ | 558 | $ | 789 | $ | 238 | $ | 240 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 195 | $ | 162 | $ | — | $ | — | ||||||||||||
Interest cost | 21,106 | 24,174 | 3,085 | 3,972 | 540 | 657 | ||||||||||||||||||
Expected return on plan assets | (31,447 | ) | (30,975 | ) | (3,782 | ) | (3,675 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 11,130 | 7,887 | 3,182 | 2,916 | 174 | 63 | ||||||||||||||||||
Amortization of prior service cost | 57 | 237 | (1,008 | ) | (1,008 | ) | — | — | ||||||||||||||||
Net periodic benefit cost | $ | 846 | $ | 1,323 | $ | 1,672 | $ | 2,367 | $ | 714 | $ | 720 | ||||||||||||
PNM made contributions to its pension plan trust of zero and $60.0 million in the three and nine months ended September 30, 2013 and zero and $77.7 million in the three and nine months ended September 30, 2012. PNM does not anticipate making additional contributions to its pension trust in 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, PNM estimates minimum required contributions for its pension plan trust would total $49.1 million for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% to 5.2%. Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2013 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2012. PNM expects contributions during 2013 to the OPEB trust to total $3.3 million. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.1 million in the three and nine months ended September 30, 2013 and $0.4 million and $1.1 million in the three and nine months ended September 30, 2012 and are expected to total $1.5 million during 2013. | ||||||||||||||||||||||||
TNMP Plans | ||||||||||||||||||||||||
The following tables present the components of the TNMP Plans' net periodic benefit cost (income): | ||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 75 | $ | 61 | $ | — | $ | — | ||||||||||||
Interest cost | 772 | 909 | 141 | 156 | 9 | 11 | ||||||||||||||||||
Expected return on plan assets | (1,212 | ) | (1,331 | ) | (126 | ) | (129 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 262 | 115 | — | (52 | ) | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 14 | 14 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (178 | ) | $ | (307 | ) | $ | 104 | $ | 50 | $ | 9 | $ | 11 | ||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 225 | $ | 183 | $ | — | $ | — | ||||||||||||
Interest cost | 2,315 | 2,727 | 424 | 468 | 27 | 33 | ||||||||||||||||||
Expected return on plan assets | (3,637 | ) | (3,993 | ) | (377 | ) | (387 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 787 | 345 | — | (156 | ) | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 43 | 42 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (535 | ) | $ | (921 | ) | $ | 315 | $ | 150 | $ | 27 | $ | 33 | ||||||||||
TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and nine months ended September 30, 2013 and zero and $5.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to its pension trust in 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no minimum required contributions to its pension plan trust for 2014-2017. Minimum required contributions were developed using current funding assumptions, including discount rates of 4.8% and 5.2%. 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 to the OPEB trust of zero and $0.3 million in the three and nine months ended September 30, 2013 and zero and $0.3 million in the three and nine months ended September 30, 2012. TNMP does not anticipate making additional contributions to the OPEB trust in 2013. 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, 2013 and 2012 and are expected to total $0.1 million during 2013. |
Regulatory_and_Rate_Matters
Regulatory and Rate Matters | 9 Months Ended |
Sep. 30, 2013 | |
Regulatory and Rate Matters | ' |
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 10. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. | |
PNM | |
Renewable Portfolio Standard | |
The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be "fully diversified." Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In June 2013, the NMPRC initiated a new rulemaking proceeding in which it proposed to consider amending or eliminating specific diversity targets and to reconsider the inclusion of avoided environmental and capacity costs in the application of the RCT. A public hearing was held on September 10, 2013. | |
The REA provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC had established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers' annual electric charges beginning in 2013 and continuing thereafter. | |
In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM's 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of a new 10 MW geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM's voluntary renewable energy tariff. The plan will enable PNM to comply with the statutory RPS amount in 2013, but requires a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan had been expected to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. Construction of the geothermal facility has been delayed due to a longer than expected permitting process. PNM still anticipates that the facility will begin energy production January 1, 2014, but full-scale production will be delayed. PNM does not believe this delay will affect its ability to comply with the diversity requirements as amended in December 2012. | |
PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets the RPS quantity and diversity requirements within the RCT in 2014 and 2015. PNM's proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of an existing 100 MW wind energy center beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. A public hearing was held in October 2013. The NMPRC is required to approve or modify the plan within 180 days of the filing date. PNM cannot predict the outcome of this proceeding. | |
PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. | |
Renewable Energy Rider | |
On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The approved rates are $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM, which is discussed under Renewable Portfolio Standard above. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held on its inclusion in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM's next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider are capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps are deferred for future recovery without carrying costs. As a separate component of the rider, if PNM's earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM must refund to customers during May through December 2014 the amount over 10.5%. | |
In compliance with the NMPRC's rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills.  The NMPRC suspended the effective date of the new rate for a period of nine months from April 1, 2013 and appointed a Hearing Examiner to conduct a hearing on the proposed change.  On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.0030468 per KWh on May 28, 2013. | |
In its 2014 renewable energy procurement plan described above, PNM proposed to increase the rider rate to $0.0044391 effective January 1, 2014. PNM expects an order in this case in December 2013. | |
Energy Efficiency and Load Management | |
Program Costs | |
Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of a utility's annual revenue. | |
In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million and requested that the NMPRC issue an order by April 1, 2013. Portions of the program plan and proposed profit incentive are opposed by other parties to the case. PNM subsequently revised its proposed profit incentive to $2.9 million. After a hearing held in February 2013, the Hearing Examiner recommended approval of the programs as proposed and recommended an annual incentive of $1.7 million. The NMPRC has not yet acted on the Hearing Examiner's recommendations. PNM is not able to predict the outcome of this matter. | |
Disincentives/Incentives Adder | |
The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. A rule approved by the NMPRC authorized electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per KW for demand savings related to energy efficiency and demand response programs beginning in 2010. The NMAG and NMIEC appealed the NMPRC order adopting this rule to the New Mexico Supreme Court. PNM began implementing a rate rider under the rule to collect adders related to its 2010 program savings in December 2010 while the appeal of the rule was pending. In July 2011, the Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011. | |
In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific adders of $0.002 per KWh and $4 per KW for savings due to programs implemented in 2011. PNM is presently collecting $1.3 million in adder revenues consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the adders and to refund all adder revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM is not required to refund any adder revenues and is authorized to continue collecting the adders. However, in an order on rehearing, which it subsequently rescinded, the NMPRC further reduced the amount of the authorized adders. Prior to the rescission, PNM appealed the rehearing order to the Supreme Court. In March 2012, the Supreme Court granted PNM's motion to vacate the rehearing order and dismiss PNM's appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG sought to overturn the NMPRC order allowing PNM to continue to collect adders in light of the 2011 Supreme Court decision. On May 21, 2012, the Supreme Court dismissed the writ proceeding. On September 20, 2013, the Supreme Court issued a decision in the NMIEC and NMAG appeal. The Supreme Court affirmed the NMPRC's decision authorizing the incentive and remanded the case to the NMPRC. On October, 2, 2013, the NMPRC closed the docket. | |
On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013. | |
Energy Efficiency Rulemaking | |
On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC's energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service from the rates charged on a per KWh of consumption, as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. | |
On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the product (expressed in dollars) of the utility's weighted cost of capital (expressed as a percent) and its approved annual program costs. The NOPR establishes a schedule for comments and sets a public hearing in November 2013. | |
2010 Electric Rate Case and FPPAC | |
An order of the NMPRC approving an amended stipulation in PNM's 2010 Electric Rate Case limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $38.4 million of FPPAC costs being deferred for future collection at June 30, 2014. The portion of the costs and insurance recovery attributable to customers covered by the FPPAC resulting from the mine fire incident discussed in Note 10 are included in the FPPAC amounts. | |
Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to either over or under-collections in the balancing account. A hearing has been scheduled to begin on December 10, 2013. PNM is unable to predict the outcome of this proceeding. | |
Integrated Resource Plan | |
NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. The NMPRC assigned the case to a Hearing Examiner and designated a mediator to facilitate negotiations. The NMPRC staff filed a motion in December 2011 to dismiss the protests and terminate the proceeding on the ground that PNM's IRP fully complies with NMPRC rules. On September 18, 2013, the NMPRC issued an order that closed this docket. | |
Consistent with the NMPRC's IRP rule, PNM has initiated the process to prepare its 2014 IRP. Initial public participation meetings have been held. The 2014 IRP is scheduled to be filed at the NMPRC by June 30, 2014. | |
Emergency FPPAC | |
In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM's base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM's motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC's order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed. | |
Applications for Approvals to Purchase Delta | |
As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On January 3, 2013, PNM filed an application with the NMPRC for a CCN to own and operate Delta and for a determination of related ratemaking principles and treatment. On June 26, 2013, the NMPRC granted PNM's CCN application and approved PNM's proposed ratemaking treatment. PNM filed an application for approval of the Delta acquisition at FERC on January 24, 2013. FERC approved the purchase on February 26, 2013. Closing on the purchase is anticipated in early 2014. | |
Application for Approval of La Luz Generating Station | |
On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requests a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. Both contracts allow PNM to cancel if NMPRC approval is not obtained. A hearing on PNM's application is scheduled to begin on April 8, 2014. PNM is unable to predict the outcome of this matter. | |
San Juan Generating Station Units 2 and 3 Retirement | |
PNM anticipates filing an application at the NMPRC to retire SJGS Units 2 and 3, as discussed in Note 10, before the end of 2013. In the same application, PNM will also seek approval to recover its remaining costs in SJGS 2 and 3 and for a CCN for some of the resources to replace the retired units, which PNM anticipates will include PNM's share of PVNGS Unit 3 and additional capacity in SJGS Unit 4. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. | |
Transmission Rate Case | |
In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms. In December 2010, FERC issued an order accepting PNM's filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM's wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM's transmission system to transmit power at the wholesale level. The rate increase did not impact PNM's retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC's approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter. | |
Formula Transmission Rate Case | |
On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM's annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. The rates resulting from PNM's application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM's request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM's 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013. | |
On March 1, 2013, FERC issued an order (1) accepting PNM's revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its return-on-equity ("ROE") using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM's 60% ownership of the EIP transmission line, which was acquired in 2003 ; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC's order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM's wholesale electric transmission service customers. The new rates will not apply to PNM's retail customers. On June 10, 2013, FERC denied PNM's motion for rehearing regarding FERC's order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding. | |
Tri-State Complaint | |
On March 13, 2013, Tri-State filed a complaint with FERC alleging that PNM's existing transmission rates approved by FERC on January 2, 2013 in the transmission rate case discussed above are unjust and unreasonable under the Federal Power Act. Tri-State's allegations were premised upon FERC's March 1, 2013 order and certain data provided by PNM in PNM's Formula Transmission Rate Case discussed above. Tri-State sought a reduction in PNM's annual transmission revenue requirement for the period between March 13, 2013 and the implementation of PNM's proposed rates under the Formula Transmission Rate Case. Tri-State also requested that FERC consolidate the complaint proceeding with the Formula Transmission Rate Case. On April 2, 2013, PNM answered Tri-State's complaint, asking FERC to dismiss the complaint and deny Tri-State's request to consolidate the complaint proceeding with the Formula Transmission Rate Case. On June 10, 2013, FERC dismissed Tri-State's complaint and denied Tri-State's request to consolidate the complaint proceeding with the PNM FERC Transmission Formula Rate Case. This matter is now concluded. | |
Firm-Requirements Wholesale Customers | |
Navopache Electric Cooperative, Inc. Rate Case | |
In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM's filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement would result in an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter. | |
City of Gallup, New Mexico Contract Approval Case | |
PNM provides both energy and power services to Gallup, PNM's second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will increase by $3.1 million during the term of the amended agreement. On September 26, 2013, Gallup issued a request for proposals for long term power supply. Proposals are due November 26, 2013. PNM anticipates submitting a proposal, but is unable to predict if services provided to Gallup will continue upon expiration of the amended agreement. | |
TNMP | |
Advanced Meter System Deployment | |
In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period. | |
In February 2012, the PUCT opened a proceeding to consider the feasibility of an "opt-out" program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012. | |
On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service will be borne by opt-out customers through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT are required to initiate proceedings to establish these charges. | |
On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP's filing seeks recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48. An additional $0.5 million in ongoing expenses would be recovered via a proposed monthly charge of $38.99. As the proceeding has just been initiated, TNMP cannot predict the outcome of this proceeding although TNMP does not expect it to have a material impact on its financial position, results of operations, or cash flows. | |
Energy Efficiency | |
TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP's new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to permit TNMP to collect the substantially all of the requested $5.6 million. The settlement was approved by the PUCT on October 25, 2013. | |
Transmission Cost of Service Rates | |
TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. | |
On January 31, 2013, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base was $21.9 million, which would increase revenues $2.9 million annually. On March 19, 2013, the PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered March 20, 2013. On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013. | |
Consolidated Tax Savings Adjustment | |
On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment ("CTSA") from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013. |
Related_Party_Transactions
Related Party Transactions | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||
Related Party Transactions | ' | |||||||||||||
Related Party Transactions | ||||||||||||||
PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP: | ||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
(In thousands) | ||||||||||||||
Services billings: | ||||||||||||||
PNMR to PNM | $ | 22,241 | $ | 22,143 | 65,729 | 68,030 | ||||||||
PNMR to TNMP | 6,731 | 6,439 | 20,948 | 20,206 | ||||||||||
PNM to TNMP | 140 | 184 | 381 | 473 | ||||||||||
TNMP to PNMR | 2 | 4 | 6 | 12 | ||||||||||
Interest billings: | ||||||||||||||
PNMR to TNMP | 139 | 22 | 354 | 72 | ||||||||||
PNMR to PNM | — | — | 1 | 1 | ||||||||||
PNM to PNMR | 35 | 45 | 113 | 134 | ||||||||||
Income tax sharing payments: | ||||||||||||||
PNMR to PNM | — | — | 45,000 | 63,114 | ||||||||||
PNMR to TNMP | — | — | — | 1,952 | ||||||||||
Income_Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2013 | |
Income Tax Disclosure [Abstract] | ' |
Income Taxes | ' |
Income Taxes | |
As required under GAAP, the Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. Year-to-date income tax expense is then calculated by applying the anticipated annual effective tax rate to year-to-date earnings before taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, as well as adjustments due to enactment of new tax laws, be excluded from the estimated annual effective tax rate calculation. | |
On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico for 2013 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $1.5 million as additional income tax expense during the three months ended March 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment. | |
On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse. The portion of the adjustment related to PNM's regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. The portion of the adjustment that is not related to PNM's regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. This additional income tax expense is reflected in PNMR's Corporate and Other segment. | |
The future reduction in taxes payable to the State of New Mexico resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income resulted in a further impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $2.4 million as additional income tax expense during the three months ended June 30, 2013. This impairment is reflected in PNMR's Corporate and Other segment. | |
On April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property. Adoption of the safe harbor method is elective for years ending on or after December 31, 2012. On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material. | |
In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM. As of September 30, 2013, $45.0 million had been transferred to PNM. | |
On September 13, 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material. |
Goodwill
Goodwill | 9 Months Ended |
Sep. 30, 2013 | |
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 June 6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. | |
GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR's reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. | |
GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit's fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit's fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis in not required. | |
In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. | |
An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. For the annual evaluation performed as of April 1, 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. | |
The annual evaluations performed as of April 1, 2013 and 2012 did not indicate impairments of the goodwill of any of PNMR's reporting units. The April 1, 2013 and 2012 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by more than 10%. The April 1, 2012 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by more than 10%. Since the April 1, 2013 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company's goodwill is contained in Note 22 of Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. |
Sale_of_First_Choice
Sale of First Choice | 9 Months Ended |
Sep. 30, 2013 | |
Discontinued Operations and Disposal Groups [Abstract] | ' |
Sale of First Choice | ' |
Sale of First Choice | |
On September 23, 2011, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the amounts of certain components of working capital at closing. Closing occurred on November 1, 2011. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. PNMR and the purchaser disagreed about the calculation of working capital at October 31, 2011. In accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012. The decision resulted in PNMR being awarded $6.4 million of the $8.2 million in dispute. PNMR recorded an additional pre-tax gain of $1.0 million, which is included in other income in the three months ended September 30, 2012. |
Significant_Accounting_Policie1
Significant Accounting Policies and Responsibility for Financial Statements (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Accounting Policies [Abstract] | ' |
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 the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. | |
PNMR shared services' administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12. | |
Segment Reporting | ' |
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. | |
Variable Interest Entity | ' |
GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity, by focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. |
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | |||||||||||||||
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 | Consolidated | |||||||||||||
and Other | ||||||||||||||||
Three Months Ended September 30, 2013 | (In thousands) | |||||||||||||||
Electric operating revenues | $ | 326,026 | $ | 73,704 | $ | — | $ | 399,730 | ||||||||
Cost of energy | 100,200 | 14,474 | — | 114,674 | ||||||||||||
Margin | 225,826 | 59,230 | — | 285,056 | ||||||||||||
Other operating expenses | 104,730 | 23,126 | (3,282 | ) | 124,574 | |||||||||||
Depreciation and amortization | 25,879 | 13,850 | 3,014 | 42,743 | ||||||||||||
Operating income | 95,217 | 22,254 | 268 | 117,739 | ||||||||||||
Interest income | 2,298 | — | (34 | ) | 2,264 | |||||||||||
Other income (deductions) | 2,211 | 716 | (3,455 | ) | (528 | ) | ||||||||||
Net interest charges | (20,124 | ) | (6,655 | ) | (3,586 | ) | (30,365 | ) | ||||||||
Segment earnings (loss) before income taxes | 79,602 | 16,315 | (6,807 | ) | 89,110 | |||||||||||
Income taxes (benefit) | 27,652 | 6,209 | (3,565 | ) | 30,296 | |||||||||||
Segment earnings (loss) | 51,950 | 10,106 | (3,242 | ) | 58,814 | |||||||||||
Valencia non-controlling interest | (4,127 | ) | — | — | (4,127 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 47,691 | $ | 10,106 | $ | (3,242 | ) | $ | 54,555 | |||||||
Nine Months Ended September 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 863,609 | $ | 201,384 | $ | — | $ | 1,064,993 | ||||||||
Cost of energy | 283,715 | 41,324 | — | 325,039 | ||||||||||||
Margin | 579,894 | 160,060 | — | 739,954 | ||||||||||||
Other operating expenses | 311,372 | 67,274 | (10,192 | ) | 368,454 | |||||||||||
Depreciation and amortization | 77,763 | 37,810 | 9,616 | 125,189 | ||||||||||||
Operating income | 190,759 | 54,976 | 576 | 246,311 | ||||||||||||
Interest income | 7,839 | — | (108 | ) | 7,731 | |||||||||||
Other income (deductions) | 6,977 | 1,409 | (7,390 | ) | 996 | |||||||||||
Net interest charges | (59,971 | ) | (20,661 | ) | (11,647 | ) | (92,279 | ) | ||||||||
Segment earnings (loss) before income taxes | 145,604 | 35,724 | (18,569 | ) | 162,759 | |||||||||||
Income taxes (benefit) | 49,184 | 13,554 | (4,138 | ) | 58,600 | |||||||||||
Segment earnings (loss) | 96,420 | 22,170 | (14,431 | ) | 104,159 | |||||||||||
Valencia non-controlling interest | (10,904 | ) | — | — | (10,904 | ) | ||||||||||
Subsidiary preferred stock dividends | (396 | ) | — | — | (396 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 85,120 | $ | 22,170 | $ | (14,431 | ) | $ | 92,859 | |||||||
At September 30, 2013: | ||||||||||||||||
Total Assets | $ | 4,192,470 | $ | 1,162,587 | $ | 73,757 | $ | 5,428,814 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Additions to utility and non-utility plant included in accounts payable | $ | 15,995 | $ | 544 | $ | 1,668 | $ | 18,207 | ||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
Three Months Ended September 30, 2012 | (In thousands) | |||||||||||||||
Electric operating revenues | $ | 321,731 | $ | 68,680 | $ | — | $ | 390,411 | ||||||||
Cost of energy | 99,217 | 11,560 | — | 110,777 | ||||||||||||
Margin | 222,514 | 57,120 | — | 279,634 | ||||||||||||
Other operating expenses | 101,104 | 22,331 | (4,771 | ) | 118,664 | |||||||||||
Depreciation and amortization | 24,437 | 13,819 | 4,564 | 42,820 | ||||||||||||
Operating income | 96,973 | 20,970 | 207 | 118,150 | ||||||||||||
Interest income | 3,173 | — | (43 | ) | 3,130 | |||||||||||
Other income (deductions) | 5,210 | 366 | (827 | ) | 4,749 | |||||||||||
Net interest charges | (19,230 | ) | (7,047 | ) | (4,238 | ) | (30,515 | ) | ||||||||
Segment earnings (loss) before income taxes | 86,126 | 14,289 | (4,901 | ) | 95,514 | |||||||||||
Income taxes (benefit) | 31,235 | 5,205 | (2,902 | ) | 33,538 | |||||||||||
Segment earnings (loss) | 54,891 | 9,084 | (1,999 | ) | 61,976 | |||||||||||
Valencia non-controlling interest | (3,980 | ) | — | — | (3,980 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 50,779 | $ | 9,084 | $ | (1,999 | ) | $ | 57,864 | |||||||
Nine Months Ended September 30, 2012 | ||||||||||||||||
Electric operating revenues | $ | 832,242 | $ | 187,404 | $ | — | $ | 1,019,646 | ||||||||
Cost of energy | 263,009 | 34,333 | — | 297,342 | ||||||||||||
Margin | 569,233 | 153,071 | — | 722,304 | ||||||||||||
Other operating expenses | 311,468 | 64,239 | (12,676 | ) | 363,031 | |||||||||||
Depreciation and amortization | 72,017 | 37,173 | 13,099 | 122,289 | ||||||||||||
Operating income (loss) | 185,748 | 51,659 | (423 | ) | 236,984 | |||||||||||
Interest income | 9,938 | 1 | (131 | ) | 9,808 | |||||||||||
Other income (deductions) | 9,201 | 1,244 | (4,797 | ) | 5,648 | |||||||||||
Net interest charges | (56,652 | ) | (21,214 | ) | (12,414 | ) | (90,280 | ) | ||||||||
Segment earnings (loss) before income taxes | 148,235 | 31,690 | (17,765 | ) | 162,160 | |||||||||||
Income taxes (benefit) | 51,929 | 11,577 | (8,897 | ) | 54,609 | |||||||||||
Segment earnings (loss) | 96,306 | 20,113 | (8,868 | ) | 107,551 | |||||||||||
Valencia non-controlling interest | (10,699 | ) | — | — | (10,699 | ) | ||||||||||
Subsidiary preferred stock dividends | (396 | ) | — | — | (396 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 85,211 | $ | 20,113 | $ | (8,868 | ) | $ | 96,456 | |||||||
At September 30, 2012: | ||||||||||||||||
Total Assets | $ | 4,073,331 | $ | 1,060,062 | $ | 126,814 | $ | 5,260,207 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Additions to utility and non-utility plant included in accounts payable | $ | 6,056 | $ | 886 | $ | 1,063 | $ | 8,005 | ||||||||
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Equity [Abstract] | ' | |||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | ' | |||||||||||||||
Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2013 is as follows: | ||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Investment | Liability | for Cash Flow | ||||||||||||||
Securities | Adjustment | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
PNMR | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | (216 | ) | $ | (81,630 | ) | |||||
 Amounts reclassified from AOCI (pre-tax) | (9,190 | ) | 4,773 | 153 | (4,264 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,639 | (1,893 | ) | (54 | ) | 1,692 | ||||||||||
 Other OCI changes (pre-tax) | 19,056 | — | (363 | ) | 18,693 | |||||||||||
Income tax impact of other OCI changes | (7,544 | ) | — | 127 | (7,417 | ) | ||||||||||
Net change after income taxes | 5,961 | 2,880 | (137 | ) | 8,704 | |||||||||||
Balance at September 30, 2013 | $ | 22,367 | $ | (94,940 | ) | $ | (353 | ) | $ | (72,926 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | — | $ | (81,414 | ) | ||||||
 Amounts reclassified from AOCI (pre-tax) | (9,190 | ) | 4,773 | — | (4,417 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,639 | (1,893 | ) | — | 1,746 | |||||||||||
 Other OCI changes (pre-tax) | 19,056 | — | — | 19,056 | ||||||||||||
Income tax impact of other OCI changes | (7,544 | ) | — | — | (7,544 | ) | ||||||||||
Net change after income taxes | 5,961 | 2,880 | — | 8,841 | ||||||||||||
Balance at September 30, 2013 | $ | 22,367 | $ | (94,940 | ) | $ | — | $ | (72,573 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2012 | $ | — | $ | — | $ | (216 | ) | $ | (216 | ) | ||||||
 Amounts reclassified from AOCI (pre-tax) | — | — | 153 | 153 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (54 | ) | (54 | ) | ||||||||||
 Other OCI changes (pre-tax) | — | — | (363 | ) | (363 | ) | ||||||||||
Income tax impact of other OCI changes | — | — | 127 | 127 | ||||||||||||
Net change after income taxes | — | — | (137 | ) | (137 | ) | ||||||||||
Balance at September 30, 2013 | $ | — | $ | — | $ | (353 | ) | $ | (353 | ) | ||||||
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) (Public Service Company of New Mexico [Member]) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Public Service Company of New Mexico [Member] | ' | |||||||||||||||
Variable Interest Entity [Line Items] | ' | |||||||||||||||
Noncontrolling Interest Summarized Financial Information [Table Text Block] | ' | |||||||||||||||
Summarized financial information for Valencia is as follows: | ||||||||||||||||
Results of Operations | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands) | ||||||||||||||||
Operating revenues | $ | 5,453 | $ | 5,358 | $ | 15,150 | $ | 14,916 | ||||||||
Operating expenses | (1,326 | ) | (1,378 | ) | (4,246 | ) | (4,217 | ) | ||||||||
Earnings attributable to non-controlling interest | $ | 4,127 | $ | 3,980 | $ | 10,904 | $ | 10,699 | ||||||||
Financial Position | ||||||||||||||||
September 30, | December 31, | |||||||||||||||
2013 | 2012 | |||||||||||||||
(In thousands) | ||||||||||||||||
Current assets | $ | 3,457 | $ | 3,655 | ||||||||||||
Net property, plant, and equipment | 75,841 | 77,953 | ||||||||||||||
Total assets | 79,298 | 81,608 | ||||||||||||||
Current liabilities | 1,028 | 765 | ||||||||||||||
Owners' equity – non-controlling interest | $ | 78,270 | $ | 80,843 | ||||||||||||
Fair_Value_of_Derivative_and_O1
Fair Value of Derivative and Other Financial Instruments (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Line Items] | ' | |||||||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | |||||||||||||||||||
The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | ||||||||||||||||
September 30, 2013 | (In thousands) | |||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,748,841 | $ | 1,929,828 | $ | — | $ | 1,926,126 | $ | 3,702 | ||||||||||
Investment in PVNGS lessor notes | $ | 53,300 | $ | 55,094 | $ | — | $ | — | $ | 55,094 | ||||||||||
Other investments | $ | 2,803 | $ | 6,941 | $ | 739 | $ | — | $ | 6,202 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,290,608 | $ | 1,400,109 | $ | — | $ | 1,400,109 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 53,300 | $ | 55,094 | $ | — | $ | — | $ | 55,094 | ||||||||||
Other investments | $ | 458 | $ | 458 | $ | 458 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 336,128 | $ | 393,122 | $ | — | $ | 393,122 | $ | — | ||||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — | ||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,672,290 | $ | 1,969,362 | $ | — | $ | 1,966,725 | $ | 2,637 | ||||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | ||||||||||
Other investments | $ | 5,599 | $ | 6,965 | $ | 774 | $ | — | $ | 6,191 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,215,579 | $ | 1,385,433 | $ | — | $ | 1,385,433 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | ||||||||||
Other investments | $ | 494 | $ | 494 | $ | 494 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 311,589 | $ | 418,166 | $ | — | $ | 418,166 | $ | — | ||||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — | ||||||||||
PNMR and PNM [Member] | ' | |||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Line Items] | ' | |||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | ' | |||||||||||||||||||
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, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Current assets | $ | 5,743 | $ | 3,785 | ||||||||||||||||
Deferred charges | 4,284 | 352 | ||||||||||||||||||
10,027 | 4,137 | |||||||||||||||||||
Current liabilities | (1,017 | ) | (1,000 | ) | ||||||||||||||||
Long-term liabilities | (1,347 | ) | (1,933 | ) | ||||||||||||||||
(2,364 | ) | (2,933 | ) | |||||||||||||||||
Net | $ | 7,663 | $ | 1,204 | ||||||||||||||||
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block] | ' | |||||||||||||||||||
The following table presents the effect on earnings, excluding income tax effects and settlements, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented. | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Electric operating revenues | $ | 7,077 | $ | (740 | ) | $ | 5,743 | $ | 897 | |||||||||||
Cost of energy | (72 | ) | 263 | 421 | (278 | ) | ||||||||||||||
   Total gain (loss) | $ | 7,005 | $ | (477 | ) | $ | 6,164 | $ | 619 | |||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | ' | |||||||||||||||||||
Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR's and PNM's net buy (sell) volume positions: | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
MMBTU | MWh | |||||||||||||||||||
September 30, 2013 | ||||||||||||||||||||
PNMR and PNM | 980,000 | (3,801,738 | ) | |||||||||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR and PNM | 1,127,500 | (2,477,520 | ) | |||||||||||||||||
Schedule of Collateral Related to Derivative [Table Text Block] | ' | |||||||||||||||||||
Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. | ||||||||||||||||||||
Contingent Feature – | Contractual Liability | Existing Cash Collateral | Net Exposure | |||||||||||||||||
Credit Rating Downgrade | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
September 30, 2013 | ||||||||||||||||||||
PNMR and PNM | $ | 2,250 | $ | — | $ | 2,224 | ||||||||||||||
December 31, 2012 | ||||||||||||||||||||
PNMR and PNM | $ | 2,933 | $ | — | $ | 2,777 | ||||||||||||||
Available-for-sale Securities [Table Text Block] | ' | |||||||||||||||||||
The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. | ||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||
Unrealized Gains | Fair Value | Unrealized Gains | Fair Value | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 24,414 | $ | — | $ | 4,628 | ||||||||||||
Equity securities: | ||||||||||||||||||||
   Domestic value | 10,519 | 34,967 | 5,223 | 30,044 | ||||||||||||||||
   Domestic growth | 23,355 | 67,527 | 15,212 | 51,650 | ||||||||||||||||
International and other | 1,543 | 16,159 | 247 | 14,868 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
   U.S. Government | 262 | 16,711 | 1,305 | 32,592 | ||||||||||||||||
   Municipals | 1,120 | 37,074 | 4,069 | 43,861 | ||||||||||||||||
   Corporate and other | 221 | 14,553 | 1,100 | 14,868 | ||||||||||||||||
$ | 37,020 | $ | 211,405 | $ | 27,156 | $ | 192,511 | |||||||||||||
The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Proceeds from sales | $ | 103,230 | $ | 90,518 | $ | 179,336 | $ | 136,305 | ||||||||||||
Gross realized gains | $ | 2,611 | $ | 6,263 | $ | 8,962 | $ | 11,029 | ||||||||||||
Gross realized (losses) | $ | (1,202 | ) | $ | (5,131 | ) | $ | (2,920 | ) | $ | (7,055 | ) | ||||||||
Investments Classified by Contractual Maturity Date [Table Text Block] | ' | |||||||||||||||||||
At September 30, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities: | ||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Available-for-Sale | Held-to-Maturity | |||||||||||||||||||
PNMR and PNM | PNMR | PNM | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Within 1 year | $ | 1,284 | $ | 4,840 | $ | 1,138 | ||||||||||||||
After 1 year through 5 years | 16,768 | 55,310 | 53,956 | |||||||||||||||||
After 5 years through 10 years | 8,027 | — | — | |||||||||||||||||
After 10 years through 15 years | 3,277 | — | — | |||||||||||||||||
After 15 years through 20 years | 5,512 | — | — | |||||||||||||||||
After 20 years | 33,470 | — | — | |||||||||||||||||
$ | 68,338 | $ | 60,150 | $ | 55,094 | |||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block] | ' | |||||||||||||||||||
Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | ||||||||||||||||||
September 30, 2013 | (In thousands) | |||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Decommissioning and reclamation investments: | ||||||||||||||||||||
   Cash and cash equivalents | $ | 24,414 | $ | 24,414 | $ | — | ||||||||||||||
   Equity securities: | ||||||||||||||||||||
     Domestic value | 34,967 | 34,967 | — | |||||||||||||||||
     Domestic growth | 67,527 | 67,527 | — | |||||||||||||||||
International and other | 16,159 | 16,159 | — | |||||||||||||||||
   Fixed income securities: | ||||||||||||||||||||
     U.S. government | 16,711 | 14,949 | 1,762 | |||||||||||||||||
     Municipals | 37,074 | — | 37,074 | |||||||||||||||||
     Corporate and other | 14,553 | — | 14,553 | |||||||||||||||||
          | $ | 211,405 | $ | 158,016 | $ | 53,389 | ||||||||||||||
Commodity derivative assets | $ | 10,027 | $ | — | $ | 10,027 | ||||||||||||||
Commodity derivative liabilities | (2,364 | ) | — | (2,364 | ) | |||||||||||||||
          Net | $ | 7,663 | $ | — | $ | 7,663 | ||||||||||||||
31-Dec-12 | ||||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Decommissioning and reclamation investments: | ||||||||||||||||||||
   Cash and cash equivalents | $ | 4,628 | $ | 4,628 | $ | — | ||||||||||||||
   Equity securities: | ||||||||||||||||||||
     Domestic value | 30,044 | 30,044 | — | |||||||||||||||||
     Domestic growth | 51,650 | 51,650 | — | |||||||||||||||||
     International and other | 14,868 | 14,868 | — | |||||||||||||||||
   Fixed income securities: | ||||||||||||||||||||
     U.S. government | 32,592 | 27,737 | 4,855 | |||||||||||||||||
     Municipals | 43,861 | — | 43,861 | |||||||||||||||||
     Corporate and other | 14,868 | — | 14,868 | |||||||||||||||||
          | $ | 192,511 | $ | 128,927 | $ | 63,584 | ||||||||||||||
Commodity derivative assets | $ | 4,137 | $ | — | $ | 4,137 | ||||||||||||||
Commodity derivative liabilities | (2,933 | ) | — | (2,933 | ) | |||||||||||||||
          Net | $ | 1,204 | $ | — | $ | 1,204 | ||||||||||||||
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | ' | |||||||||||||||
Information regarding the computation of earnings per share is as follows: | ||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Net Earnings Attributable to PNMR | $ | 54,555 | $ | 57,864 | $ | 92,859 | $ | 96,456 | ||||||||
Average Number of Common Shares: | ||||||||||||||||
Outstanding during period | 79,654 | 79,654 | 79,654 | 79,654 | ||||||||||||
    Vested awards of restricted stock | 177 | 114 | 194 | 156 | ||||||||||||
Average Shares - Basic | 79,831 | 79,768 | 79,848 | 79,810 | ||||||||||||
Dilutive Effect of Common Stock Equivalents (1): | ||||||||||||||||
Stock options and restricted stock | 503 | 622 | 608 | 600 | ||||||||||||
Average Shares - Diluted | 80,334 | 80,390 | 80,456 | 80,410 | ||||||||||||
Net Earnings Per Share of Common Stock: | ||||||||||||||||
Basic | $ | 0.68 | $ | 0.73 | $ | 1.16 | $ | 1.21 | ||||||||
Diluted | $ | 0.68 | $ | 0.72 | $ | 1.15 | $ | 1.2 | ||||||||
(1) | Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013. |
StockBased_Compensation_Tables
Stock-Based Compensation (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | |||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block] | ' | |||||||||||||
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 | 2013 | 2012 | ||||||||||||
Expected quarterly dividends per share | $ | 0.165 | $ | 0.145 | ||||||||||
Risk-free interest rate | 0.34 | % | 0.65 | % | ||||||||||
Market-Based Shares | ||||||||||||||
Dividend yield | 2.86 | % | 3.45 | % | ||||||||||
Expected volatility | 25.11 | % | 43.98 | % | ||||||||||
Risk-free interest rate | 0.36 | % | 1.04 | % | ||||||||||
The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months ended September 30, 2013: | ||||||||||||||
Stock Option Shares | Weighted- | Restricted Stock | Weighted- | |||||||||||
Average | Average | |||||||||||||
Exercise | Grant Date Fair Value | |||||||||||||
Price | ||||||||||||||
Outstanding at beginning of period | 1,992,700 | $ | 20.72 | 353,722 | $ | 14.03 | ||||||||
Granted | — | $ | — | 249,113 | $ | 20.03 | ||||||||
Exercised | (260,579 | ) | $ | 13.43 | (275,988 | ) | $ | 15.92 | ||||||
Forfeited | — | $ | — | (8,366 | ) | $ | 18.37 | |||||||
Expired | (292,644 | ) | $ | 27.23 | — | $ | — | |||||||
Outstanding at end of period | 1,439,477 | $ | 20.72 | 318,481 | $ | 17.88 | ||||||||
The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: | ||||||||||||||
Nine Months Ended September 30, | ||||||||||||||
Stock Options | 2013 | 2012 | ||||||||||||
Weighted-average grant date fair value of options granted | $ | — | $ | — | ||||||||||
Total fair value of options that vested (in thousands) | $ | 625 | $ | 1,058 | ||||||||||
Total intrinsic value of options exercised (in thousands) | $ | 2,466 | $ | 4,515 | ||||||||||
Restricted Stock | ||||||||||||||
Weighted-average grant date fair value | $ | 20.03 | $ | 15.63 | ||||||||||
Total fair value of restricted shares that vested (in thousands) | $ | 4,395 | $ | 4,755 | ||||||||||
Financing_Tables
Financing (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Schedule of Short-term Debt [Table Text Block] | ' | ||||||||
hort-term debt outstanding consisted of: | |||||||||
September 30, | December 31, | ||||||||
Short-term Debt | 2013 | 2012 | |||||||
(In thousands) | |||||||||
PNM – Revolving credit facility | $ | — | $ | 21,100 | |||||
TNMP – Revolving credit facility | 12,000 | — | |||||||
PNMR: | |||||||||
Revolving credit facility | — | 37,600 | |||||||
PNMR Term Loan Agreement | 100,000 | 100,000 | |||||||
$ | 112,000 | $ | 158,700 | ||||||
Pension_and_Other_Postretireme1
Pension and Other Postretirement Benefit Plans (Tables) | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||
Public Service Company of New Mexico [Member] | ' | |||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ' | |||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | |||||||||||||||||||||||
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 | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 65 | $ | 54 | $ | — | $ | — | ||||||||||||
Interest cost | 7,035 | 8,058 | 1,029 | 1,324 | 180 | 219 | ||||||||||||||||||
Expected return on plan assets | (10,482 | ) | (10,325 | ) | (1,261 | ) | (1,225 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 3,710 | 2,629 | 1,061 | 972 | 58 | 21 | ||||||||||||||||||
Amortization of prior service cost | 19 | 79 | (336 | ) | (336 | ) | — | — | ||||||||||||||||
Net periodic benefit cost | $ | 282 | $ | 441 | $ | 558 | $ | 789 | $ | 238 | $ | 240 | ||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 195 | $ | 162 | $ | — | $ | — | ||||||||||||
Interest cost | 21,106 | 24,174 | 3,085 | 3,972 | 540 | 657 | ||||||||||||||||||
Expected return on plan assets | (31,447 | ) | (30,975 | ) | (3,782 | ) | (3,675 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 11,130 | 7,887 | 3,182 | 2,916 | 174 | 63 | ||||||||||||||||||
Amortization of prior service cost | 57 | 237 | (1,008 | ) | (1,008 | ) | — | — | ||||||||||||||||
Net periodic benefit cost | $ | 846 | $ | 1,323 | $ | 1,672 | $ | 2,367 | $ | 714 | $ | 720 | ||||||||||||
Texas-New Mexico Power Company [Member] | ' | |||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ' | |||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | |||||||||||||||||||||||
The following tables present the components of the TNMP Plans' net periodic benefit cost (income): | ||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 75 | $ | 61 | $ | — | $ | — | ||||||||||||
Interest cost | 772 | 909 | 141 | 156 | 9 | 11 | ||||||||||||||||||
Expected return on plan assets | (1,212 | ) | (1,331 | ) | (126 | ) | (129 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 262 | 115 | — | (52 | ) | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 14 | 14 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (178 | ) | $ | (307 | ) | $ | 104 | $ | 50 | $ | 9 | $ | 11 | ||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 225 | $ | 183 | $ | — | $ | — | ||||||||||||
Interest cost | 2,315 | 2,727 | 424 | 468 | 27 | 33 | ||||||||||||||||||
Expected return on plan assets | (3,637 | ) | (3,993 | ) | (377 | ) | (387 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 787 | 345 | — | (156 | ) | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 43 | 42 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (535 | ) | $ | (921 | ) | $ | 315 | $ | 150 | $ | 27 | $ | 33 | ||||||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||
Schedule of Related Party Transactions [Table Text Block] | ' | |||||||||||||
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, | |||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||
(In thousands) | ||||||||||||||
Services billings: | ||||||||||||||
PNMR to PNM | $ | 22,241 | $ | 22,143 | 65,729 | 68,030 | ||||||||
PNMR to TNMP | 6,731 | 6,439 | 20,948 | 20,206 | ||||||||||
PNM to TNMP | 140 | 184 | 381 | 473 | ||||||||||
TNMP to PNMR | 2 | 4 | 6 | 12 | ||||||||||
Interest billings: | ||||||||||||||
PNMR to TNMP | 139 | 22 | 354 | 72 | ||||||||||
PNMR to PNM | — | — | 1 | 1 | ||||||||||
PNM to PNMR | 35 | 45 | 113 | 134 | ||||||||||
Income tax sharing payments: | ||||||||||||||
PNMR to PNM | — | — | 45,000 | 63,114 | ||||||||||
PNMR to TNMP | — | — | — | 1,952 | ||||||||||
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | $399,730 | $390,411 | $1,064,993 | $1,019,646 | ' |
Cost of energy | 114,674 | 110,777 | 325,039 | 297,342 | ' |
Margin | 285,056 | 279,634 | 739,954 | 722,304 | ' |
Other operating expenses | 124,574 | 118,664 | 368,454 | 363,031 | ' |
Depreciation and amortization | 42,743 | 42,820 | 125,189 | 122,289 | ' |
Operating income | 117,739 | 118,150 | 246,311 | 236,984 | ' |
Interest income | 2,264 | 3,130 | 7,731 | 9,808 | ' |
Other income (deductions) | -528 | 4,749 | 996 | 5,648 | ' |
Net interest charges | -30,365 | -30,515 | -92,279 | -90,280 | ' |
Earnings before Income Taxes | 89,110 | 95,514 | 162,759 | 162,160 | ' |
Income taxes (benefit) | 30,296 | 33,538 | 58,600 | 54,609 | ' |
Net Earnings | 58,814 | 61,976 | 104,159 | 107,551 | ' |
Valencia non-controlling interest | -4,127 | -3,980 | -10,904 | -10,699 | ' |
Subsidiary preferred stock dividends | -132 | -132 | -396 | -396 | ' |
Net Earnings Attributable to PNMR | 54,555 | 57,864 | 92,859 | 96,456 | ' |
Total Assets | 5,428,814 | 5,260,207 | 5,428,814 | 5,260,207 | 5,372,583 |
Goodwill | 278,297 | 278,297 | 278,297 | 278,297 | 278,297 |
Additions to utility and non-utility plant included in accounts payable | 18,207 | 8,005 | 18,207 | 8,005 | ' |
PNM Electric [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 326,026 | 321,731 | 863,609 | 832,242 | ' |
Cost of energy | 100,200 | 99,217 | 283,715 | 263,009 | ' |
Margin | 225,826 | 222,514 | 579,894 | 569,233 | ' |
Other operating expenses | 104,730 | 101,104 | 311,372 | 311,468 | ' |
Depreciation and amortization | 25,879 | 24,437 | 77,763 | 72,017 | ' |
Operating income | 95,217 | 96,973 | 190,759 | 185,748 | ' |
Interest income | 2,298 | 3,173 | 7,839 | 9,938 | ' |
Other income (deductions) | 2,211 | 5,210 | 6,977 | 9,201 | ' |
Net interest charges | -20,124 | -19,230 | -59,971 | -56,652 | ' |
Earnings before Income Taxes | 79,602 | 86,126 | 145,604 | 148,235 | ' |
Income taxes (benefit) | 27,652 | 31,235 | 49,184 | 51,929 | ' |
Net Earnings | 51,950 | 54,891 | 96,420 | 96,306 | ' |
Valencia non-controlling interest | -4,127 | -3,980 | -10,904 | -10,699 | ' |
Subsidiary preferred stock dividends | -132 | -132 | -396 | -396 | ' |
Net Earnings Attributable to PNMR | 47,691 | 50,779 | 85,120 | 85,211 | ' |
Total Assets | 4,192,470 | 4,073,331 | 4,192,470 | 4,073,331 | ' |
Goodwill | 51,632 | 51,632 | 51,632 | 51,632 | ' |
Additions to utility and non-utility plant included in accounts payable | 15,995 | 6,056 | 15,995 | 6,056 | ' |
TNMP Electric [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 73,704 | 68,680 | 201,384 | 187,404 | ' |
Cost of energy | 14,474 | 11,560 | 41,324 | 34,333 | ' |
Margin | 59,230 | 57,120 | 160,060 | 153,071 | ' |
Other operating expenses | 23,126 | 22,331 | 67,274 | 64,239 | ' |
Depreciation and amortization | 13,850 | 13,819 | 37,810 | 37,173 | ' |
Operating income | 22,254 | 20,970 | 54,976 | 51,659 | ' |
Interest income | 0 | 0 | 0 | 1 | ' |
Other income (deductions) | 716 | 366 | 1,409 | 1,244 | ' |
Net interest charges | -6,655 | -7,047 | -20,661 | -21,214 | ' |
Earnings before Income Taxes | 16,315 | 14,289 | 35,724 | 31,690 | ' |
Income taxes (benefit) | 6,209 | 5,205 | 13,554 | 11,577 | ' |
Net Earnings | 10,106 | 9,084 | 22,170 | 20,113 | ' |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | ' |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | ' |
Net Earnings Attributable to PNMR | 10,106 | 9,084 | 22,170 | 20,113 | ' |
Total Assets | 1,162,587 | 1,060,062 | 1,162,587 | 1,060,062 | ' |
Goodwill | 226,665 | 226,665 | 226,665 | 226,665 | ' |
Additions to utility and non-utility plant included in accounts payable | 544 | 886 | 544 | 886 | ' |
Corporate and Other [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 0 | 0 | 0 | 0 | ' |
Cost of energy | 0 | 0 | 0 | 0 | ' |
Margin | 0 | 0 | 0 | 0 | ' |
Other operating expenses | -3,282 | -4,771 | -10,192 | -12,676 | ' |
Depreciation and amortization | 3,014 | 4,564 | 9,616 | 13,099 | ' |
Operating income | 268 | 207 | 576 | -423 | ' |
Interest income | -34 | -43 | -108 | -131 | ' |
Other income (deductions) | -3,455 | -827 | -7,390 | -4,797 | ' |
Net interest charges | -3,586 | -4,238 | -11,647 | -12,414 | ' |
Earnings before Income Taxes | -6,807 | -4,901 | -18,569 | -17,765 | ' |
Income taxes (benefit) | -3,565 | -2,902 | -4,138 | -8,897 | ' |
Net Earnings | -3,242 | -1,999 | -14,431 | -8,868 | ' |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | ' |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | ' |
Net Earnings Attributable to PNMR | -3,242 | -1,999 | -14,431 | -8,868 | ' |
Total Assets | 73,757 | 126,814 | 73,757 | 126,814 | ' |
Goodwill | 0 | 0 | 0 | 0 | ' |
Additions to utility and non-utility plant included in accounts payable | $1,668 | $1,063 | $1,668 | $1,063 | ' |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Loss) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Equity [Abstract] | ' | ' | ' | ' |
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process | ' | ' | 19.60% | ' |
Percentage of Pension Liability Adjustment Capitalized into Other Accounts | ' | ' | 1.10% | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | ($81,630) | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | -4,264 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 1,692 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 18,693 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | -7,417 | ' |
Total Other Comprehensive Income (Loss) | 5,668 | 1,770 | 8,704 | 5,998 |
Balance at March 31, 2013 | -72,926 | ' | -72,926 | ' |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | 16,406 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | -9,190 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 3,639 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 19,056 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | -7,544 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 5,961 | ' |
Balance at March 31, 2013 | 22,367 | ' | 22,367 | ' |
Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -97,820 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 4,773 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | -1,893 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 0 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 2,880 | ' |
Balance at March 31, 2013 | -94,940 | ' | -94,940 | ' |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -216 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 153 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | -54 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | -363 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 127 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | -137 | ' |
Balance at March 31, 2013 | -353 | ' | -353 | ' |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -81,414 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | -4,417 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 1,746 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 19,056 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | -7,544 | ' |
Total Other Comprehensive Income (Loss) | 5,871 | 1,833 | 8,841 | 6,183 |
Balance at March 31, 2013 | -72,573 | ' | -72,573 | ' |
Public Service Company of New Mexico [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | 16,406 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | -9,190 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 3,639 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 19,056 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | -7,544 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 5,961 | ' |
Balance at March 31, 2013 | 22,367 | ' | 22,367 | ' |
Public Service Company of New Mexico [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -97,820 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 4,773 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | -1,893 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 0 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 2,880 | ' |
Balance at March 31, 2013 | -94,940 | ' | -94,940 | ' |
Public Service Company of New Mexico [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | 0 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 0 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 0 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 0 | ' |
Balance at March 31, 2013 | 0 | ' | 0 | ' |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -216 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 153 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | -54 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | -363 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 127 | ' |
Total Other Comprehensive Income (Loss) | -203 | -63 | -137 | -185 |
Balance at March 31, 2013 | -353 | ' | -353 | ' |
Texas-New Mexico Power Company [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | 0 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 0 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 0 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 0 | ' |
Balance at March 31, 2013 | 0 | ' | 0 | ' |
Texas-New Mexico Power Company [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | 0 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 0 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | 0 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 0 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | 0 | ' |
Balance at March 31, 2013 | 0 | ' | 0 | ' |
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Balance at December 31, 2012 | ' | ' | -216 | ' |
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | ' | ' | 153 | ' |
Income tax impact of amounts reclassified from accumulated other comprehensive income | ' | ' | -54 | ' |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | ' | ' | -363 | ' |
Other Comprehensive Income (Loss), Tax | ' | ' | 127 | ' |
Total Other Comprehensive Income (Loss) | ' | ' | -137 | ' |
Balance at March 31, 2013 | ($353) | ' | ($353) | ' |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | 30-May-08 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Purchased Through May 30, 2028 [Member] | Delta [Member] | Delta [Member] | Delta [Member] | ||||||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Property Lease Guarantee [Member] | Valencia [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | |||||||||||
Maximum [Member] | Public Service Company of New Mexico [Member] | |||||||||||||||||||||||||
Public Service Company of New Mexico [Member] | MW | |||||||||||||||||||||||||
Variable Interest Entity [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of mega watts purchased (in megawatts) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 145 | ' | ' | ' |
Long Term Contract For Purchase of Electric Power Fixed Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $4,800,000 | $4,800,000 | $14,100,000 | $14,000,000 | ' | $1,600,000 | $1,600,000 | $4,800,000 | $4,700,000 | ' | ' | ' | ' | ' | ' | ' |
Long Term Contract For Purchase of Electric Power Variable Charges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | 600,000 | 1,000,000 | 900,000 | ' | 700,000 | 300,000 | 1,300,000 | 600,000 | ' | ' | ' | ' | ' | ' | ' |
Variable Interest Entity, Statement Of Operation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,453,000 | 5,358,000 | 15,150,000 | 14,916,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,326,000 | -1,378,000 | -4,246,000 | -4,217,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Earnings Attributable to non-controlling interest | 4,127,000 | 3,980,000 | 10,904,000 | 10,699,000 | ' | 4,127,000 | 3,980,000 | 10,904,000 | 10,699,000 | ' | 4,127,000 | 3,980,000 | 10,904,000 | 10,699,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current assets | 400,520,000 | ' | 400,520,000 | ' | 442,191,000 | 380,216,000 | ' | 380,216,000 | ' | 387,689,000 | 3,457,000 | ' | 3,457,000 | ' | 3,655,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net property, plant and equipment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,841,000 | ' | 75,841,000 | ' | 77,953,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Assets | 5,428,814,000 | 5,260,207,000 | 5,428,814,000 | 5,260,207,000 | 5,372,583,000 | 4,192,470,000 | ' | 4,192,470,000 | ' | 4,163,907,000 | 79,298,000 | ' | 79,298,000 | ' | 81,608,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current liabilities | 415,593,000 | ' | 415,593,000 | ' | 434,103,000 | 186,272,000 | ' | 186,272,000 | ' | 242,751,000 | 1,028,000 | ' | 1,028,000 | ' | 765,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Owners' equity - non-controlling interest | 78,270,000 | ' | 78,270,000 | ' | 80,843,000 | 78,270,000 | ' | 78,270,000 | ' | 80,843,000 | 78,270,000 | ' | 78,270,000 | ' | 80,843,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Fixed Rate Percentage of Renewal Options After Original Lease Term | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Renewal Options After Original Lease Term (in years) | ' | ' | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Lease, Percentage of Unit 2 Capacity That May Be Extended | ' | ' | ' | ' | ' | ' | ' | 14.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Extended Lease Term Option (in years) | ' | ' | ' | ' | ' | ' | ' | '6 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Future Minimum Payments Due | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 52,600,000 | ' | ' | ' | ' | ' | ' |
Loss Contingency, Range of Possible Loss, Portion Not Accrued | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 154,100,000 | ' | ' | ' | ' |
Operating Leases, Future Minimum Payments Due, Next Six Months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,800,000 | 26,000,000 | ' | ' | ' | ' | ' |
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,700,000 | ' | 40,700,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Payments to Acquire Businesses, Gross | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,000,000 | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,900,000 | 16,900,000 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,200,000 | 3,200,000 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,300,000 | 25,300,000 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | 21,000,000 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,900,000 | 18,900,000 |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,800,000 | 6,800,000 |
Net Earnings | $54,555,000 | $57,864,000 | $92,859,000 | $96,456,000 | ' | $47,823,000 | $50,911,000 | $85,516,000 | $85,607,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $600,000 | $900,000 |
Long term contract option to purchase, ownership percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, number of days to set FMV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '60 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, purchase price - percentage of adjusted NBV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, purchase price - percentage of FMV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, approximate approval period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair_Value_of_Derivative_and_O2
Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Derivatives, Fair Value [Line Items] | ' | ' |
Assets, Current | $400,520,000 | $442,191,000 |
Liabilities, Current | 415,593,000 | 434,103,000 |
Commodity derivative instruments, Current assets | 5,743,000 | 3,785,000 |
Commodity derivative instruments, Deferred charges | 4,284,000 | 352,000 |
Commodity derivative instruments, Current liabilities | -1,017,000 | -1,000,000 |
Commodity derivative instruments, Long-term liabilities | -1,347,000 | -1,933,000 |
PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Margin Deposit Assets | 2,000,000 | 1,900,000 |
Public Service Company of New Mexico [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Assets, Current | 380,216,000 | 387,689,000 |
Liabilities, Current | 186,272,000 | 242,751,000 |
Commodity derivative instruments, Current assets | 5,743,000 | 3,785,000 |
Commodity derivative instruments, Deferred charges | 4,284,000 | 352,000 |
Commodity derivative instruments, Current liabilities | -1,017,000 | -1,000,000 |
Commodity derivative instruments, Long-term liabilities | -1,347,000 | -1,933,000 |
Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Commodity derivative instruments, Current assets | 5,743,000 | 3,785,000 |
Commodity derivative instruments, Deferred charges | 4,284,000 | 352,000 |
Commodity derivative instruments, Assets | 10,027,000 | 4,137,000 |
Commodity derivative instruments, Current liabilities | -1,017,000 | -1,000,000 |
Commodity derivative instruments, Long-term liabilities | -1,347,000 | -1,933,000 |
Commodity derivative instruments, Liabilities | -2,364,000 | -2,933,000 |
Commodity derivative instruments, Net | 7,663,000 | 1,204,000 |
Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Fair Value Hedging [Member] | Public Service Company of New Mexico [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Assets, Current | 600,000 | 100,000 |
Assets, Noncurrent | 100,000 | ' |
Liabilities, Current | 100,000 | ' |
Palo Verde Nuclear Generating Station [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Commodity derivative instruments, Current assets | 2,300,000 | ' |
Commodity derivative instruments, Deferred charges | $3,800,000 | ' |
Palo Verde Nuclear Generating Station [Member] | Firm Contract [Member] | Public Service Company of New Mexico [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Percentage of Electric Power Plant Output Sold through 2013 | 100.00% | ' |
Fair_Value_of_Derivative_and_O3
Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (Commodity Contract [Member], Fair Value Hedging [Member], USD $) | 9 Months Ended | 3 Months Ended | ||||||||||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Electric operating revenues [Member] | Electric operating revenues [Member] | Cost of energy [Member] | Cost of energy [Member] | PNMR and PNM [Member] | PNMR and PNM [Member] | PNMR and PNM [Member] | PNMR and PNM [Member] | PNMR and PNM [Member] | PNMR and PNM [Member] | |||
Electric operating revenues [Member] | Electric operating revenues [Member] | Cost of energy [Member] | Cost of energy [Member] | |||||||||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (loss) | $6,164 | $619 | $5,743 | $897 | $421 | ($278) | $7,005 | ($477) | $7,077 | ($740) | ($72) | $263 |
Fair_Value_of_Derivative_and_O4
Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (PNMR and PNM [Member], USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Derivative [Line Items] | ' | ' |
Contractual Liability | $2,250 | $2,933 |
Existing Cash Collateral | 0 | 0 |
Net Exposure | $2,224 | $2,777 |
Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Volume positions (Decatherms / MWh) | -3,801,738 | 1,127,500 |
Fair_Value_of_Derivative_and_O5
Fair Value of Derivative and Other Financial Instruments, Available for Sale Securities (Details) (PNMR and PNM [Member], USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | $37,020 | ' | $27,156 |
Available-for-sale securities, Fair value | 211,405 | ' | 211,405 | ' | 192,511 |
Proceeds from sales | 103,230 | 90,518 | 179,336 | 136,305 | ' |
Gross realized gains | 2,611 | 6,263 | 8,962 | 11,029 | ' |
Gross realized (losses) | -1,202 | -5,131 | -2,920 | -7,055 | ' |
Cash and equivalents [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 0 | ' | 0 |
Available-for-sale securities, Fair value | 24,414 | ' | 24,414 | ' | 4,628 |
Domestic value [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 10,519 | ' | 5,223 |
Available-for-sale securities, Fair value | 34,967 | ' | 34,967 | ' | 30,044 |
Domestic growth [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 23,355 | ' | 15,212 |
Available-for-sale securities, Fair value | 67,527 | ' | 67,527 | ' | 51,650 |
International and other [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 1,543 | ' | 247 |
Available-for-sale securities, Fair value | 16,159 | ' | 16,159 | ' | 14,868 |
U.S. Government [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 262 | ' | 1,305 |
Available-for-sale securities, Fair value | 16,711 | ' | 16,711 | ' | 32,592 |
Municipals [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 1,120 | ' | 4,069 |
Available-for-sale securities, Fair value | 37,074 | ' | 37,074 | ' | 43,861 |
Corporate and other [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 221 | ' | 1,100 |
Available-for-sale securities, Fair value | $14,553 | ' | $14,553 | ' | $14,868 |
Fair_Value_of_Derivative_and_O6
Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) | Sep. 30, 2013 |
In Thousands, unless otherwise specified | |
PNM Resources [Member] | ' |
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | ' |
Held-to-maturity debt securities, Due within 1 year | $4,840 |
Held-to-maturity debt securities, After 1 year through 5 years | 55,310 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | 60,150 |
Public Service Company of New Mexico [Member] | ' |
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | ' |
Held-to-maturity debt securities, Due within 1 year | 1,138 |
Held-to-maturity debt securities, After 1 year through 5 years | 53,956 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | 55,094 |
PNMR and PNM [Member] | ' |
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | ' |
Available-for-sale debt securities, Within 1 year | 1,284 |
Available-for-sale debt securities, After 1 year through 5 years | 16,768 |
Available-for-sale debt securities, After 5 years through 10 years | 8,027 |
Available-for-sale debt securities, After 10 years through 15 years | 3,277 |
Available-for-sale debt securities, After 15 years through 20 years | 5,512 |
Available-for-sale debt securities, After 20 years | 33,470 |
Available-for-sale debt securities | $68,338 |
Fair_Value_of_Derivative_and_O7
Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Net | ' | $281 |
Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Net | ' | 0 |
Level 3 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Net | ' | 0 |
PNMR and PNM [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 211,405 | 192,511 |
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 211,405 | 192,511 |
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 158,016 | 128,927 |
PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 53,389 | 63,584 |
PNMR and PNM [Member] | Cash and equivalents [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 24,414 | 4,628 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 24,414 | 4,628 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 24,414 | 4,628 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | Domestic value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 34,967 | 30,044 |
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 34,967 | 30,044 |
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 34,967 | 30,044 |
PNMR and PNM [Member] | Domestic value [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | Domestic growth [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 67,527 | 51,650 |
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 67,527 | 51,650 |
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 67,527 | 51,650 |
PNMR and PNM [Member] | Domestic growth [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | International and other [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 16,159 | 14,868 |
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 16,159 | 14,868 |
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 16,159 | 14,868 |
PNMR and PNM [Member] | International and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | U.S. Government [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 16,711 | 32,592 |
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 16,711 | 32,592 |
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 14,949 | 27,737 |
PNMR and PNM [Member] | U.S. Government [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 1,762 | 4,855 |
PNMR and PNM [Member] | Municipals [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 37,074 | 43,861 |
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 37,074 | 43,861 |
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | Municipals [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 37,074 | 43,861 |
PNMR and PNM [Member] | Corporate and other [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 14,553 | 14,868 |
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 14,553 | 14,868 |
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 0 | 0 |
PNMR and PNM [Member] | Corporate and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 14,553 | 14,868 |
Public Service Company of New Mexico [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,400,109 | 1,385,433 |
Investment In PVNGS lessor notes | 55,094 | 84,198 |
Other investments | 458 | 494 |
Public Service Company of New Mexico [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 458 | 494 |
Public Service Company of New Mexico [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,400,109 | 1,385,433 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 0 | 0 |
Public Service Company of New Mexico [Member] | Level 3 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Investment In PVNGS lessor notes | 55,094 | 84,198 |
Other investments | 0 | 0 |
PNM Resources [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,929,828 | 1,969,362 |
Investment In PVNGS lessor notes | 55,094 | 84,198 |
Other investments | 6,941 | 6,965 |
PNM Resources [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 739 | 774 |
PNM Resources [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,926,126 | 1,966,725 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 0 | 0 |
PNM Resources [Member] | Level 3 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 3,702 | 2,637 |
Investment In PVNGS lessor notes | 55,094 | 84,198 |
Other investments | 6,202 | 6,191 |
Texas-New Mexico Power Company [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 393,122 | 418,166 |
Other investments | 281 | 281 |
Texas-New Mexico Power Company [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Other investments | 281 | ' |
Texas-New Mexico Power Company [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 393,122 | 418,166 |
Other investments | 0 | ' |
Texas-New Mexico Power Company [Member] | Level 3 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Other investments | 0 | ' |
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Fair Value [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 10,027 | 4,137 |
Commodity derivative instruments, Liabilities | -2,364 | -2,933 |
Commodity derivative instruments, Net | 7,663 | 1,204 |
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 0 | 0 |
Commodity derivative instruments, Liabilities | 0 | 0 |
Commodity derivative instruments, Net | 0 | 0 |
Commodity Contract [Member] | PNMR and PNM [Member] | Measured on a recurring basis [Member] | Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 10,027 | 4,137 |
Commodity derivative instruments, Liabilities | -2,364 | -2,933 |
Commodity derivative instruments, Net | 7,663 | 1,204 |
Carrying Amount [Member] | Public Service Company of New Mexico [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,290,608 | 1,215,579 |
Investment In PVNGS lessor notes | 53,300 | 77,682 |
Other investments | 458 | 494 |
Carrying Amount [Member] | PNM Resources [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,748,841 | 1,672,290 |
Investment In PVNGS lessor notes | 53,300 | 77,682 |
Other investments | 2,803 | 5,599 |
Carrying Amount [Member] | Texas-New Mexico Power Company [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 336,128 | 311,589 |
Other investments | $281 | $281 |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Thousands, except Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Earnings Per Share [Abstract] | ' | ' | ' | ' | ||||
Net Earnings Attributable to PNMR | $54,555 | $57,864 | $92,859 | $96,456 | ||||
Average Number of Common Shares: | ' | ' | ' | ' | ||||
Outstanding during period | 79,654,000 | 79,654,000 | 79,654,000 | 79,654,000 | ||||
Vested awards of restricted stock | 177,000 | 114,000 | 194,000 | 156,000 | ||||
Average Shares - Basic | 79,831,000 | 79,768,000 | 79,848,000 | 79,810,000 | ||||
Dilutive Effect of Common Stock Equivalents: | ' | ' | ' | ' | ||||
Stock options and restricted stock | 503,000 | [1] | 622,000 | [1] | 608,000 | [1] | 600,000 | [1] |
Average Shares - Diluted | 80,334,000 | 80,390,000 | 80,456,000 | 80,410,000 | ||||
Net Earnings Per Share of Common Stock | ' | ' | ' | ' | ||||
Basic (dollars per share) | $0.68 | $0.73 | $1.16 | $1.21 | ||||
Diluted (dollars per share) | $0.68 | $0.72 | $1.15 | $1.20 | ||||
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares) | ' | ' | 793,010 | ' | ||||
[1] | Excludes the effect of out-of-the-money options for 793,010 shares of common stock at September 30, 2013. |
StockBased_Compensation_Detail
Stock-Based Compensation (Details) (USD $) | 9 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | |||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | |
Stock Options [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Market-Based Shares [Member] | Market-Based Shares [Member] | Executive [Member] | Executive [Member] | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Performance Equity Plan [Member] | ||||
Performance Shares [Member] | Performance Shares [Member] | Common Stock [Member] | Common Stock [Member] | ||||||||||
Chairman, President, and Chief Executive Officer [Member] | Chairman, President, and Chief Executive Officer [Member] | ||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at beginning of period, Shares | 1,992,700 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share) | $20.72 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Granted, Shares | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Granted, Weighted-Average Exercise Price (in dollars per share) | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Exercised, Shares | -260,579 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Exercised, Weighted-Average Exercise Price (in dollars per share) | $13.43 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Forfeited, Shares | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share) | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Expired, Shares | -292,644 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Expired, Weighted-Average Exercise Price (in dollars per share) | $27.23 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Shares | 1,439,477 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share) | $20.72 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Aggregate Intrinsic Value | ' | ' | ' | $6,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years) | ' | ' | ' | '3 years 6 months 22 days | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, No intrinsic value | 793,010 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted-average grant date fair value options granted (dollars per share) | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total fair value of options that vested | 625,000 | 1,058,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total intrinsic value of options exercised | 2,466,000 | 4,515,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at beginning of period, Shares | ' | ' | ' | ' | 353,722 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $14.03 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Granted, Shares | ' | ' | ' | ' | 249,113 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $20.03 | $15.63 | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Vested, Shares | ' | ' | ' | ' | -275,988 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $15.92 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Forfeited, Shares | ' | ' | ' | ' | -8,366 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $18.37 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at end of period, Shares | ' | ' | ' | ' | 318,481 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $17.88 | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total fair value of shares that vested | ' | ' | ' | ' | 4,395,000 | 4,755,000 | ' | ' | ' | ' | ' | ' | ' |
Expected quarterly dividends per share | ' | ' | ' | ' | $0.17 | $0.14 | ' | ' | ' | ' | ' | ' | ' |
Risk-free interest rate | ' | ' | ' | ' | 0.34% | 0.65% | 0.36% | 1.04% | ' | ' | ' | ' | ' |
Granted and Vested in Period | ' | ' | ' | ' | ' | ' | ' | ' | 100,953 | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One | ' | ' | ' | ' | ' | ' | ' | ' | ' | 188,129 | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two | ' | ' | ' | ' | ' | ' | ' | ' | ' | 198,369 | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three | ' | ' | ' | ' | ' | ' | ' | ' | ' | 179,811 | ' | ' | ' |
Shares received if achieves specified improvement in total shareholders return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000 | 35,000 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | ' | ' | ' | ' | ' | ' | 2.86% | 3.45% | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | ' | ' | ' | ' | ' | ' | 25.11% | 43.98% | ' | ' | ' | ' | ' |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $5,700,000 | ' | $3,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Financing_Shortterm_Debt_Detai
Financing, Short-term Debt (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Apr. 22, 2013 |
Line of Credit [Member] | Line of Credit [Member] | Revolving Credit Facility [Member] | PNM Resources [Member] | PNM Resources [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Available Borrowing Capacity [Member] | Available Borrowing Capacity [Member] | Available Borrowing Capacity [Member] | Available Borrowing Capacity [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Affiliated Entity [Member] | PNMR Term Loan Agreement [Member] | PNMR Term Loan Agreement [Member] | PNMR Term Loan Agreement [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | PNM Term Loan Agreement [Member] | PNM Term Loan Agreement [Member] | |||
Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | PNM Resources [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | PNM Resources [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Intercompany loan agreements [Member] | Notes Payable to Banks [Member] | Texas-New Mexico Power Company [Member] | Notes Payable to Banks [Member] | Notes Payable to Banks [Member] | |||||||||||||
Texas-New Mexico Power Company [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Short term debt, number of options to extend | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.44% | ' |
Line of Credit Facility, Maximum Borrowing Capacity | ' | ' | ' | ' | ' | $300,000,000 | ' | ' | ' | $400,000,000 | ' | ' | ' | $75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Collateral Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' | ' |
Proceeds from Short-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' |
Short-term Debt, Weighted Average Interest Rate | 1.31% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Short-term debt | 112,000,000 | 158,700,000 | 112,000,000 | 158,700,000 | ' | 0 | 37,600,000 | 0 | 21,100,000 | 0 | 21,100,000 | 12,000,000 | 0 | 12,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | 100,000,000 | ' | ' | ' | 75,000,000 |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 755,900,000 | 291,400,000 | 396,800,000 | 67,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Short-term debt – affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,100,000 | 28,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43,000,000 | ' | ' | ' | ' | ' | ' |
Restricted Cash and Investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6,500,000 | $15,700,000 | $0 | ' | ' | ' | ' | ' | ' | ' |
Short term debt, option to extend - period of extension | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Financing_Financing_Activities
Financing, Financing Activities (Details) (USD $) | 9 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | ||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Mar. 06, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Apr. 03, 2013 | Apr. 03, 2013 | Mar. 06, 2013 | Apr. 03, 2013 | Mar. 06, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 02, 2013 | Apr. 22, 2013 | Sep. 30, 2013 | |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | PNMR Term Loan Agreement [Member] | PNMR Term Loan Agreement [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Senior Unsecured Note, Due 2015, at 9 point 25 percent [Member] | Senior Unsecured Note, Due 2015, at 9 point 25 percent [Member] | Subsequent Event [Member] | Notes Payable to Banks [Member] | Notes Payable to Banks [Member] | ||||
Texas-New Mexico Power Company [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | First Mortgage Bonds, due 2043, Series 2013A [Member] | First Mortgage Bonds, due 2043, Series 2013A [Member] | Local Lines of Credit [Member] | PNM Term Loan Agreement [Member] | PNM Term Loan Agreement [Member] | ||||||||||||||
Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | $1,000 | ' | ' | ' | ' | ' | $265,500,000 | $93,200,000 | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.50% | 9.50% | 6.95% | 6.95% | 9.25% | ' | ' | ' | 1.44% |
Debt Instrument, Cash Offered for Debt Exchanged | ' | ' | ' | ' | ' | ' | ' | 140 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash paid in debt exchange | -13,048,000 | 0 | ' | ' | ' | -13,048,000 | 0 | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Cash for Bond Exchange Conversion | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.14 | ' | ' | ' | ' | ' |
Debt Instrument, Unamortized Premium | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,200,000 | ' | ' | ' | ' | ' | ' |
Short-term debt | 112,000,000 | ' | 158,700,000 | 0 | 21,100,000 | 12,000,000 | ' | ' | 0 | 100,000,000 | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' |
Repayments of Lines of Credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' |
Unsecured Long-term Debt, Noncurrent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,000,000 | ' | ' | ' |
Debt Instrument, Cash Paid for Unsecured Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | ' | ' | ' |
Debt Instruments, NMPRC Approved credit facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $50,000,000 | ' | ' |
Commitments_and_Contingencies_
Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $) | Dec. 21, 2011 | Dec. 21, 2011 | Oct. 31, 2012 | Sep. 30, 2013 | Nov. 08, 2010 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 06, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Jan. 31, 2010 | Sep. 30, 2013 | Jan. 31, 2010 | Sep. 30, 2012 | Oct. 31, 2012 | Sep. 30, 2013 | Oct. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | mw | San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station Units 2 and 3 [Member] | Four Corners [Member] | Clean Air Act related to Regional Haze [Member] | Clean Air Act Related to Post Combustion Controls [Member] | Clean Air Act Related to Post Combustion Controls [Member] | Mercury Control [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Environmental Protection Agency [Member] | Environmental Protection Agency [Member] | Nuclear Spent Fuel And Waste Disposal [Member] | Nuclear Spent Fuel And Waste Disposal [Member] | Nuclear Spent Fuel And Waste Disposal [Member] |
Public Service Company of New Mexico [Member] | PNM Electric [Member] | state | Four Corners [Member] | Four Corners [Member] | San Juan Generating Station [Member] | San Juan Generating Station Units 1 and 4 [Member] | San Juan Generating Station And Four Corners [Member] | San Juan Generating Station Units 1 and 4 [Member] | San Juan Generating Station And Four Corners [Member] | Mercury Control [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | WildEarth Guardians filed an action to challenge EPA's rule in the Tenth Circuit [Member] | Clean Air Act Related to Post Combustion Controls [Member] | Palo Verde Nuclear Generating Station [Member] | Other Deferred Credits [Member] | Other Deferred Credits [Member] | ||||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station [Member] | Four Corners [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | |||||||
compliance_alternative | opp | opp | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | San Juan Generating Station Units 1 and 4 [Member] | San Juan Generating Station [Member] | San Juan Generating Station Units 1 and 4 [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | |||||||||||||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | ||||||||||||||||||||
Public Utilities, Commitments and Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Estimate of Possible Loss | ' | ' | ' | ' | ' | ' | $75 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $42.80 | ' | ' |
Public Utilities, Number of Compliance alternatives | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Plant Requirement to Meet NOx emissions Limit | ' | ' | ' | ' | ' | ' | 0.015 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of States To Address Regional Haze | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum | ' | ' | ' | ' | ' | 250 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Total Capital Cost If Requirement Occurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 824 | ' | 910 | ' | ' | ' | ' | ' | ' |
Estimated Installation Capital Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85 | 60 | 90 | 80 | ' | ' | ' | ' | ' |
Estimated Portion of Total Capital Costs if Requirement Occurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105 | ' | 110 | ' | ' | ' | ' | ' | ' |
Jointly Owned Utility Plant, Proportionate Ownership Share | ' | ' | 46.30% | ' | ' | ' | ' | ' | ' | 52.00% | ' | 55.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units | ' | ' | ' | 299 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net book value | ' | ' | ' | 287 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Government Standard Emission Limit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.06 | ' | 0.07 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current Annual Mercury Control Costs | ' | ' | ' | ' | ' | ' | ' | ' | 0.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contingent Estimated Annual Mercury Control Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards | 25 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Mercury Removal Rate, Percentage | ' | 99.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Proposed Seeking Shorter Compliance Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' |
Public Utilities, Number of years after issuance of final determination to achieve compliance with requirements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' |
Loss Contingency Accrual, at Carrying Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $12.40 | $13.90 |
Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage | ' | ' | ' | ' | 48.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_and_Contingencies_1
Commitments and Contingencies (Other Commitments and Contingencies) (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Oct. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | Surface [Member] | TGP Granada, LLC and its affiliate Complaint [Member] | TGP Granada, LLC and its affiliate Complaint [Member] | Nuclear Plant [Member] | Nuclear Plant [Member] | Nuclear Plant [Member] | Nuclear Plant [Member] | Loss on Long-term Purchase Commitment [Member] | Loss on Long-term Purchase Commitment [Member] | Loss on Long-term Purchase Commitment [Member] | Loss on Long-term Purchase Commitment [Member] | Loss on Long-term Purchase Commitment [Member] | Loss on Long-term Purchase Commitment [Member] | San Juan Underground Mine Fire [Member] | Continuous Highwall Mining [Member] | SJCC Arbitration [Member] | SJCC Arbitration [Member] | NMTRD Coal Severance Tax [Member] | NMTRD Coal Severance Tax [Member] | |||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Tortoise Capital Resources Corporation [Member] | Palo Verde Nuclear Generating Station [Member] | Maximum [Member] | Commercial Providers [Member] | Industry Wide Retrospective Assessment Program [Member] | Surface [Member] | Surface [Member] | Surface [Member] | Underground [Member] | Underground [Member] | Underground [Member] | Fuel and Purchased Power Adjustment Clause [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | Four Corners [Member] | Four Corners [Member] | ||||||
Coal Supply [Member] | Coal Supply [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | ||||||||||||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | |||||||||||||||||||||
Public Utilities, Commitments and Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other current assets | $37,404,000 | $31,490,000 | $32,294,000 | $27,457,000 | ' | $15,800,000 | $9,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Final Reclamation, capped amount to be collected | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Preliminary estimate increased deferral related to mine fire incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,600,000 | ' | ' | ' | ' | ' |
Public Utilities, Insurance Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,700,000 | ' | ' | ' | ' | ' |
Public Utilities, Proposed Retroactive Surface Mining Royalty Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12.50% | ' | ' | ' | ' |
Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.00% | ' | ' | ' | ' |
Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' |
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 46.30% | ' | ' | ' | ' |
Public Utilities, SJCC Disputed Mining Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500,000 | ' | ' | ' |
Public Utilities, PNM Share of SJCC Disputed Mining Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | ' | ' | ' |
Public Utilities, PNM Share of SJCC Disputed Mining Costs to pass through FPPAC | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' |
Public Utilities, Potential Unbilled Mining Costs Owed to SJCC | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,200,000 | ' | ' | ' |
Public Utilities, Potential Overbilled Mining Costs SJCC Owes to SJGS Owners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,100,000 | ' | ' | ' |
Public Utilities, Potential Capital Improvements billed as Mining Costs to SJGS Owners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,900,000 | ' | ' | ' |
Public Utilities, PNM Share of arbitration ruling | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 46.30% | ' | ' |
Public Utilities, FFPAC Percentage of mining costs overbilled or unbilled ruled by arbitration | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33.00% | ' | ' |
Public Utilities, FFPAC Percentage of capital improvements billed as mining costs ruled by arbitration | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25.00% | ' | ' |
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' |
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.00% |
Public Utilities, Liability Insurance Coverage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,600,000,000 | 375,000,000 | 13,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Ownership Percentage in Nuclear Reactor | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Maximum Potential Assessment Per Incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Annual Payment Limitation Related to Incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Aggregate Amount of All Risk Insurance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,750,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Sublimit Amount under Nuclear Electric Insurance Limited | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Lease ownership percentage in EIP | ' | ' | ' | ' | ' | ' | ' | ' | 60.00% | 40.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Option to Purchase Leased Capacity At Fair Value | ' | ' | ' | ' | 7,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Estimate of Possible Loss | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,900,000 | ' | ' | 19,700,000 | ' | ' | ' | ' | ' | ' |
Loss Contingency Accrual, at Carrying Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,700,000 | 26,800,000 | ' | 4,600,000 | 4,200,000 | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets | ' | ' | ' | ' | ' | ' | ' | $100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pension_and_Other_Postretireme2
Pension and Other Postretirement Benefit Plans (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Public Service Company of New Mexico [Member] | Pension Plan [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | $0 | $0 | $0 | $0 |
Interest cost | 7,035,000 | 8,058,000 | 21,106,000 | 24,174,000 |
Long-term return on plan assets | -10,482,000 | -10,325,000 | -31,447,000 | -30,975,000 |
Amortization of net loss | 3,710,000 | 2,629,000 | 11,130,000 | 7,887,000 |
Amortization of prior service cost | 19,000 | 79,000 | 57,000 | 237,000 |
Net periodic benefit cost | 282,000 | 441,000 | 846,000 | 1,323,000 |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | 60,000,000 | 77,700,000 |
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 49,100,000 | ' | 49,100,000 | ' |
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | ' | ' | 4.80% | ' |
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | ' | ' | 5.20% | ' |
Public Service Company of New Mexico [Member] | OPEB [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 65,000 | 54,000 | 195,000 | 162,000 |
Interest cost | 1,029,000 | 1,324,000 | 3,085,000 | 3,972,000 |
Long-term return on plan assets | -1,261,000 | -1,225,000 | -3,782,000 | -3,675,000 |
Amortization of net loss | 1,061,000 | 972,000 | 3,182,000 | 2,916,000 |
Amortization of prior service cost | -336,000 | -336,000 | -1,008,000 | -1,008,000 |
Net periodic benefit cost | 558,000 | 789,000 | 1,672,000 | 2,367,000 |
Defined Benefit Plan, Contributions by Employer | 800,000 | 800,000 | 2,400,000 | 2,400,000 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 3,300,000 | ' | 3,300,000 | ' |
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 180,000 | 219,000 | 540,000 | 657,000 |
Long-term return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net loss | 58,000 | 21,000 | 174,000 | 63,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net periodic benefit cost | 238,000 | 240,000 | 714,000 | 720,000 |
Defined Benefit Plan, Contributions by Employer | 400,000 | 400,000 | 1,100,000 | 1,100,000 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 1,500,000 | ' | 1,500,000 | ' |
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 772,000 | 909,000 | 2,315,000 | 2,727,000 |
Long-term return on plan assets | -1,212,000 | -1,331,000 | -3,637,000 | -3,993,000 |
Amortization of net loss | 262,000 | 115,000 | 787,000 | 345,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net periodic benefit cost | -178,000 | -307,000 | -535,000 | -921,000 |
Defined Benefit Plan, Contributions by Employer | 0 | ' | 1,000,000 | 5,300,000 |
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 4.80% | ' | ' | ' |
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 5.20% | ' | ' | ' |
Texas-New Mexico Power Company [Member] | OPEB [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 75,000 | 61,000 | 225,000 | 183,000 |
Interest cost | 141,000 | 156,000 | 424,000 | 468,000 |
Long-term return on plan assets | -126,000 | -129,000 | -377,000 | -387,000 |
Amortization of net loss | 0 | -52,000 | 0 | -156,000 |
Amortization of prior service cost | 14,000 | 14,000 | 43,000 | 42,000 |
Net periodic benefit cost | 104,000 | 50,000 | 315,000 | 150,000 |
Defined Benefit Plan, Contributions by Employer | 0 | 0 | 300,000 | 300,000 |
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 0 | 0 | 0 | 0 |
Interest cost | 9,000 | 11,000 | 27,000 | 33,000 |
Long-term return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net loss | 0 | 0 | 0 | 0 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net periodic benefit cost | 9,000 | 11,000 | 27,000 | 33,000 |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 100,000 | ' | 100,000 | ' |
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Contributions by Employer | $100,000 | $100,000 | $100,000 | $100,000 |
Regulatory_and_Rate_Matters_De
Regulatory and Rate Matters (Details) (USD $) | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2011 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 20, 2011 | Sep. 30, 2013 | Nov. 29, 2010 | 3-May-10 | 3-May-10 | Oct. 05, 2012 | Sep. 30, 2013 | Aug. 11, 2011 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Jul. 31, 2011 | Sep. 30, 2013 | Jul. 03, 2012 | Oct. 27, 2010 | Sep. 30, 2013 | Aug. 02, 2013 | Jan. 02, 2013 | Dec. 06, 2012 | Sep. 15, 2011 | Sep. 30, 2013 | Jul. 30, 2011 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 28, 2012 | Sep. 30, 2013 | Jan. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2013 |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Delta [Member] | |
Emergency FPPAC [Member] | La Luz Generating Station [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard [Member] | Renewable Portfolio Standard Supplemental Procurement [Member] | Renewable Portfolio Standard Supplemental Procurement Reduction [Member] | Renewable Portfolio Standard Supplemental Procurement Reduction [Member] | 2014 Wind generated Renewable Energy Credits [Member] | Renewable Portfolio Standard 2014 [Member] | Renewable Portfolio Standard 2014 [Member] | 2015 Wind generated Renewable Energy Credits [Member] | NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] | NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] | NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] | NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] | NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] | 2010 Energy Efficiency Application [Member] | 2010 Energy Efficiency Application [Member] | 2010 Energy Efficiency Application [Member] | 2010 Energy Efficiency Application [Member] | 2010 Energy Efficiency Application [Member] | 2010 Electric Rate Case [Member] | 2010 Electric Rate Case [Member] | Renewable Energy Rider [Member] | Renewable Energy Rider [Member] | Renewable Energy Rider [Member] | Renewable Energy Rider [Member] | Renewable Energy Rider [Member] | Integrated Resource Plan, 2011 [Member] | Integrated Resource Plan, 2011 [Member] | Transmission Rate Case [Member] | Transmission Rate Case [Member] | Formula Transmission Rate Case [Member] | Formula Transmission Rate Case [Member] | Formula Transmission Rate Case [Member] | Firm Requirements Wholesale Power Rate Case [Member] | Firm Requirements Wholesale Power Rate Case [Member] | City of Gallup, New Mexico Contract [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Energy Efficiency [Member] | Energy Efficiency [Member] | Transmission Rate Filings [Member] | August 2013 Transmission Rate Filings [Member] | Public Service Company of New Mexico [Member] | |
MW | MW | Minimum [Member] | Maximum [Member] | Maximum [Member] | Wind Energy [Member] | Wind Energy [Member] | Solar Energy [Member] | Solar Energy [Member] | Renewable Technologies [Member] | Renewable Technologies [Member] | Distributed Generation [Member] | Distributed Generation [Member] | Required Percentage by 2011 [Member] | Required Percentage by 2015 [Member] | Required Percentage by 2015 [Member] | Required Percentage by 2020 [Member] | MW | Minimum [Member] | Maximum [Member] | MWh | MW | MW | MWh | Per KWh [Member] | Per kilowatt [Member] | Disincentives / Incentives Adder [Member] | Disincentives / Incentives Adder [Member] | Disincentives / Incentives Adder [Member] | Per KWh [Member] | Per kilowatt [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Protests_Filed | Minimum [Member] | Maximum [Member] | Applications for Approvals to Purchase Delta [Member] | |||||||||||||||||||||||||
Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Distributed Generation [Member] | MW | MW | Maximum [Member] | Amended [Member] | Amended [Member] | MW | ||||||||||||||||||||||||||||||||||||||||||||||||
Minimum [Member] | Minimum [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate Matters [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 15.00% | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Required Percentage of Diversification | ' | ' | ' | ' | ' | ' | ' | 20.00% | 30.00% | 20.00% | 20.00% | 5.00% | 10.00% | 1.50% | 1.50% | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Reasonable Cost Threshold | ' | ' | ' | ' | 2.00% | 3.00% | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold | ' | ' | ' | 0.25% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Renewable Procurements Spending Required by NMPRC | ' | ' | $900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts of Solar PV Capacity | ' | ' | ' | 20 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 1.5 | 2 | ' | 23 | 23 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts of Wind Energy Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watt Hours of Wind Generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000 | ' | ' | 120,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rider Rate For 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.0044391 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated Cost of Mega Watts of Solar PV Capacity | ' | ' | ' | 45,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,500,000 | ' | ' | ' | ' | 46,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts of Geothermal Capacity | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Wind Capacity Planned Purchase Agreement Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Program Costs Related To Energy Efficiency | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Proposed Profit Incentive Adder Revenues Related To Energy Efficiency Program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,200,000 | 2,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Adder Allowed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.01 | 10 | ' | ' | ' | 0.002 | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider Recovered | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Regulatory Costs Approved | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage ownership of EIP transmission line | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Eliminated Recovery of Adder Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider Net Over-Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider Program Costs Over-Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider Incentives Under-Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider Estimated Incentives Under-Recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Regulatory Costs to be Collected | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,200,000 | 38,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Regulatory Costs Incurred and Eligible For Recovery, Amount Deferred for Collection in Future Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Revenue To be Collected in 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Revenue To be Collected in 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Rider to be Implemented | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.0030468 | 0.0030468 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rider Rate For 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.0022335 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Rider Rate For 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.0028371 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Order Disapproved Recovery of Costs As Regulatory Agency Had Not Acted on Specific Procurements Proposed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Planning Period Covered of IRP | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of protests that were filed to IRP requesting rejection of the plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Regulatory Costs Not yet Approved | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,100,000 | 3,200,000 | 1,300,000 | ' | ' | 8,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts Natural Gas Peaking Units to be Purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 132 |
Public Utilities, Number of Mega Watts of Gas-fired Generation | ' | 40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Installation Capital Costs | ' | 63,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Return on Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12.25% | 10.81% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Regulatory Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Collection of Deployment Costs Through Surcharge Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 years | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Completion Period of Advanced Meter Deployment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Non-standard metering service cost initial fee range | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 142.84 | 247.48 | ' | ' | ' | ' | ' |
Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Non-standard metering ongoing expenses monthly charge | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38.99 | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Increase Annual Transmission Service Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Revenue from Proposed Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,900,000 | 18,100,000 | ' |
Public Utilities, Total Revenue Requirement Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | 2,800,000 | ' |
Public Utilities, Contract Extension | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated Increase in Revenue over amendment term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Deployment Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,300,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Program Implementation Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,800,000 | ' | ' | ' | ' |
Public Utilities, Approved Program Implementation Costs, Bonus | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' |
Public Utilities, Unapproved 2014 Program Implementation Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,600,000 | ' | ' | ' |
Public Utilities, Unapproved 2014 Program Implementation Costs, Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,700,000 | ' | ' | ' |
Public Utilities, Unapproved 2014 Program Implementation Costs, Bonus | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | ' | ' | ' |
Public Utilities, Unapproved 2014 Program Implementation Costs, Overcollection refund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $100,000 | ' | ' | ' |
Public Utilities, Retention Percentage of Sales Margins | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Frequency of IRP filings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Service billings [Member] | TNMP to PNMR [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | $2 | $4 | $6 | $12 |
Service billings [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 22,241 | 22,143 | 65,729 | 68,030 |
Service billings [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 6,731 | 6,439 | 20,948 | 20,206 |
Service billings [Member] | PNM to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 140 | 184 | 381 | 473 |
Interest charges [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 0 | 0 | 1 | 1 |
Interest charges [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 139 | 22 | 354 | 72 |
Interest charges [Member] | PNM to PNMR [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 35 | 45 | 113 | 134 |
Income tax sharing payments [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 0 | 0 | 45,000 | 63,114 |
Income tax sharing payments [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | $0 | $0 | $0 | $1,952 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 1 Months Ended | 3 Months Ended | ||
In Millions, unless otherwise specified | 31-May-13 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 |
Income Tax Contingency [Line Items] | ' | ' | ' | ' |
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease | ' | ' | ' | $1.50 |
New Mexico Corporate tax rate, current | ' | 7.60% | ' | ' |
New Mexico Corporate tax rate, 2014 | ' | 5.90% | ' | ' |
Increase in regulatory liabilities due to change in state corporate tax rate | ' | 23.9 | ' | ' |
Increase in income tax expense due to change in state corporate tax rate | ' | ' | 1.2 | ' |
Additional Income Tax Expense, Impairment of NM Wind Credits | ' | ' | 2.4 | ' |
Federal Tax Refund | 96.2 | ' | ' | ' |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' |
Federal Tax Refund | 77.4 | ' | ' | ' |
PNMR to PNM [Member] | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' |
Federal Income Tax Refund Transferred to Related Party | ' | $45 | ' | ' |
Goodwill_Details
Goodwill (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 |
In Thousands, unless otherwise specified | |||
Goodwill [Line Items] | ' | ' | ' |
Goodwill | $278,297 | $278,297 | $278,297 |
Public Service Company of New Mexico [Member] | ' | ' | ' |
Goodwill [Line Items] | ' | ' | ' |
Goodwill | 51,632 | 51,632 | ' |
Texas-New Mexico Power Company [Member] | ' | ' | ' |
Goodwill [Line Items] | ' | ' | ' |
Goodwill | $226,665 | $226,665 | ' |
Minimum [Member] | Public Service Company of New Mexico [Member] | ' | ' | ' |
Goodwill [Line Items] | ' | ' | ' |
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | ' | ' |
Minimum [Member] | Texas-New Mexico Power Company [Member] | ' | ' | ' |
Goodwill [Line Items] | ' | ' | ' |
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | ' | ' |
Sale_of_First_Choice_Details
Sale of First Choice (Details) (First Choice [Member], USD $) | 0 Months Ended | 1 Months Ended | 3 Months Ended | |
In Millions, unless otherwise specified | Sep. 23, 2011 | Aug. 31, 2012 | Oct. 31, 2011 | Sep. 30, 2012 |
Other Income [Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' | ' | ' | ' |
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds | $270 | ' | ' | ' |
Business Disposition, Awarded Purchase Price Disputed | ' | 6.4 | ' | ' |
Business Disposition, Sale Price Disputed | ' | ' | 8.2 | ' |
Gain (Loss) on Disposition of Business | ' | ' | ' | $1 |