Document_and_Entity_Informatio
Document and Entity Information | 6 Months Ended | |
Jun. 30, 2014 | Jul. 25, 2014 | |
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-Jun-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q2 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 79,653,624 |
Public Service Company of New Mexico [Member] | ' | ' |
Document Information [Line Items] | ' | ' |
Entity Registrant Name | 'PUBLIC SERVICE CO OF NEW MEXICO | ' |
Entity Central Index Key | '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 $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Electric Operating Revenues | $346,160 | $347,599 | $675,057 | $665,263 |
Operating Expenses: | ' | ' | ' | ' |
Cost of energy | 109,419 | 105,659 | 222,033 | 210,365 |
Administrative and general | 45,235 | 43,139 | 89,093 | 87,829 |
Energy production costs | 45,846 | 46,831 | 93,134 | 90,404 |
Depreciation and amortization | 42,163 | 41,639 | 84,130 | 82,446 |
Transmission and distribution costs | 16,068 | 17,148 | 32,974 | 33,443 |
Taxes other than income taxes | 16,133 | 15,316 | 33,644 | 32,205 |
Total operating expenses | 274,864 | 269,732 | 555,008 | 536,692 |
Operating income | 71,296 | 77,867 | 120,049 | 128,571 |
Other Income and Deductions: | ' | ' | ' | ' |
Interest income | 2,040 | 2,833 | 4,158 | 5,467 |
Gains on available-for-sale securities | 4,699 | 3,217 | 7,272 | 4,747 |
Other income | 3,180 | 2,610 | 4,754 | 4,323 |
Other (deductions) | -2,169 | -4,194 | -5,102 | -7,546 |
Net other income and deductions | 7,750 | 4,466 | 11,082 | 6,991 |
Interest Charges | 29,972 | 30,616 | 59,506 | 61,914 |
Earnings before Income Taxes | 49,074 | 51,717 | 71,625 | 73,648 |
Income Taxes | 15,893 | 20,334 | 22,313 | 28,303 |
Net Earnings | 33,181 | 31,383 | 49,312 | 45,345 |
(Earnings) Attributable to Valencia Non-controlling Interest | -3,908 | -3,573 | -7,439 | -6,777 |
Preferred Stock Dividend Requirements of Subsidiary | -132 | -132 | -264 | -264 |
Net Earnings Attributable to PNMR | 29,141 | 27,678 | 41,609 | 38,304 |
Net Earnings Attributable to PNMR per Common Share: | ' | ' | ' | ' |
Basic (dollars per share) | $0.37 | $0.35 | $0.52 | $0.48 |
Diluted (dollars per share) | $0.36 | $0.34 | $0.52 | $0.48 |
Dividends Declared per Common Share (dollars per share) | $0.19 | $0.17 | $0.37 | $0.33 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Electric Operating Revenues | 275,704 | 279,690 | 538,441 | 537,583 |
Operating Expenses: | ' | ' | ' | ' |
Cost of energy | 92,642 | 91,855 | 189,268 | 183,514 |
Administrative and general | 40,603 | 36,622 | 79,213 | 75,381 |
Energy production costs | 45,846 | 46,836 | 93,134 | 90,402 |
Depreciation and amortization | 27,023 | 26,051 | 54,105 | 51,884 |
Transmission and distribution costs | 10,183 | 11,133 | 21,510 | 21,735 |
Taxes other than income taxes | 9,601 | 8,891 | 20,100 | 19,125 |
Total operating expenses | 225,898 | 221,388 | 457,330 | 442,041 |
Operating income | 49,806 | 58,302 | 81,111 | 95,542 |
Other Income and Deductions: | ' | ' | ' | ' |
Interest income | 2,065 | 2,868 | 4,193 | 5,541 |
Gains on available-for-sale securities | 4,699 | 3,217 | 7,272 | 4,747 |
Other income | 2,443 | 1,614 | 3,555 | 2,930 |
Other (deductions) | -1,630 | -1,471 | -3,647 | -2,911 |
Net other income and deductions | 7,577 | 6,228 | 11,373 | 10,307 |
Interest Charges | 20,023 | 19,890 | 39,835 | 39,847 |
Earnings before Income Taxes | 37,360 | 44,640 | 52,649 | 66,002 |
Income Taxes | 13,106 | 14,943 | 17,189 | 21,532 |
Net Earnings | 24,254 | 29,697 | 35,460 | 44,470 |
(Earnings) Attributable to Valencia Non-controlling Interest | -3,908 | -3,573 | -7,439 | -6,777 |
Net Earnings Attributable to PNMR | 20,346 | 26,124 | 28,021 | 37,693 |
Preferred Stock Dividends Requirements | -132 | -132 | -264 | -264 |
Net Earnings Attributable to PNMR | 20,214 | 25,992 | 27,757 | 37,429 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Electric Operating Revenues | 70,456 | 67,909 | 136,616 | 127,680 |
Operating Expenses: | ' | ' | ' | ' |
Cost of energy | 16,777 | 13,804 | 32,765 | 26,851 |
Administrative and general | 8,768 | 10,686 | 18,609 | 21,804 |
Depreciation and amortization | 12,003 | 12,279 | 23,844 | 23,960 |
Transmission and distribution costs | 5,885 | 6,016 | 11,464 | 11,708 |
Taxes other than income taxes | 5,758 | 5,457 | 11,408 | 10,636 |
Total operating expenses | 49,191 | 48,242 | 98,090 | 94,959 |
Operating income | 21,265 | 19,667 | 38,526 | 32,721 |
Other Income and Deductions: | ' | ' | ' | ' |
Other income | 586 | 609 | 1,006 | 946 |
Other (deductions) | -72 | -123 | -304 | -252 |
Net other income and deductions | 514 | 486 | 702 | 694 |
Interest Charges | 6,655 | 6,759 | 13,252 | 14,005 |
Earnings before Income Taxes | 15,124 | 13,394 | 25,976 | 19,410 |
Income Taxes | 5,590 | 5,055 | 9,640 | 7,345 |
Net Earnings Attributable to PNMR | $9,534 | $8,339 | $16,336 | $12,065 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Comprehensive Income (USD $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Net earnings | $29,141 | $27,678 | $41,609 | $38,304 |
Net Earnings | 33,181 | 31,383 | 49,312 | 45,345 |
Unrealized Gain on Available-for-Sale Securities: | ' | ' | ' | ' |
Unrealized holding gains arising during the period, net of income tax (expense) benefit | 3,999 | 443 | 6,046 | 5,190 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense (benefit) | -3,397 | -3,333 | -5,369 | -4,140 |
Pension Liability Adjustment: | ' | ' | ' | ' |
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 780 | 960 | 1,560 | 1,920 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1) | 0 | -6 | -100 | 2 |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35) | 79 | 33 | 115 | 64 |
Net change after income taxes | 1,461 | -1,903 | 2,252 | 3,036 |
Comprehensive Income | 34,642 | 29,480 | 51,564 | 48,381 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | -3,908 | -3,573 | -7,439 | -6,777 |
Preferred Stock Dividend Requirements of Subsidiary | -132 | -132 | -264 | -264 |
Comprehensive Income Attributable to PNMR | 30,602 | 25,775 | 43,861 | 41,340 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Net earnings | 20,346 | 26,124 | 28,021 | 37,693 |
Net Earnings | 24,254 | 29,697 | 35,460 | 44,470 |
Unrealized Gain on Available-for-Sale Securities: | ' | ' | ' | ' |
Unrealized holding gains arising during the period, net of income tax (expense) benefit | 3,999 | 443 | 6,046 | 5,190 |
Reclassification adjustment for (gains) included in net earnings, net of income tax expense (benefit) | -3,397 | -3,333 | -5,369 | -4,140 |
Pension Liability Adjustment: | ' | ' | ' | ' |
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) | 780 | 960 | 1,560 | 1,920 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Net change after income taxes | 1,382 | -1,930 | 2,237 | 2,970 |
Comprehensive Income | 25,636 | 27,767 | 37,697 | 47,440 |
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | -3,908 | -3,573 | -7,439 | -6,777 |
Comprehensive Income Attributable to PNMR | 21,728 | 24,194 | 30,258 | 40,663 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Net earnings | 9,534 | 8,339 | 16,336 | 12,065 |
Fair Value Adjustment for Cash Flow Hedges: | ' | ' | ' | ' |
Change in fair market value, net of income tax (expense) benefit of $0, $3, $53 and $(1) | 0 | -6 | -100 | 2 |
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(42), $(18), $(61) and $(35) | 79 | 33 | 115 | 64 |
Net change after income taxes | 79 | 27 | 15 | 66 |
Comprehensive Income Attributable to PNMR | $9,613 | $8,366 | $16,351 | $12,131 |
Condensed_Consolidated_Stateme2
Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Unrealized holding gains (losses) arising during the period, income tax (expense) | ($2,602) | ($290) | ($3,809) | ($3,401) |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense | 2,210 | 2,185 | 3,488 | 2,714 |
Pension liability adjustment, income tax (expense) benefit | -508 | -631 | -1,016 | -1,262 |
Change in fair market value, income tax (expense) | 0 | 3 | 53 | -1 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | -42 | -18 | -61 | -35 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Unrealized holding gains (losses) arising during the period, income tax (expense) | -2,602 | -290 | -3,809 | -3,401 |
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense | 2,210 | 2,185 | 3,488 | 2,714 |
Pension liability adjustment, income tax (expense) benefit | -508 | -631 | -1,016 | -1,262 |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Change in fair market value, income tax (expense) | 0 | 3 | 53 | -1 |
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit) | ($42) | ($18) | ($61) | ($35) |
Condensed_Consolidated_Stateme3
Condensed Consolidated Statements of Cash Flows (USD $) | 6 Months Ended | |
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 |
Cash Flows From Operating Activities: | ' | ' |
Net Earnings | $49,312 | $45,345 |
Net earnings | 41,609 | 38,304 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 103,436 | 103,914 |
Deferred income tax expense | 24,252 | 27,797 |
Net unrealized (gains) losses on commodity derivatives | 3,187 | 1,729 |
Realized (gains) on available-for-sale securities | -7,272 | -4,747 |
Stock based compensation expense | 3,399 | 3,198 |
Other, net | 38 | 255 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -17,543 | -23,021 |
Materials, supplies, and fuel stock | 6,346 | -159 |
Other current assets | -20,688 | 3,870 |
Other assets | 18,237 | 6,356 |
Accounts payable | -29,384 | -7,424 |
Accrued interest and taxes | -2,830 | 93,077 |
Other current liabilities | -3,341 | -21,310 |
Other liabilities | -3,343 | -68,972 |
Net cash flows from operating activities | 123,806 | 159,908 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -160,893 | -153,512 |
Proceeds from sales of available-for-sale securities | 53,119 | 76,106 |
Purchases of available-for-sale securities | -54,338 | -77,882 |
Return of principal on PVNGS lessor notes | 10,231 | 10,965 |
Other, net | 750 | 1,254 |
Net cash flows from investing activities | -151,131 | -143,069 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), net | -44,200 | 1,300 |
Long-term borrowings | 255,000 | 75,000 |
Repayment of long-term debt | -125,000 | -9,445 |
Cash paid in debt exchange | 0 | -13,048 |
Proceeds from stock option exercise | 4,446 | 11,345 |
Awards of common stock | -13,939 | -19,741 |
Dividends paid | -29,732 | -24,958 |
Valencia’s transactions with its owner | -8,189 | -8,675 |
Other, net | -1,482 | -2,804 |
Net cash flows from financing activities | 36,904 | 8,974 |
Change in Cash and Cash Equivalents | 9,579 | 25,813 |
Cash and Cash Equivalents at Beginning of Period | 2,533 | 8,985 |
Cash and Cash Equivalents at End of Period | 12,112 | 34,798 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of amounts capitalized | 54,712 | 58,267 |
Income taxes paid (refunded), net | -2,534 | -95,472 |
Supplemental schedule of noncash investing activities: | ' | ' |
Changes in accrued plant additions | -7,909 | -3,375 |
Premium on long-term debt incurred in connection with debt exchange | 0 | 36,297 |
Public Service Company of New Mexico [Member] | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net Earnings | 35,460 | 44,470 |
Net earnings | 28,021 | 37,693 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 71,327 | 69,179 |
Deferred income tax expense | 19,716 | 21,836 |
Net unrealized (gains) losses on commodity derivatives | 3,187 | 1,729 |
Realized (gains) on available-for-sale securities | -7,272 | -4,747 |
Other, net | 193 | -876 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -13,885 | -15,841 |
Materials, supplies, and fuel stock | 6,447 | -238 |
Other current assets | -22,588 | 4,299 |
Other assets | 18,790 | 6,196 |
Accounts payable | -26,737 | -5,829 |
Accrued interest and taxes | -1,575 | 45,380 |
Other current liabilities | 3,943 | -23,523 |
Other liabilities | -3,193 | -69,059 |
Net cash flows from operating activities | 83,813 | 72,976 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -92,567 | -98,673 |
Proceeds from sales of available-for-sale securities | 53,119 | 76,106 |
Purchases of available-for-sale securities | -54,338 | -77,882 |
Return of principal on PVNGS lessor notes | 10,231 | 10,965 |
Other, net | -70 | 1,227 |
Net cash flows from investing activities | -83,625 | -88,257 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), net | -49,200 | -21,100 |
Short-term borrowings (repayments), affiliate, net | -32,500 | 0 |
Long-term borrowings | 175,000 | 75,000 |
Repayment of long-term debt | -75,000 | 0 |
Dividends paid | -264 | -264 |
Valencia’s transactions with its owner | -8,189 | -8,675 |
Other, net | -700 | -1,169 |
Net cash flows from financing activities | 9,147 | 43,792 |
Change in Cash and Cash Equivalents | 9,335 | 28,511 |
Cash and Cash Equivalents at Beginning of Period | 21 | 3,958 |
Cash and Cash Equivalents at End of Period | 9,356 | 32,469 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of amounts capitalized | 36,601 | 37,845 |
Income taxes paid (refunded), net | -215 | -44,999 |
Supplemental schedule of noncash investing activities: | ' | ' |
Changes in accrued plant additions | -5,595 | 817 |
Texas-New Mexico Power Company [Member] | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net earnings | 16,336 | 12,065 |
Adjustments to reconcile net earnings to net cash flows from operating activities: | ' | ' |
Depreciation and amortization | 25,728 | 26,034 |
Deferred income tax expense | 6,162 | 4,348 |
Other, net | -38 | -10 |
Changes in certain assets and liabilities: | ' | ' |
Accounts receivable and unbilled revenues | -3,658 | -7,180 |
Materials, supplies, and fuel stock | -101 | 79 |
Other current assets | -803 | -4,082 |
Other assets | -273 | 590 |
Accounts payable | 1,381 | 807 |
Accrued interest and taxes | -726 | -1,517 |
Other current liabilities | 2,167 | 1,278 |
Other liabilities | 365 | 886 |
Net cash flows from operating activities | 46,540 | 33,298 |
Cash Flows From Investing Activities: | ' | ' |
Additions to utility and non-utility plant | -64,502 | -47,390 |
Net cash flows from investing activities | -64,502 | -47,390 |
Cash Flows From Financing Activities: | ' | ' |
Short-term borrowings (repayments), net | 0 | 25,000 |
Short-term borrowings (repayments), net | -4,200 | 7,500 |
Long-term borrowings | 80,000 | 0 |
Repayment of long-term debt | -50,000 | 0 |
Cash paid in debt exchange | 0 | -13,048 |
Dividends paid | -6,803 | -3,726 |
Other, net | -783 | -1,634 |
Net cash flows from financing activities | 18,214 | 14,092 |
Change in Cash and Cash Equivalents | 252 | 0 |
Cash and Cash Equivalents at Beginning of Period | 1 | 1 |
Cash and Cash Equivalents at End of Period | 253 | 1 |
Supplemental Cash Flow Disclosures: | ' | ' |
Interest paid, net of amounts capitalized | 11,847 | 13,267 |
Income taxes paid (refunded), net | -304 | 696 |
Supplemental schedule of noncash investing activities: | ' | ' |
Changes in accrued plant additions | 1,038 | -886 |
Premium on long-term debt incurred in connection with debt exchange | $0 | $36,297 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | 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] | ||
Current Assets: | ' | ' | ' | ' | ' | ' |
Cash and cash equivalents | $12,112 | $2,533 | $9,356 | $21 | $253 | $1 |
Accounts receivable | 92,230 | 90,251 | 68,254 | 70,126 | 23,976 | 20,125 |
Unbilled revenues | 72,690 | 58,806 | 63,069 | 48,992 | 9,621 | 9,814 |
Other receivables | 40,369 | 53,909 | 39,354 | 52,964 | 1,341 | 1,246 |
Affiliate receivables | ' | ' | 11,269 | 10,054 | ' | ' |
Materials, supplies, and fuel stock | 60,877 | 67,223 | 58,073 | 64,520 | 2,804 | 2,703 |
Regulatory assets | 45,287 | 24,416 | 40,089 | 19,394 | 5,198 | 5,022 |
Commodity derivative instruments | 4,082 | 4,064 | 4,082 | 4,064 | ' | ' |
Income taxes receivable | 6,471 | 7,066 | 6,342 | 4,030 | ' | ' |
Current portion of accumulated deferred income taxes | 58,681 | 58,681 | 43,826 | 43,827 | 6,501 | 6,501 |
Other current assets | 54,026 | 34,590 | 49,385 | 30,510 | 1,662 | 980 |
Total current assets | 446,825 | 401,539 | 393,099 | 348,502 | 51,356 | 46,392 |
Other Property and Investments: | ' | ' | ' | ' | ' | ' |
Investment in PVNGS lessor notes | 17,519 | 32,200 | 17,519 | 32,200 | ' | ' |
Available-for-sale securities | 236,427 | 226,855 | 236,427 | 226,855 | ' | ' |
Other investments | 1,798 | 1,835 | 432 | 445 | 245 | 245 |
Non-utility property | 4,284 | 4,353 | 976 | 976 | 2,240 | 2,240 |
Total other property and investments | 260,028 | 265,243 | 255,354 | 260,476 | 2,485 | 2,485 |
Utility Plant: | ' | ' | ' | ' | ' | ' |
Plant in service and plant held for future use | 5,659,379 | 5,563,061 | 4,375,493 | 4,314,016 | 1,119,014 | 1,074,193 |
Less accumulated depreciation and amortization | 1,860,816 | 1,838,832 | 1,426,935 | 1,402,531 | 362,640 | 352,105 |
Net plant in service and plant held for future use | 3,798,563 | 3,724,229 | 2,948,558 | 2,911,485 | 756,374 | 722,088 |
Construction work in progress | 146,760 | 132,080 | 114,601 | 107,344 | 27,633 | 16,790 |
Nuclear fuel, net of accumulated amortization of $44,785 and $47,347 | 78,216 | 77,602 | 78,216 | 77,602 | ' | ' |
Net utility plant | 4,023,539 | 3,933,911 | 3,141,375 | 3,096,431 | 784,007 | 738,878 |
Deferred Charges and Other Assets: | ' | ' | ' | ' | ' | ' |
Regulatory assets | 499,640 | 523,955 | 365,239 | 384,217 | 134,401 | 139,738 |
Goodwill | 278,297 | 278,297 | 51,632 | 51,632 | 226,665 | 226,665 |
Commodity derivative instruments | 1,515 | 3,002 | 1,515 | 3,002 | ' | ' |
Other deferred charges | 94,348 | 94,263 | 82,315 | 83,356 | 9,603 | 8,273 |
Total deferred charges and other assets | 873,800 | 899,517 | 500,701 | 522,207 | 370,669 | 374,676 |
Total assets | 5,604,192 | 5,500,210 | 4,290,529 | 4,227,616 | 1,208,517 | 1,162,431 |
Current Liabilities: | ' | ' | ' | ' | ' | ' |
Short-term debt | 105,000 | 149,200 | 0 | 49,200 | ' | ' |
Short-term debt - affiliate | ' | ' | 0 | 32,500 | ' | ' |
Short-term debt – affiliate | ' | ' | ' | ' | 25,200 | 29,400 |
Current installments of long-term debt | 158,066 | 75,000 | 39,300 | 75,000 | ' | ' |
Accounts payable | 88,191 | 109,666 | 63,501 | 84,643 | 14,945 | 12,543 |
Affiliate payables | ' | ' | 23,053 | 20,498 | 3,941 | 3,181 |
Customer deposits | 12,914 | 13,456 | 12,914 | 13,456 | ' | ' |
Accrued interest and taxes | 46,564 | 49,600 | 29,207 | 27,665 | 23,052 | 23,778 |
Regulatory liabilities | 473 | 1,081 | 473 | 1,081 | ' | ' |
Commodity derivative instruments | 5,073 | 2,699 | 5,073 | 2,699 | ' | ' |
Dividends declared | 132 | 14,864 | 132 | 132 | ' | ' |
Other current liabilities | 70,456 | 77,105 | 52,650 | 50,392 | 3,602 | 8,999 |
Total current liabilities | 486,869 | 492,671 | 226,303 | 357,266 | 70,740 | 77,901 |
Long-term Debt | 1,717,188 | 1,670,420 | 1,351,337 | 1,215,618 | 365,851 | 336,036 |
Deferred Credits and Other Liabilities: | ' | ' | ' | ' | ' | ' |
Accumulated deferred income taxes | 852,846 | 801,408 | 689,190 | 651,239 | 203,289 | 190,197 |
Accumulated deferred investment tax credits | 24,773 | 25,855 | 24,773 | 25,855 | ' | ' |
Regulatory liabilities | 465,176 | 460,649 | 418,178 | 414,611 | 46,998 | 46,038 |
Asset retirement obligations | 100,100 | 96,135 | 99,152 | 95,225 | 815 | 782 |
Accrued pension liability and postretirement benefit cost | 72,726 | 80,046 | 69,624 | 76,611 | 3,102 | 3,435 |
Commodity derivative instruments | 915 | 1,094 | 915 | 1,094 | ' | ' |
Other deferred credits | 99,257 | 109,805 | 83,056 | 91,340 | 5,243 | 5,111 |
Total deferred credits and other liabilities | 1,615,793 | 1,574,992 | 1,384,888 | 1,355,975 | 259,447 | 245,563 |
Total liabilities | 3,819,850 | 3,738,083 | 2,962,528 | 2,928,859 | 696,038 | 659,500 |
Commitments and Contingencies (See Note [11]) | ' | ' | ' | ' | ' | ' |
Cumulative preferred stock of subsidiary without mandatory redemption requirements | 11,529 | 11,529 | 11,529 | 11,529 | ' | ' |
Company common stockholders’ equity: | ' | ' | ' | ' | ' | ' |
Common stock outstanding | 1,172,209 | 1,178,369 | 1,061,776 | 1,061,776 | 64 | 64 |
Paid-in-capital | ' | ' | ' | ' | 404,166 | 404,166 |
Accumulated other comprehensive income (loss), net of income taxes | -55,888 | -58,140 | -55,640 | -57,877 | -248 | -263 |
Retained earnings | 580,213 | 553,340 | 234,057 | 206,300 | 108,497 | 98,964 |
Total Company common stockholders' equity | 1,696,534 | 1,673,569 | 1,240,193 | 1,210,199 | 512,479 | 502,931 |
Non-controlling interest in Valencia | 76,279 | 77,029 | 76,279 | 77,029 | ' | ' |
Total equity | 1,772,813 | 1,750,598 | 1,316,472 | 1,287,228 | ' | ' |
Total liabilities and stockholders' equity | $5,604,192 | $5,500,210 | $4,290,529 | $4,227,616 | $1,208,517 | $1,162,431 |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Allowance for uncollectible accounts | $1,535 | $1,423 |
Accumulated depreciation, nuclear fuel | 44,785 | 47,347 |
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 | 1,535 | 1,423 |
Accumulated depreciation, nuclear fuel | $44,785 | $47,347 |
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] | Parent [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] | Parent [Member] | Non-controlling Interest in Valencia [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | AOCI [Member] | Retained Earnings [Member] | ||||||||
Balance at Dec. 31, 2013 | $1,750,598 | $1,178,369 | ($58,140) | $553,340 | $1,673,569 | $77,029 | $1,287,228 | $1,061,776 | ($57,877) | $206,300 | $1,210,199 | $77,029 | ' | ' | ' | ' | ' |
Balance TNMP at Dec. 31, 2013 | 1,673,569 | ' | ' | ' | ' | ' | 1,210,199 | ' | ' | ' | ' | ' | 502,931 | 64 | 404,166 | -263 | 98,964 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from stock option exercise | 4,446 | 4,446 | ' | ' | 4,446 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Awards of common stock | -13,939 | -13,939 | ' | ' | -13,939 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Excess tax (shortfall) from stock-based payment arrangements | -66 | -66 | ' | ' | -66 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock based compensation expense | 3,399 | 3,399 | ' | ' | 3,399 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Valencia’s transactions with its owner | -8,189 | ' | ' | ' | ' | -8,189 | -8,189 | 0 | 0 | 0 | 0 | -8,189 | ' | ' | ' | ' | ' |
Net earnings | 41,609 | ' | ' | ' | ' | ' | 28,021 | ' | ' | ' | ' | ' | 16,336 | ' | ' | ' | 16,336 |
Net earnings before subsidiary preferred stock dividends | 49,312 | ' | ' | 41,873 | 41,873 | 7,439 | 35,460 | 0 | 0 | 28,021 | 28,021 | 7,439 | ' | ' | ' | ' | ' |
Subsidiary preferred stock dividends | -264 | ' | ' | -264 | -264 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total other comprehensive income | 2,252 | ' | 2,252 | ' | 2,252 | ' | 2,237 | 0 | 2,237 | 0 | 2,237 | 0 | 15 | ' | ' | 15 | ' |
Dividends declared on preferred stock | ' | ' | ' | ' | ' | ' | -264 | 0 | 0 | -264 | -264 | 0 | ' | ' | ' | ' | ' |
Dividends declared on common stock | -14,736 | ' | ' | -14,736 | -14,736 | ' | ' | ' | ' | ' | ' | ' | -6,803 | ' | ' | ' | -6,803 |
Balance TNMP at Jun. 30, 2014 | 1,696,534 | ' | ' | ' | ' | ' | 1,240,193 | ' | ' | ' | ' | ' | 512,479 | 64 | 404,166 | -248 | 108,497 |
Balance at Jun. 30, 2014 | 1,772,813 | 1,172,209 | -55,888 | 580,213 | 1,696,534 | 76,279 | 1,316,472 | 1,061,776 | -55,640 | 234,057 | 1,240,193 | 76,279 | ' | ' | ' | ' | ' |
Balance at Mar. 31, 2014 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net earnings | 29,141 | ' | ' | ' | ' | ' | 20,346 | ' | ' | ' | ' | ' | 9,534 | ' | ' | ' | ' |
Net earnings before subsidiary preferred stock dividends | 33,181 | ' | ' | ' | ' | ' | 24,254 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Subsidiary preferred stock dividends | -132 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total other comprehensive income | 1,461 | ' | ' | ' | ' | ' | 1,382 | ' | ' | ' | ' | ' | 79 | ' | ' | ' | ' |
Balance TNMP at Jun. 30, 2014 | 1,696,534 | ' | ' | ' | ' | ' | 1,240,193 | ' | ' | ' | ' | ' | 512,479 | ' | ' | ' | ' |
Balance at Jun. 30, 2014 | $1,772,813 | ' | ' | ' | ' | ' | $1,316,472 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Significant_Accounting_Policie
Significant Accounting Policies and Responsibility for Financial Statements | 6 Months Ended |
Jun. 30, 2014 | |
Accounting Policies [Abstract] | ' |
Significant Accounting Policies and Responsibility for Financial Statements | ' |
Significant Accounting Policies and Responsibility for Financial Statements | |
Financial Statement Preparation | |
In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at June 30, 2014 and December 31, 2013, the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2014 and 2013, and the consolidated cash flows for the six months ended June 30, 2014 and 2013. 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 2013 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2014 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 2013 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. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants. | |
PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 14. | |
Dividends on Common Stock | |
Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.185 per share in July 2014 and $0.165 in July 2013, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. | |
TNMP declared and paid cash dividends of $6.8 million and $3.7 million in the six months ended June 30, 2014 and 2013. | |
New Accounting Pronouncements | |
Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. | |
Accounting Standards Update 2014-09 – Revenue from Contracts with Customers | |
On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. | |
Accounting Standards Update 2014-12 – Compensation-Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period | |
On June 19, 2014, the FASB issued ASU No. 2014-12, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The new standard is effective for the Company beginning on January 1, 2016. Early adoption is permitted and the standard permits the use of either the prospective or retrospective transition methods. Although the Company is in the process of analyzing the impacts this new standard will have on its consolidated financial statements, the Company currently treats the performance targets covered by the standard as performance conditions, so the Company does not expect its impact will be significant. |
Earnings_Per_Share
Earnings Per Share | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Earnings Per Share | ' | |||||||||||||||
Earnings Per Share | ||||||||||||||||
In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Net Earnings Attributable to PNMR | $ | 29,141 | $ | 27,678 | $ | 41,609 | $ | 38,304 | ||||||||
Average Number of Common Shares: | ||||||||||||||||
Outstanding during period | 79,654 | 79,654 | 79,654 | 79,654 | ||||||||||||
Vested awards of restricted stock | 110 | 194 | 146 | 202 | ||||||||||||
Average Shares – Basic | 79,764 | 79,848 | 79,800 | 79,856 | ||||||||||||
Dilutive Effect of Common Stock Equivalents (1): | ||||||||||||||||
Stock options and restricted stock | 464 | 607 | 508 | 661 | ||||||||||||
Average Shares – Diluted | 80,228 | 80,455 | 80,308 | 80,517 | ||||||||||||
Net Earnings Per Share of Common Stock: | ||||||||||||||||
Basic | $ | 0.37 | $ | 0.35 | $ | 0.52 | $ | 0.48 | ||||||||
Diluted | $ | 0.36 | $ | 0.34 | $ | 0.52 | $ | 0.48 | ||||||||
(1) | Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014. |
Segment_Information
Segment Information | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Segment Information | ' | |||||||||||||||
Segment Information | ||||||||||||||||
The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. | ||||||||||||||||
PNM | ||||||||||||||||
PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates. | ||||||||||||||||
TNMP | ||||||||||||||||
TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. | ||||||||||||||||
Corporate and Other | ||||||||||||||||
The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. | ||||||||||||||||
The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. | ||||||||||||||||
PNMR SEGMENT INFORMATION | ||||||||||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
(In thousands) | ||||||||||||||||
Three Months Ended June 30, 2014 | ||||||||||||||||
Electric operating revenues | $ | 275,704 | $ | 70,456 | $ | — | $ | 346,160 | ||||||||
Cost of energy | 92,642 | 16,777 | — | 109,419 | ||||||||||||
Margin | 183,062 | 53,679 | — | 236,741 | ||||||||||||
Other operating expenses | 106,233 | 20,411 | (3,362 | ) | 123,282 | |||||||||||
Depreciation and amortization | 27,023 | 12,003 | 3,137 | 42,163 | ||||||||||||
Operating income | 49,806 | 21,265 | 225 | 71,296 | ||||||||||||
Interest income | 2,065 | — | (25 | ) | 2,040 | |||||||||||
Other income (deductions) | 5,512 | 514 | (316 | ) | 5,710 | |||||||||||
Net interest charges | (20,023 | ) | (6,655 | ) | (3,294 | ) | (29,972 | ) | ||||||||
Segment earnings (loss) before income taxes | 37,360 | 15,124 | (3,410 | ) | 49,074 | |||||||||||
Income taxes (benefit) | 13,106 | 5,590 | (2,803 | ) | 15,893 | |||||||||||
Segment earnings (loss) | 24,254 | 9,534 | (607 | ) | 33,181 | |||||||||||
Valencia non-controlling interest | (3,908 | ) | — | — | (3,908 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 20,214 | $ | 9,534 | $ | (607 | ) | $ | 29,141 | |||||||
Six Months Ended June 30, 2014 | ||||||||||||||||
Electric operating revenues | $ | 538,441 | $ | 136,616 | $ | — | $ | 675,057 | ||||||||
Cost of energy | 189,268 | 32,765 | — | 222,033 | ||||||||||||
Margin | 349,173 | 103,851 | — | 453,024 | ||||||||||||
Other operating expenses | 213,957 | 41,481 | (6,593 | ) | 248,845 | |||||||||||
Depreciation and amortization | 54,105 | 23,844 | 6,181 | 84,130 | ||||||||||||
Operating income | 81,111 | 38,526 | 412 | 120,049 | ||||||||||||
Interest income | 4,193 | — | (35 | ) | 4,158 | |||||||||||
Other income (deductions) | 7,180 | 702 | (958 | ) | 6,924 | |||||||||||
Net interest charges | (39,835 | ) | (13,252 | ) | (6,419 | ) | (59,506 | ) | ||||||||
Segment earnings (loss) before income taxes | 52,649 | 25,976 | (7,000 | ) | 71,625 | |||||||||||
Income taxes (benefit) | 17,189 | 9,640 | (4,516 | ) | 22,313 | |||||||||||
Segment earnings (loss) | 35,460 | 16,336 | (2,484 | ) | 49,312 | |||||||||||
Valencia non-controlling interest | (7,439 | ) | — | — | (7,439 | ) | ||||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 27,757 | $ | 16,336 | $ | (2,484 | ) | $ | 41,609 | |||||||
At June 30, 2014: | ||||||||||||||||
Total Assets | $ | 4,290,529 | $ | 1,208,517 | $ | 105,146 | $ | 5,604,192 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
(In thousands) | ||||||||||||||||
Three Months Ended June 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 279,690 | $ | 67,909 | $ | — | $ | 347,599 | ||||||||
Cost of energy | 91,855 | 13,804 | — | 105,659 | ||||||||||||
Margin | 187,835 | 54,105 | — | 241,940 | ||||||||||||
Other operating expenses | 103,482 | 22,159 | (3,207 | ) | 122,434 | |||||||||||
Depreciation and amortization | 26,051 | 12,279 | 3,309 | 41,639 | ||||||||||||
Operating income (loss) | 58,302 | 19,667 | (102 | ) | 77,867 | |||||||||||
Interest income | 2,868 | — | (35 | ) | 2,833 | |||||||||||
Other income (deductions) | 3,360 | 486 | (2,213 | ) | 1,633 | |||||||||||
Net interest charges | (19,890 | ) | (6,759 | ) | (3,967 | ) | (30,616 | ) | ||||||||
Segment earnings (loss) before income taxes | 44,640 | 13,394 | (6,317 | ) | 51,717 | |||||||||||
Income taxes (benefit) | 14,943 | 5,055 | 336 | 20,334 | ||||||||||||
Segment earnings (loss) | 29,697 | 8,339 | (6,653 | ) | 31,383 | |||||||||||
Valencia non-controlling interest | (3,573 | ) | — | — | (3,573 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 25,992 | $ | 8,339 | $ | (6,653 | ) | $ | 27,678 | |||||||
Six Months Ended June 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 537,583 | $ | 127,680 | $ | — | $ | 665,263 | ||||||||
Cost of energy | 183,514 | 26,851 | — | 210,365 | ||||||||||||
Margin | 354,069 | 100,829 | — | 454,898 | ||||||||||||
Other operating expenses | 206,643 | 44,148 | (6,910 | ) | 243,881 | |||||||||||
Depreciation and amortization | 51,884 | 23,960 | 6,602 | 82,446 | ||||||||||||
Operating income | 95,542 | 32,721 | 308 | 128,571 | ||||||||||||
Interest income | 5,541 | — | (74 | ) | 5,467 | |||||||||||
Other income (deductions) | 4,766 | 694 | (3,936 | ) | 1,524 | |||||||||||
Net interest charges | (39,847 | ) | (14,005 | ) | (8,062 | ) | (61,914 | ) | ||||||||
Segment earnings (loss) before income taxes | 66,002 | 19,410 | (11,764 | ) | 73,648 | |||||||||||
Income taxes (benefit) | 21,532 | 7,345 | (574 | ) | 28,303 | |||||||||||
Segment earnings (loss) | 44,470 | 12,065 | (11,190 | ) | 45,345 | |||||||||||
Valencia non-controlling interest | (6,777 | ) | — | — | (6,777 | ) | ||||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 37,429 | $ | 12,065 | $ | (11,190 | ) | $ | 38,304 | |||||||
At June 30, 2013: | ||||||||||||||||
Total Assets | $ | 4,185,189 | $ | 1,155,928 | $ | 62,789 | $ | 5,403,906 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income (Loss) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Equity [Abstract] | ' | |||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ' | |||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2014 and 2013 is as follows: | ||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Available-for- | Liability | for Cash Flow | ||||||||||||||
Sale Securities | Adjustment | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
PNMR | ||||||||||||||||
Balance at December 31, 2013 | $ | 25,748 | $ | (83,625 | ) | $ | (263 | ) | $ | (58,140 | ) | |||||
Amounts reclassified from AOCI (pre-tax) | (8,857 | ) | 2,576 | 176 | (6,105 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,488 | (1,016 | ) | (61 | ) | 2,411 | ||||||||||
Other OCI changes (pre-tax) | 9,855 | — | (153 | ) | 9,702 | |||||||||||
Income tax impact of other OCI changes | (3,809 | ) | — | 53 | (3,756 | ) | ||||||||||
Net change after income taxes | 677 | 1,560 | 15 | 2,252 | ||||||||||||
Balance at June 30, 2014 | $ | 26,425 | $ | (82,065 | ) | $ | (248 | ) | $ | (55,888 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2013 | $ | 25,748 | $ | (83,625 | ) | $ | — | $ | (57,877 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | (8,857 | ) | 2,576 | — | (6,281 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,488 | (1,016 | ) | — | 2,472 | |||||||||||
Other OCI changes (pre-tax) | 9,855 | — | — | 9,855 | ||||||||||||
Income tax impact of other OCI changes | (3,809 | ) | — | — | (3,809 | ) | ||||||||||
Net change after income taxes | 677 | 1,560 | — | 2,237 | ||||||||||||
Balance at June 30, 2014 | $ | 26,425 | $ | (82,065 | ) | $ | — | $ | (55,640 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2013 | $ | — | $ | — | $ | (263 | ) | $ | (263 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | — | — | 176 | 176 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (61 | ) | (61 | ) | ||||||||||
Other OCI changes (pre-tax) | — | — | (153 | ) | (153 | ) | ||||||||||
Income tax impact of other OCI changes | — | — | 53 | 53 | ||||||||||||
Net change after income taxes | — | — | 15 | 15 | ||||||||||||
Balance at June 30, 2014 | $ | — | $ | — | $ | (248 | ) | $ | (248 | ) | ||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Available-for- | Liability | for Cash Flow | ||||||||||||||
Sale 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) | (6,854 | ) | 3,182 | 99 | (3,573 | ) | ||||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | (35 | ) | 1,417 | ||||||||||
Other OCI changes (pre-tax) | 8,591 | — | 3 | 8,594 | ||||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | (1 | ) | (3,402 | ) | |||||||||
Net change after income taxes | 1,050 | 1,920 | 66 | 3,036 | ||||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | (150 | ) | $ | (78,594 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | — | $ | (81,414 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | (6,854 | ) | 3,182 | — | (3,672 | ) | ||||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | — | 1,452 | |||||||||||
Other OCI changes (pre-tax) | 8,591 | — | — | 8,591 | ||||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | — | (3,401 | ) | ||||||||||
Net change after income taxes | 1,050 | 1,920 | — | 2,970 | ||||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | — | $ | (78,444 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2012 | $ | — | $ | — | $ | (216 | ) | $ | (216 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | — | — | 99 | 99 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (35 | ) | (35 | ) | ||||||||||
Other OCI changes (pre-tax) | — | — | 3 | 3 | ||||||||||||
Income tax impact of other OCI changes | — | — | (1 | ) | (1 | ) | ||||||||||
Net change after income taxes | — | — | 66 | 66 | ||||||||||||
Balance at June 30, 2013 | $ | — | $ | — | $ | (150 | ) | $ | (150 | ) | ||||||
Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the six months ended June 30, 2014 and 2013, approximately 23.0% and 16.4% of the amount reclassified was capitalized into construction work in process and approximately 2.1% and 2.5% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings. |
Variable_Interest_Entities
Variable Interest Entities | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Variable Interest Entities [Abstract] | ' | |||||||||||||||
Variable Interest Entities | ' | |||||||||||||||
Variable Interest Entities | ||||||||||||||||
GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. | ||||||||||||||||
Valencia | ||||||||||||||||
PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and six months ended June 30, 2014, PNM paid $4.8 million and $9.6 million for fixed charges and $0.5 million and $0.7 million for variable charges. For the three and six months ended June 30, 2013, PNM paid $4.7 million and $9.4 million for fixed charges and $0.2 million and $0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest. | ||||||||||||||||
Summarized financial information for Valencia is as follows: | ||||||||||||||||
Results of Operations | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands) | ||||||||||||||||
Operating revenues | $ | 5,307 | $ | 4,922 | $ | 10,238 | $ | 9,697 | ||||||||
Operating expenses | (1,399 | ) | (1,349 | ) | (2,799 | ) | (2,920 | ) | ||||||||
Earnings attributable to non-controlling interest | $ | 3,908 | $ | 3,573 | $ | 7,439 | $ | 6,777 | ||||||||
Financial Position | ||||||||||||||||
June 30, | December 31, | |||||||||||||||
2014 | 2013 | |||||||||||||||
(In thousands) | ||||||||||||||||
Current assets | $ | 3,232 | $ | 2,658 | ||||||||||||
Net property, plant, and equipment | 73,729 | 75,137 | ||||||||||||||
Total assets | 76,961 | 77,795 | ||||||||||||||
Current liabilities | 682 | 766 | ||||||||||||||
Owners’ equity – non-controlling interest | $ | 76,279 | $ | 77,029 | ||||||||||||
During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price, after which PNM was to determine, in its sole discretion, whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the purchase by the NMPRC and FERC would be required, which process could take in excess of 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. PNM is discussing these issues with the owner of Valencia. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed. | ||||||||||||||||
PVNGS Leases | ||||||||||||||||
PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provide PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and Note 6, for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. | ||||||||||||||||
PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $36.5 million as of June 30, 2014 over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of June 30, 2014, PNM could have been required to pay the beneficial owners up to $144.7 million, which would result in PNM taking ownership of the leased assets and termination of the leases. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. | ||||||||||||||||
PNM has evaluated the PVNGS lease arrangements, including the notices, amendments, and agreements referred to 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 $26.0 million at June 30, 2014 and December 31, 2013, that are included in other current liabilities on the Condensed Consolidated Balance Sheets. | ||||||||||||||||
Delta | ||||||||||||||||
PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which is a variable interest under GAAP. PNM also controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owns Delta. PNM made fixed and variable payments to Delta under the PPA. For the three and six months ended June 30, 2014, PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.3 million and $0.5 million under the PPA. For the three and six months ended June 30, 2013, PNM incurred fixed capacity charges of $1.6 million and $3.2 million and variable energy charges of $0.4 million and $0.6 million. PNM’s only quantifiable obligation under the PPA was to make the fixed payments, which as of June 30, 2014 aggregated $36.2 million through the end of the PPA. PNM would also pay variable costs, which could not be quantified since the amounts were based on how much the generating plant operated. | ||||||||||||||||
This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that 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. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing was subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. At closing, PNM made a cash payment of $22.8 million, which reflected an adjustment for estimated working capital compared to a targeted working capital and included amounts placed in escrow. Delta had project financing debt, which PNM retired at closing of the purchase, amounting to $14.6 million at June 30, 2014 and at closing. | ||||||||||||||||
Delta informed PNM that at June 30, 2014 and December 31, 2013, it had total assets of $22.4 million and $23.7 million, including net property, plant, and equipment of $19.0 million and $20.3 million, and total liabilities of $16.5 million and $18.2 million. Delta also indicated its revenue for the three and six months ended June 30, 2014 was $2.5 million and $4.3 million and its net earnings were $0.3 million and $0.6 million. Revenue for the three and six months ended June 30, 2013 was $2.2 million and $4.0 million and net earnings were $0.1 million and $0.3 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. |
Lease_Commitments
Lease Commitments | 6 Months Ended |
Jun. 30, 2014 | |
Leases [Abstract] | ' |
Lease Commitments | ' |
Lease Commitments | |
The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and an interest in the EIP transmission line. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. | |
The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Each of the leases provides PNM with an option to purchase the leased assets at fair market value at the end of the lease. In addition, the leases provide PNM with options to renew the leases at fixed rates set forth in each of the leases for two years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional six years (the “Maximum Option Period”) if the appraised remaining useful lives and fair values of the leased assets are greater than parameters set forth in the leases. The rental payments during the renewal option periods would be 50% of the amounts during the original terms of the leases. | |
Following procedures set forth in the PVNGS leases, PNM notified each of the lessors under the Unit 1 leases that it would elect to renew those leases for the Maximum Option Period on the expiration date of the original leases. In addition, PNM notified the lessor under the one Unit 2 lease containing the Maximum Option Period provision that it would elect to renew that lease for the Maximum Option Period on the expiration date of the original lease. On December 11, 2013, PNM and each of the Unit 1 lessors entered into amendments to each of the Unit 1 leases setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2023. Similarly, on March 18, 2014, PNM and the lessor under the one Unit 2 lease containing the Maximum Option Period provision entered into an amendment to that lease setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring on January 15, 2024. | |
For the three PVNGS Unit 2 leases which do not contain the Maximum Option Period provisions, PNM, following procedures set forth in the leases, notified each of the lessors that PNM would elect to purchase the assets underlying those leases on the expiration date of the original leases. On February 25, 2014, PNM and the lessor under one of the Unit 2 leases entered into a letter agreement that establishes that the purchase price, representing the fair market value, to be paid by PNM for the assets underlying that lease will be $78.1 million on January 15, 2016. This lease is for 31.2494 MW of the entitlement from PVNGS Unit 2. The lease remains in existence and PNM will record the purchase at the termination of the lease on January 15, 2016. | |
On May 1, 2014, PNM and the trusts that are the lessors under the other two PVNGS Unit 2 leases signed a letter agreement that establishes a binding agreement regarding the purchase price, representing the fair market value, to be paid by PNM for the assets underlying those leases of $85.2 million on January 15, 2016. These leases are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development, a wholly-owned subsidiary of PNMR, is also a party to the letter agreement, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014 and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014 and declines to $1.2 million on January 14, 2016. PNMR and PNM are unable to predict whether or not the early purchase will occur. |
Fair_Value_of_Derivative_and_O
Fair Value of Derivative and Other Financial Instruments | 6 Months Ended | |||||||||||||||||||
Jun. 30, 2014 | ||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Abstract] | ' | |||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments | ' | |||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments | ||||||||||||||||||||
Energy Related Derivative Contracts | ||||||||||||||||||||
Overview | ||||||||||||||||||||
The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2013 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 purchases and normal sales 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 purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle. | ||||||||||||||||||||
During the six months ended June 30, 2014 and the year ended December 31, 2013, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions. | ||||||||||||||||||||
Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique. | ||||||||||||||||||||
Commodity Derivatives | ||||||||||||||||||||
Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
June 30, | December 31, | |||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Current assets | $ | 4,082 | $ | 4,064 | ||||||||||||||||
Deferred charges | 1,515 | 3,002 | ||||||||||||||||||
5,597 | 7,066 | |||||||||||||||||||
Current liabilities | (5,073 | ) | (2,699 | ) | ||||||||||||||||
Long-term liabilities | (915 | ) | (1,094 | ) | ||||||||||||||||
(5,988 | ) | (3,793 | ) | |||||||||||||||||
Net | $ | (391 | ) | $ | 3,273 | |||||||||||||||
Included in the above table are $3.0 million of current assets and $1.5 million of deferred charges at June 30, 2014 and $3.0 million of current assets and $3.0 million of deferred charges at December 31, 2013 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at June 30, 2014 and December 31, 2013. | ||||||||||||||||||||
At June 30, 2014 and December 31, 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at June 30, 2014 and December 31, 2013, amounts posted as cash collateral under margin arrangements were $2.4 million and $2.8 million for both PNMR and PNM. PNMR and PNM had obligations to return cash collateral of $0.1 million at June 30, 2014 and $0.2 million at December 31, 2013. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets. | ||||||||||||||||||||
PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.4 million of current assets and $0.6 million of current liabilities at June 30, 2014 and $0.4 million of current assets and $0.1 million of current liabilities at December 31, 2013 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. | ||||||||||||||||||||
The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Electric operating revenues | $ | (324 | ) | $ | 3,269 | $ | (4,475 | ) | $ | (1,334 | ) | |||||||||
Cost of energy | 57 | (263 | ) | 245 | 493 | |||||||||||||||
Total gain (loss) | $ | (267 | ) | $ | 3,006 | $ | (4,230 | ) | $ | (841 | ) | |||||||||
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 | |||||||||||||||||||
June 30, 2014 | ||||||||||||||||||||
PNMR and PNM | 1,165,000 | (2,809,507 | ) | |||||||||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR and PNM | 905,000 | (3,343,783 | ) | |||||||||||||||||
In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral. | ||||||||||||||||||||
The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. | ||||||||||||||||||||
Contingent Feature – | Contractual Liability | Existing Cash Collateral | Net Exposure | |||||||||||||||||
Credit Rating Downgrade | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
June 30, 2014 | ||||||||||||||||||||
PNMR and PNM | $ | 2,740 | $ | — | $ | 1,663 | ||||||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR and PNM | $ | 2,398 | $ | — | $ | 2,152 | ||||||||||||||
Sale of Power from PVNGS Unit 3 | ||||||||||||||||||||
Because PNM’s 134 MW share of Unit 3 at PVNGS is not included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of June 30, 2014, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015. | ||||||||||||||||||||
Non-Derivative Financial Instruments | ||||||||||||||||||||
The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines that serve SJGS (Note 11). The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At June 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.9 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust. | ||||||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||||||
Unrealized Gains | Fair Value | Unrealized Gains | Fair Value | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 3,114 | $ | — | $ | 3,356 | ||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 16,014 | 42,664 | 14,523 | 39,460 | ||||||||||||||||
Domestic growth | 19,931 | 75,621 | 25,656 | 76,292 | ||||||||||||||||
International and other | 2,227 | 17,848 | 1,040 | 16,633 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 534 | 19,814 | 158 | 21,941 | ||||||||||||||||
Municipals | 4,282 | 65,872 | 1,018 | 58,568 | ||||||||||||||||
Corporate and other | 625 | 11,494 | 207 | 10,605 | ||||||||||||||||
$ | 43,613 | $ | 236,427 | $ | 42,602 | $ | 226,855 | |||||||||||||
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 and reflect impairments. | ||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Proceeds from sales | $ | 30,316 | $ | 61,821 | $ | 53,119 | $ | 76,106 | ||||||||||||
Gross realized gains | $ | 5,364 | $ | 4,905 | $ | 8,482 | $ | 6,243 | ||||||||||||
Gross realized (losses) | $ | (665 | ) | $ | (1,688 | ) | $ | (1,210 | ) | $ | (1,496 | ) | ||||||||
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments. | ||||||||||||||||||||
The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings. | ||||||||||||||||||||
At June 30, 2014, 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 | $ | 2,911 | $ | 12,017 | $ | 12,017 | ||||||||||||||
After 1 year through 5 years | 21,556 | 33,776 | 33,050 | |||||||||||||||||
After 5 years through 10 years | 10,875 | — | — | |||||||||||||||||
After 10 years through 15 years | 9,114 | — | — | |||||||||||||||||
After 15 years through 20 years | 11,431 | — | — | |||||||||||||||||
After 20 years | 41,293 | — | — | |||||||||||||||||
$ | 97,180 | $ | 45,793 | $ | 45,067 | |||||||||||||||
Fair Value Disclosures | ||||||||||||||||||||
The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. | ||||||||||||||||||||
For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services. | ||||||||||||||||||||
Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at June 30, 2014 and December 31, 2013 for items recorded at fair value. | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | ||||||||||||||||||
June 30, 2014 | (In thousands) | |||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Available-for-sale securities | ||||||||||||||||||||
Cash and cash equivalents | $ | 3,114 | $ | 3,114 | $ | — | ||||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 42,664 | 42,664 | — | |||||||||||||||||
Domestic growth | 75,621 | 75,621 | — | |||||||||||||||||
International and other | 17,848 | 17,848 | — | |||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 19,814 | 18,053 | 1,761 | |||||||||||||||||
Municipals | 65,872 | — | 65,872 | |||||||||||||||||
Corporate and other | 11,494 | 2,481 | 9,013 | |||||||||||||||||
$ | 236,427 | $ | 159,781 | $ | 76,646 | |||||||||||||||
Commodity derivative assets | $ | 5,597 | $ | — | $ | 5,597 | ||||||||||||||
Commodity derivative liabilities | (5,988 | ) | — | (5,988 | ) | |||||||||||||||
Net | $ | (391 | ) | $ | — | $ | (391 | ) | ||||||||||||
31-Dec-13 | ||||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Available-for-sale securities | ||||||||||||||||||||
Cash and cash equivalents | $ | 3,356 | $ | 3,356 | $ | — | ||||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 39,460 | 39,460 | — | |||||||||||||||||
Domestic growth | 76,292 | 76,292 | — | |||||||||||||||||
International and other | 16,633 | 16,633 | — | |||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 21,941 | 20,194 | 1,747 | |||||||||||||||||
Municipals | 58,568 | — | 58,568 | |||||||||||||||||
Corporate and other | 10,605 | 2,245 | 8,360 | |||||||||||||||||
$ | 226,855 | $ | 158,180 | $ | 68,675 | |||||||||||||||
Commodity derivative assets | $ | 7,066 | $ | — | $ | 7,066 | ||||||||||||||
Commodity derivative liabilities | (3,793 | ) | — | (3,793 | ) | |||||||||||||||
Net | $ | 3,273 | $ | — | $ | 3,273 | ||||||||||||||
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 six months ended June 30, 2014 and the year ended December 31, 2013. | ||||||||||||||||||||
The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | ||||||||||||||||
June 30, 2014 | (In thousands) | |||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,875,254 | $ | 2,088,787 | $ | — | $ | 2,088,787 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 42,234 | $ | 45,067 | $ | — | $ | — | $ | 45,067 | ||||||||||
Other investments | $ | 1,798 | $ | 2,525 | $ | 677 | $ | — | $ | 1,848 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,390,637 | $ | 1,530,418 | $ | — | $ | 1,530,418 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 42,234 | $ | 45,067 | $ | — | $ | — | $ | 45,067 | ||||||||||
Other investments | $ | 432 | $ | 432 | $ | 432 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 365,851 | $ | 431,706 | $ | — | $ | 431,706 | $ | — | ||||||||||
Other investments | $ | 245 | $ | 245 | $ | 245 | $ | — | $ | — | ||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,745,420 | $ | 1,905,230 | $ | — | $ | 1,905,230 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 52,958 | $ | 57,279 | $ | — | $ | — | $ | 57,279 | ||||||||||
Other investments | $ | 1,835 | $ | 3,196 | $ | 690 | $ | — | $ | 2,506 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,290,618 | $ | 1,382,938 | $ | — | $ | 1,382,938 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 52,958 | $ | 57,279 | $ | — | $ | — | $ | 57,279 | ||||||||||
Other investments | $ | 445 | $ | 445 | $ | 445 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 336,036 | $ | 390,814 | $ | — | $ | 390,814 | $ | — | ||||||||||
Other investments | $ | 245 | $ | 245 | $ | 245 | $ | — | $ | — | ||||||||||
StockBased_Compensation
Stock-Based Compensation | 6 Months Ended | |||||||||||||
Jun. 30, 2014 | ||||||||||||||
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 since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards also have time vesting 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 2013 Annual Reports on Form 10-K. | ||||||||||||||
Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. | ||||||||||||||
The stock-based compensation expense related to 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 grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At June 30, 2014 and December 31, 2013, PNMR had unrecognized expense related to stock awards of $7.7 million and $4.6 million. | ||||||||||||||
The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period. | ||||||||||||||
The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: | ||||||||||||||
Six Months Ended June 30, | ||||||||||||||
Restricted Shares and Performance Based Shares | 2014 | 2013 | ||||||||||||
Expected quarterly dividends per share | $ | 0.185 | $ | 0.165 | ||||||||||
Risk-free interest rate | 0.62 | % | 0.34 | % | ||||||||||
Market-Based Shares | ||||||||||||||
Dividend yield | 2.82 | % | 2.86 | % | ||||||||||
Expected volatility | 25.11 | % | 25.11 | % | ||||||||||
Risk-free interest rate | 0.64 | % | 0.36 | % | ||||||||||
The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the six months ended June 30, 2014: | ||||||||||||||
Stock Option Shares | Weighted- | Restricted Stock | Weighted- | |||||||||||
Average | Average | |||||||||||||
Exercise | Grant Date Fair Value | |||||||||||||
Price | ||||||||||||||
Outstanding at beginning of period | 1,343,666 | $ | 20.63 | 315,305 | $ | 17.87 | ||||||||
Granted | — | $ | — | 242,164 | $ | 21.27 | ||||||||
Exercised | (236,260 | ) | $ | 18.9 | (292,052 | ) | $ | 16.64 | ||||||
Forfeited | (17,151 | ) | $ | 26.43 | — | $ | — | |||||||
Expired | (22,784 | ) | $ | 25.91 | — | $ | — | |||||||
Outstanding at end of period | 1,067,471 | $ | 20.8 | 265,417 | $ | 22.31 | ||||||||
Included as restricted stock granted and exercised in the table above are 112,864 shares that were based upon achieving performance or market targets for 2013. The Board approved these shares in February 2014 (based upon achieving market targets, weighted at 60%, at maximum levels, and performance targets, weighted at 40%, at below threshold levels for the 2011 through 2013 performance period). | ||||||||||||||
PNMR’s stock-based compensation program provides for performance or market targets through 2016. Excluded from the above table are maximums of 198,369, 179,811, and 175,735 restricted stock shares for periods ending in 2014, 2015, and 2016 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, with certain exceptions, 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 restricted stock shares under the retention award agreement. | ||||||||||||||
At June 30, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $9.4 million with a weighted-average remaining contract life of 3.20 years. At June 30, 2014, the exercise price of 297,350 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value. | ||||||||||||||
The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: | ||||||||||||||
Six Months Ended June 30, | ||||||||||||||
Stock Options | 2014 | 2013 | ||||||||||||
Weighted-average grant date fair value of options granted | $ | — | $ | — | ||||||||||
Total fair value of options that vested (in thousands) | $ | — | $ | 625 | ||||||||||
Total intrinsic value of options exercised (in thousands) | $ | 1,779 | $ | 2,189 | ||||||||||
Restricted Stock | ||||||||||||||
Weighted-average grant date fair value | $ | 21.27 | $ | 20.03 | ||||||||||
Total fair value of restricted shares that vested (in thousands) | $ | 4,854 | $ | 4,383 | ||||||||||
Financing
Financing | 6 Months Ended | ||||||||
Jun. 30, 2014 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Financing | ' | ||||||||
Financing | |||||||||
Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. | |||||||||
Financing Activities | |||||||||
On January 8, 2014, PNM entered into a new $50.0 million unsecured revolving credit facility (the “PNM New Mexico Credit Facility”) by and among PNM, the lenders identified therein, U.S. Bank National Association, as Administrative Agent, and BOKF, NA dba Bank of Albuquerque, as Syndication Agent. The nine participating lenders are all banks that have a significant presence in New Mexico and PNM’s service territory or are headquartered in New Mexico. The PNM New Mexico Credit Facility expires on January 8, 2018 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility. | |||||||||
On March 5, 2014, PNM entered into a new $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM Term Loan Agreement. PNM also used the funds to repay other short-term amounts outstanding. The PNM Term Loan Agreement would otherwise have terminated on October 21, 2014. There were no prepayment penalties paid in connection with the termination of the PNM Term Loan Agreement. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.10% at June 30, 2014, must be repaid on or before September 4, 2015, and is reflected as long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision. | |||||||||
On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provided that TNMP would issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”) on or about June 27, 2014, subject to satisfaction of certain conditions. TNMP issued the Series 2014A Bonds on June 27, 2014. TNMP used $50.0 million of the proceeds to repay the full outstanding amount of the TNMP 2011 Term Loan Agreement and used the remaining $30.0 million of proceeds to reduce short-term debt. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement were reflected as being long-term at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrated TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis. | |||||||||
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. 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 and matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At June 30, 2014, the weighted average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility and 1.00% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of: | |||||||||
June 30, | December 31, | ||||||||
Short-term Debt | 2014 | 2013 | |||||||
(In thousands) | |||||||||
PNM: | |||||||||
Revolving credit facility | $ | — | $ | 49,200 | |||||
PNM New Mexico Credit Facility | — | — | |||||||
TNMP – Revolving credit facility | — | — | |||||||
PNMR: | |||||||||
Revolving credit facility | 5,000 | — | |||||||
PNMR Term Loan Agreement | 100,000 | 100,000 | |||||||
$ | 105,000 | $ | 149,200 | ||||||
At July 25, 2014, PNMR, PNM, and TNMP had $292.3 million, $369.6 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 25, 2014, on a consolidated basis, was $771.8 million for PNMR. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At July 25, 2014, PNMR, PNM and TNMP had consolidated invested cash of $1.9 million, none, and none. |
Pension_and_Other_Postretireme
Pension and Other Postretirement Benefit Plans | 6 Months Ended | |||||||||||||||||||||||
Jun. 30, 2014 | ||||||||||||||||||||||||
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 2013 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. The Society of Actuaries has proposed a change in mortality assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates. If adopted, this change will have impacts on the Company’s pension plans, as the mortality assumptions are used as the basis for stating the pension obligation in financial statements, determining funding requirements, and making minimum lump-sum calculations. The Company, with the assistance of its consulting actuaries, is studying the impact of the mortality table changes. This study is on-going and subject to change. Preliminary estimates indicate that, beginning in 2016, the Company’s pension liabilities could increase by as much as 7% over those using the current mortality assumptions. Although pension expense and funding requirements also will likely increase, these changes are not expected to be material. | ||||||||||||||||||||||||
PNM Plans | ||||||||||||||||||||||||
The following tables present the components of the PNM Plans’ net periodic benefit cost: | ||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 45 | $ | 65 | $ | — | $ | — | ||||||||||||
Interest cost | 7,541 | 7,035 | 1,159 | 1,029 | 205 | 180 | ||||||||||||||||||
Expected return on plan assets | (9,511 | ) | (10,482 | ) | (1,410 | ) | (1,261 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 3,255 | 3,710 | 556 | 1,061 | 52 | 58 | ||||||||||||||||||
Amortization of prior service cost | (241 | ) | 19 | (336 | ) | (336 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 1,044 | $ | 282 | $ | 14 | $ | 558 | $ | 257 | $ | 238 | ||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 91 | $ | 130 | $ | — | $ | — | ||||||||||||
Interest cost | 15,082 | 14,071 | 2,315 | 2,057 | 411 | 360 | ||||||||||||||||||
Expected return on plan assets | (19,022 | ) | (20,965 | ) | (2,819 | ) | (2,522 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 6,510 | 7,420 | 1,113 | 2,121 | 105 | 116 | ||||||||||||||||||
Amortization of prior service cost | (483 | ) | 38 | (672 | ) | (672 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 2,087 | $ | 564 | $ | 28 | $ | 1,114 | $ | 516 | $ | 476 | ||||||||||||
PNM does not anticipate making any contributions to its pension trust in 2014 due to the current funded status of the pension plan. PNM made contributions to its pension plan trust of zero and $60.0 million in the three and six months ended June 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2015-2018 are estimated to total $61.5 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 5.2% to 5.5%. Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $1.6 million in the three and six months ended June 30, 2014 and $1.1 million and $1.6 million in the three and six months ended June 30, 2013. PNM expects to make contributions to the OPEB trust totaling $3.3 million in 2014 and $14.0 million for 2015-2018. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.7 million in the three and six months ended June 30, 2014 and $0.4 million and $0.8 million in the three and six months ended June 30, 2013 and are expected to total $1.5 million during 2014. | ||||||||||||||||||||||||
TNMP Plans | ||||||||||||||||||||||||
The following tables present the components of the TNMP Plans’ net periodic benefit cost (income): | ||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 59 | $ | 75 | $ | — | $ | — | ||||||||||||
Interest cost | 798 | 772 | 155 | 141 | 10 | 9 | ||||||||||||||||||
Expected return on plan assets | (1,132 | ) | (1,212 | ) | (133 | ) | (126 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 166 | 262 | (31 | ) | — | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 8 | 14 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (168 | ) | $ | (178 | ) | $ | 58 | $ | 104 | $ | 10 | $ | 9 | ||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 119 | $ | 150 | $ | — | $ | — | ||||||||||||
Interest cost | 1,597 | 1,544 | 309 | 283 | 20 | 18 | ||||||||||||||||||
Expected return on plan assets | (2,263 | ) | (2,425 | ) | (267 | ) | (252 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 333 | 524 | (61 | ) | — | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 16 | 28 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (333 | ) | $ | (357 | ) | $ | 116 | $ | 209 | $ | 20 | $ | 18 | ||||||||||
TNMP does not anticipate making additional contributions to its pension trust in 2014 due to the current funded status of the pension plan. TNMP made contributions to its pension plan trust of zero and $1.0 million in the three and six months ended June 30, 2013. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, TNMP estimates there would be no contributions to its pension plan trust for 2015-2018. The anticipated contributions were developed using current funding assumptions, including discount rates of 5.2% and 5.5%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made contributions to the OPEB trust of $0.3 million in the three and six months ended June 30, 2014 and $0.3 million in the three and six months ended June 30, 2013. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2014 and $1.4 million for 2015-2018. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and six months ended June 30, 2014 and 2013 and are expected to total $0.1 million during 2014. |
Commitments_and_Contingencies
Commitments and Contingencies | 6 Months Ended | |
Jun. 30, 2014 | ||
Commitments and Contingencies Disclosure [Abstract] | ' | |
Commitments and Contingencies | ' | |
Commitments and Contingencies | ||
Overview | ||
There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows. | ||
With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of 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 2013 Annual Reports on Form 10-K. | ||
Commitments and Contingencies Related to the Environment | ||
Nuclear Spent Fuel and Waste Disposal | ||
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. PNM is unable to predict the outcome of this matter. | ||
PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At June 30, 2014 and December 31, 2013, PNM had a liability for interim storage costs of $12.1 million and $11.9 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 EIS 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 fuel 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 EIS to support an updated Waste Confidence Decision within 24 months. In September 2013, the NRC issued its draft EIS to support an updated Waste Confidence Decision. In late 2013, the NRC held a series of nationwide public meetings to receive stakeholder input on the draft EIS. NRC Commissioners have instructed the staff to issue the final generic EIS and rule by no later than September 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, PVNGS does not have any licensing actions pending with the NRC. The petitioners 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. In August 2013, the D.C. Circuit ordered the NRC to resume reviewing the license application. PNM is unable to predict the impact of these decisions. | ||
In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. The fee applicable to PVNGS Units 1 and 2 is recovered by PNM in its retail rates. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of the intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. On January 3, 2014, the DOE notified Congress of the intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. PNM anticipates challenges to this action and is unable to predict its ultimate outcome. | ||
The Clean Air Act | ||
Regional Haze | ||
In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018. | ||
SJGS | ||
BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that 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 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 the rule’s 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. | ||
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. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs were to 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. | ||
Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional 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 under either SCRs or SNCRs as described above would be about 46.3%. | ||
During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by the 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. Certain aspects of this alternative are subject to approval by the NMPRC. At June 30, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $286 million. | ||
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. | ||
This revised plan primarily focuses on how SJGS would meet the regional haze rule and also indicates that PNM would build a natural gas-fired generating plant in the “four corners” region 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. | ||
It was contemplated that the retirement of SJGS Units 2 and 3 under the revised plan might result in shifts in ownership among SJGS owners or other changes in the contractual cost sharing arrangements, as would be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may be required to seek approvals of their utility commissions or governing boards for any such changes. | ||
The parties file periodic 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. | ||
Due to the long lead times on certain equipment purchases, PNM began 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 and in July 2014 entered into a contract for management of the SNCR construction, but has not yet entered into a construction and procurement contract. | ||
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 deemed the SIP application complete on December 17, 2013. On April 30, 2014, EPA issued an advance copy of its proposed approval of the revised SIP and it was published in the Federal Register on May 12, 2014. EPA provided a 30 day public comment period, which ended on June 11, 2014. PNM filed comments in support of EPA’s proposed approval. Final EPA action on the revised SIP is expected by about the end of September 2014. | ||
On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requested: | ||
• | Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date, estimated to be approximately $205 million, along with a regulated return on those costs | |
• | A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018 | |
• | An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million | |
• | A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would be a reduction of 340 MW in PNM’s ownership of SJGS | |
In its filing, PNM requested the NMPRC to issue its final ruling on the application no later than December 2014. On February 11, 2014, the Hearing Examiner issued an order finding that PNM’s application is complete. The order also stated that there was not a statutory time clock for the request to retire SJGS Units 2 and 3 and the statutory time clock on the CCN requests has not yet begun. The Hearing Examiner found that the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014. | ||
The above estimate of PNM’s share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 includes gross receipts taxes, AFUDC, and other PNM costs. This amount and the above estimate of net book value of SJGS Units 2 and 3 at December 31, 2017 reflect the requested exchange of 78 MW of capacity out of SJGS Unit 3 and into SJGS Unit 4 resulting in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 52%. The December 20, 2013 NMPRC filing identifies a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM has included the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. Specific approvals to acquire other facilities and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $268.3 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs 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 Note 12 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters. | ||
As discussed under SJGS Ownership Restructuring Matters below, the owners of SJGS are attempting to negotiate agreements concerning numerous matters, the resolution of which is necessary in order to facilitate the shutdown of SJGS Units 2 and 3 and comply with the revised SIP. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time. PNM’s ultimate ownership percentage in SJGS Unit 4 will depend on the final resolution of the negotiations among the SJGS owners and is subject to NMPRC approval. On July 1, 2014, pursuant to an order of the hearing examiner in the case, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS, which are memorialized in the resolution and term sheet described below. PNM filed testimony with the NMPRC on July 15, 2014 further describing the proposed terms. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting that the NMPRC take action on this case by the end of February 2015. | ||
PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished within the required timeframes or at all. 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 need to rely on EPA’s pledge to work with PNM and the State of New Mexico to develop a reasonable FIP compliance plan or otherwise negotiate a solution with EPA or seek relief from the Tenth Circuit in order to continue to be able to operate the plant, including during the installation process for any alternate solution. 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 its share of 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 2013 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4. PNM is unable to predict the actions of the SJGS participants. Likewise, PNM cannot predict the impact of those actions on the ownership of SJGS or the operations of SJGS and PNM. | ||
The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 in order to facilitate the shutdown of 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 have resulted in certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4 prior to the shutdown of SJGS Units 2 and 3. Based on the status of negotiations at the time of PNM’s December 20, 2013 NMPRC filing, PNM requested NMPRC approval to exchange 78 MW of its capacity in SJGS Unit 3 for an equal amount of capacity in SJGS Unit 4. The discussions among the SJGS participants regarding restructuring have also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. The SJGS participants engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners. | ||
On June 26, 2014, a non-binding resolution was unanimously approved by the SJGS Coordination Committee. The resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The non-binding resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The non-binding resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. The participants continue to negotiate definitive agreements that would formalize these matters, as well as addressing plant decommissioning liabilities and indemnification. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it proposes to acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in the December 20, 2013 NMPRC filing. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 59%. PNM’s remaining replacement power plans otherwise remain as previously proposed. | ||
A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Any final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained. | ||
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 property common to more than one unit. 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 SJGS 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. In addition, other capital projects related to Unit 4 were not approved by the participants. The SJPPA provides that PNM, in its capacity as operating agent of SJGS, 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 must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. On March 11, 2014, PNM requested that the owners of Unit 4 approve the expenditure of $1.9 million of costs critical to being able to comply with the time frame in the revised SIP with respect to the Unit 4 project. The Unit 4 owners did not approve the expenditures. Thereafter, PNM, as operating agent for SJGS, issued a “Prudent Utility Practice” notice under the SJPPA indicating PNM was restarting certain critical activities to keep the Unit 4 SNCR project on schedule. On June 27, 2014, PNM requested that the Unit 4 owners approve the expenditure of an additional $6.4 million of costs critical to the next phase of the Unit 4 capital project and compliance with the revised SIP deadline. The Unit 4 owners did not approve the additional expenditures. PNM subsequently issued a notice to the participants on July 14, 2014, that, consistent with “Prudent Utility Practice,” PNM must continue the work on Unit 4 and would begin to incur the additional expenditures. PNM cannot predict the outcome of this matter, its impact on SJGS’ compliance with the CAA, or the impact on PNM’s financial position, results of operations, and cash flows. | ||
Four Corners | ||
On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to 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. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shutdown by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 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. | ||
APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. In March 2014, APS received a draft of the EIS in connection with the DOI review process. The deadline for comments on the draft EIS, which originally were due by the May 27, 2014, was extended to June 27, 2014. On June 19, 2014, PNM submitted comments on the draft EIS as owner and operator of two electric transmission lines that are part of the connected action for the EIS. In addition, APS will require a PSD permit from EPA to install SCR control technology at Four Corners. PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners participants. | ||
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 $80.3 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 is unable to predict the ultimate outcome of this matter. | ||
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. Oral argument was presented before the Tenth Circuit on January 23, 2014. On July 23, 2014, the Tenth Circuit issued a unanimous decision affirming EPA’s action and denying WEG’s petition for review. PNM is unable to predict whether WEG will file a petition for rehearing or otherwise appeal the decision. | ||
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. 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. Oral argument was heard before the Tenth Circuit on March 20, 2014. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes. | ||
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. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO2 sources through ambient monitoring or modeling. 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 November 8, 2013, PNM received an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In the revised permit, PNM agreed to reduce SO2 emissions to 0.1 pound per MMBTU and to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These reductions will help SJGS meet the NAAQS. It is anticipated that the equipment modifications 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 the plant in complying 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 has stated it intends to propose a new standard. Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half 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 at any of its affected facilities 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 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 $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. In accordance with the stipulated order, PNM will repeat the mercury study required under the Consent Decree using sorbent traps instead of the monitoring system used in the initial study. The results of the mercury study will establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM cannot predict the ultimate 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. On April 2, 2012, the Four Corners participants filed motions to dismiss. 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. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. 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. Although an agreement was reached resolving claims related 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. | ||
Cooling Water Intake Structures | ||
EPA issued its final cooling water intake structures rule on May 19, 2014, which establishes 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 final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting “best technology available” standards for reducing impingement. To minimize entrainment mortality, the permitting authority must establish the “best technology available” for entrainment on a site-specific basis, taking into consideration an array of factors, including social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. PNM is performing analyses to determine the potential costs of compliance with the rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material. | ||
Effluent Limitation Guidelines | ||
On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired 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 waste operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions and will follow through on a separate agreement to issue a final rule on coal ash waste disposal by December 19, 2014. If EPA misses the December 19, 2014 deadline to issue a coal ash rule, then the agreement allows the environmental groups to require the EPA to issue the final effluent limits earlier. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. | ||
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 City of Santa Fe has 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 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 voluntarily agreed to conduct similar sampling activities on the site beginning in April 2014, as well as more specific “fingerprint” analysis, which may help identify potential off-site sources. 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 and 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. On January 29, 2014, EPA entered into a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014. | ||
PNM advocates for the non-hazardous regulation of CCBs. 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. 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 June 30, 2014 and December 31, 2013, prepayments for coal, which are included in other current assets, amounted to $21.6 million and $12.3 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. PNM and the other owners of SJGS are evaluating alternatives for the supply of coal after the expiration of the current coal sales agreement. | ||
APS purchases all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 21% for the first full year of the new contract and will further increase over the contract term. PNM anticipates that its share of the increased costs will be recovered through its FPPAC. | ||
In 2013, 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. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $54.6 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of June 30, 2014. At June 30, 2014 and December 31, 2013, liabilities, in current dollars, of $23.3 million and $23.8 million for surface mine reclamation and $8.2 million and $7.8 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. The updated coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. 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 underground mine area thereby increasing the overall reclamation costs. It has not been decided how costs would be divided among the owners of SJGS. Regulatory determinations made by the NMPRC may also affect the impact on PNM. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. PNM is currently unable to determine the outcome of these matters or the range of possible impacts. | ||
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. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC has completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembled it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. | ||
The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM included the portion of such costs allocable to its customers subject to New Mexico regulation in its FPPAC. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between $17.4 million and $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and informed PNM that it settled with its insurance carrier. PNM’s portion of the insurance recovery is $18.7 million. PNM has credited its FPPAC balancing account for the insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 12. | ||
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. There is no legal deadline for adoption of the final 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 were submitted to a panel for binding arbitration. The issues were: 1) whether the SJGS participants owed SJCC unbilled mining costs of $5.2 million or whether SJCC owed the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $13.9 million as mining costs that SJCC should have considered to be capital costs, which were not billable under the mining contract. PNM’s share of amounts subject to the arbitration are approximately 46.3%. A hearing before the arbitration panel on the remaining issues was held in May 2014. The arbitration panel found in favor of SJCC on both issues. Of PNM’s share of the costs, approximately 33% of the first issue was passed through PNM’s FPPAC and the rest impacted earnings in the three months ended June 30, 2014. The amounts related to the second issue were recorded when billed in prior periods and had no impact in 2014. | ||
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. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in 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. | ||
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 retrospective premium assessment per incident for all three units is $38.9 million, with a maximum 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, 2014, a sublimit of $2.25 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 premium assessments of $4.8 million for each retrospective premium 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 is not 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 long-term 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 issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding, and on November 1, 2013 issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time. | ||
PNM is participating in this proceeding since 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. 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. | ||
Rights-of-Way Matter | ||
On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. In June 2014, the utilities and Bernalillo County reached an agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenge to the ordinance is unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations. | ||
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. The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way. | ||
In a separate matter, in September 2012, 43 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. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allotees’ appeal was dismissed with prejudice concluding this matter. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. PNM is in the process of investigating the validity of this notice of revocation and its potential impact in light of the BIA’s position and the recent dismissal with prejudice of the appeal, and is therefore unable at this time to predict the likely outcome of this matter. |
Regulatory_and_Rate_Matters
Regulatory and Rate Matters | 6 Months Ended |
Jun. 30, 2014 | |
Regulated Operations [Abstract] | ' |
Regulatory and Rate Matters | ' |
Regulatory and Rate Matters | |
The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2013 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.” The current diversity requirements are 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, subject to the limitation of the RCT. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. On motions for rehearing, the NMPRC reversed its weighting decision in April 2014. | |
The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. | |
The NMPRC approved PNM’s 2014 renewable energy procurement plan on December 18, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s 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 Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. | |
PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements include the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). The NMPRC has scheduled a public hearing on the plan to begin September 11, 2014. PNM expects a decision by December 2, 2014. | |
PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. | |
Renewable Energy Rider | |
The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. On April 1, 2014, PNM made a filing with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013. At the currently approved rider rate, PNM would collect an estimated $34.6 million annually. | |
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 an electric utility’s annual revenue. | |
In October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013. | |
Disincentives/Incentives | |
The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing a NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million. | |
Energy Efficiency Rulemaking | |
On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. | |
On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013. | |
FPPAC Continuation Application | |
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 both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed to resolve this case. A public hearing on the stipulation was held on February 25, 2014. The Hearing Examiner recommended approval of the settlement in its entirety to the NMPRC. On April 23, 2014, the NMPRC approved the stipulation. The settlement allows PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, resolves all costs related to the San Juan Coal mine fire discussed in Note 11, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, requires PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and requires PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the $10.5 million write off as a regulatory disallowance in the fourth quarter of 2013. | |
Integrated Resource Plan | |
NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. | |
Applications for Approvals to Purchase Delta | |
As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM acquired energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. PNM closed on the purchase on July 17, 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 requested a determination of related ratemaking principles and treatment. 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. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a value of up to $56.0 million to be included in rate base for the facility. A public hearing was held on April 29, 2014. The NMPRC issued an order certifying the stipulation on June 18, 2014. Construction of the facility is expected to be completed in late 2015. | |
San Juan Generating Station Units 2 and 3 Retirement | |
As discussed in Note 11, on December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. In that application, PNM also sought approval to recover the net book value of SJGS Units 2 and 3 at the date of retirement, for a CCN to include PNM’s share of PVNGS Unit 3 as a resource to serve New Mexico consumers, authority to install SNCRs on SJGS Units 1 and 4, and a CCN to exchange 78 MW in SJGS Unit 3 for the same amount of capacity in SJGS Unit 4. Based upon a non-binding agreement in principle among the SJGS owners, PNM made a filing on July 1, 2014 that advised the NMPRC that it proposes to acquire an additional 132 MW of SJGS Unit 4, at no initial cost, effective December 31, 2017, rather than the exchange of 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 contemplated in its initial application. The public hearing in the NMPRC case is now scheduled to begin on October 6, 2014. PNM is currently requesting the NMPRC take action on this case by the end of February 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters. | |
Four Corners Right of First Refusal | |
On June 16, 2014, PNM notified the NMPRC that it intended to provide a waiver of its right of first refusal (“ROFR”) to acquire some or all of the 7% interest in Four Corners held by EPE that is intended to be acquired by APS. On July 1, 2014, the staff of the NMPRC filed a petition asking for an inquiry by the NMPRC into whether it was in the public interest for PNM to waive its ROFR, because the cost of this capacity may be less than the cost of other resources that PNM has proposed or is considering as replacement capacity for the capacity that PNM has proposed to retire at SJGS (Note 11). The petition requested the NMPRC to initiate an inquiry, direct PNM not to waive its ROFR, and direct PNM to respond to the questions that staff attached to its petition. In its July 7, 2014 response to the staff’s petition, PNM stated that it will not file a waiver of its ROFR prior to the earlier of a NMPRC order disposing of the matter or the expiration of the 120 day period allowed for the exercise of the ROFR. The response explained that the capacity under discussion is still held by EPE, which has regulated operations in New Mexico, and EPE has not yet filed with the NMPRC for abandonment of that capacity. The response also explained that if the Four Corners capacity was no longer an economical resource for EPE to hold, then it likely would not be an economical resource for PNM to acquire, and it would increase PNM’s dependency on coal-fired generation. The NMPRC has not acted on the staff’s petition. | |
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. In a settlement of a prior transmission rate case, the parties agreed that no party would oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM’s proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula. | |
On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003 ; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates apply to all of PNM’s wholesale electric transmission service customers. The new rates do 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. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding. | |
City of Gallup, New Mexico Contract | |
PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On 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. | |
On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s 2013 revenues for power sold under the Gallup contract were $2.9 million and $6.1 million in the three and six months ended June 30, 2014 and totaled $11.7 million during 2013. | |
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 requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012. | |
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 were 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 sought recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48 and an additional $0.5 million in ongoing expenses via a proposed monthly charge of $38.99. On June 20, 2014, the PUCT approved a settlement among the parties permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing monthly expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP does not expect the settlement 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 that includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On August 28, 2012, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.2 million effective January 1, 2013. On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The parties have agreed on terms that would resolve TNMP’s application and are preparing settlement documents for submission to the PUCT. | |
Transmission Cost of Service Rates | |
TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. | |
On January 31, 2013, TNMP filed an application to update its transmission rates to reflect an increase in total rate base of $21.9 million, which would increase revenues $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 20, 2013. | |
On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $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. | |
On January 21, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $18.2 million, which would increase revenues by $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 13, 2014. | |
On July 18, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $25.2 million, which would increase revenues by $4.2 million annually. The request, which is subject to PUCT approval, asks that new rates become effective on September 1, 2014. |
Income_Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2014 | |
Income Tax Disclosure [Abstract] | ' |
Income Taxes | ' |
Income Taxes | |
On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation for 2013, 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 was 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 during the period that includes the date of enactment, which was in three months ended June 30, 2013. At that time, the portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. In addition, the portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the three months ended June 30, 2013. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2014, PNM’s regulatory liability was reduced by $4.6 million, which increased deferred tax liabilities. Additionally, deferred tax assets not related to PNM’s regulatory activities were reduced by $0.2 million, which increased income tax expense in the 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. | |
In 2013, the FASB issued Accounting Standards Update 2013-11, which requires entities to present liabilities for uncertain tax positions as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such carryforward could be used to offset those liabilities upon settlement. The update was required to be applied prospectively for periods beginning after December 15, 2013, and early adoption was permitted. The Company elected not to adopt the change for 2013, but did adopt it for 2014 as required by the update. Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating deferred tax assets of $19.9 million for PNMR, $11.2 million for PNM, and $6.8 million for TNMP, along with the elimination of the corresponding assets and liabilities associated with uncertain tax positions. There was no impact to earning from adopting the update. | |
In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008 resulting in years prior to 2009 being closed to examination by federal taxing authorities. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million, TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment. After the settlements, the liabilities related to uncertain tax positions for PNMR, PNM, and TNMP were $14.3 million, $11.5 million, and none. As discussed above, these liabilities are presented as reductions of deferred tax assets for net operating loss carryforwards in the Condensed Consolidated Balance Sheets at June 30, 2014. |
Related_Party_Transactions
Related Party Transactions | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||||
Related Party Transactions | ' | |||||||||||||||
Related Party Transactions | ||||||||||||||||
PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands) | ||||||||||||||||
Services billings: | ||||||||||||||||
PNMR to PNM | $ | 22,190 | $ | 20,837 | $ | 43,256 | $ | 43,489 | ||||||||
PNMR to TNMP | 6,963 | 6,856 | 14,224 | 14,217 | ||||||||||||
PNM to TNMP | 133 | 133 | 242 | 241 | ||||||||||||
TNMP to PNMR | — | 2 | — | 4 | ||||||||||||
Interest billings: | ||||||||||||||||
PNMR to TNMP | 83 | 119 | 180 | 215 | ||||||||||||
PNMR to PNM | — | — | 54 | 1 | ||||||||||||
PNM to PNMR | 25 | 37 | 51 | 78 | ||||||||||||
Income tax sharing payments: | ||||||||||||||||
PNMR to PNM | — | 45,000 | — | 45,000 | ||||||||||||
PNMR to TNMP | — | — | — | — | ||||||||||||
Goodwill
Goodwill | 6 Months Ended |
Jun. 30, 2014 | |
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 is not required. | |
In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. | |
An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2014 and 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, 2014 and 2013 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2014 and 2013 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 30% and 27%. The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 26%. Since the April 1, 2014 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 21 of Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K. |
Significant_Accounting_Policie1
Significant Accounting Policies and Responsibility for Financial Statements (Policies) | 6 Months Ended |
Jun. 30, 2014 | |
Accounting Policies [Abstract] | ' |
Principles of Consolidation | ' |
Principles of Consolidation | |
The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants. | |
PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 14. | |
Dividends Declared | ' |
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 $0.185 per share in July 2014 and $0.165 in July 2013, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. | |
TNMP declared and paid cash dividends of $6.8 million and $3.7 million in the six months ended June 30, 2014 and 2013. | |
New Accounting Pronouncements | ' |
New Accounting Pronouncements | |
Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. | |
Accounting Standards Update 2014-09 – Revenue from Contracts with Customers | |
On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. | |
Accounting Standards Update 2014-12 – Compensation-Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period | |
On June 19, 2014, the FASB issued ASU No. 2014-12, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The new standard is effective for the Company beginning on January 1, 2016. Early adoption is permitted and the standard permits the use of either the prospective or retrospective transition methods. Although the Company is in the process of analyzing the impacts this new standard will have on its consolidated financial statements, the Company currently treats the performance targets covered by the standard as performance conditions, so the Company does not expect its impact will be significant. | |
Consolidation, Variable Interest Entity | ' |
GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. |
Earnings_Per_Share_Tables
Earnings Per Share (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | ' | |||||||||||||||
Information regarding the computation of earnings per share is as follows: | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Net Earnings Attributable to PNMR | $ | 29,141 | $ | 27,678 | $ | 41,609 | $ | 38,304 | ||||||||
Average Number of Common Shares: | ||||||||||||||||
Outstanding during period | 79,654 | 79,654 | 79,654 | 79,654 | ||||||||||||
Vested awards of restricted stock | 110 | 194 | 146 | 202 | ||||||||||||
Average Shares – Basic | 79,764 | 79,848 | 79,800 | 79,856 | ||||||||||||
Dilutive Effect of Common Stock Equivalents (1): | ||||||||||||||||
Stock options and restricted stock | 464 | 607 | 508 | 661 | ||||||||||||
Average Shares – Diluted | 80,228 | 80,455 | 80,308 | 80,517 | ||||||||||||
Net Earnings Per Share of Common Stock: | ||||||||||||||||
Basic | $ | 0.37 | $ | 0.35 | $ | 0.52 | $ | 0.48 | ||||||||
Diluted | $ | 0.36 | $ | 0.34 | $ | 0.52 | $ | 0.48 | ||||||||
(1) | Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014. |
Segment_Information_Tables
Segment Information (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||||||
Schedule of Segment Reporting Information, by Segment | ' | |||||||||||||||
The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. | ||||||||||||||||
PNMR SEGMENT INFORMATION | ||||||||||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
(In thousands) | ||||||||||||||||
Three Months Ended June 30, 2014 | ||||||||||||||||
Electric operating revenues | $ | 275,704 | $ | 70,456 | $ | — | $ | 346,160 | ||||||||
Cost of energy | 92,642 | 16,777 | — | 109,419 | ||||||||||||
Margin | 183,062 | 53,679 | — | 236,741 | ||||||||||||
Other operating expenses | 106,233 | 20,411 | (3,362 | ) | 123,282 | |||||||||||
Depreciation and amortization | 27,023 | 12,003 | 3,137 | 42,163 | ||||||||||||
Operating income | 49,806 | 21,265 | 225 | 71,296 | ||||||||||||
Interest income | 2,065 | — | (25 | ) | 2,040 | |||||||||||
Other income (deductions) | 5,512 | 514 | (316 | ) | 5,710 | |||||||||||
Net interest charges | (20,023 | ) | (6,655 | ) | (3,294 | ) | (29,972 | ) | ||||||||
Segment earnings (loss) before income taxes | 37,360 | 15,124 | (3,410 | ) | 49,074 | |||||||||||
Income taxes (benefit) | 13,106 | 5,590 | (2,803 | ) | 15,893 | |||||||||||
Segment earnings (loss) | 24,254 | 9,534 | (607 | ) | 33,181 | |||||||||||
Valencia non-controlling interest | (3,908 | ) | — | — | (3,908 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 20,214 | $ | 9,534 | $ | (607 | ) | $ | 29,141 | |||||||
Six Months Ended June 30, 2014 | ||||||||||||||||
Electric operating revenues | $ | 538,441 | $ | 136,616 | $ | — | $ | 675,057 | ||||||||
Cost of energy | 189,268 | 32,765 | — | 222,033 | ||||||||||||
Margin | 349,173 | 103,851 | — | 453,024 | ||||||||||||
Other operating expenses | 213,957 | 41,481 | (6,593 | ) | 248,845 | |||||||||||
Depreciation and amortization | 54,105 | 23,844 | 6,181 | 84,130 | ||||||||||||
Operating income | 81,111 | 38,526 | 412 | 120,049 | ||||||||||||
Interest income | 4,193 | — | (35 | ) | 4,158 | |||||||||||
Other income (deductions) | 7,180 | 702 | (958 | ) | 6,924 | |||||||||||
Net interest charges | (39,835 | ) | (13,252 | ) | (6,419 | ) | (59,506 | ) | ||||||||
Segment earnings (loss) before income taxes | 52,649 | 25,976 | (7,000 | ) | 71,625 | |||||||||||
Income taxes (benefit) | 17,189 | 9,640 | (4,516 | ) | 22,313 | |||||||||||
Segment earnings (loss) | 35,460 | 16,336 | (2,484 | ) | 49,312 | |||||||||||
Valencia non-controlling interest | (7,439 | ) | — | — | (7,439 | ) | ||||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 27,757 | $ | 16,336 | $ | (2,484 | ) | $ | 41,609 | |||||||
At June 30, 2014: | ||||||||||||||||
Total Assets | $ | 4,290,529 | $ | 1,208,517 | $ | 105,146 | $ | 5,604,192 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
PNM | TNMP | Corporate | Consolidated | |||||||||||||
and Other | ||||||||||||||||
(In thousands) | ||||||||||||||||
Three Months Ended June 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 279,690 | $ | 67,909 | $ | — | $ | 347,599 | ||||||||
Cost of energy | 91,855 | 13,804 | — | 105,659 | ||||||||||||
Margin | 187,835 | 54,105 | — | 241,940 | ||||||||||||
Other operating expenses | 103,482 | 22,159 | (3,207 | ) | 122,434 | |||||||||||
Depreciation and amortization | 26,051 | 12,279 | 3,309 | 41,639 | ||||||||||||
Operating income (loss) | 58,302 | 19,667 | (102 | ) | 77,867 | |||||||||||
Interest income | 2,868 | — | (35 | ) | 2,833 | |||||||||||
Other income (deductions) | 3,360 | 486 | (2,213 | ) | 1,633 | |||||||||||
Net interest charges | (19,890 | ) | (6,759 | ) | (3,967 | ) | (30,616 | ) | ||||||||
Segment earnings (loss) before income taxes | 44,640 | 13,394 | (6,317 | ) | 51,717 | |||||||||||
Income taxes (benefit) | 14,943 | 5,055 | 336 | 20,334 | ||||||||||||
Segment earnings (loss) | 29,697 | 8,339 | (6,653 | ) | 31,383 | |||||||||||
Valencia non-controlling interest | (3,573 | ) | — | — | (3,573 | ) | ||||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 25,992 | $ | 8,339 | $ | (6,653 | ) | $ | 27,678 | |||||||
Six Months Ended June 30, 2013 | ||||||||||||||||
Electric operating revenues | $ | 537,583 | $ | 127,680 | $ | — | $ | 665,263 | ||||||||
Cost of energy | 183,514 | 26,851 | — | 210,365 | ||||||||||||
Margin | 354,069 | 100,829 | — | 454,898 | ||||||||||||
Other operating expenses | 206,643 | 44,148 | (6,910 | ) | 243,881 | |||||||||||
Depreciation and amortization | 51,884 | 23,960 | 6,602 | 82,446 | ||||||||||||
Operating income | 95,542 | 32,721 | 308 | 128,571 | ||||||||||||
Interest income | 5,541 | — | (74 | ) | 5,467 | |||||||||||
Other income (deductions) | 4,766 | 694 | (3,936 | ) | 1,524 | |||||||||||
Net interest charges | (39,847 | ) | (14,005 | ) | (8,062 | ) | (61,914 | ) | ||||||||
Segment earnings (loss) before income taxes | 66,002 | 19,410 | (11,764 | ) | 73,648 | |||||||||||
Income taxes (benefit) | 21,532 | 7,345 | (574 | ) | 28,303 | |||||||||||
Segment earnings (loss) | 44,470 | 12,065 | (11,190 | ) | 45,345 | |||||||||||
Valencia non-controlling interest | (6,777 | ) | — | — | (6,777 | ) | ||||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | ||||||||||
Segment earnings (loss) attributable to PNMR | $ | 37,429 | $ | 12,065 | $ | (11,190 | ) | $ | 38,304 | |||||||
At June 30, 2013: | ||||||||||||||||
Total Assets | $ | 4,185,189 | $ | 1,155,928 | $ | 62,789 | $ | 5,403,906 | ||||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | ||||||||
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Loss) (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Equity [Abstract] | ' | |||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) | ' | |||||||||||||||
Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2014 and 2013 is as follows: | ||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Available-for- | Liability | for Cash Flow | ||||||||||||||
Sale Securities | Adjustment | Hedges | Total | |||||||||||||
(In thousands) | ||||||||||||||||
PNMR | ||||||||||||||||
Balance at December 31, 2013 | $ | 25,748 | $ | (83,625 | ) | $ | (263 | ) | $ | (58,140 | ) | |||||
Amounts reclassified from AOCI (pre-tax) | (8,857 | ) | 2,576 | 176 | (6,105 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,488 | (1,016 | ) | (61 | ) | 2,411 | ||||||||||
Other OCI changes (pre-tax) | 9,855 | — | (153 | ) | 9,702 | |||||||||||
Income tax impact of other OCI changes | (3,809 | ) | — | 53 | (3,756 | ) | ||||||||||
Net change after income taxes | 677 | 1,560 | 15 | 2,252 | ||||||||||||
Balance at June 30, 2014 | $ | 26,425 | $ | (82,065 | ) | $ | (248 | ) | $ | (55,888 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2013 | $ | 25,748 | $ | (83,625 | ) | $ | — | $ | (57,877 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | (8,857 | ) | 2,576 | — | (6,281 | ) | ||||||||||
Income tax impact of amounts reclassified | 3,488 | (1,016 | ) | — | 2,472 | |||||||||||
Other OCI changes (pre-tax) | 9,855 | — | — | 9,855 | ||||||||||||
Income tax impact of other OCI changes | (3,809 | ) | — | — | (3,809 | ) | ||||||||||
Net change after income taxes | 677 | 1,560 | — | 2,237 | ||||||||||||
Balance at June 30, 2014 | $ | 26,425 | $ | (82,065 | ) | $ | — | $ | (55,640 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2013 | $ | — | $ | — | $ | (263 | ) | $ | (263 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | — | — | 176 | 176 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (61 | ) | (61 | ) | ||||||||||
Other OCI changes (pre-tax) | — | — | (153 | ) | (153 | ) | ||||||||||
Income tax impact of other OCI changes | — | — | 53 | 53 | ||||||||||||
Net change after income taxes | — | — | 15 | 15 | ||||||||||||
Balance at June 30, 2014 | $ | — | $ | — | $ | (248 | ) | $ | (248 | ) | ||||||
Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||
Unrealized | Fair Value | |||||||||||||||
Gain on | Pension | Adjustment | ||||||||||||||
Available-for- | Liability | for Cash Flow | ||||||||||||||
Sale 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) | (6,854 | ) | 3,182 | 99 | (3,573 | ) | ||||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | (35 | ) | 1,417 | ||||||||||
Other OCI changes (pre-tax) | 8,591 | — | 3 | 8,594 | ||||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | (1 | ) | (3,402 | ) | |||||||||
Net change after income taxes | 1,050 | 1,920 | 66 | 3,036 | ||||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | (150 | ) | $ | (78,594 | ) | |||||
PNM | ||||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | — | $ | (81,414 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | (6,854 | ) | 3,182 | — | (3,672 | ) | ||||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | — | 1,452 | |||||||||||
Other OCI changes (pre-tax) | 8,591 | — | — | 8,591 | ||||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | — | (3,401 | ) | ||||||||||
Net change after income taxes | 1,050 | 1,920 | — | 2,970 | ||||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | — | $ | (78,444 | ) | ||||||
TNMP | ||||||||||||||||
Balance at December 31, 2012 | $ | — | $ | — | $ | (216 | ) | $ | (216 | ) | ||||||
Amounts reclassified from AOCI (pre-tax) | — | — | 99 | 99 | ||||||||||||
Income tax impact of amounts reclassified | — | — | (35 | ) | (35 | ) | ||||||||||
Other OCI changes (pre-tax) | — | — | 3 | 3 | ||||||||||||
Income tax impact of other OCI changes | — | — | (1 | ) | (1 | ) | ||||||||||
Net change after income taxes | — | — | 66 | 66 | ||||||||||||
Balance at June 30, 2013 | $ | — | $ | — | $ | (150 | ) | $ | (150 | ) | ||||||
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) (Public Service Company of New Mexico [Member]) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
Public Service Company of New Mexico [Member] | ' | |||||||||||||||
Variable Interest Entity [Line Items] | ' | |||||||||||||||
Noncontrolling Interest Summarized Financial Information | ' | |||||||||||||||
Summarized financial information for Valencia is as follows: | ||||||||||||||||
Results of Operations | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands) | ||||||||||||||||
Operating revenues | $ | 5,307 | $ | 4,922 | $ | 10,238 | $ | 9,697 | ||||||||
Operating expenses | (1,399 | ) | (1,349 | ) | (2,799 | ) | (2,920 | ) | ||||||||
Earnings attributable to non-controlling interest | $ | 3,908 | $ | 3,573 | $ | 7,439 | $ | 6,777 | ||||||||
Financial Position | ||||||||||||||||
June 30, | December 31, | |||||||||||||||
2014 | 2013 | |||||||||||||||
(In thousands) | ||||||||||||||||
Current assets | $ | 3,232 | $ | 2,658 | ||||||||||||
Net property, plant, and equipment | 73,729 | 75,137 | ||||||||||||||
Total assets | 76,961 | 77,795 | ||||||||||||||
Current liabilities | 682 | 766 | ||||||||||||||
Owners’ equity – non-controlling interest | $ | 76,279 | $ | 77,029 | ||||||||||||
Fair_Value_of_Derivative_and_O1
Fair Value of Derivative and Other Financial Instruments (Tables) | 6 Months Ended | |||||||||||||||||||
Jun. 30, 2014 | ||||||||||||||||||||
Fair Value of Derivative and Other Financial Instruments [Line Items] | ' | |||||||||||||||||||
Fair Value, by Balance Sheet Grouping | ' | |||||||||||||||||||
The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below: | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | ||||||||||||||||
June 30, 2014 | (In thousands) | |||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,875,254 | $ | 2,088,787 | $ | — | $ | 2,088,787 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 42,234 | $ | 45,067 | $ | — | $ | — | $ | 45,067 | ||||||||||
Other investments | $ | 1,798 | $ | 2,525 | $ | 677 | $ | — | $ | 1,848 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,390,637 | $ | 1,530,418 | $ | — | $ | 1,530,418 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 42,234 | $ | 45,067 | $ | — | $ | — | $ | 45,067 | ||||||||||
Other investments | $ | 432 | $ | 432 | $ | 432 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 365,851 | $ | 431,706 | $ | — | $ | 431,706 | $ | — | ||||||||||
Other investments | $ | 245 | $ | 245 | $ | 245 | $ | — | $ | — | ||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR | ||||||||||||||||||||
Long-term debt | $ | 1,745,420 | $ | 1,905,230 | $ | — | $ | 1,905,230 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 52,958 | $ | 57,279 | $ | — | $ | — | $ | 57,279 | ||||||||||
Other investments | $ | 1,835 | $ | 3,196 | $ | 690 | $ | — | $ | 2,506 | ||||||||||
PNM | ||||||||||||||||||||
Long-term debt | $ | 1,290,618 | $ | 1,382,938 | $ | — | $ | 1,382,938 | $ | — | ||||||||||
Investment in PVNGS lessor notes | $ | 52,958 | $ | 57,279 | $ | — | $ | — | $ | 57,279 | ||||||||||
Other investments | $ | 445 | $ | 445 | $ | 445 | $ | — | $ | — | ||||||||||
TNMP | ||||||||||||||||||||
Long-term debt | $ | 336,036 | $ | 390,814 | $ | — | $ | 390,814 | $ | — | ||||||||||
Other investments | $ | 245 | $ | 245 | $ | 245 | $ | — | $ | — | ||||||||||
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 | ' | |||||||||||||||||||
Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows: | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
June 30, | December 31, | |||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Current assets | $ | 4,082 | $ | 4,064 | ||||||||||||||||
Deferred charges | 1,515 | 3,002 | ||||||||||||||||||
5,597 | 7,066 | |||||||||||||||||||
Current liabilities | (5,073 | ) | (2,699 | ) | ||||||||||||||||
Long-term liabilities | (915 | ) | (1,094 | ) | ||||||||||||||||
(5,988 | ) | (3,793 | ) | |||||||||||||||||
Net | $ | (391 | ) | $ | 3,273 | |||||||||||||||
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | ' | |||||||||||||||||||
The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented. | ||||||||||||||||||||
Economic Hedges | ||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Electric operating revenues | $ | (324 | ) | $ | 3,269 | $ | (4,475 | ) | $ | (1,334 | ) | |||||||||
Cost of energy | 57 | (263 | ) | 245 | 493 | |||||||||||||||
Total gain (loss) | $ | (267 | ) | $ | 3,006 | $ | (4,230 | ) | $ | (841 | ) | |||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | ' | |||||||||||||||||||
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 | |||||||||||||||||||
June 30, 2014 | ||||||||||||||||||||
PNMR and PNM | 1,165,000 | (2,809,507 | ) | |||||||||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR and PNM | 905,000 | (3,343,783 | ) | |||||||||||||||||
Schedule of Collateral Related to Derivative | ' | |||||||||||||||||||
Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions. | ||||||||||||||||||||
Contingent Feature – | Contractual Liability | Existing Cash Collateral | Net Exposure | |||||||||||||||||
Credit Rating Downgrade | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
June 30, 2014 | ||||||||||||||||||||
PNMR and PNM | $ | 2,740 | $ | — | $ | 1,663 | ||||||||||||||
December 31, 2013 | ||||||||||||||||||||
PNMR and PNM | $ | 2,398 | $ | — | $ | 2,152 | ||||||||||||||
Available-for-sale Securities | ' | |||||||||||||||||||
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 and reflect impairments. | ||||||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||||
June 30, | June 30, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Proceeds from sales | $ | 30,316 | $ | 61,821 | $ | 53,119 | $ | 76,106 | ||||||||||||
Gross realized gains | $ | 5,364 | $ | 4,905 | $ | 8,482 | $ | 6,243 | ||||||||||||
Gross realized (losses) | $ | (665 | ) | $ | (1,688 | ) | $ | (1,210 | ) | $ | (1,496 | ) | ||||||||
The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table. At June 30, 2014 and December 31, 2013, the fair value of available-for-sale securities included $231.9 million and $222.5 million for the NDT and $4.5 million and $4.4 million for the mine reclamation trust. | ||||||||||||||||||||
June 30, 2014 | December 31, 2013 | |||||||||||||||||||
Unrealized Gains | Fair Value | Unrealized Gains | Fair Value | |||||||||||||||||
PNMR and PNM | (In thousands) | |||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 3,114 | $ | — | $ | 3,356 | ||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 16,014 | 42,664 | 14,523 | 39,460 | ||||||||||||||||
Domestic growth | 19,931 | 75,621 | 25,656 | 76,292 | ||||||||||||||||
International and other | 2,227 | 17,848 | 1,040 | 16,633 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 534 | 19,814 | 158 | 21,941 | ||||||||||||||||
Municipals | 4,282 | 65,872 | 1,018 | 58,568 | ||||||||||||||||
Corporate and other | 625 | 11,494 | 207 | 10,605 | ||||||||||||||||
$ | 43,613 | $ | 236,427 | $ | 42,602 | $ | 226,855 | |||||||||||||
Investments Classified by Contractual Maturity Date | ' | |||||||||||||||||||
At June 30, 2014, 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 | $ | 2,911 | $ | 12,017 | $ | 12,017 | ||||||||||||||
After 1 year through 5 years | 21,556 | 33,776 | 33,050 | |||||||||||||||||
After 5 years through 10 years | 10,875 | — | — | |||||||||||||||||
After 10 years through 15 years | 9,114 | — | — | |||||||||||||||||
After 15 years through 20 years | 11,431 | — | — | |||||||||||||||||
After 20 years | 41,293 | — | — | |||||||||||||||||
$ | 97,180 | $ | 45,793 | $ | 45,067 | |||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis | ' | |||||||||||||||||||
Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at June 30, 2014 and December 31, 2013 for items recorded at fair value. | ||||||||||||||||||||
GAAP Fair Value Hierarchy | ||||||||||||||||||||
Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | ||||||||||||||||||
June 30, 2014 | (In thousands) | |||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Available-for-sale securities | ||||||||||||||||||||
Cash and cash equivalents | $ | 3,114 | $ | 3,114 | $ | — | ||||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 42,664 | 42,664 | — | |||||||||||||||||
Domestic growth | 75,621 | 75,621 | — | |||||||||||||||||
International and other | 17,848 | 17,848 | — | |||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 19,814 | 18,053 | 1,761 | |||||||||||||||||
Municipals | 65,872 | — | 65,872 | |||||||||||||||||
Corporate and other | 11,494 | 2,481 | 9,013 | |||||||||||||||||
$ | 236,427 | $ | 159,781 | $ | 76,646 | |||||||||||||||
Commodity derivative assets | $ | 5,597 | $ | — | $ | 5,597 | ||||||||||||||
Commodity derivative liabilities | (5,988 | ) | — | (5,988 | ) | |||||||||||||||
Net | $ | (391 | ) | $ | — | $ | (391 | ) | ||||||||||||
31-Dec-13 | ||||||||||||||||||||
PNMR and PNM | ||||||||||||||||||||
Available-for-sale securities | ||||||||||||||||||||
Cash and cash equivalents | $ | 3,356 | $ | 3,356 | $ | — | ||||||||||||||
Equity securities: | ||||||||||||||||||||
Domestic value | 39,460 | 39,460 | — | |||||||||||||||||
Domestic growth | 76,292 | 76,292 | — | |||||||||||||||||
International and other | 16,633 | 16,633 | — | |||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
U.S. Government | 21,941 | 20,194 | 1,747 | |||||||||||||||||
Municipals | 58,568 | — | 58,568 | |||||||||||||||||
Corporate and other | 10,605 | 2,245 | 8,360 | |||||||||||||||||
$ | 226,855 | $ | 158,180 | $ | 68,675 | |||||||||||||||
Commodity derivative assets | $ | 7,066 | $ | — | $ | 7,066 | ||||||||||||||
Commodity derivative liabilities | (3,793 | ) | — | (3,793 | ) | |||||||||||||||
Net | $ | 3,273 | $ | — | $ | 3,273 | ||||||||||||||
StockBased_Compensation_Tables
Stock-Based Compensation (Tables) | 6 Months Ended | |||||||||||||
Jun. 30, 2014 | ||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | |||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | ' | |||||||||||||
The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: | ||||||||||||||
Six Months Ended June 30, | ||||||||||||||
Restricted Shares and Performance Based Shares | 2014 | 2013 | ||||||||||||
Expected quarterly dividends per share | $ | 0.185 | $ | 0.165 | ||||||||||
Risk-free interest rate | 0.62 | % | 0.34 | % | ||||||||||
Market-Based Shares | ||||||||||||||
Dividend yield | 2.82 | % | 2.86 | % | ||||||||||
Expected volatility | 25.11 | % | 25.11 | % | ||||||||||
Risk-free interest rate | 0.64 | % | 0.36 | % | ||||||||||
The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the six months ended June 30, 2014: | ||||||||||||||
Stock Option Shares | Weighted- | Restricted Stock | Weighted- | |||||||||||
Average | Average | |||||||||||||
Exercise | Grant Date Fair Value | |||||||||||||
Price | ||||||||||||||
Outstanding at beginning of period | 1,343,666 | $ | 20.63 | 315,305 | $ | 17.87 | ||||||||
Granted | — | $ | — | 242,164 | $ | 21.27 | ||||||||
Exercised | (236,260 | ) | $ | 18.9 | (292,052 | ) | $ | 16.64 | ||||||
Forfeited | (17,151 | ) | $ | 26.43 | — | $ | — | |||||||
Expired | (22,784 | ) | $ | 25.91 | — | $ | — | |||||||
Outstanding at end of period | 1,067,471 | $ | 20.8 | 265,417 | $ | 22.31 | ||||||||
The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares: | ||||||||||||||
Six Months Ended June 30, | ||||||||||||||
Stock Options | 2014 | 2013 | ||||||||||||
Weighted-average grant date fair value of options granted | $ | — | $ | — | ||||||||||
Total fair value of options that vested (in thousands) | $ | — | $ | 625 | ||||||||||
Total intrinsic value of options exercised (in thousands) | $ | 1,779 | $ | 2,189 | ||||||||||
Restricted Stock | ||||||||||||||
Weighted-average grant date fair value | $ | 21.27 | $ | 20.03 | ||||||||||
Total fair value of restricted shares that vested (in thousands) | $ | 4,854 | $ | 4,383 | ||||||||||
Financing_Tables
Financing (Tables) | 6 Months Ended | ||||||||
Jun. 30, 2014 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Schedule of Short-term Debt [Table Text Block] | ' | ||||||||
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. 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 and matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At June 30, 2014, the weighted average interest rate was 1.66% for borrowings under the PNMR Revolving Credit Facility and 1.00% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2014. Short-term debt outstanding consisted of: | |||||||||
June 30, | December 31, | ||||||||
Short-term Debt | 2014 | 2013 | |||||||
(In thousands) | |||||||||
PNM: | |||||||||
Revolving credit facility | $ | — | $ | 49,200 | |||||
PNM New Mexico Credit Facility | — | — | |||||||
TNMP – Revolving credit facility | — | — | |||||||
PNMR: | |||||||||
Revolving credit facility | 5,000 | — | |||||||
PNMR Term Loan Agreement | 100,000 | 100,000 | |||||||
$ | 105,000 | $ | 149,200 | ||||||
At July 25, 2014, PNMR, PNM, and TNMP had $292.3 million, $369.6 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at July 25, 2014, on a consolidated basis, was $771.8 million for PNMR. As of July 25, 2014, PNM had $5.5 million in borrowings from PNMR and TNMP had $25.7 million in borrowings from PNMR under their intercompany loan agreements. At July 25, 2014, PNMR, PNM and TNMP had consolidated invested cash of $1.9 million, none, and none. |
Pension_and_Other_Postretireme1
Pension and Other Postretirement Benefit Plans (Tables) | 6 Months Ended | |||||||||||||||||||||||
Jun. 30, 2014 | ||||||||||||||||||||||||
Public Service Company of New Mexico [Member] | ' | |||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ' | |||||||||||||||||||||||
Schedule of Net Benefit Costs | ' | |||||||||||||||||||||||
The following tables present the components of the PNM Plans’ net periodic benefit cost: | ||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 45 | $ | 65 | $ | — | $ | — | ||||||||||||
Interest cost | 7,541 | 7,035 | 1,159 | 1,029 | 205 | 180 | ||||||||||||||||||
Expected return on plan assets | (9,511 | ) | (10,482 | ) | (1,410 | ) | (1,261 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 3,255 | 3,710 | 556 | 1,061 | 52 | 58 | ||||||||||||||||||
Amortization of prior service cost | (241 | ) | 19 | (336 | ) | (336 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 1,044 | $ | 282 | $ | 14 | $ | 558 | $ | 257 | $ | 238 | ||||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 91 | $ | 130 | $ | — | $ | — | ||||||||||||
Interest cost | 15,082 | 14,071 | 2,315 | 2,057 | 411 | 360 | ||||||||||||||||||
Expected return on plan assets | (19,022 | ) | (20,965 | ) | (2,819 | ) | (2,522 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 6,510 | 7,420 | 1,113 | 2,121 | 105 | 116 | ||||||||||||||||||
Amortization of prior service cost | (483 | ) | 38 | (672 | ) | (672 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 2,087 | $ | 564 | $ | 28 | $ | 1,114 | $ | 516 | $ | 476 | ||||||||||||
Texas-New Mexico Power Company [Member] | ' | |||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ' | |||||||||||||||||||||||
Schedule of Net Benefit Costs | ' | |||||||||||||||||||||||
The following tables present the components of the TNMP Plans’ net periodic benefit cost (income): | ||||||||||||||||||||||||
Three Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 59 | $ | 75 | $ | — | $ | — | ||||||||||||
Interest cost | 798 | 772 | 155 | 141 | 10 | 9 | ||||||||||||||||||
Expected return on plan assets | (1,132 | ) | (1,212 | ) | (133 | ) | (126 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 166 | 262 | (31 | ) | — | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 8 | 14 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (168 | ) | $ | (178 | ) | $ | 58 | $ | 104 | $ | 10 | $ | 9 | ||||||||||
Six Months Ended June 30, | ||||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Components of Net Periodic | ||||||||||||||||||||||||
Benefit Cost (Income) | ||||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 119 | $ | 150 | $ | — | $ | — | ||||||||||||
Interest cost | 1,597 | 1,544 | 309 | 283 | 20 | 18 | ||||||||||||||||||
Expected return on plan assets | (2,263 | ) | (2,425 | ) | (267 | ) | (252 | ) | — | — | ||||||||||||||
Amortization of net (gain) loss | 333 | 524 | (61 | ) | — | — | — | |||||||||||||||||
Amortization of prior service cost | — | — | 16 | 28 | — | — | ||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (333 | ) | $ | (357 | ) | $ | 116 | $ | 209 | $ | 20 | $ | 18 | ||||||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 6 Months Ended | |||||||||||||||
Jun. 30, 2014 | ||||||||||||||||
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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands) | ||||||||||||||||
Services billings: | ||||||||||||||||
PNMR to PNM | $ | 22,190 | $ | 20,837 | $ | 43,256 | $ | 43,489 | ||||||||
PNMR to TNMP | 6,963 | 6,856 | 14,224 | 14,217 | ||||||||||||
PNM to TNMP | 133 | 133 | 242 | 241 | ||||||||||||
TNMP to PNMR | — | 2 | — | 4 | ||||||||||||
Interest billings: | ||||||||||||||||
PNMR to TNMP | 83 | 119 | 180 | 215 | ||||||||||||
PNMR to PNM | — | — | 54 | 1 | ||||||||||||
PNM to PNMR | 25 | 37 | 51 | 78 | ||||||||||||
Income tax sharing payments: | ||||||||||||||||
PNMR to PNM | — | 45,000 | — | 45,000 | ||||||||||||
PNMR to TNMP | — | — | — | — | ||||||||||||
Significant_Accounting_Policie2
Significant Accounting Policies and Responsibility for Financial Statements Significant Accounting Policies and Responsibility for Financial Statements (Details) (USD $) | 1 Months Ended | 3 Months Ended | 6 Months Ended | 1 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Jul. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jul. 31, 2014 |
Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | ||||||
Dividends on Common Stock [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock, Dividends, Per Share, Declared | $0.17 | $0.19 | $0.17 | $0.37 | $0.33 | ' | ' | $0.19 |
Dividends, Common Stock, Cash | ' | ' | ' | $14,736 | ' | $6,803 | $3,700 | ' |
Earnings_Per_Share_Details
Earnings Per Share (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||||||
In Thousands, except Share data, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | ||||
Earnings Per Share [Abstract] | ' | ' | ' | ' | ||||
Net Earnings Attributable to PNMR | $29,141 | $27,678 | $41,609 | $38,304 | ||||
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 | 110,000 | 194,000 | 146,000 | 202,000 | ||||
Average Shares – Basic | 79,764,000 | 79,848,000 | 79,800,000 | 79,856,000 | ||||
Dilutive Effect of Common Stock Equivalents: | ' | ' | ' | ' | ||||
Stock options and restricted stock | 464,000 | [1] | 607,000 | [1] | 508,000 | [1] | 661,000 | [1] |
Average Shares – Diluted | 80,228,000 | 80,455,000 | 80,308,000 | 80,517,000 | ||||
Net Earnings Per Share of Common Stock: | ' | ' | ' | ' | ||||
Basic (dollars per share) | $0.37 | $0.35 | $0.52 | $0.48 | ||||
Diluted (dollars per share) | $0.36 | $0.34 | $0.52 | $0.48 | ||||
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares) | ' | ' | 297,350 | ' | ||||
[1] | Excludes the effect of out-of-the-money options for 297,350 shares of common stock at June 30, 2014. |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 6 Months Ended | |||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | $346,160 | $347,599 | $675,057 | $665,263 | ' |
Cost of energy | 109,419 | 105,659 | 222,033 | 210,365 | ' |
Margin | 236,741 | 241,940 | 453,024 | 454,898 | ' |
Other operating expenses | 123,282 | 122,434 | 248,845 | 243,881 | ' |
Depreciation and amortization | 42,163 | 41,639 | 84,130 | 82,446 | ' |
Operating income | 71,296 | 77,867 | 120,049 | 128,571 | ' |
Interest income | 2,040 | 2,833 | 4,158 | 5,467 | ' |
Other income (deductions) | 5,710 | 1,633 | 6,924 | 1,524 | ' |
Net interest charges | -29,972 | -30,616 | -59,506 | -61,914 | ' |
Earnings before Income Taxes | 49,074 | 51,717 | 71,625 | 73,648 | ' |
Income taxes (benefit) | 15,893 | 20,334 | 22,313 | 28,303 | ' |
Segment earnings (loss) | 33,181 | 31,383 | 49,312 | 45,345 | ' |
Valencia non-controlling interest | -3,908 | -3,573 | -7,439 | -6,777 | ' |
Subsidiary preferred stock dividends | -132 | -132 | -264 | -264 | ' |
Segment earnings (loss) attributable to PNMR | 29,141 | 27,678 | 41,609 | 38,304 | ' |
Total Assets | 5,604,192 | 5,403,906 | 5,604,192 | 5,403,906 | 5,500,210 |
Goodwill | 278,297 | 278,297 | 278,297 | 278,297 | 278,297 |
PNM Electric [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 275,704 | 279,690 | 538,441 | 537,583 | ' |
Cost of energy | 92,642 | 91,855 | 189,268 | 183,514 | ' |
Margin | 183,062 | 187,835 | 349,173 | 354,069 | ' |
Other operating expenses | 106,233 | 103,482 | 213,957 | 206,643 | ' |
Depreciation and amortization | 27,023 | 26,051 | 54,105 | 51,884 | ' |
Operating income | 49,806 | 58,302 | 81,111 | 95,542 | ' |
Interest income | 2,065 | 2,868 | 4,193 | 5,541 | ' |
Other income (deductions) | 5,512 | 3,360 | 7,180 | 4,766 | ' |
Net interest charges | -20,023 | -19,890 | -39,835 | -39,847 | ' |
Earnings before Income Taxes | 37,360 | 44,640 | 52,649 | 66,002 | ' |
Income taxes (benefit) | 13,106 | 14,943 | 17,189 | 21,532 | ' |
Segment earnings (loss) | 24,254 | 29,697 | 35,460 | 44,470 | ' |
Valencia non-controlling interest | -3,908 | -3,573 | -7,439 | -6,777 | ' |
Subsidiary preferred stock dividends | -132 | -132 | -264 | -264 | ' |
Segment earnings (loss) attributable to PNMR | 20,214 | 25,992 | 27,757 | 37,429 | ' |
Total Assets | 4,290,529 | 4,185,189 | 4,290,529 | 4,185,189 | ' |
Goodwill | 51,632 | 51,632 | 51,632 | 51,632 | ' |
TNMP Electric [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 70,456 | 67,909 | 136,616 | 127,680 | ' |
Cost of energy | 16,777 | 13,804 | 32,765 | 26,851 | ' |
Margin | 53,679 | 54,105 | 103,851 | 100,829 | ' |
Other operating expenses | 20,411 | 22,159 | 41,481 | 44,148 | ' |
Depreciation and amortization | 12,003 | 12,279 | 23,844 | 23,960 | ' |
Operating income | 21,265 | 19,667 | 38,526 | 32,721 | ' |
Interest income | 0 | 0 | 0 | 0 | ' |
Other income (deductions) | 514 | 486 | 702 | 694 | ' |
Net interest charges | -6,655 | -6,759 | -13,252 | -14,005 | ' |
Earnings before Income Taxes | 15,124 | 13,394 | 25,976 | 19,410 | ' |
Income taxes (benefit) | 5,590 | 5,055 | 9,640 | 7,345 | ' |
Segment earnings (loss) | 9,534 | 8,339 | 16,336 | 12,065 | ' |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | ' |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | ' |
Segment earnings (loss) attributable to PNMR | 9,534 | 8,339 | 16,336 | 12,065 | ' |
Total Assets | 1,208,517 | 1,155,928 | 1,208,517 | 1,155,928 | ' |
Goodwill | 226,665 | 226,665 | 226,665 | 226,665 | ' |
Corporate and Other [Member] | ' | ' | ' | ' | ' |
Segment Reporting Information, Profit (Loss) [Abstract] | ' | ' | ' | ' | ' |
Electric operating revenues | 0 | 0 | 0 | 0 | ' |
Cost of energy | 0 | 0 | 0 | 0 | ' |
Margin | 0 | 0 | 0 | 0 | ' |
Other operating expenses | -3,362 | -3,207 | -6,593 | -6,910 | ' |
Depreciation and amortization | 3,137 | 3,309 | 6,181 | 6,602 | ' |
Operating income | 225 | -102 | 412 | 308 | ' |
Interest income | -25 | -35 | -35 | -74 | ' |
Other income (deductions) | -316 | -2,213 | -958 | -3,936 | ' |
Net interest charges | -3,294 | -3,967 | -6,419 | -8,062 | ' |
Earnings before Income Taxes | -3,410 | -6,317 | -7,000 | -11,764 | ' |
Income taxes (benefit) | -2,803 | 336 | -4,516 | -574 | ' |
Segment earnings (loss) | -607 | -6,653 | -2,484 | -11,190 | ' |
Valencia non-controlling interest | 0 | 0 | 0 | 0 | ' |
Subsidiary preferred stock dividends | 0 | 0 | 0 | 0 | ' |
Segment earnings (loss) attributable to PNMR | -607 | -6,653 | -2,484 | -11,190 | ' |
Total Assets | 105,146 | 62,789 | 105,146 | 62,789 | ' |
Goodwill | $0 | $0 | $0 | $0 | ' |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Loss) (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Equity [Abstract] | ' | ' | ' | ' |
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process | ' | ' | 23.00% | 16.40% |
Percentage of Pension Liability Adjustment Capitalized into Other Accounts | ' | ' | 2.10% | 2.50% |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | ($58,140) | ($81,630) |
Amounts reclassified from AOCI (pre-tax) | ' | ' | -6,105 | -3,573 |
Income tax impact of amounts reclassified | ' | ' | 2,411 | 1,417 |
Other OCI changes (pre-tax) | ' | ' | 9,702 | 8,594 |
Income tax impact of other OCI changes | ' | ' | -3,756 | -3,402 |
Net change after income taxes | 1,461 | -1,903 | 2,252 | 3,036 |
Ending Balance | -55,888 | -78,594 | -55,888 | -78,594 |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | 25,748 | 16,406 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | -8,857 | -6,854 |
Income tax impact of amounts reclassified | ' | ' | 3,488 | 2,714 |
Other OCI changes (pre-tax) | ' | ' | 9,855 | 8,591 |
Income tax impact of other OCI changes | ' | ' | -3,809 | -3,401 |
Net change after income taxes | ' | ' | 677 | 1,050 |
Ending Balance | 26,425 | 17,456 | 26,425 | 17,456 |
Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -83,625 | -97,820 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | 2,576 | 3,182 |
Income tax impact of amounts reclassified | ' | ' | -1,016 | -1,262 |
Other OCI changes (pre-tax) | ' | ' | ' | ' |
Income tax impact of other OCI changes | ' | ' | ' | ' |
Net change after income taxes | ' | ' | 1,560 | 1,920 |
Ending Balance | -82,065 | -95,900 | -82,065 | -95,900 |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -263 | -216 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | 176 | 99 |
Income tax impact of amounts reclassified | ' | ' | -61 | -35 |
Other OCI changes (pre-tax) | ' | ' | -153 | 3 |
Income tax impact of other OCI changes | ' | ' | 53 | -1 |
Net change after income taxes | ' | ' | 15 | 66 |
Ending Balance | -248 | -150 | -248 | -150 |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -57,877 | -81,414 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | -6,281 | -3,672 |
Income tax impact of amounts reclassified | ' | ' | 2,472 | 1,452 |
Other OCI changes (pre-tax) | ' | ' | 9,855 | 8,591 |
Income tax impact of other OCI changes | ' | ' | -3,809 | -3,401 |
Net change after income taxes | 1,382 | -1,930 | 2,237 | 2,970 |
Ending Balance | -55,640 | -78,444 | -55,640 | -78,444 |
Public Service Company of New Mexico [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | 25,748 | 16,406 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | -8,857 | -6,854 |
Income tax impact of amounts reclassified | ' | ' | 3,488 | 2,714 |
Other OCI changes (pre-tax) | ' | ' | 9,855 | 8,591 |
Income tax impact of other OCI changes | ' | ' | -3,809 | -3,401 |
Net change after income taxes | ' | ' | 677 | 1,050 |
Ending Balance | 26,425 | 17,456 | 26,425 | 17,456 |
Public Service Company of New Mexico [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -83,625 | -97,820 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | 2,576 | 3,182 |
Income tax impact of amounts reclassified | ' | ' | -1,016 | -1,262 |
Other OCI changes (pre-tax) | ' | ' | ' | ' |
Income tax impact of other OCI changes | ' | ' | ' | ' |
Net change after income taxes | ' | ' | 1,560 | 1,920 |
Ending Balance | -82,065 | -95,900 | -82,065 | -95,900 |
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] | ' | ' | ' | ' |
Beginning Balance | ' | ' | ' | ' |
Amounts reclassified from AOCI (pre-tax) | ' | ' | ' | ' |
Income tax impact of amounts reclassified | ' | ' | ' | ' |
Other OCI changes (pre-tax) | ' | ' | ' | ' |
Income tax impact of other OCI changes | ' | ' | ' | ' |
Net change after income taxes | ' | ' | ' | ' |
Ending Balance | ' | ' | ' | ' |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -263 | -216 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | 176 | 99 |
Income tax impact of amounts reclassified | ' | ' | -61 | -35 |
Other OCI changes (pre-tax) | ' | ' | -153 | 3 |
Income tax impact of other OCI changes | ' | ' | 53 | -1 |
Net change after income taxes | 79 | 27 | 15 | 66 |
Ending Balance | -248 | -150 | -248 | -150 |
Texas-New Mexico Power Company [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | ' | ' |
Amounts reclassified from AOCI (pre-tax) | ' | ' | ' | ' |
Income tax impact of amounts reclassified | ' | ' | ' | ' |
Other OCI changes (pre-tax) | ' | ' | ' | ' |
Income tax impact of other OCI changes | ' | ' | ' | ' |
Net change after income taxes | ' | ' | ' | ' |
Ending Balance | ' | ' | ' | ' |
Texas-New Mexico Power Company [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | ' | ' |
Amounts reclassified from AOCI (pre-tax) | ' | ' | ' | ' |
Income tax impact of amounts reclassified | ' | ' | ' | ' |
Other OCI changes (pre-tax) | ' | ' | ' | ' |
Income tax impact of other OCI changes | ' | ' | ' | ' |
Net change after income taxes | ' | ' | ' | ' |
Ending Balance | ' | ' | ' | ' |
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ' | ' | ' | ' |
Beginning Balance | ' | ' | -263 | -216 |
Amounts reclassified from AOCI (pre-tax) | ' | ' | 176 | 99 |
Income tax impact of amounts reclassified | ' | ' | -61 | -35 |
Other OCI changes (pre-tax) | ' | ' | -153 | 3 |
Income tax impact of other OCI changes | ' | ' | 53 | -1 |
Net change after income taxes | ' | ' | 15 | 66 |
Ending Balance | ($248) | ($150) | ($248) | ($150) |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 1 Months Ended | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | |||||||||||||||||||
Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2012 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Oct. 08, 2013 | 30-May-08 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 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] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Valencia [Member] | Variable Interest Entity, Not Primary Beneficiary [Member] | Delta [Member] | Delta [Member] | Delta [Member] | Delta [Member] | ||||||
Public Service Company of New Mexico [Member] | Property Lease Guarantee [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] | Purchased Through May 30, 2028 [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] | |||||||||||
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) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 158 | ' | ' | ' | ' | ' |
Long Term Contract For Purchase of Electric Power Fixed Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $4,800,000 | $4,700,000 | $9,600,000 | $9,400,000 | ' | ' | ' | ' | $1,600,000 | $1,600,000 | $3,200,000 | $3,200,000 |
Long Term Contract For Purchase of Electric Power Variable Charges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | 200,000 | 700,000 | 300,000 | ' | ' | ' | ' | 300,000 | 400,000 | 500,000 | 600,000 |
Variable Interest Entity, Statement Of Operation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,307,000 | 4,922,000 | 10,238,000 | 9,697,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Operating expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,399,000 | -1,349,000 | -2,799,000 | -2,920,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Earnings attributable to non-controlling interest | 3,908,000 | 3,573,000 | 7,439,000 | 6,777,000 | ' | 3,908,000 | 3,573,000 | 7,439,000 | 6,777,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,908,000 | 3,573,000 | 7,439,000 | 6,777,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Current assets | 446,825,000 | ' | 446,825,000 | ' | 401,539,000 | 393,099,000 | ' | 393,099,000 | ' | 348,502,000 | ' | ' | ' | ' | ' | ' | ' | ' | 3,232,000 | ' | 3,232,000 | ' | 2,658,000 | ' | ' | ' | ' | ' | ' | ' |
Net property, plant, and equipment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73,729,000 | ' | 73,729,000 | ' | 75,137,000 | ' | ' | ' | ' | ' | ' | ' |
Total assets | 5,604,192,000 | 5,403,906,000 | 5,604,192,000 | 5,403,906,000 | 5,500,210,000 | 4,290,529,000 | ' | 4,290,529,000 | ' | 4,227,616,000 | ' | ' | ' | ' | ' | ' | ' | ' | 76,961,000 | ' | 76,961,000 | ' | 77,795,000 | ' | ' | ' | ' | ' | ' | ' |
Current liabilities | 486,869,000 | ' | 486,869,000 | ' | 492,671,000 | 226,303,000 | ' | 226,303,000 | ' | 357,266,000 | ' | ' | ' | ' | ' | ' | ' | ' | 682,000 | ' | 682,000 | ' | 766,000 | ' | ' | ' | ' | ' | ' | ' |
Owners’ equity – non-controlling interest | 76,279,000 | ' | 76,279,000 | ' | 77,029,000 | 76,279,000 | ' | 76,279,000 | ' | 77,029,000 | ' | ' | ' | ' | ' | ' | ' | ' | 76,279,000 | ' | 76,279,000 | ' | 77,029,000 | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, ownership percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, estimated purchase price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85,000,000 | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, purchase price - percentage of adjusted NBV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, purchase price - percentage of FMV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, number of days to set FMV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '60 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long term contract option to purchase, approximate approval period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Renewal Options After Original Lease Term (in years) | ' | ' | '6 years | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Extended Lease Term Option (in years) | ' | ' | ' | ' | ' | ' | ' | '6 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Future Minimum Payments Due | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating leases, future minimum payments due, renewal term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 145,200,000 | ' | ' | ' | ' |
Loss Contingency, Range of Possible Loss, Portion Not Accrued | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 144,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Future Minimum Payments Due, Next Six Months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of Long Term Contract For Purchase of Electric Power Fixed Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' |
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,200,000 | ' | 36,200,000 | ' |
Payments to Acquire Businesses, Gross | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,600,000 | ' | 14,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,400,000 | ' | 22,400,000 | ' | 23,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | 19,000,000 | ' | 20,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,500,000 | ' | 16,500,000 | ' | 18,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500,000 | 2,200,000 | 4,300,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net earnings | $29,141,000 | $27,678,000 | $41,609,000 | $38,304,000 | ' | $20,346,000 | $26,124,000 | $28,021,000 | $37,693,000 | ' | ' | ' | ' | $300,000 | $100,000 | $600,000 | $300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Lease_Commitments_Details
Lease Commitments (Details) (USD $) | 6 Months Ended | ||||||||
In Millions, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Feb. 25, 2014 | 1-May-14 | Jun. 30, 2014 | 1-May-14 | 1-May-14 | 1-May-14 |
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] | Maximum [Member] | Minimum [Member] | ||
Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 31.2494 MW [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | |||
MW | MW | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | ||||||
Operating Leased Assets [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Rental Payments, Fixed renewal option period during original terms of leases | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' |
Purchase Price of Leased Asset to be paid January 15, 2016 | ' | ' | ' | $78.10 | ' | ' | $85.20 | ' | ' |
Leased Capacity to be Purchased | ' | ' | ' | ' | 32.76 | 31.2494 | ' | ' | ' |
Early Purchase Price of Leased Asset effective June 1, 2014 | ' | ' | ' | ' | ' | ' | 79.9 | ' | ' |
Additional consideration for early purchase of leased asset effective June 1, 2014 | ' | ' | ' | ' | ' | ' | ' | $5.80 | $1.20 |
Operating Lease, Extended Term | '2 years | ' | ' | ' | ' | ' | ' | ' | ' |
Operating Leases, Renewal Options After Original Lease Term (in years) | '6 years | '2 years | ' | ' | ' | ' | ' | ' | ' |
Fair_Value_of_Derivative_and_O2
Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
Derivatives, Fair Value [Line Items] | ' | ' |
Assets, Current | $446,825,000 | $401,539,000 |
Liabilities, Current | 486,869,000 | 492,671,000 |
Current assets | 4,082,000 | 4,064,000 |
Deferred charges | 1,515,000 | 3,002,000 |
Commodity derivative instruments, Current liabilities | -5,073,000 | -2,699,000 |
Commodity derivative instruments, Long-term liabilities | -915,000 | -1,094,000 |
PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Margin Deposit Assets | 2,400,000 | 2,800,000 |
Derivative, Collateral, Obligation to Return Cash | 100,000 | 200,000 |
Derivative, Collateral, Right to Reclaim Cash | 0 | ' |
Public Service Company of New Mexico [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Assets, Current | 393,099,000 | 348,502,000 |
Liabilities, Current | 226,303,000 | 357,266,000 |
Current assets | 4,082,000 | 4,064,000 |
Deferred charges | 1,515,000 | 3,002,000 |
Commodity derivative instruments, Current liabilities | -5,073,000 | -2,699,000 |
Commodity derivative instruments, Long-term liabilities | -915,000 | -1,094,000 |
Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Current assets | 4,082,000 | 4,064,000 |
Deferred charges | 1,515,000 | 3,002,000 |
Commodity derivative instruments, Assets | 5,597,000 | 7,066,000 |
Commodity derivative instruments, Current liabilities | -5,073,000 | -2,699,000 |
Commodity derivative instruments, Long-term liabilities | -915,000 | -1,094,000 |
Commodity derivative instruments, Liabilities | -5,988,000 | -3,793,000 |
Commodity derivative instruments, Net | -391,000 | 3,273,000 |
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 | 400,000 | 400,000 |
Liabilities, Current | 600,000 | 100,000 |
Palo Verde Nuclear Generating Station [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Current assets | 3,000,000 | 3,000,000 |
Deferred charges | 1,500,000 | 3,000,000 |
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% | ' |
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Public Utilities, Number of Megawatts Nuclear Generation | 134 | ' |
Palo Verde Nuclear Generating Station Unit 3 [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Derivative, Average Forward Price | ' | 37 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 5,597,000 | 7,066,000 |
Commodity derivative instruments, Liabilities | -5,988,000 | -3,793,000 |
Commodity derivative instruments, Net | -391,000 | 3,273,000 |
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 5,597,000 | 7,066,000 |
Commodity derivative instruments, Liabilities | -5,988,000 | -3,793,000 |
Commodity derivative instruments, Net | -391,000 | 3,273,000 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 0 | 0 |
Commodity derivative instruments, Liabilities | 0 | 0 |
Commodity derivative instruments, Net | $0 | $0 |
Fair_Value_of_Derivative_and_O3
Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (PNMR and PNM [Member], Commodity Contract [Member], Fair Value Hedging [Member], USD $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Gain (loss) | ($267) | $3,006 | ($4,230) | ($841) |
Electric operating revenues [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Gain (loss) | -324 | 3,269 | -4,475 | -1,334 |
Cost of energy [Member] | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Gain (loss) | $57 | ($263) | $245 | $493 |
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 $) | Jun. 30, 2014 | Dec. 31, 2013 |
Derivative [Line Items] | ' | ' |
Derivative, Collateral, Right to Reclaim Cash | $0 | ' |
Contractual Liability | 2,740,000 | 2,398,000 |
Existing Cash Collateral | 0 | 0 |
Net Exposure | $1,663,000 | $2,152,000 |
Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Volume positions (Decatherms / MWh) | -2,809,507 | -3,343,783 |
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 | 6 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | $43,613 | ' | $42,602 |
Available-for-sale securities, Fair value | 236,427 | ' | 236,427 | ' | 226,855 |
Proceeds from sales | 30,316 | 61,821 | 53,119 | 76,106 | ' |
Gross realized gains | 5,364 | 4,905 | 8,482 | 6,243 | ' |
Gross realized (losses) | -665 | -1,688 | -1,210 | -1,496 | ' |
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 | 3,114 | ' | 3,114 | ' | 3,356 |
Domestic value [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 16,014 | ' | 14,523 |
Available-for-sale securities, Fair value | 42,664 | ' | 42,664 | ' | 39,460 |
Domestic growth [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 19,931 | ' | 25,656 |
Available-for-sale securities, Fair value | 75,621 | ' | 75,621 | ' | 76,292 |
International and other [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 2,227 | ' | 1,040 |
Available-for-sale securities, Fair value | 17,848 | ' | 17,848 | ' | 16,633 |
U.S. Government [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 534 | ' | 158 |
Available-for-sale securities, Fair value | 19,814 | ' | 19,814 | ' | 21,941 |
Municipals [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 4,282 | ' | 1,018 |
Available-for-sale securities, Fair value | 65,872 | ' | 65,872 | ' | 58,568 |
Corporate and other [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Unrealized gains | ' | ' | 625 | ' | 207 |
Available-for-sale securities, Fair value | 11,494 | ' | 11,494 | ' | 10,605 |
Fair Value, Measurements, Recurring [Member] | Nuclear Decommissioning Trust [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Fair value | 231,900 | ' | 231,900 | ' | 222,500 |
Fair Value, Measurements, Recurring [Member] | Mine Reclamation Trust [Member] | ' | ' | ' | ' | ' |
Schedule of Available-for-sale Securities [Line Items] | ' | ' | ' | ' | ' |
Available-for-sale securities, Fair value | $4,500 | ' | $4,500 | ' | $4,400 |
Fair_Value_of_Derivative_and_O6
Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) | Jun. 30, 2014 |
In Thousands, unless otherwise specified | |
PNMR and PNM [Member] | ' |
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | ' |
Available-for-sale debt securities, Within 1 year | $2,911 |
Available-for-sale debt securities, After 1 year through 5 years | 21,556 |
Available-for-sale debt securities, After 5 years through 10 years | 10,875 |
Available-for-sale debt securities, After 10 years through 15 years | 9,114 |
Available-for-sale debt securities, After 15 years through 20 years | 11,431 |
Available-for-sale debt securities, After 20 years | 41,293 |
Available-for-sale debt securities | 97,180 |
PNM Resources [Member] | ' |
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract] | ' |
Held-to-maturity debt securities, Due within 1 year | 12,017 |
Held-to-maturity debt securities, After 1 year through 5 years | 33,776 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | 45,793 |
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 | 12,017 |
Held-to-maturity debt securities, After 1 year through 5 years | 33,050 |
Held-to-maturity debt securities, After 5 years through 10 years | 0 |
Held-to-maturity debt securities | $45,067 |
Fair_Value_of_Derivative_and_O7
Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
PNMR and PNM [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | $236,427 | $226,855 |
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 236,427 | 226,855 |
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 159,781 | 158,180 |
PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 76,646 | 68,675 |
PNMR and PNM [Member] | Cash and equivalents [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 3,114 | 3,356 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 3,114 | 3,356 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 3,114 | 3,356 |
PNMR and PNM [Member] | Cash and equivalents [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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 | 42,664 | 39,460 |
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 42,664 | 39,460 |
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 42,664 | 39,460 |
PNMR and PNM [Member] | Domestic value [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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 | 75,621 | 76,292 |
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 75,621 | 76,292 |
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 75,621 | 76,292 |
PNMR and PNM [Member] | Domestic growth [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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 | 17,848 | 16,633 |
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 17,848 | 16,633 |
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 17,848 | 16,633 |
PNMR and PNM [Member] | International and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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 | 19,814 | 21,941 |
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 19,814 | 21,941 |
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 18,053 | 20,194 |
PNMR and PNM [Member] | U.S. Government [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 1,761 | 1,747 |
PNMR and PNM [Member] | Municipals [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 65,872 | 58,568 |
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 65,872 | 58,568 |
PNMR and PNM [Member] | Municipals [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 65,872 | 58,568 |
PNMR and PNM [Member] | Corporate and other [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 11,494 | 10,605 |
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 11,494 | 10,605 |
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 2,481 | 2,245 |
PNMR and PNM [Member] | Corporate and other [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Investments | 9,013 | 8,360 |
Public Service Company of New Mexico [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,530,418 | 1,382,938 |
Investment In PVNGS lessor notes | 45,067 | 57,279 |
Other investments | 432 | 445 |
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 432 | 445 |
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,530,418 | 1,382,938 |
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 | 45,067 | 57,279 |
Other investments | 0 | 0 |
PNM Resources [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 2,088,787 | 1,905,230 |
Investment In PVNGS lessor notes | 45,067 | 57,279 |
Other investments | 2,525 | 3,196 |
PNM Resources [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Investment In PVNGS lessor notes | 0 | 0 |
Other investments | 677 | 690 |
PNM Resources [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 2,088,787 | 1,905,230 |
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 | 0 | 0 |
Investment In PVNGS lessor notes | 45,067 | 57,279 |
Other investments | 1,848 | 2,506 |
Texas-New Mexico Power Company [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 431,706 | 390,814 |
Other investments | 245 | 245 |
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 1 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 0 | 0 |
Other investments | 245 | 245 |
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 431,706 | 390,814 |
Other investments | 0 | 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 | 0 |
Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value Measurement [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 5,597 | 7,066 |
Commodity derivative instruments, Liabilities | -5,988 | -3,793 |
Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, 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 Contract [Member] | PNMR and PNM [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Commodity derivative instruments, Assets | 5,597 | 7,066 |
Commodity derivative instruments, Liabilities | -5,988 | -3,793 |
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 | 1,390,637 | 1,290,618 |
Investment In PVNGS lessor notes | 42,234 | 52,958 |
Other investments | 432 | 445 |
Carrying Amount [Member] | PNM Resources [Member] | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Long-term debt | 1,875,254 | 1,745,420 |
Investment In PVNGS lessor notes | 42,234 | 52,958 |
Other investments | 1,798 | 1,835 |
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 | 365,851 | 336,036 |
Other investments | $245 | $245 |
StockBased_Compensation_Detail
Stock-Based Compensation (Details) (USD $) | 6 Months Ended | 6 Months Ended | 1 Months Ended | 6 Months Ended | |||||||||
Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Feb. 28, 2014 | Jun. 30, 2014 | Mar. 31, 2012 | Mar. 31, 2012 | Jun. 30, 2014 | |
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, Vesting Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $7,700,000 | ' | $4,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at beginning of period, Shares | 1,343,666 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share) | $20.63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Granted, Shares | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Granted, Weighted-Average Exercise Price (in dollars per share) | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Exercised, Shares | -236,260 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Exercised, Weighted-Average Exercise Price (in dollars per share) | $18.90 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Forfeited, Shares | -17,151 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share) | $26.43 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Expired, Shares | -22,784 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Expired, Weighted-Average Exercise Price (in dollars per share) | $25.91 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Shares | 1,067,471 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share) | $20.80 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | 315,305 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $17.87 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Granted, Shares | ' | ' | ' | ' | 242,164 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $21.27 | $20.03 | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Vested, Shares | ' | ' | ' | ' | -292,052 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $16.64 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Forfeited, Shares | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $0 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at end of period, Shares | ' | ' | ' | ' | 265,417 | ' | ' | ' | ' | ' | ' | ' | ' |
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value (in dollars per share) | ' | ' | ' | ' | $22.31 | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Aggregate Intrinsic Value | ' | ' | ' | 9,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years) | ' | ' | ' | '3 years 2 months 13 days | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options, Outstanding at end of period, No intrinsic value | 297,350 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted-average grant date fair value options granted (dollars per share) | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total fair value of options that vested | 0 | 625,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total intrinsic value of options exercised | 1,779,000 | 2,189,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Total fair value of shares that vested | ' | ' | ' | ' | $4,854,000 | $4,383,000 | ' | ' | ' | ' | ' | ' | ' |
Expected quarterly dividends per share | ' | ' | ' | ' | $0.19 | $0.17 | ' | ' | ' | ' | ' | ' | ' |
Risk-free interest rate | ' | ' | ' | ' | 0.62% | 0.34% | 0.64% | 0.36% | ' | ' | ' | ' | ' |
Granted and Vested in Period | ' | ' | ' | ' | ' | ' | ' | ' | 112,864 | ' | ' | ' | ' |
Share based Compensation, weighted percentage assigned to achieving market targets | ' | ' | ' | ' | ' | ' | ' | ' | 60.00% | ' | ' | ' | ' |
Share based Compensation, weighted percentage assigned to achieving performance targets | ' | ' | ' | ' | ' | ' | ' | ' | 40.00% | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One | ' | ' | ' | ' | ' | ' | ' | ' | ' | 198,369 | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two | ' | ' | ' | ' | ' | ' | ' | ' | ' | 179,811 | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three | ' | ' | ' | ' | ' | ' | ' | ' | ' | 175,735 | ' | ' | ' |
Shares received if achieves specified improvement in total shareholders return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000 | 35,000 | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | ' | ' | ' | ' | ' | ' | 2.82% | 2.86% | ' | ' | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | ' | ' | ' | ' | ' | ' | 25.11% | 25.11% | ' | ' | ' | ' | ' |
Financing_Shortterm_Debt_Detai
Financing, Short-term Debt (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jul. 25, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jul. 25, 2014 | Apr. 22, 2013 | Jun. 30, 2014 |
Line of Credit [Member] | Line of Credit [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] | 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] | Affiliated Entity [Member] | PNMR Term Loan Agreement [Member] | PNMR Term Loan Agreement [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | Local Lines of Credit [Member] | Local Lines of Credit [Member] | Local Lines of Credit [Member] | PNM Term Loan Agreement [Member] | PNM 2014 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] | Notes Payable to Banks [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] | Intercompany loan agreements [Member] | Texas-New Mexico Power Company [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Available Borrowing Capacity [Member] | Notes Payable to Banks [Member] | Public Service Company of New Mexico [Member] | ||||||||||||
Public Service Company of New Mexico [Member] | Texas-New Mexico Power Company [Member] | Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member] | |||||||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $771,800,000 | $292,300,000 | $369,600,000 | $74,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $35,000,000 | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | 400,000,000 | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Collateral Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' |
Short-term Debt, Weighted Average Interest Rate | ' | ' | ' | ' | 1.66% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | ' | ' | ' | ' | ' | ' | ' |
Short-term debt | 105,000,000 | 149,200,000 | 105,000,000 | 149,200,000 | 5,000,000 | 0 | 0 | 49,200,000 | 0 | 49,200,000 | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | 100,000,000 | ' | 0 | 0 | ' | 75,000,000 | ' |
Short-term debt – affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,200,000 | 29,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,500,000 | 25,700,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted Cash and Investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,900,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate at Period End | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.10% |
Proceeds from Bank Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Financing_Financing_Activities
Financing, Financing Activities (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jan. 08, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Mar. 05, 2014 | Jun. 30, 2014 | Dec. 09, 2013 | Mar. 06, 2013 | Jun. 30, 2014 | Apr. 22, 2013 |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | Local Lines of Credit [Member] | Local Lines of Credit [Member] | PNMR Term Loan Agreement [Member] | PNMR Term Loan Agreement [Member] | PNM 2014 Term Loan Agreement [Member] | PNM 2014 Term Loan Agreement [Member] | 2011 Term Loan Agreement, First Mortgage Bonds Due 2014 [Member] | Bonds [Member] | First Mortgage Bonds [Member] | Notes Payable to Banks [Member] | Notes Payable to Banks [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] | First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member] | First Mortgage Bonds, due 2043, Series 2013A [Member] | Texas-New Mexico Power Company [Member] | PNM Term Loan Agreement [Member] | |||||||
Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | |||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $175,000,000 | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80,000,000 | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.03% | ' | ' | ' |
Proceeds from Bank Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | 30,000,000 | ' |
Debt Instrument, Cash for Bond Exchange Conversion | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.14 | ' | ' |
Short-term debt | 105,000,000 | 149,200,000 | 0 | 49,200,000 | 0 | ' | 0 | 100,000,000 | 100,000,000 | ' | ' | ' | ' | ' | ' | 75,000,000 |
Debt Instrument, Interest Rate at Period End | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.10% | ' | ' | ' | ' | ' | ' |
Debt Instruments, NMPRC Approved credit facility | ' | ' | ' | ' | ' | $50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pension_and_Other_Postretireme2
Pension and Other Postretirement Benefit Plans (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | |
Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ' | ' |
Pension liability, Estimated percentage increase due to change in assumptions | 7.00% | ' | 7.00% | ' |
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 | 7,541,000 | 7,035,000 | 15,082,000 | 14,071,000 |
Expected return on plan assets | -9,511,000 | -10,482,000 | -19,022,000 | -20,965,000 |
Amortization of net (gain) loss | 3,255,000 | 3,710,000 | 6,510,000 | 7,420,000 |
Amortization of prior service cost | -241,000 | 19,000 | -483,000 | 38,000 |
Net Periodic Benefit Cost (Income) | 1,044,000 | 282,000 | 2,087,000 | 564,000 |
Defined Benefit Plan, Contributions by Employer | ' | 0 | ' | 60,000,000 |
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 61,500,000 | ' | 61,500,000 | ' |
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) | ' | ' | 5.20% | ' |
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | ' | ' | 5.50% | ' |
Public Service Company of New Mexico [Member] | OPEB [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 45,000 | 65,000 | 91,000 | 130,000 |
Interest cost | 1,159,000 | 1,029,000 | 2,315,000 | 2,057,000 |
Expected return on plan assets | -1,410,000 | -1,261,000 | -2,819,000 | -2,522,000 |
Amortization of net (gain) loss | 556,000 | 1,061,000 | 1,113,000 | 2,121,000 |
Amortization of prior service cost | -336,000 | -336,000 | -672,000 | -672,000 |
Net Periodic Benefit Cost (Income) | 14,000 | 558,000 | 28,000 | 1,114,000 |
Defined Benefit Plan, Contributions by Employer | 800,000 | 1,100,000 | 1,600,000 | 1,600,000 |
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 14,000,000 | ' | 14,000,000 | ' |
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 | 205,000 | 180,000 | 411,000 | 360,000 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 52,000 | 58,000 | 105,000 | 116,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | 257,000 | 238,000 | 516,000 | 476,000 |
Defined Benefit Plan, Contributions by Employer | 400,000 | 400,000 | 700,000 | 800,000 |
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 | 798,000 | 772,000 | 1,597,000 | 1,544,000 |
Expected return on plan assets | -1,132,000 | -1,212,000 | -2,263,000 | -2,425,000 |
Amortization of net (gain) loss | 166,000 | 262,000 | 333,000 | 524,000 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | -168,000 | -178,000 | -333,000 | -357,000 |
Defined Benefit Plan, Contributions by Employer | ' | 0 | ' | 1,000,000 |
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 0 | ' | 0 | ' |
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 5.20% | ' | ' | ' |
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent) | 5.50% | ' | ' | ' |
Texas-New Mexico Power Company [Member] | OPEB [Member] | ' | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' |
Service cost | 59,000 | 75,000 | 119,000 | 150,000 |
Interest cost | 155,000 | 141,000 | 309,000 | 283,000 |
Expected return on plan assets | -133,000 | -126,000 | -267,000 | -252,000 |
Amortization of net (gain) loss | -31,000 | 0 | -61,000 | 0 |
Amortization of prior service cost | 8,000 | 14,000 | 16,000 | 28,000 |
Net Periodic Benefit Cost (Income) | 58,000 | 104,000 | 116,000 | 209,000 |
Defined Benefit Plan, Contributions by Employer | ' | ' | 300,000 | 300,000 |
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year | 1,400,000 | ' | 1,400,000 | ' |
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year | 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 | 10,000 | 9,000 | 20,000 | 18,000 |
Expected return on plan assets | 0 | 0 | 0 | 0 |
Amortization of net (gain) loss | 0 | 0 | 0 | 0 |
Amortization of prior service cost | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost (Income) | 10,000 | 9,000 | 20,000 | 18,000 |
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 |
Commitments_and_Contingencies_
Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $) | Dec. 21, 2011 | Dec. 21, 2011 | Oct. 31, 2012 | Jun. 30, 2014 | Jun. 26, 2014 | Dec. 20, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Aug. 06, 2012 | Jun. 30, 2014 | Dec. 20, 2013 | Jun. 30, 2014 | Dec. 20, 2013 | Dec. 20, 2013 | Jun. 30, 2014 | Jun. 26, 2014 | Dec. 20, 2013 | Dec. 20, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 27, 2014 | Mar. 11, 2014 | Jan. 31, 2010 | Oct. 31, 2012 | Oct. 31, 2012 | Jan. 31, 2010 | Jun. 30, 2014 | Oct. 31, 2012 | Oct. 31, 2012 | Dec. 20, 2013 | Nov. 08, 2013 |
mw | 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] | PNM Electric [Member] | PNMR and PNM [Member] | Other Deferred Credits [Member] | Other Deferred Credits [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] | Clean Air Act Related to Post Combustion Controls [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Mercury Control [Member] | Environmental Protection Agency [Member] | Environmental Protection Agency [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] | Minimum [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | Maximum [Member] | San Juan Generating Station [Member] | |
San Juan Generating Station [Member] | San Juan Generating Station Units 2 and 3 [Member] | San Juan Generating Station Units 1 and 4 [Member] | San Juan Generating Station Units 1 and 4 [Member] | Nuclear Spent Fuel And Waste Disposal [Member] | Nuclear Spent Fuel And Waste Disposal [Member] | San Juan Generating Station Units 2 and 3 [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | state | 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] | PNMR and PNM [Member] | Public Service Company of New Mexico [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] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [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] | Public Service Company of New Mexico [Member] | Mercury Control [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] | National Ambient Air Quality Standards [Member] | |||
Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | MW | Nuclear Spent Fuel And Waste Disposal [Member] | Nuclear Spent Fuel And Waste Disposal [Member] | Four Corners [Member] | Four Corners [Member] | Four Corners Units 4 and 5 (Coal) [Member] | San Juan Generating Station [Member] | San Juan Generating Station Unit 3 [Member] | San Juan Generating Station Unit 3 [Member] | San Juan Generating Station Units 2 and 3 [Member] | San Juan Generating Station Unit 4 [Member] | San Juan Generating Station Unit 4 [Member] | San Juan Generating Station Unit 4 [Member] | Palo Verde Nuclear Generating Station Unit 3 [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] | San Juan Generating Station And Four Corners [Member] | Clean Air Act, SCR [Member] [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station And Four Corners [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | |||||||||
Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | compliance_alternative | MW | MW | MW | MW | MW | MW | Four Corners [Member] | San Juan Generating Station Unit 4 [Member] | San Juan Generating Station Unit 4 [Member] | opp | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | opp | 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] | |||||||||||||||||||
San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station Units 1 and 4 [Member] | ||||||||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Estimate of Possible Loss | ' | ' | ' | ' | ' | ' | ' | $58,000,000 | ' | ' | ' | ' | ' | $80,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency Accrual | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,100,000 | 11,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual Fee, Nuclear Waste Disposal | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revised Annual Fee, Nuclear Waste Disposal | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of States To Address Regional Haze | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Total Capital Cost If Requirement Occurred | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 824,000,000 | ' | ' | ' | 910,000,000 | ' | ' | ' |
Estimated Installation Capital Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85,000,000 | ' | ' | ' | 90,000,000 | 82,000,000 | ' |
Estimated Portion of Total Capital Costs if Requirement Occured | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,000,000 | ' | ' | ' | 110,000,000 | ' | ' |
Jointly Owned Utility Plant, Proportionate Ownership Share | ' | ' | 46.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net book value | ' | ' | ' | 286,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Time Period to Recover Retired Units NBV | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Expected NBV of Units at Retirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 205,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Megawatts Nuclear Generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 134 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 134 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Proposed value per Kilowatt effective January 1, 2018 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 132 | 78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Costs to obtain additional ownership | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Overall Reduction Of Ownership, in Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 340 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Ownership To Be Exchanged, in Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share | ' | ' | ' | ' | 59.00% | 52.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts, December2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 177 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units | ' | ' | ' | ' | ' | ' | ' | ' | 268,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of ownership held by exiting owners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | 38.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Ownership Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.00% | ' | 50.00% | ' | ' | 38.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Expenditure, Installation Capital Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Additional Expenditure, Installation Capital Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Compliance alternatives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Plant Requirement to Meet NOx emissions Limit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.015 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Revised SO2 Emissions Agreed Upon | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.1 |
Public Utilities, Government Standard Emission Limit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.06 | ' | ' | 0.07 | ' | ' | ' | ' | ' |
Current Annual Mercury Control Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contingent Estimated Annual Mercury Control Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $6,600,000 | ' | ' | ' | ' |
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% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_and_Contingencies_1
Commitments and Contingencies (Other Commitments and Contingencies) (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Apr. 02, 2014 | Jan. 06, 2014 | Sep. 01, 2012 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Apr. 01, 2014 | Jun. 30, 2014 | Jun. 30, 2014 |
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Coal Supply [Member] | Coal Supply [Member] | Surface [Member] | Surface [Member] | Surface [Member] | Surface [Member] | Underground [Member] | Underground [Member] | Underground [Member] | San Juan Underground Mine Fire [Member] | San Juan Underground Mine Fire [Member] | San Juan Underground Mine Fire [Member] | NMTRD Coal Severance Tax [Member] | NMTRD Coal Severance Tax [Member] | Navajo Nation Allottee Matters [Member] | Navajo Nation Allottee Matters [Member] | Navajo Nation Allottee Matters [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | San Juan Generating Station [Member] | Nuclear Plant [Member] | Nuclear Plant [Member] | Nuclear Plant [Member] | Commercial Providers [Member] | Industry Wide Retrospective Assessment Program [Member] | |||
Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [Member] | Public Service Company of New Mexico [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] | Fuel and Purchased Power Adjustment Clause [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Fuel and Purchased Power Adjustment Clause [Member] | Four Corners [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] | Continuous Highwall Mining [Member] | SJCC Arbitration [Member] | SJCC Arbitration [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | Maximum [Member] | Nuclear Plant [Member] | Nuclear Plant [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] | Minimum [Member] | Maximum [Member] | Four Corners [Member] | Allotment_Parcel | Allotment_Parcel | Allotment_Parcel | Public Service Company of New Mexico [Member] | Palo Verde Nuclear 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] | |||||||||
San Juan Generating Station [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] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | Palo Verde Nuclear Generating Station [Member] | |||||||||||||||||||||
San Juan Generating Station [Member] | San Juan Generating Station [Member] | ||||||||||||||||||||||||||||
Public Utilities, Commitments And Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other Assets, Current | $54,026,000 | $34,590,000 | $49,385,000 | $30,510,000 | $21,600,000 | $12,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated Increase in Coal Cost, Percentage | ' | ' | ' | ' | 21.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Estimate of Possible Loss | ' | ' | ' | ' | ' | ' | ' | ' | ' | 54,600,000 | ' | ' | 93,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency Accrual | ' | ' | ' | ' | ' | ' | ' | 23,300,000 | 23,800,000 | ' | 8,200,000 | 7,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Final Reclamation, capped amount to be collected | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated increased coal costs and deferral of cost recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,400,000 | 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, 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,900,000 | ' | ' | ' | ' | ' | ' |
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, 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, Liability Insurance Coverage Sublimit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,250,000,000 | ' | ' |
Public Utilities, Maximum Amount under Nuclear Electric Insurance Limited | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $4,800,000 | ' | ' | ' | ' |
Number of landowners claiming to be Navajo allottees | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43 | ' | ' | ' | ' | ' | ' | ' | ' |
Number of allotment parcels' appraisal requested for review | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 58 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of allotments where landowners are revoking rights of way renewal consents | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory_and_Rate_Matters_De
Regulatory and Rate Matters (Details) (USD $) | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Oct. 05, 2012 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2014 | Jul. 31, 2011 | Jun. 30, 2014 | 2-May-14 | Jun. 03, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Jul. 30, 2011 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Aug. 28, 2012 | Jun. 30, 2014 | Jan. 31, 2013 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Jun. 30, 2014 | Dec. 20, 2013 | Jun. 26, 2014 | Dec. 20, 2013 | Jun. 30, 2014 |
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] | Texas-New Mexico Power Company [Member] | Texas-New Mexico Power Company [Member] | Delta [Member] | San Juan Generating Station Unit 3 [Member] | San Juan Generating Station Unit 4 [Member] | San Juan Generating Station Unit 4 [Member] | Four Corners [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] | 2014 Wind generated Renewable Energy Credits [Member] | Renewable Portfolio Standard 2014 [Member] | 2015 Wind generated Renewable Energy Credits [Member] | Renewable Portfolio Standard 2015 [Member] | 2010 Energy Efficiency Application [Member] | 2010 Energy Efficiency Application [Member] | 2010 Electric Rate Case [Member] | 2010 Electric Rate Case [Member] | FPPAC Continuation Application [Member] | Renewable Energy Rider [Member] | Integrated Resource Plan, 2011 [Member] | Integrated Resource Plan, 2011 [Member] | Formula Transmission Rate Case [Member] | Formula Transmission Rate Case [Member] | Formula Transmission Rate Case [Member] | City of Gallup, New Mexico Contract [Member] | City of Gallup, New Mexico Contract [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] | January 2014 Transmission Rate Filings [Member] | July 2014 Transmission Rate Filings [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] | |
MW | Maximum [Member] | Maximum [Member] | Wind Energy [Member] | Solar Energy [Member] | Renewable Technologies [Member] | Distributed Generation [Member] | Required Percentage by 2011 [Member] | Required Percentage by 2015 [Member] | Required Percentage by 2020 [Member] | MWh | MW | MWh | MW | Disincentives / Incentives Adder [Member] | Disincentives / Incentives Adder [Member] | Maximum [Member] | customer | Minimum [Member] | Maximum [Member] | Applications for Approvals to Purchase Delta [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Clean Air Act, SNCR [Member] | Right of first refusal [Member] | |||||||||||||||||||
Minimum [Member] | Minimum [Member] | Minimum [Member] | Minimum [Member] | MW | MW | MW | MW | ||||||||||||||||||||||||||||||||||||
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 | ' | ' | ' | 30.00% | 20.00% | 5.00% | 1.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Reasonable Cost Threshold | ' | 3.00% | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts of Solar PV Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23 | ' | 40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Number of Mega Watts of Wind Energy Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 102 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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, Annual Revenue To be Collected Under Current Rider Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Estimated Cost of Mega Watts of Solar PV Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 46,700,000 | ' | 79,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Wind Capacity Planned Purchase Agreement Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Program Costs Related To Energy Efficiency | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program, Percentage of Program Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage ownership of EIP transmission line | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Planning Period Covered of IRP | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Regulatory Costs Not yet Approved | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Requested Rate Increase (Decrease), Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | 1,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Rate Base Value | 56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 78 | ' | ' | ' |
Public Utilities, Additional Ownership To Be Obtained, in Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 132 | 78 | ' |
Percentage of ownership held by exiting owners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.00% |
Period of time to file a waiver of rights of first refusal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '120 days |
Public Utilities, Return on Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.81% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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, Approved Non-standard metering service cost initial fee range | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 63.97 | 168.61 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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, Approved Non-standard metering ongoing expenses monthly charge | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36.78 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Presumed number of customers that will elect non-standard meter service | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,081 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Non-standard metering ongoing expenses monthly charge | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38.99 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Additional Revenue from Proposed Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,900,000 | 18,100,000 | 18,200,000 | 25,200,000 | ' | ' | ' | ' | ' |
Public Utilities, Total Revenue Requirement Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | 2,800,000 | 2,900,000 | 4,200,000 | ' | ' | ' | ' | ' |
Public Utilities, Revenue For Power Sold Under Specific Contract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,900,000 | 6,100,000 | 11,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Deployment Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Approved Program Implementation Costs, Bonus | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Unapproved 2014 Program Implementation Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Unapproved 2015 Program Implementation Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Retention Percentage of Sales Margins | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Under-collected balance write-off | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $10,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Period over which to write off remaining uncollected balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '18 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Frequency of IRP filings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 6 Months Ended | |||||
Jun. 30, 2014 | Mar. 31, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 | Dec. 31, 2013 | Mar. 31, 2013 | |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease | ' | ' | ' | ' | ' | ' | $1,500,000 |
New Mexico Corporate tax rate, current | 7.60% | ' | ' | 7.60% | ' | ' | ' |
New Mexico Corporate tax rate, 2014 | 5.90% | ' | ' | 5.90% | ' | ' | ' |
Increase in regulatory liabilities due to change in state corporate tax rate | 23,900,000 | ' | ' | ' | ' | ' | ' |
Increase in income tax expense due to change in state corporate tax rate | ' | ' | 1,200,000 | ' | ' | ' | ' |
Decrease in regulatory liabilities due to change in state corporate tax rate | ' | 4,600,000 | ' | ' | ' | ' | ' |
Decrease in deferred tax asset due to change in state corporate tax rate | ' | 200,000 | ' | ' | ' | ' | ' |
Additional Income Tax Expense, Impairment of NM Wind Credits | ' | ' | 2,400,000 | ' | ' | ' | ' |
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset | ' | ' | ' | ' | ' | 19,900,000 | ' |
Income Tax Expense (Benefit) | -15,893,000 | ' | -20,334,000 | -22,313,000 | -28,303,000 | ' | ' |
Liability for Uncertain Tax Positions, Noncurrent | 14,300,000 | ' | ' | 14,300,000 | ' | ' | ' |
Public Service Company of New Mexico [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset | ' | ' | ' | ' | ' | 11,200,000 | ' |
Income Tax Expense (Benefit) | -13,106,000 | ' | -14,943,000 | -17,189,000 | -21,532,000 | ' | ' |
Liability for Uncertain Tax Positions, Noncurrent | 11,500,000 | ' | ' | 11,500,000 | ' | ' | ' |
Texas-New Mexico Power Company [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset | ' | ' | ' | ' | ' | 6,800,000 | ' |
Income Tax Expense (Benefit) | -5,590,000 | ' | -5,055,000 | -9,640,000 | -7,345,000 | ' | ' |
Liability for Uncertain Tax Positions, Noncurrent | 0 | ' | ' | 0 | ' | ' | ' |
Tax Years 2003 and 2005 - 2008 [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Expense (Benefit) | 1,300,000 | ' | ' | ' | ' | ' | ' |
Tax Years 2003 and 2005 - 2008 [Member] | Public Service Company of New Mexico [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Expense (Benefit) | -1,100,000 | ' | ' | ' | ' | ' | ' |
Tax Years 2003 and 2005 - 2008 [Member] | Texas-New Mexico Power Company [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Expense (Benefit) | 0 | ' | ' | ' | ' | ' | ' |
Tax Years 2003 and 2005 - 2008 [Member] | PNM Resources [Member] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Contingency [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | 2,000,000 | ' | ' | 2,000,000 | ' | ' | ' |
Income Tax Expense (Benefit) | $200,000 | ' | ' | ' | ' | ' | ' |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 6 Months Ended | ||
In Thousands, unless otherwise specified | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2014 | Jun. 30, 2013 |
Service billings [Member] | TNMP to PNMR [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | $0 | $2 | $0 | $4 |
Service billings [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 22,190 | 20,837 | 43,256 | 43,489 |
Service billings [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 6,963 | 6,856 | 14,224 | 14,217 |
Service billings [Member] | PNM to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 133 | 133 | 242 | 241 |
Interest charges [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 0 | 0 | 54 | 1 |
Interest charges [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 83 | 119 | 180 | 215 |
Interest charges [Member] | PNM to PNMR [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 25 | 37 | 51 | 78 |
Income tax sharing payments [Member] | PNMR to PNM [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | 0 | 45,000 | 0 | 45,000 |
Income tax sharing payments [Member] | PNMR to TNMP [Member] | ' | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' | ' |
Amount of related party transaction | $0 | $0 | $0 | $0 |
Goodwill_Details
Goodwill (Details) (USD $) | Jun. 30, 2014 | Dec. 31, 2013 | Jun. 30, 2013 | Jun. 30, 2014 | Apr. 01, 2014 | Dec. 31, 2013 | Apr. 01, 2013 | Jun. 30, 2014 | Dec. 31, 2013 | Apr. 01, 2012 |
In Thousands, unless otherwise specified | 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] | |||
Goodwill [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Goodwill | $278,297 | $278,297 | $278,297 | $51,632 | $51,600 | $51,632 | ' | $226,665 | $226,665 | $226,700 |
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | ' | ' | ' | ' | 30.00% | ' | 27.00% | ' | ' | 26.00% |