Texas New Mexico Power 10-K 27 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 20, 2015	Jun. 30, 2014
Document Information [Line Items]
Entity Registrant Name	PNM RESOURCES INC
Entity Central Index Key	1108426
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		79,653,624
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$2,336,240,792
Public Service Company of New Mexico [Member]
Document Information [Line Items]
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Central Index Key	81023
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		39,117,799
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Texas-New Mexico Power Company [Member]
Document Information [Line Items]
Entity Registrant Name	TEXAS NEW MEXICO POWER CO
Entity Central Index Key	22767
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		6,358
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No

Consolidated_Statements_of_Ear

Consolidated Statements of Earnings (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Electric Operating Revenues	$1,435,853	$1,387,923	$1,342,403
Operating Expenses:
Cost of energy	471,556	432,316	399,850
Administrative and general	171,111	179,210	187,740
Energy production costs	185,638	175,819	185,417
Regulatory disallowances	1,062	12,235	0
Depreciation and amortization	172,634	166,881	164,173
Transmission and distribution costs	66,571	70,124	71,125
Taxes other than income taxes	67,584	64,496	60,377
Total operating expenses	1,136,156	1,101,081	1,068,682
Operating income	299,697	286,842	273,721
Other Income and Deductions:
Interest income	8,483	10,043	13,072
Gains on available-for-sale securities	10,527	10,612	12,965
Other income	12,048	10,572	12,746
Gain on sale of First Choice	0	0	1,012
Other (deductions)	-10,481	-21,552	-17,636
Net other income and deductions	20,577	9,675	22,159
Interest Charges	119,627	121,448	120,845
Earnings before Income Taxes	200,647	175,069	175,035
Income Taxes	69,738	59,513	54,910
Net Earnings	130,909	115,556	120,125
(Earnings) Attributable to Valencia Non-controlling Interest	-14,127	-14,521	-14,050
Net Earnings Attributable to Company	116,254	100,507	105,547
Preferred Stock Dividends Requirements	-528	-528	-528
Net Earnings Available for PNM Common Stock	116,254	100,507	105,547
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$1.46	$1.26	$1.32
Diluted (dollars per share)	$1.45	$1.25	$1.31
Public Service Company of New Mexico [Member]
Electric Operating Revenues	1,147,914	1,116,312	1,092,264
Operating Expenses:
Cost of energy	403,626	374,710	353,649
Administrative and general	152,645	157,144	169,285
Energy production costs	185,638	175,819	185,403
Regulatory disallowances	1,062	12,235	0
Depreciation and amortization	109,524	103,826	97,291
Transmission and distribution costs	43,128	45,936	46,039
Taxes other than income taxes	39,578	37,457	34,715
Total operating expenses	935,201	907,127	886,382
Operating income	212,713	209,185	205,882
Other Income and Deductions:
Interest income	8,557	10,182	13,243
Gains on available-for-sale securities	10,527	10,612	12,965
Other income	8,949	7,650	8,126
Gain on sale of First Choice			0
Other (deductions)	-7,218	-6,974	-7,801
Net other income and deductions	20,815	21,470	26,533
Interest Charges	79,442	79,175	76,101
Earnings before Income Taxes	154,086	151,480	156,314
Income Taxes	52,633	48,804	50,713
Net Earnings	101,453	102,676	105,601
(Earnings) Attributable to Valencia Non-controlling Interest	-14,127	-14,521	-14,050
Net Earnings Attributable to Company	87,326	88,155	91,551
Preferred Stock Dividends Requirements	-528	-528	-528
Net Earnings Available for PNM Common Stock	86,798	87,627	91,023
Texas-New Mexico Power Company [Member]
Electric Operating Revenues	287,939	271,611	250,140
Operating Expenses:
Cost of energy	67,930	57,606	46,201
Administrative and general	36,982	44,635	40,775
Depreciation and amortization	50,056	50,219	49,340
Transmission and distribution costs	23,443	24,188	25,086
Taxes other than income taxes	23,940	22,778	21,218
Total operating expenses	202,351	199,426	182,620
Operating income	85,588	72,185	67,520
Other Income and Deductions:
Interest income	0	0	1
Other income	2,865	2,377	4,698
Gain on sale of First Choice			0
Other (deductions)	-727	-458	-1,959
Net other income and deductions	2,138	1,919	2,740
Interest Charges	27,396	27,393	28,161
Earnings before Income Taxes	60,330	46,711	42,099
Income Taxes	22,523	17,621	15,352
Net Earnings	37,807	29,090	26,747
(Earnings) Attributable to Valencia Non-controlling Interest	0	0	0
Net Earnings Attributable to Company	37,807	29,090	26,747
Preferred Stock Dividends Requirements	0	0	0
Net Earnings Available for PNM Common Stock	$37,807	$29,090	$26,747

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net earnings (loss)	$116,254	$100,507	$105,547
Net Earnings	130,909	115,556	120,125
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	10,661	16,564	23,286
Reclassification adjustment for (gains) included in net earnings (loss), net of income tax expense	-8,401	-7,222	-22,514
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit	-9,258	10,355	-18,174
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax (expense) benefit	3,120	3,840	2,786
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	-100	-181	-275
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense	363	134	117
Total Other Comprehensive Income (Loss)	-3,615	23,490	-14,774
Comprehensive Income	127,294	139,046	105,351
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-14,127	-14,521	-14,050
Preferred Stock Dividend Requirements of Subsidiary	528	528	528
Comprehensive Income Attributable to PNMR	112,639	123,997	90,773
Public Service Company of New Mexico [Member]
Net earnings (loss)	87,326	88,155	91,551
Net Earnings	101,453	102,676	105,601
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	10,661	16,564	23,286
Reclassification adjustment for (gains) included in net earnings (loss), net of income tax expense	-8,401	-7,222	-22,514
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit	-9,258	10,355	-18,174
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax (expense) benefit	3,120	3,840	2,786
Fair Value Adjustment for Designated Cash Flow Hedges:
Total Other Comprehensive Income (Loss)	-3,878	23,537	-14,616
Comprehensive Income	97,575	126,213	90,985
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-14,127	-14,521	-14,050
Preferred Stock Dividend Requirements of Subsidiary	528	528	528
Comprehensive Income Attributable to PNMR	83,448	111,692	76,935
Texas-New Mexico Power Company [Member]
Net earnings (loss)	37,807	29,090	26,747
Net Earnings	37,807	29,090	26,747
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	-100	-181	-275
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense	363	134	117
Total Other Comprehensive Income (Loss)	263	-47	-158
Preferred Stock Dividend Requirements of Subsidiary	0	0	0
Comprehensive Income Attributable to PNMR	$38,070	$29,043	$26,589

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrealized holding gains (losses) arising during the period, income tax (expense)	($6,812)	($10,855)	($15,262)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	5,461	4,734	14,755
Experience gain (loss), income tax (expense) benefit	6,024	-6,781	11,910
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, income tax (expense) benefit	-2,032	-2,524	-1,825
Change in fair market value, income tax (expense)	53	98	153
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	-195	-73	-65
Texas-New Mexico Power Company [Member]
Change in fair market value, income tax (expense)	53	98	153
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	-195	-73	-65
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense)	-6,812	-10,855	-15,262
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	5,461	4,734	14,755
Experience gain (loss), income tax (expense) benefit	6,024	-6,781	11,910
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, income tax (expense) benefit	($2,032)	($2,524)	($1,825)

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows From Operating Activities:
Net Earnings	$130,909	$115,556	$120,125
Net earnings	116,254	100,507	105,547
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	209,867	208,173	206,499
Deferred income tax expense	72,481	60,430	56,243
(Gain) on sale of First Choice	0	0	-1,012
Net unrealized (gains) on derivatives	-6,504	-1,866	-1,598
Realized (gains) on available-for-sale securities	-10,527	-10,612	-12,965
Loss on reacquired debt	0	3,253	0
Abandonment of leased premises	0	0	7,411
Stock based compensation expense	5,931	5,320	3,585
Regulatory disallowances	1,062	12,235	0
Other, net	-1,518	-1,647	-798
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	-4,975	-7,562	-2,547
Materials, supplies, and fuel stock	5,504	-7,580	-5,412
Other current assets	-30,436	8,577	-2,598
Other assets	290	-12,801	-30,778
Accounts payable	-2,311	4,484	14,020
Accrued interest and taxes	2,040	91,537	255
Other current liabilities	-2,453	-19,648	-19,905
Proceeds from governmental grants	0	0	21,567
Other liabilities	45,516	-61,262	-70,743
Net cash flows from operating activities	414,876	386,587	281,349
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-460,658	-348,039	-308,909
Proceeds from sales of available-for-sale securities	117,989	271,140	167,330
Purchases of available-for-sale securities	-127,016	-282,000	-176,748
Proceeds from sale of First Choice	0	0	-4,034
Return of principal on PVNGS lessor notes	20,758	23,357	23,455
Purchase of Rio Bravo	-36,235	0	0
Other, net	-167	4,096	4,943
Net cash flows from investing activities	-485,329	-331,446	-285,895
Cash Flows From Financing Activities:
Short-term loan			100,000
Revolving credit facilities borrowings (repayments), net	-43,600	-9,500	-24,000
Long-term borrowings	355,000	75,000	20,000
Repayment of long-term debt	-125,000	-29,468	-22,387
Cash paid in debt exchange		-13,048
Proceeds from stock option exercise	6,999	4,618	11,684
Purchase of common stock	-17,319	-13,807	-25,168
Dividends paid	-59,468	-51,508	-45,137
Valencia’s transactions with its owner	-17,610	-18,335	-15,630
Other, net	-2,808	-5,545	-922
Net cash flows from financing activities	96,194	-61,593	-1,560
Change in Cash and Cash Equivalents	25,741	-6,452	-6,106
Cash and Cash Equivalents at Beginning of Year	2,533	8,985	15,091
Cash and Cash Equivalents at End of Year	28,274	2,533	8,985
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	108,741	110,768	113,265
Income taxes paid (refunded), net	-2,597	-95,327	5,302
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	3,089	6,006	-17,983
Premium on long-term debt incurred in connection with debt exchange		36,297
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	101,453	102,676	105,601
Net earnings	87,326	88,155	91,551
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	143,303	136,732	129,514
Deferred income tax expense	55,787	50,043	65,479
Net unrealized (gains) on derivatives	-6,504	-1,866	-1,598
Realized (gains) on available-for-sale securities	-10,527	-10,612	-12,965
Regulatory disallowances	1,062	12,235	0
Other, net	-1,391	-1,614	-170
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	-5,919	-3,021	-4,756
Materials, supplies, and fuel stock	5,570	-7,730	-5,268
Other current assets	-29,146	8,556	-3,014
Other assets	7,150	-13,363	-27,338
Accounts payable	212	2,807	11,028
Accrued interest and taxes	-3,599	72,740	47,666
Other current liabilities	-659	-27,376	-2,539
Proceeds from governmental grants	0	0	21,567
Other liabilities	42,325	-59,753	-54,787
Net cash flows from operating activities	299,117	260,454	268,420
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-316,800	-239,906	-196,800
Proceeds from sales of available-for-sale securities	117,989	271,140	167,330
Purchases of available-for-sale securities	-127,016	-282,000	-176,748
Return of principal on PVNGS lessor notes	20,758	23,357	23,455
Purchase of Rio Bravo	-36,235	0	0
Other, net	-363	3,843	2,406
Net cash flows from investing activities	-341,667	-223,566	-180,357
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	-49,200	28,100	-44,900
Short-term borrowings (repayments) - affiliate, net	-32,500	32,500	0
Long-term borrowings	275,000	75,000	20,000
Repayment of long-term debt	-75,000	0	-20,000
Dividends paid	-30,791	-155,556	-34,961
Valencia’s transactions with its owner	-17,610	-18,335	-15,630
Other, net	-1,890	-2,534	-921
Net cash flows from financing activities	68,009	-40,825	-96,412
Change in Cash and Cash Equivalents	25,459	-3,937	-8,349
Cash and Cash Equivalents at Beginning of Year	21	3,958	12,307
Cash and Cash Equivalents at End of Year	25,480	21	3,958
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	73,787	71,306	73,036
Income taxes paid (refunded), net	-228	-77,434	-63,113
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	1,616	7,921	-19,732
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net Earnings	37,807	29,090	26,747
Net earnings	37,807	29,090	26,747
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	52,847	54,395	54,396
Deferred income tax expense	20,549	20,662	4,378
Other, net	-10	-30	-889
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	944	-4,542	2,208
Materials, supplies, and fuel stock	-66	150	-143
Other current assets	380	-1,137	-3,515
Other assets	-6,607	941	-3,145
Accounts payable	2,514	3,709	-666
Accrued interest and taxes	4,796	-6,713	9,825
Other current liabilities	-203	-3,197	-2,106
Other liabilities	3,112	460	4,311
Net cash flows from operating activities	116,063	93,788	91,401
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-127,191	-89,117	-92,973
Net cash flows from investing activities	-127,191	-89,117	-92,973
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	5,000	0	0
Short-term borrowings (repayments) - affiliate, net	-6,700	1,100	27,600
Long-term borrowings	80,000	0	0
Repayment of long-term debt	-50,000	0	0
Cash paid in debt exchange	0	-13,048	0
Equity contribution from parent	0	13,800	0
Dividends paid	-16,336	-3,726	-26,028
Other, net	-836	-2,797	0
Net cash flows from financing activities	11,128	-4,671	1,572
Change in Cash and Cash Equivalents	0	0	0
Cash and Cash Equivalents at Beginning of Year	1	1	1
Cash and Cash Equivalents at End of Year	1	1	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	22,803	25,436	25,360
Income taxes paid (refunded), net	-355	4,484	1,848
Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	-854	141	-2,749
Premium on long-term debt incurred in connection with debt exchange		$36,297

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$28,274,000	$2,533,000
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,423 for PNMR and PNM	87,038,000	90,251,000
Unbilled revenues	63,719,000	58,806,000
Other receivables	39,857,000	53,909,000
Materials, supplies, and fuel stock	63,628,000	67,223,000
Regulatory assets	47,855,000	24,416,000
Commodity derivative instruments	11,232,000	4,064,000
Income taxes receivable	6,360,000	7,066,000
Current portion of accumulated deferred income taxes	26,383,000	58,681,000
Other current assets	58,471,000	34,590,000
Total current assets	432,817,000	401,539,000
Other Property and Investments:
Investment in PVNGS lessor notes	9,538,000	32,200,000
Available-for-sale securities	250,145,000	226,855,000
Other investments	1,762,000	1,835,000
Non-utility property	3,406,000	4,353,000
Total other property and investments	264,851,000	265,243,000
Utility Plant:
Plant in service and plant held for future use	5,941,581,000	5,563,061,000
Less accumulated depreciation and amortization	1,939,760,000	1,838,832,000
Net plant in service and plant held for future use	4,001,821,000	3,724,229,000
Construction work in progress	190,389,000	132,080,000
Nuclear fuel, net of accumulated amortization of $44,507 and $47,347 for PNMR and PNM	77,796,000	77,602,000
Net utility plant	4,270,006,000	3,933,911,000
Deferred Charges and Other Assets:
Regulatory assets	491,007,000	523,955,000
Goodwill	278,297,000	278,297,000
Commodity derivative instruments	0	3,002,000
Other deferred charges	92,347,000	94,263,000
Total deferred charges and other assets	861,651,000	899,517,000
Total Assets	5,829,325,000	5,500,210,000
Current Liabilities:
Short-term debt	105,600,000	149,200,000
Current installments of long-term debt	333,066,000	75,000,000
Accounts payable	110,029,000	109,666,000
Customer deposits	12,555,000	13,456,000
Accrued interest and taxes	53,863,000	49,600,000
Regulatory liabilities	1,703,000	1,081,000
Commodity derivative instruments	1,209,000	2,699,000
Dividends declared	16,063,000	14,864,000
Other current liabilities	70,194,000	77,105,000
Total current liabilities	704,282,000	492,671,000
Long-term Debt	1,642,024,000	1,670,420,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	891,111,000	827,263,000
Regulatory liabilities	466,143,000	460,649,000
Asset retirement obligations	104,170,000	96,135,000
Accrued pension liability and postretirement benefit cost	110,738,000	80,046,000
Commodity derivative instruments	477,000	1,094,000
Other deferred credits	103,759,000	109,805,000
Total deferred credits and other liabilities	1,676,398,000	1,574,992,000
Total liabilities	4,022,704,000	3,738,083,000
Commitments and Contingencies (See Note 16)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529,000	11,529,000
Company common stockholders’ equity:
Common stock outstanding	1,173,845,000	1,178,369,000
Accumulated other comprehensive income (loss), net of income taxes	-61,755,000	-58,140,000
Retained earnings	609,456,000	553,340,000
Total PNMR common stockholders’ equity	1,721,546,000	1,673,569,000
Non-controlling interest in Valencia	73,546,000	77,029,000
Total equity	1,795,092,000	1,750,598,000
Total liabilities and stockholders' equity	5,829,325,000	5,500,210,000
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	1,000	1,000
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,423 for PNMR and PNM	19,416,000	20,125,000
Unbilled revenues	9,579,000	9,814,000
Other receivables	2,063,000	1,246,000
Materials, supplies, and fuel stock	2,769,000	2,703,000
Regulatory assets	3,875,000	5,022,000
Current portion of accumulated deferred income taxes	6,398,000	6,501,000
Other current assets	938,000	980,000
Total current assets	45,039,000	46,392,000
Other Property and Investments:
Other investments	242,000	245,000
Non-utility property	2,240,000	2,240,000
Total other property and investments	2,482,000	2,485,000
Utility Plant:
Plant in service and plant held for future use	1,182,112,000	1,074,193,000
Less accumulated depreciation and amortization	375,407,000	352,105,000
Net plant in service and plant held for future use	806,705,000	722,088,000
Construction work in progress	16,538,000	16,790,000
Net utility plant	823,243,000	738,878,000
Deferred Charges and Other Assets:
Regulatory assets	133,962,000	139,738,000
Goodwill	226,665,000	226,665,000
Other deferred charges	8,850,000	8,273,000
Total deferred charges and other assets	369,477,000	374,676,000
Total Assets	1,240,241,000	1,162,431,000
Current Liabilities:
Short-term debt	5,000,000	0
Short-term debt - affiliate	22,700,000	29,400,000
Accounts payable	14,203,000	12,543,000
Affiliate payables	2,469,000	3,181,000
Accrued interest and taxes	28,574,000	23,778,000
Other current liabilities	2,271,000	8,999,000
Total current liabilities	75,217,000	77,901,000
Long-term Debt	365,667,000	336,036,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	217,945,000	190,197,000
Regulatory liabilities	40,662,000	46,038,000
Asset retirement obligations	848,000	782,000
Accrued pension liability and postretirement benefit cost	7,888,000	3,435,000
Other deferred credits	7,349,000	5,111,000
Total deferred credits and other liabilities	274,692,000	245,563,000
Total liabilities	715,576,000	659,500,000
Commitments and Contingencies (See Note 16)
Company common stockholders’ equity:
Common stock outstanding	64,000	64,000
Paid-in-capital	404,166,000	404,166,000
Accumulated other comprehensive income (loss), net of income taxes	0	-263,000
Retained earnings	120,435,000	98,964,000
Total PNMR common stockholders’ equity	524,665,000	502,931,000
Total liabilities and stockholders' equity	1,240,241,000	1,162,431,000
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	25,480,000	21,000
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,423 for PNMR and PNM	67,622,000	70,126,000
Unbilled revenues	54,140,000	48,992,000
Other receivables	37,622,000	52,964,000
Affiliate receivables	8,853,000	10,054,000
Materials, supplies, and fuel stock	60,859,000	64,520,000
Regulatory assets	43,980,000	19,394,000
Commodity derivative instruments	11,232,000	4,064,000
Income taxes receivable	6,105,000	4,030,000
Current portion of accumulated deferred income taxes	12,418,000	43,827,000
Other current assets	53,095,000	30,510,000
Total current assets	381,406,000	348,502,000
Other Property and Investments:
Investment in PVNGS lessor notes	9,538,000	32,200,000
Available-for-sale securities	250,145,000	226,855,000
Other investments	397,000	445,000
Non-utility property	96,000	976,000
Total other property and investments	260,176,000	260,476,000
Utility Plant:
Plant in service and plant held for future use	4,581,066,000	4,314,016,000
Less accumulated depreciation and amortization	1,486,406,000	1,402,531,000
Net plant in service and plant held for future use	3,094,660,000	2,911,485,000
Construction work in progress	169,673,000	107,344,000
Nuclear fuel, net of accumulated amortization of $44,507 and $47,347 for PNMR and PNM	77,796,000	77,602,000
Net utility plant	3,342,129,000	3,096,431,000
Deferred Charges and Other Assets:
Regulatory assets	357,045,000	384,217,000
Goodwill	51,632,000	51,632,000
Commodity derivative instruments	0	3,002,000
Other deferred charges	81,264,000	83,356,000
Total deferred charges and other assets	489,941,000	522,207,000
Total Assets	4,473,652,000	4,227,616,000
Current Liabilities:
Short-term debt	0	49,200,000
Short-term debt - affiliate	0	32,500,000
Current installments of long-term debt	214,300,000	75,000,000
Accounts payable	86,055,000	84,643,000
Customer deposits	12,555,000	13,456,000
Affiliate payables	18,232,000	20,498,000
Accrued interest and taxes	29,298,000	27,665,000
Regulatory liabilities	1,703,000	1,081,000
Commodity derivative instruments	1,209,000	2,699,000
Dividends declared	132,000	132,000
Other current liabilities	52,053,000	50,392,000
Total current liabilities	415,537,000	357,266,000
Long-term Debt	1,276,357,000	1,215,618,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	715,814,000	677,094,000
Regulatory liabilities	425,481,000	414,611,000
Asset retirement obligations	103,182,000	95,225,000
Accrued pension liability and postretirement benefit cost	102,850,000	76,611,000
Commodity derivative instruments	477,000	1,094,000
Other deferred credits	86,023,000	91,340,000
Total deferred credits and other liabilities	1,433,827,000	1,355,975,000
Total liabilities	3,125,721,000	2,928,859,000
Commitments and Contingencies (See Note 16)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529,000	11,529,000
Company common stockholders’ equity:
Common stock outstanding	1,061,776,000	1,061,776,000
Accumulated other comprehensive income (loss), net of income taxes	-61,755,000	-57,877,000
Retained earnings	262,835,000	206,300,000
Total PNMR common stockholders’ equity	1,262,856,000	1,210,199,000
Non-controlling interest in Valencia	73,546,000	77,029,000
Total equity	1,336,402,000	1,287,228,000
Total liabilities and stockholders' equity	$4,473,652,000	$4,227,616,000

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Allowance for uncollectible accounts	$1,466	$1,423
Accumulated depreciation, nuclear fuel	44,507	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 outstanding	115,293	115,293
Common stock, par value	$0	$0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	79,653,624	79,653,624
Common stock, shares outstanding	79,653,624	79,653,624
Cumulative preferred stock of subsidiary, shares authorized	10,000,000
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,466	1,423
Accumulated depreciation, nuclear fuel	$44,507	$47,347
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
Cumulative preferred stock of subsidiary, stated value	$100	$100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding	115,293	115,293
Texas-New Mexico Power Company [Member]
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
Common stock, par value	$10	$10
Cumulative preferred stock of subsidiary, shares authorized	1,000,000

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)	Total	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Total PNMR Common Stockholders' Equity [Member]	Non-controlling Interest in Valencia [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member]	Texas-New Mexico Power Company [Member]
In Thousands, unless otherwise specified								Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Total PNMR Common Stockholders' Equity [Member]	Non-controlling Interest in Valencia [Member]		Common Stock [Member]	Additional Paid-in Capital [Member]	AOCI [Member]	Retained Earnings [Member]
Balance TNMP at Dec. 31, 2011													$463,253	$64	$416,394	($58)	$46,853
Balance at Dec. 31, 2011	1,656,408	1,193,191	-66,856	447,650	1,573,985	82,423	1,294,512	1,061,776	-66,798	217,111	1,212,089	82,423
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	11,684		0	0	11,684	0
Purchases to satisfy awards of common stock	25,168		0	0	25,168	0
Net earnings (loss)	105,547						91,551						26,747	0	0	0
Excess tax (shortfall) from stock-based payment arrangements	-473	-473	0	0	-473	0
Stock based compensation expense	3,585		0	0	3,585	0
Valenciabs transactions with its owner	-15,630	0	0	0	0		-15,630	0	0	0	0
Net earnings	120,125	0	0	106,075	106,075	14,050	105,601	0	0	91,551	91,551	14,050	26,747
Preferred Stock Dividends Requirements	-528	0	0		-528	0	-528	0	0		-528	0	0
Total other comprehensive income (loss)	-14,774	0	-14,774	0	-14,774	0	-14,616	0	-14,616	0	-14,616	0	-158	0	0	-158	0
Equity contribution from parent													0
Dividends declared on common stock	-46,199	0	0	-46,199	-46,199	0	-34,433	0	0	-34,433	-34,433	0	-26,028	0		0	0
Balance TNMP at Dec. 31, 2012													463,814	64	390,366	-216	73,600
Balance at Dec. 31, 2012	1,689,030	1,182,819	-81,630	506,998	1,608,187	80,843	1,334,906	1,061,776	-81,414	273,701	1,254,063	80,843
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	4,618		0	0	4,618	0
Purchases to satisfy awards of common stock	13,807		0	0	13,807	0
Net earnings (loss)	100,507						88,155						29,090	0	0	0
Excess tax (shortfall) from stock-based payment arrangements	-581	-581	0	0	-581	0
Stock based compensation expense	5,320		0	0	5,320	0
Valenciabs transactions with its owner	-18,335	0	0	0	0		-18,335	0	0	0	0
Net earnings	115,556	0	0	101,035	101,035	14,521	102,676	0	0	88,155	88,155	14,521	29,090
Preferred Stock Dividends Requirements	-528	0	0		-528	0	-528	0	0		-528	0	0
Total other comprehensive income (loss)	23,490	0	23,490	0	23,490	0	23,537	0	23,537	0	23,537	0	-47	0	0	-47	0
Equity contribution from parent													13,800	0	13,800	0	0
Dividends declared on common stock	-54,165	0	0	-54,165	-54,165	0	-155,028	0	0	-155,028	-155,028	0	-3,726	0	0	0
Balance TNMP at Dec. 31, 2013	1,673,569						1,210,199						502,931	64	404,166	-263	98,964
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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	6,999		0	0	6,999	0
Purchases to satisfy awards of common stock	17,319		0	0	17,319	0
Net earnings (loss)	116,254						87,326						37,807	0	0	0
Excess tax (shortfall) from stock-based payment arrangements	-135	-135	0	0	-135	0
Stock based compensation expense	5,931		0	0	5,931	0
Valenciabs transactions with its owner	-17,610	0	0	0	0		-17,610	0	0	0	0
Net earnings	130,909	0	0	116,782	116,782	14,127	101,453	0	0	87,326	87,326	14,127	37,807
Preferred Stock Dividends Requirements	-528	0	0		-528	0	-528	0	0		-528	0	0
Total other comprehensive income (loss)	-3,615	0	-3,615	0	-3,615	0	-3,878	0	-3,878	0	-3,878	0	263	0	0	263	0
Equity contribution from parent													0
Dividends declared on common stock	-60,138	0	0	-60,138	-60,138	0	-30,263	0	0	-30,263	-30,263	0	-16,336	0	0	0
Balance TNMP at Dec. 31, 2014	1,721,546						1,262,856						524,665	64	404,166	0	120,435
Balance at Dec. 31, 2014	$1,795,092	$1,173,845	($61,755)	$609,456	$1,721,546	$73,546	$1,336,402	$1,061,776	($61,755)	$262,835	$1,262,856	$73,546

Summary_of_the_Business_and_Si

Summary of the Business and Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Summary of the Business and Significant Accounting Policies

Summary of the Business and Significant Accounting Policies

Nature of Business

PNMR is an investor-owned holding company of energy and energy-related businesses. PNMR’s primary subsidiaries are PNM and TNMP. PNM is a public utility with regulated operations primarily engaged in the generation, transmission, and distribution of electricity. TNMP is a wholly owned subsidiary of TNP, which is a holding company that is wholly owned by PNMR. TNMP provides regulated transmission and distribution services in Texas. PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM.

Financial Statement Preparation and Presentation

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.

The Notes to Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. For discussion purposes, 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 and 2012 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2014 financial statement presentation.

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 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 (Note 9). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 18.

Accounting for the Effects of Certain Types of Regulation

The Company maintains its accounting records in accordance with the uniform system of accounts prescribed by FERC and adopted by the NMPRC and PUCT.

Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to the regulated operations. Regulators may assign costs to accounting periods that differ from accounting methods applied by non-regulated utilities.  When it is probable that regulators will permit recovery of costs through future rates, costs that otherwise would be expensed are deferred as regulatory assets.  Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred.  Regulatory assets and liabilities are amortized into earnings over the authorized recovery period. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the NMPRC, PUCT, and FERC. Information on regulatory assets and regulatory liabilities is contained in Note 4.

In some circumstances, regulators allow a requested increase in rates to be implemented, subject to refund, before the regulatory process has been completed and a decision rendered by the regulator. When this occurs, the Company assesses the possible outcomes of the rate proceeding. The Company records a provision for refund to the extent the amounts being collected, subject to refund, exceed the amount the Company determines is probable of ultimately being allowed by the regulator.

Competition Transition Charge

In connection with the adoption of Senate Bill 7 by the Texas Legislature in 1999 that deregulated electric utilities operating within ERCOT, TNMP was allowed to recover its stranded costs through the CTC and to also recover a carrying charge on the CTC. The amounts yet to be collect are recorded as regulatory assets by TNMP. TNMP’s calculation of allowable carrying charges on stranded costs recoverable from its transmission and distribution customers is based on a Texas Supreme Court ruling and the PUCT’s application of that ruling.

Cash and Cash Equivalents

Investments in highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.

Utility Plant

Utility plant is stated at cost, which includes capitalized payroll-related costs such as taxes, pension, and other fringe benefits, administrative costs, and AFUDC where authorized by rate regulation.

Repairs, including major maintenance activities, and minor replacements of property are expensed when incurred, except as required by regulators for ratemaking purposes. Major replacements are charged to utility plant. Gains or losses resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to accumulated depreciation.

Allowance for Funds Used During Construction

As provided by the FERC uniform systems of accounts, AFUDC is charged to regulated utility plant for construction projects. This allowance is a non-cash item designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). The allowance for borrowed funds used during construction is recorded in interest charges and the allowance for equity funds used during construction is recorded in other income on the Consolidated Statements of Earnings.

For the years ended December 31, 2014, 2013, and 2012, PNM recorded $4.2 million, $3.3 million, and $3.5 million of allowance for borrowed funds used during construction and $5.6 million, $4.4 million, and $3.8 million of allowance for equity funds used during construction. TNMP recorded $0.5 million, $0.4 million, and $0.7 million of allowance for borrowed funds used during construction and zero, zero, and $0.6 million of allowance for equity funds used during construction.

Capitalized Interest

The Company capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC. Interest was capitalized at the overall weighted average borrowing rate of 6.6%, 6.9%, and 6.6% for 2014, 2013, and 2012. In 2014, 2013, and 2012, capitalized interest was $1.6 million, $1.5 million, and $1.2 million for PNMR consolidated; $1.1 million, $1.1 million, and $0.8 million for PNM; and $0.1 million, zero, and zero for TNMP.

Materials, Supplies, and Fuel Stock

Materials and supplies relate to transmission, distribution, and generating assets. Materials and supplies are charged to inventory when purchased and are expensed or capitalized as appropriate when issued. Materials and supplies are valued using an average costing method.

Coal is valued using a rolling weighted average costing method that is updated based on the current period cost per ton. Periodic aerial surveys are performed on the coal piles and adjustments are made.

Inventories consisted of the following at December 31:

PNMR

PNM

TNMP

2014

2013

2014

2013

2014

2013

(In thousands)

Coal

$

17,525

$

24,872

$

17,525

$

24,872

$

—

$

—

Materials and supplies

46,103

42,351

43,334

39,648

2,769

2,703

$

63,628

$

67,223

$

60,859

$

64,520

$

2,769

$

2,703

Investments

In 1985 and 1986, PNM entered into eleven operating leases for interests in certain PVNGS generation facilities (Note 7). The 10.3% and 10.15% lessor notes that were issued by the owners of the assets subject to these leases were subsequently purchased and held by the PVNGS Capital Trust, which is consolidated by PNM. Eight leases continue and are classified as operating leases. The PVNGS Capital Trust held certain of the lessor notes to their maturity in January 2015 and intends to hold the other lessor notes until their maturity in 2016. The PVNGS lessor notes are carried at amortized cost. Similarly, in 1985, PNM entered into two operating leases for the EIP transmission line for which the owners had issued lessor notes. In 2003, PNM acquired a 60% ownership interest in the EIP, collapsing the lease relating to it. In 2004, PNM purchased the outstanding lessor note relating to the remaining 40% interest. The remaining EIP lessor note bore interest at 10.25% and matured in 2012.

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). All of these investments are classified as available-for-sale. PNM evaluates the securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2014, 2013, and 2012, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $4.8 million, $3.5 million, and $4.8 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI. The available-for-sale securities are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in PNM’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions.

Goodwill

Under GAAP, the Company does not amortize goodwill. Goodwill is evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill might be impaired. See Note 21.

Asset Impairment

Tangible long-lived assets are evaluated in relation to the estimated future undiscounted cash flows to assess recoverability when events and circumstances indicate that the assets might be impaired.

Revenue Recognition

Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience.

PNM’s wholesale electricity sales are recorded as electric operating revenues and the wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are net settled or “booked-out” are recorded net in earnings. A book-out is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.

Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consists primarily of trade receivables from customers. In the normal course of business, credit is extended to customers on a short-term basis. The Company calculates the allowance for uncollectible accounts based on historical experience and estimated default rates. The accounts receivable balances are reviewed monthly and adjustments to the allowance for uncollectible accounts and bad debt expense are made as necessary. Amounts that are deemed uncollectible are written off.

Depreciation and Amortization

PNM’s provision for depreciation and amortization of utility plant, other than nuclear fuel, is based upon composite straight-line rates approved by the NMPRC. Amortization of nuclear fuel is based on units-of-production. TNMP’s provision for depreciation and amortization of utility plant is based upon straight-line rates approved by the PUCT. Depreciation of non-utility property is computed based on the straight-line method. The provision for depreciation of certain equipment is allocated between operating expenses and construction projects based on the use of the equipment. Average straight-line rates used were as follows:

Year ended December 31

2014

2013

2012

PNM

Electric plant

2.26

%

2.27

%

2.25

%

Common, intangible, and general plant

4.64

%

4.87

%

5.35

%

TNMP

3.59

%

3.66

%

3.56

%

Amortization of Debt Acquisition Costs

Discount, premium, and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. Gains and losses incurred upon the early retirement of long-term debt are recognized in other income or other deductions, except for amounts attributable to NMPRC, FERC, or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues.

Derivatives

The Company records derivative instruments, including energy contracts, other than those designated as normal purchases or normal sales, in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or normal sale criteria are met. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.

The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity. GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances.

Decommissioning and Reclamation Costs

PNM owns and leases nuclear and fossil-fuel generating facilities. In accordance with GAAP, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Nuclear decommissioning costs and related accruals are based on periodic site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions, including estimates of future decommissioning costs at current price levels, inflation rates, and discount rates. PNM’s accruals for PVNGS Units 1, 2, and 3, including portions held under leases, have been made based on such estimates, the guidelines of the NRC, and the extended PVNGS license periods. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 is currently excluded. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fueled generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. See Note 15 and Note 16.

In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation, as well as the costs for final reclamation of the coal mines. The reclamation costs are based on periodic site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions, including estimates of future reclamation costs at current price levels, inflation rates, and discount rates. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for a discussion of the final reclamation costs.

Environmental Costs

The normal operations of the Company involve activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred.

The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Amounts recorded for environmental expense in the years ended December 31, 2014, 2013, and 2012, as well as the amounts of environmental liabilities at December 31, 2014 and 2013 were insignificant.

Pension and Other Postretirement Benefits

See Note 12 for a discussion of pension and postretirement benefits expense, including a discussion of the actuarial assumptions.

Stock-Based Compensation

See Note 13 for a discussion of stock-based compensation expense.

Income Taxes

Income taxes are recognized using the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current NMPRC, FERC, and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC, FERC, and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets. See Note 11.

The Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. Year-to-date income tax expense is then calculated by applying the anticipated annual effective tax rate to year-to-date earnings before taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, as well as adjustments due to enactment of new tax laws, be excluded from the estimated annual effective tax rate calculation.

Excise Taxes

The Company pays certain fees or taxes which are either considered to be an excise tax or similar to an excise tax. Substantially all of these taxes are recorded on a net basis in the Consolidated Statements of Earnings.

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard 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 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is in the process of analyzing the impacts of this new standard.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 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 includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale and transmission rates.
	TNMP
	TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT.
	Corporate and Other
	The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.
	The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.
	PNMR SEGMENT INFORMATION
	2014	PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Electric operating revenues	$	1,147,914		$	287,939		$	—		$	1,435,853
	Cost of energy	403,626			67,930			—			471,556
	Margin	744,288			220,009			—			964,297
	Other operating expenses	422,051			84,365			(14,450		)	491,966
	Depreciation and amortization	109,524			50,056			13,054			172,634
	Operating income	212,713			85,588			1,396			299,697
	Interest income	8,557			—			(74		)	8,483
	Other income (deductions)	12,258			2,138			(2,302		)	12,094
	Interest charges	(79,442		)	(27,396		)	(12,789		)	(119,627		)
	Segment earnings (loss) before income taxes	154,086			60,330			(13,769		)	200,647
	Income taxes (benefit)	52,633			22,523			(5,418		)	69,738
	Segment earnings (loss)	101,453			37,807			(8,351		)	130,909
	Valencia non-controlling interest	(14,127		)	—			—			(14,127		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	86,798		$	37,807		$	(8,351	)	$	116,254
	Gross property additions	$	316,800		$	127,191		$	16,667		$	460,658
	At December 31, 2014:
	Total Assets	$	4,473,652		$	1,240,241		$	115,432		$	5,829,325
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2013	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,116,312		$	271,611		$	—		$	1,387,923
	Cost of energy	374,710			57,606			—			432,316
	Margin	741,602			214,005			—			955,607
	Other operating expenses	428,591			91,601			(18,308		)	501,884
	Depreciation and amortization	103,826			50,219			12,836			166,881
	Operating income	209,185			72,185			5,472			286,842
	Interest income	10,182			—			(139		)	10,043
	Other income (deductions)	11,288			1,919			(13,575		)	(368		)
	Interest charges	(79,175		)	(27,393		)	(14,880		)	(121,448		)
	Segment earnings (loss) before income taxes	151,480			46,711			(23,122		)	175,069
	Income taxes (benefit)	48,804			17,621			(6,912		)	59,513
	Segment earnings (loss)	102,676			29,090			(16,210		)	115,556
	Valencia non-controlling interest	(14,521		)	—			—			(14,521		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	87,627		$	29,090		$	(16,210	)	$	100,507
	Gross property additions	$	239,906		$	89,117		$	19,016		$	348,039
	At December 31, 2013:
	Total Assets	$	4,227,616		$	1,162,431		$	110,163		$	5,500,210
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2012	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,092,264		$	250,140		$	(1	)	$	1,342,403
	Cost of energy	353,649			46,201			—			399,850
	Margin	738,615			203,939			(1		)	942,553
	Other operating expenses	435,442			87,079			(17,862		)	504,659
	Depreciation and amortization	97,291			49,340			17,542			164,173
	Operating income	205,882			67,520			319			273,721
	Interest income	13,243			1			(172		)	13,072
	Gain on sale of First Choice	—			—			1,012			1,012
	Other income (deductions)	13,290			2,739			(7,954		)	8,075
Interest charges	(76,101		)	(28,161		)	(16,583		)	(120,845		)
Segment earnings (loss) before income taxes	156,314			42,099			(23,378		)	175,035
Income taxes (benefit)	50,713			15,352			(11,155		)	54,910
Segment earnings (loss)	105,601			26,747			(12,223		)	120,125
Valencia non-controlling interest	(14,050		)	—			—			(14,050		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	91,023		$	26,747		$	(12,223	)	$	105,547
Gross property additions	$	196,800		$	92,973		$	19,136		$	308,909
At December 31, 2012:
Total Assets	$	4,163,907		$	1,086,229		$	122,447		$	5,372,583
Goodwill	$	51,632		$	226,665		$	—		$	278,297
Major Customers
No individual customer accounted for more than 10% of the electric operating revenues of PNMR or PNM. The acquiror of First Choice, including the former First Choice operations, accounted for 15% and 17% of TNMP’s electric operating revenues in 2014 and 2013. Two other unaffiliated customers of TNMP accounted for revenues of 15% in 2014, 16% in 2013, and 17% in 2012 and 11% in 2014, 10% in 2013, and 10% in 2012.

Sale_of_First_Choice

Sale of First Choice	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Sale of First Choice	Sale of First Choice
	PNMR completed the sale of First Choice, which was also a subsidiary of TNP, on November 1, 2011. First Choice was a competitive REP operating in Texas. The amount received was subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. In 2012, PNMR received an additional amount and recorded a pre-tax gain of $1.0 million, which is included in Other income in the Consolidated Statements of Earnings. PNMR Services Company continued to provide certain services at cost to First Choice for a transitional period through August 1, 2012. Because PNMR continues to have direct cash flows resulting from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities
	The operations of PNM and TNMP are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to its regulated operations. Regulatory assets represent probable future recovery of previously incurred costs that will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below.
	PNM
		December 31,
		2014			2013
	Assets:	(In thousands)
	Current:
	FPPAC	$	43,980		$	19,394
	Non-Current:
	Coal mine reclamation costs	34,224			40,144
	Deferred income taxes	63,645			61,850
	Loss on reacquired debt	25,439			27,490
	Pension and OPEB	222,545			206,691
	FPPAC	—			25,386
	Renewable energy costs	5,263			13,311
	Other	5,929			9,345
		357,045			384,217
	Total regulatory assets	$	401,025		$	403,611
	Liabilities:
	Current:
	Other	$	(1,703	)	$	(1,081	)
	Non-Current:
	Cost of removal	(277,148		)	(266,075		)
	Deferred income taxes	(75,941		)	(80,495		)
	AROs	(35,834		)	(37,567		)
	Renewable energy tax benefits	(24,854		)	(26,011		)
	Other	(11,704		)	(4,463		)
		(425,481		)	(414,611		)
	Total regulatory liabilities	$	(427,184	)	$	(415,692	)
	TNMP
		December 31,
		2014			2013
	Assets:	(In thousands)
	Current:
	Transmission cost recovery factor	$	2,482		$	4,250
	Other	1,393			772
		3,875			5,022
	Non-Current:
	CTC, including carrying charges	55,292			63,606
	Deferred income taxes	10,556			10,868
	Pension	23,803			19,938
	Loss on reacquired debt	36,703			38,616
	AMS retirement costs	6,453			5,083
	Other	1,155			1,627
		133,962			139,738
	Total regulatory assets	$	137,837		$	144,760
	Liabilities:
	Non-Current:
	Cost of removal	$	(29,391	)	$	(30,863	)
	Deferred income taxes	(3,923		)	(4,563		)
	AMS surcharge	(5,227		)	(7,251		)
	OPEB	(2,121		)	(3,361		)
	Total regulatory liabilities	$	(40,662	)	$	(46,038	)
	The Company’s regulatory assets and regulatory liabilities are reflected in rates charged to customers or have been addressed in a regulatory proceeding. The Company does not receive or pay a rate of return on the following regulatory assets and regulatory liabilities (and their remaining amortization periods): coal mine reclamation costs (through 2020); deferred income taxes (over the remaining life of the taxable item, up to the remaining life of utility plant); pension and OPEB costs (through 2033); and AROs (to be determined in a future regulatory proceeding). In addition, TNMP does not receive a return on substantially all of its loss on reacquired debt (through 2043).
	The Company is permitted, under rate regulation, to accrue and record a regulatory liability for the estimated cost of removal and salvage associated with certain of its assets through depreciation expense. Under GAAP, actuarial losses and prior service costs for pension plans are required to be recorded in AOCI; however, to the extent authorized for recovery through the regulatory process these amounts are recorded as regulatory assets or liabilities. Based on prior regulatory approvals, the amortization of these amounts will be included in the Company’s rates.
	Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that future recovery of its regulatory assets are probable.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Stockholders’ Equity
	Common Stock and Equity Contributions
	PNMR, PNM, and TNMP did not issue any common stock during the three year period ended December 31, 2014. PNMR funded a cash equity contribution of $13.8 million to TNMP in 2013. PNMR offers shares of PNMR common stock through the PNMR Direct Plan. PNMR utilizes shares of its common stock purchased on the open market, by an independent agent, rather than issuing additional shares to satisfy subscriptions under the PNMR Direct Plan. The shares of PNMR common stock utilized in the PNMR Direct Plan are offered under a SEC shelf registration statement that expires in August 2015.
	Dividends on Common Stock
	The declaration of common dividends by PNMR is dependent upon a number of factors, including the ability of PNMR’s subsidiaries to pay dividends. PNMR’s primary sources of dividends are its operating subsidiaries.
	PNM declared and paid cash dividends to PNMR of $30.3 million, $155.0 million, and $34.4 million in 2014, 2013, and 2012. TNMP paid cash dividends to PNMR of $16.3 million, $3.7 million, and $26.0 million in 2014, 2013, and 2012. TNMP recorded dividends paid in 2012 as reductions of paid-in-capital.
	The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including the restriction that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC provisions allow PNM to pay dividends from equity contributions previously made by PNMR and current earnings, determined on a rolling four quarter basis, without prior NMPRC approval. The Federal Power Act also imposes certain restrictions on dividends by public utilities. Each of the PNMR Revolving Credit Facility, PNMR Term Loan Agreement, PNM Revolving Credit Facility, PNM New Mexico Credit Facility, PNM 2014 Term Loan Agreement, PNM Multi-draw Term Loan, and TNMP Revolving Credit Facility contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%, which could limit amounts of dividends that could be paid. For PNMR and PNM, these ratios reflect the present value of payments under the PVNGS leases as debt. PNM also has other financial covenants that limit the transfer of assets, through dividends or other means, including a requirement to obtain approval of certain financial counterparties to transfer more than five percent of PNM’s assets. As of December 31, 2014, none of the numerical tests would restrict the payment of dividends from the retained earnings of PNMR, PNM, or TNMP, except that PNM would not be able to distribute amounts in excess of approximately $223 million and TNMP would not be able to distribute amounts in excess of approximately $203 million without approval of regulators or financial counterparties.
	In addition, the ability of PNMR to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, financial circumstances and performance, current and future regulatory decisions, Congressional and legislative acts, and economic conditions. Conditions imposed by the NMPRC or PUCT, future growth plans and related capital requirements, and business considerations may also affect PNMR’s ability to pay dividends.
	Preferred Stock
	PNM’s cumulative preferred shares outstanding bear dividends at 4.58% per annum. PNM preferred stock does not have a mandatory redemption requirement but may be redeemed, at PNM’s option, at 102% of the stated value plus accrued dividends. The holders of the PNM preferred stock are entitled to payment before the holders of common stock in the event of any liquidation or dissolution or distribution of assets of PNM. In addition, PNM’s preferred stock is not entitled to a sinking fund and cannot be converted into any other class of stock of PNM.
	PNMR and TNMP have no preferred stock outstanding. The authorized shares of PNMR and TNMP preferred stock are 10 million shares and 1 million shares.

Financing

Financing	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Financing	Financing
	Financing Activities
	PNMR
	In the year ended December 31, 2013, PNMR purchased $23.8 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, through several open-market purchases, for $26.9 million plus accrued and unpaid interest. PNMR recognized losses of $3.3 million on these purchases, including transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which are included in Other deductions on the Consolidated Statements of Earnings.
	On December 14, 2012, PNMR entered into a $100.0 million Term Loan Agreement (as amended and restated, the “PNMR Term Loan Agreement”) among PNMR, the lenders identified therein, and JPMorgan Chase Bank, N.A., as Administrative Agent. On December 27, 2012, PNMR borrowed $100.0 million under the agreement and used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility. On December 27, 2013, PNMR entered into an agreement that amended and restated the PNMR Term Loan Agreement extending the maturity date to December 26, 2014 from December 27, 2013. On December 22, 2014, PNMR entered into another agreement that amends and restates the PNMR Term Loan Agreement extending the maturity date to December 21, 2015. The PNMR Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio, and customary events of default. The PNMR Term Loan Agreement has a cross default provision and a change of control provision.
	PNM
	In September 2012, PNM participated in the issuance of $20.0 million of new PCRBs by the City of Farmington, New Mexico, which bear interest at 2.54% and mature September 1, 2042, with a mandatory tender on June 1, 2017. The new PCRBs refunded a $20.0 million series of PCRBs, which bore interest at 5.15% and matured in 2037, that were redeemed at par and retired.
	On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the “PNM 2013 Term Loan Agreement”) among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM 2013 Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility.
	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 the PNM 2013 Term Loan Agreement. PNM also used the funds to repay other short-term amounts outstanding. The PNM 2013 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 2013 Term Loan Agreement. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.11% at December 31, 2014, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.
	On December 22, 2014, PNM entered into a new multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million and remaining capacity was $25.0 million. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.75% at December 31, 2014. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw Term Loan Agreement has a cross default provision and a change of control provision.
	PNM has a shelf registration statement for the issuance of up to $500.0 million of senior unsecured notes that will expire in May 2017.
	TNMP
	On September 30, 2011, TNMP entered into the TNMP 2011 Term Loan Agreement and borrowed $50.0 million under it. Borrowings under the TNMP 2011 Term Loan Agreement were due by June 30, 2014. TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing over the life of the debt. This hedge was accounted for as a cash-flow hedge and had a fair value loss of $0.2 million at December 31, 2013, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.
	On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP’s $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in a premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. The premium amounted to $23.2 million, after reduction for the cash paid in the exchange. A regulatory asset was recorded offsetting the premium, including the cash consideration paid in the exchange.
	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 in the Consolidated Balance Sheet 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
	The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. In December 2014, both of these facilities were amended to extend their maturity from October 31, 2018 to October 31, 2019. In addition, the amendments provide for an additional one-year extension option for each facility, subject to approval by a majority of the lenders. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. Each of these facilities contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%.  For PNMR and PNM, these ratios reflect the present value of payments under the PVNGS leases as debt.
	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.
	At December 31, 2014, interest rates on outstanding borrowings were 1.02% for the PNMR Term Loan Agreement (discussed under Financing Activities above), 1.67% for the PNMR Revolving Credit Facility, and 1.17% for the TNMP Revolving Credit Facility. The PNM Revolving Credit Facility and the PNM New Mexico Credit Facility had no borrowings outstanding at December 31, 2014. Short-term debt outstanding consists of:
			December 31,
	Short-term Debt		2014				2013
			(In thousands)
	PNM:
	Revolving Credit Facility		$	—			$	49,200
	PNM New Mexico Credit Facility		—				—
	TNMP Revolving Credit Facility		5,000				—
	PNMR
	Revolving Credit Facility		600				—
	PNMR Term Loan Agreement		100,000				100,000
			$	105,600			$	149,200
	In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $7.7 million, $3.2 million, and $0.1 million at December 31, 2014 that reduce the available capacity under their respective revolving credit facilities.
	At February 20, 2015, PNMR, PNM, and TNMP had $291.5 million, $386.8 million, and $54.9 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 February 20, 2015, on a consolidated basis, was $768.2 million for PNMR. At February 20, 2015, PNMR had invested cash of $1.9 million, PNM had invested cash of $42.5 million, and TNMP had no invested cash. The above availability does not include remaining capacity of $25.0 million available under the PNM Multi-draw Term Loan at February 20, 2015.
	Long-Term Debt
	Information concerning long-term debt outstanding is as follows:
			December 31,
	Long-term Debt		2014				2013
			(In thousands)
	PNM Debt
	Senior Unsecured Notes, Pollution Control Revenue Bonds:
	4.875% due 2033		$	146,000			$	146,000
	6.25% due 2038		36,000				36,000
	4.75% due 2040, mandatory tender at June 1, 2017		37,000				37,000
	5.20% due 2040, mandatory tender at June 1, 2020		40,045				40,045
	5.90% due 2040		255,000				255,000
	6.25% due 2040		11,500				11,500
	2.54% due 2042, mandatory tender at June 1, 2017		20,000				20,000
	4.00% due 2043, mandatory tender at June 1, 2015		39,300				39,300
	5.20% due 2043, mandatory tender at June 1, 2020		21,000				21,000
	Senior Unsecured Notes:
	7.95% due 2018		350,000				350,000
	7.50% due 2018		100,025				100,025
	5.35% due 2021		160,000				160,000
	PNM Term Loan Agreement due 2014		—				75,000
	PNM Term Loan Agreement due 2015		175,000				—
	PNM Multi-draw Term Loan due 2016		100,000				—
	Unamortized premiums (discounts)		(213		)		(252		)
			1,490,657				1,290,618
	Less current maturities		214,300				75,000
			1,276,357				1,215,618
	TNMP Debt
	First Mortgage Bonds:
	2011 Term Loan Agreement, due 2014		—				50,000
	9.50% due 2019, Series 2009A		172,302				172,302
	6.95% due 2043, Series 2013A		93,198				93,198
4.03% due 2024, Series 2014A		80,000				—
Unamortized premiums (discounts)		20,167				20,536
		365,667				336,036
Less current maturities		—				—
		365,667				336,036
PNMR Debt
Senior unsecured notes, 9.25% due 2015		118,766				118,766
Less current maturities		118,766				—
		—				118,766
Total Consolidated PNMR Debt		1,975,090				1,745,420
Less current maturities		333,066				75,000
		$	1,642,024			$	1,670,420
Reflecting mandatory tender dates, long-term debt matures as follows:
	PNMR				PNM				TNMP		PNMR Consolidated
	(In thousands)
2015	$	118,766			$	214,300			$	—	$	333,066
2016	—				100,000				—		100,000
2017	—				57,000				—		57,000
2018	—				450,025				—		450,025
2019	—				—				172,302		172,302
Thereafter	—				669,545				173,198		842,743
Total	$	118,766			$	1,490,870			$	345,500	$	1,955,136
Borrowing Arrangements Between PNMR and its Subsidiaries
PNMR has one-year intercompany loan agreements with its subsidiaries. Individual subsidiary loan agreements vary in amount up to $100.0 million and have either reciprocal or non-reciprocal terms. Interest charged to the subsidiaries is equivalent to interest paid by PNMR on its short-term borrowings. As of December 31, 2014 and 2013, PNM had outstanding borrowings of zero and $32.5 million and TNMP had outstanding borrowings of $22.7 million and $29.4 million from PNMR. At February 20, 2015, PNM and TNMP had borrowings of zero and $17.3 million from PNMR.

Lease_Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Leases 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. Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation, and has no significant rights-of-way that will expire within the next five years. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. All of the Company’s leases, including the Navajo Nation rights-of-way agreement, are accounted for as operating leases.
	The PVNGS leases were entered into in 1985 and 1986 and 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 provided PNM with an option to purchase the leased assets at fair market value at the end of the leases, but PNM does not have a fixed price purchase option. In addition, the leases provided 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 value of the leased assets are greater than parameters set forth in the leases. The rental payments during the fixed renewal option periods would be 50% of the amounts during the original terms of the leases. Gross annual lease payments, before considering the impacts of amounts returned to PNM through ownership of the lessor notes, aggregate $33.0 million for the Unit 1 leases and $23.7 million for the Unit 2 leases. For leases that are extended, the leases provide PNM with the option to purchase the leased assets at fair market value at the end of the extended lease terms.
	Each lease provided that no later than three years prior to the expiration of the lease, PNM was required to give notice to the lessor if it would “retain” the leased assets (but without specifying whether it would purchase the leased assets or extend the lease) or “return” the leased assets to the lessor. Furthermore, each lease provided that, if PNM gave notice to “retain” the leased assets, PNM was required to give notice as to which of the purchase or renewal options it would exercise no later than two years prior to the expiration of the lease. The election made under each of the leases was independent of the elections made under the other 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 January 15, 2024. The annual payments during the renewal periods aggregate $16.5 million for the PVNGS Unit 1 leases and $1.6 million for the Unit 2 lease. The table of future lease payments as of December 31, 2014 shown below includes payments during the renewal periods for those leases that will be extended at the end of their original terms.
	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 31.25 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 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, $81.8 million on December 31, 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, $4.5 million on December 31, 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.
	Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the equity participants, and take title to the leased interests. If such an event had occurred as of December 31, 2014, PNM could have been required to pay the equity participants up to approximately $122.2 million on January 15, 2015 in addition to the scheduled lease payments due on January 15, 2015. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Exercise of renewal options under the leases requires that amounts payable to equity participants under the circumstances described above would increase to the fair market value as of the renewal date. Reflecting the lease renewals that were effective on January 15, 2015, if such an event were to occur, amounts payable to equity participants under the circumstances described above would be up to $217.3 million on July 15, 2015 in addition to the scheduled lease payments due on July 15, 2015.
	PNM owns 60% of the EIP and leases the other 40%, under a lease that expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease. On November 1, 2012, PNM and the lessor entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity.
	PNMR leases a building that was used as part of its corporate headquarters, as well as housing certain support functions for the utility operations of PNM and TNMP. The lease expires on November 30, 2015 and provides for annual rents of $1.9 million, which are included in the tables below. PNMR is also obligated to pay taxes, insurance, and utilities applicable to the building. In November 2011, PNMR notified the lessor of its intent to vacate the building by the end of 2012 and made a settlement offer to terminate the lease. A termination agreement was not reached with the lessor. As of December 31, 2012, PNMR completed the abandonment of this building, as well as the partial abandonment of another leased building. In accordance with GAAP, PNMR recorded an abandonment expense of $7.4 million at December 31, 2012. PNM was allocated $6.2 million and TNMP was allocated $1.2 million of the abandonment expense for the period ended December 31, 2012, which is reflected as administrative and general expense.
	Operating lease expense, including the PVNGS and EIP leases, was:
		PNMR		PNM		TNMP
		(In thousands)
	2014	$	82,756	$	76,745	$	3,932
	2013	$	82,882	$	78,306	$	2,663
	2012	$	84,794	$	78,483	$	2,871
	As discussed under Investments in Note 1, the PVNGS Capital Trust, which is consolidated by PNM, acquired the lessor notes that were issued by the PVNGS lessors. Future minimum operating lease payments at December 31, 2014 shown below have been reduced by payments on the PVNGS lessor notes of $24.0 million in 2015 and $9.0 million in 2016 that will be returned in cash to PNM:
		PNMR		PNM		TNMP
		(In thousands)
	2015	$	36,350	$	33,144	$	1,186
	2016	28,892		27,986		636
	2017	25,185		24,907		—
	2018	25,194		24,907		—
	2019	25,203		24,907		—
	Later years	134,068		133,842		—
	Total minimum lease payments	$	274,892	$	269,693	$	1,822

Fair_Value_of_Derivative_and_O

Fair Value of Derivative and Other Financial Instruments	12 Months Ended
	Dec. 31, 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. 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.
	Commodity Risk
	Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.
	Accounting for Derivatives
	Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the years ended December 31, 2014 and 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
		December 31,
		2014				2013
		(In thousands)
	PNM and PNMR
	Current assets	$	11,232			$	4,064
	Deferred charges	—				3,002
		11,232				7,066
	Current liabilities	(1,209		)		(2,699		)
	Long-term liabilities	(477		)		(1,094		)
		(1,686		)		(3,793		)
	Net	$	9,546			$	3,273
	Included in the above table are $3.0 million of current assets at December 31, 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 December 31, 2014 and 2013.
	At December 31, 2014 and 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at December 31, 2014 and 2013, amounts posted as cash collateral under margin arrangements were $3.8 million and $2.8 million for both PNMR and PNM. At December 31, 2014 and 2013, obligations to return cash collateral were $0.2 million and $0.2 million for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the 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 $0.1 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 Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.
	The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.
		Economic
		Hedges
		Year Ended
		December 31,
		2014				2013			2012
		(In thousands)
	PNMR and PNM
	Electric operating revenues	$	4,491			$	1,727		$	6,168
	Cost of energy	593				1,109			(460		)
	Total gain	$	5,084			$	2,836		$	5,708
	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
	December 31, 2014
	PNMR and PNM	650,000			(1,919,000	)
	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				Existing Cash			Net Exposure
	Credit Rating Downgrade		Liability				Collateral
			(In thousands)
	December 31, 2014
	PNMR and PNM		$	1,686			$	—		$	167
	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 currently included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of December 31, 2014, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales.
	Non-Derivative Financial Instruments
	The carrying amounts reflected on the 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, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2014 and 2013, the fair value of available-for-sale securities included $244.6 million and $222.5 million for the NDT and $5.5 million and $4.4 million for the mine reclamation trust.
		December 31, 2014							December 31, 2013
		Unrealized				Fair Value			Unrealized			Fair Value
		Gains							Gains
	PNMR and PNM					(In thousands)
	Cash and cash equivalents	$	—			$	8,276		$	—		$	3,356
	Equity securities:
Domestic value	17,418				45,340			14,523			39,460
Domestic growth	21,354				74,053			25,656			76,292
International and other	156				16,599			1,040			16,633
Fixed income securities:
U.S. Government	903				22,563			158			21,941
Municipals	5,851				68,973			1,018			58,568
Corporate and other	666				14,341			207			10,605
	$	46,348			$	250,145		$	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 . Gross realized losses shown below exclude the change in realized impairment losses of $(0.7) million, $0.6 million, and $5.2 million.
	Year Ended December 31,
	2014				2013			2012
	(In thousands)
Proceeds from sales	$	117,989			$	271,140		$	167,330
Gross realized gains	$	15,162			$	14,308		$	15,907
Gross realized (losses)	$	(3,964	)		$	(4,298	)	$	(8,170	)
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 December 31, 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	$	3,946			$	8,019		$	8,019
After 1 year through 5 years	20,275				25,430			24,817
After 5 years through 10 years	13,422				—			—
After 10 years through 15 years	10,367				—			—
After 15 years through 20 years	11,539				—			—
After 20 years	46,328				—			—
	$	105,877			$	33,449		$	32,836
Fair Value Disclosures
The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the years ended December 31, 2014 and 2013.
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 Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at December 31, 2014 and 2013 for items recorded at fair value.
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active Market for Identical Assets (Level 1)			Significant Other Observable Inputs
								(Level 2)
December 31, 2014					(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276			$	8,276		$	—
Equity securities:
Domestic value	45,340				45,340			—
Domestic growth	74,053				74,053			—
International and other	16,599				16,599			—
Fixed income securities:
U.S. Government	22,563				20,808			1,755
Municipals	68,973				—			68,973
Corporate and other	14,341				4,843			9,498
	$	250,145			$	169,919		$	80,226
Commodity derivative assets	$	11,232			$	—		$	11,232
Commodity derivative liabilities	(1,686		)		—			(1,686		)
Net	$	9,546			$	—		$	9,546
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active Market for Identical Assets (Level 1)			Significant Other Observable Inputs
								(Level 2)
December 31, 2013					(In thousands)
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 carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt are presented below:
								GAAP Fair Value Hierarchy
	Carrying				Fair Value			Level 1			Level 2			Level 3
	Amount
December 31, 2014	(In thousands)
PNMR
Long-term debt	$	1,975,090			$	2,173,117		$	—		$	2,173,117		$	—
Investment in PVNGS lessor notes	$	31,232			$	32,836		$	—		$	—		$	32,836
Other investments	$	1,762			$	2,375		$	639		$	—		$	1,736
PNM
Long-term debt	$	1,490,657			$	1,624,222		$	—		$	1,624,222		$	—
Investment in PVNGS lessor notes	$	31,232			$	32,836		$	—		$	—		$	32,836
Other investments	$	397			$	397		$	397		$	—		$	—
TNMP
Long-term debt	$	365,667			$	427,356		$	—		$	427,356		$	—
Other investments	$	242			$	242		$	242		$	—		$	—
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		$	—		$	—
Investments Held by Employee Benefit Plans
As discussed in Note 12, PNM and TNMP have trusts that hold investment assets for their pension and other postretirement benefit plans. The fair value of the assets held by the trusts impacts the determination of the funded status of each plan, but the assets are not reflected on the Company’s Consolidated Balance Sheets. Both the PNM Pension Plan and the TNMP Pension Plan hold units of participation in the PNM Resources, Inc. Master Trust (the “PNMR Master Trust”), which was established for the investment of assets of the pension plans. Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For level 2 fair values, the pricing provider predominately uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. Level 2 investments in mutual funds are measured at net asset value as year-end. Level 3 investments are comprised of alternative investments, which are measured at net asset value at year-end and include private equity funds, hedge funds, and real estate funds. The private equity funds are not voluntarily redeemable. These investments are realized through periodic distributions occurring over a 10 to 15-year term after the initial investment. The real estate funds and hedge funds may be voluntarily redeemed, but are subject to redemption provisions that may result in the funds not being able to be redeemed in the near term. Audited financial statements are received for each fund and are reviewed by the Company annually.
The valuation of alternative investments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates and cash flows. The fair values of investments held by the employee benefit plans are as follows:
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active Market for Identical Assets			Significant			Significant
					(Level 1)			Other			Unobservable
								Observable			Inputs
								Inputs			(Level 3)
								(Level 2)
December 31, 2014					(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	588,112			$	123,668		$	398,819		$	65,625
TNMP Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	69,207			$	14,823		$	44,425		$	9,959
PNM OPEB Plan
Cash and cash equivalents	$	1,242			$	1,242		$	—		$	—
Equity securities:
International funds	10,332				—			10,332			—
Domestic value	8,365				8,365			—			—
Domestic growth	5,960				5,960			—			—
Other funds	30,997				—			30,997			—
Fixed income securities:
Mutual funds	22,122				22,122			—			—
	$	79,018			$	37,689		$	41,329		$	—
TNMP OPEB Plan
Cash and cash equivalents	$	168			$	168		$	—		$	—
Equity securities:
International funds	1,277				—			1,277			—
Domestic value	403				403			—			—
Domestic growth	1,024				1,024			—			—
Other funds	3,790				—			3,790			—
Fixed income securities:
Mutual funds	3,549				3,549			—			—
	$	10,211			$	5,144		$	5,067		$	—
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active			Significant			Significant
					Market for Identical Assets			Other			Unobservable
					(Level 1)			Observable			Inputs
								Inputs			(Level 3)
								(Level 2)
December 31, 2013	(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust	$	557,258			$	145,364		$	330,903		$	80,991
TNMP Pension Plan
Participation in PNMR Master Trust	$	66,285			$	18,657		$	32,620		$	15,008
PNM OPEB Plan
Cash and cash equivalents	$	1,152			$	1,152		$	—		$	—
Equity securities:
International funds	11,634				—			11,634			—
Domestic value	6,388				6,388			—			—
Domestic growth	24,135				7,094			17,041			—
Other funds	14,028				—			14,028			—
Fixed income securities:
Mutual funds	16,796				16,796			—			—
	$	74,133			$	31,430		$	42,703		$	—
TNMP OPEB Plan
Cash and cash equivalents	$	302			$	302		$	—		$	—
Equity securities:
International funds	1,334				—			1,334			—
Domestic value	381				381			—			—
Domestic growth	4,171				1,848			2,323			—
Other funds	1,844				—			1,844			—
Fixed income securities:
Mutual funds	1,702				1,702			—			—
	$	9,734			$	4,233		$	5,501		$	—
The fair values of investments in the PNMR Master Trust are as follows:
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in			Significant			Significant
					Active Market for			Other			Unobservable
					Identical Assets			Observable			Inputs
					(Level 1)			Inputs			(Level 3)
								(Level 2)
December 31, 2014	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	15,645			$	15,645		$	—		$	—
Equity securities:
International	23,282				—			23,282			—
Domestic value	41,778				41,778			—			—
Domestic growth	28,370				28,370			—			—
Other funds	29,719				—			29,719			—
Fixed income securities:
Corporate	242,742				—			242,015			727
U.S. Government	106,634				52,537			54,097			—
Municipals	20,156				—			20,156			—
Other funds	74,136				161			73,975			—
Alternative investments:
Private equity funds	37,220				—			—			37,220
Hedge funds	23,876				—			—			23,876
Real estate funds	13,761				—			—			13,761
	$	657,319			$	138,491		$	443,244		$	75,584
December 31, 2013
PNMR Master Trust
Cash and cash equivalents	$	16,281			$	16,281		$	—		$	—
Equity securities:
International	24,471				24,471			—			—
Domestic value	41,451				41,451			—			—
Domestic growth	36,805				36,805			—			—
Other funds	22,522				—			22,522			—
Fixed income securities:
Corporate	202,897				363			202,358			176
U.S. Government	99,748				44,541			55,207			—
Municipals	17,259				—			17,259			—
Other funds	66,286				109			66,177			—
Alternative investments:
Private equity funds	39,122				—			—			39,122
Hedge funds	34,912				—			—			34,912
Real estate funds	21,789				—			—			21,789
	$	623,543			$	164,021		$	363,523		$	95,999
A reconciliation of the changes in Level 3 fair value measurements is as follows:
	Year Ended December 31,
	2014				2013
Level 3 Fair Value Assets and Liabilities	(In thousands)
PNM Pension	Master				Master
	Trust				Trust
Balance at beginning of period	$	80,991			$	79,017
Actual return on assets sold during the period	10,376				3,303
Actual return on assets still held at period end	(5,731		)		3,361
Purchases	8,832				15,110
Sales	(28,843		)		(19,800		)
Balance at end of period	65,625				80,991
TNMP Pension
Balance at beginning of period	$	15,008			$	14,171
Actual return on assets sold during the period	3,409				1,400
Actual return on assets still held at period end	(1,883		)		1,425
Purchases	2,902				6,408
Sales	(9,477		)		(8,396		)
Balance at end of period	9,959				15,008
Total	$	75,584			$	95,999
Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
Level 3 Fair Value Assets and Liabilities
PNMR Master Trust	Private				Hedge			Real			Fixed income - corporate			Total
	equity				funds			estate
	funds							funds
					(In thousands)
Balance at December 31, 2012	$	38,212			$	31,277		$	23,699		$	—		$	93,188
Actual return on assets sold during the period	4,677				135			(109		)	1			4,704
Actual return on assets still held at period end	1,162				3,500			123			—			4,785
Purchases	3,117				16,151			2,076			175			21,519
Sales	(8,046		)		(16,151		)	(4,000		)	—			(28,197		)
Balance at December 31, 2013	39,122				34,912			21,789			176			95,999
Actual return on assets sold during the period	5,355				8,667			(236		)	—			13,786
Actual return on assets still held at period end	(296		)		(7,536		)	237			(20		)	(7,615		)
Purchases	3,656				5,500			1,971			608			11,735
Sales	(10,617		)		(17,667		)	(10,000		)	(37		)	(38,321		)
Balance at December 31, 2014	$	37,220			$	23,876		$	13,761		$	727		$	75,584

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 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.
	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. The total construction cost for the facility was $90.0 million. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. 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 years ended December 31, 2014, 2013, and 2012, PNM paid $19.1 million, $18.9 million, and $18.8 million for fixed charges and $1.2 million, $1.2 million, and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.
	PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third party entity that owns Valencia is a 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. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the 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
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Operating revenues	$	20,247		$	20,166		$	19,585
	Operating expenses	(6,120		)	(5,645		)	(5,535		)
	Earnings attributable to non-controlling interest	$	14,127		$	14,521		$	14,050
	Financial Position
		December 31,
		2014			2013
		(In thousands)
	Current assets	$	2,513		$	2,658
	Net property, plant and equipment	72,321			75,137
	Total assets	74,834			77,795
	Current liabilities	1,288			766
	Owners’ equity – non-controlling interest	$	73,546		$	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 NMPRC and FERC would be required, which process could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. 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 is leasing portions of its interests in Units 1 and 2 of PVNGS. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases, but 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 2 years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional 6 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 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 $20.3 million over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM has elected to renew. Other than as discussed in Note 7, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Consolidated Balance Sheets related to the trusts other than accrued lease payments of $26.0 million at December 31, 2014 and 2013, which are included in other current liabilities on the Consolidated Balance Sheets.
	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. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since the operating licenses for the plants have been extended for twenty years through 2045 for Unit 1 and 2046 for Unit 2; PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease terms, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so does not significantly influence the day-to-day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from potential carbon legislation or regulation.
	Rio Bravo, formerly known as Delta
	PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM 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 owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.
	In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. 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 working capital compared to a targeted working capital and included amounts placed in escrow. Delta had project financing debt, amounting to $14.6 million at closing, which PNM retired. PNM changed the name of the facility to Rio Bravo.
	PNM recorded the acquisition as a business combination and reflected the requirements of the FERC Uniform System of Accounts since the purchased assets are subject to traditional rate regulation by the NMPRC and FERC. Accordingly, as of the acquisition date, PNM recorded plant in service of $58.1 million and accumulated depreciation of $23.5 million, reflecting the original cost of the facilities and the estimated economic life to PNM. PNM also recorded current assets of $3.6 million, deferred charges of $3.4 million, current liabilities of $0.3 million, and non-current regulatory liabilities of $3.4 million.
	PNM made fixed and variable payments to Delta under the PPA. For the period from January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $3.5 million and variable energy charges of $0.6 million under the PPA. For the years ended December 31, 2013 and 2012, PNM incurred fixed capacity charges of $6.4 million, and $6.2 million and variable energy charges of $1.8 million, and $0.8 million under the PPA. PNM recovered the variable energy charges through its FPPAC.
	PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to the Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

Earnings_and_Dividends_Per_Sha

Earnings and Dividends Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings and Dividends Per Share	Earnings and Dividends Per Share
	In accordance with GAAP, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share and dividends per share is as follows:
		Year Ended December 31,
		2014		2013		2012
		(In thousands, except per share amounts)
	Earnings Attributable to PNMR	$	116,254	$	100,507	$	105,547
	Average Number of Common Shares:
	Outstanding during year	79,654		79,654		79,654
	Vested awards of restricted stock	134		191		145
	Average Shares – Basic	79,788		79,845		79,799
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	491		586		618
	Average Shares – Diluted	80,279		80,431		80,417
	Net Earnings Per Share of Common Stock:
	Basic	$	1.46	$	1.26	$	1.32
	Diluted	$	1.45	$	1.25	$	1.31
	Dividends Declared per Common Share	$	0.755	$	0.68	0.58
	(1)	Excludes out-of-the-money options for 254,050 shares of common stock at December 31, 2014. See Note 13.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	PNMR
	PNMR’s income taxes consist of the following components:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current federal income tax	$	(2,015	)	$	—		$	(1,296	)
	Current state income tax	(728		)	(917		)	(37		)
	Deferred federal income tax	59,814			50,044			51,559
	Deferred state income tax	14,831			12,578			6,921
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Total income taxes	$	69,738		$	59,513		$	54,910
	PNMR’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Federal income tax at statutory rates	$	70,226		$	61,274		$	61,262
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Flow-through of depreciation items	1,344			1,132			1,284
	Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
	State income tax, net of federal benefit	5,723			3,818			4,646
	Impairment of state net operating loss carryforwards	3,129			—			—
	Impairment of state production tax credits, net of federal benefit	894			3,880			718
	Other	(4,469		)	(3,317		)	(5,845		)
	Total income taxes	$	69,738		$	59,513		$	54,910
	Effective tax rate	34.76		%	33.99		%	31.37		%
	The components of PNMR’s net accumulated deferred income tax liability were:
		December 31,
		2014			2013
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	153,858		$	134,418
	Regulatory liabilities related to income taxes	78,858			83,838
	Federal tax credit carryforwards	54,748			40,708
	Other	68,566			75,832
	Total deferred tax assets	356,030			334,796
	Deferred tax liabilities:
	Depreciation and plant related	(914,926		)	(814,671		)
	Investment tax credit	(36,790		)	(25,855		)
	Regulatory assets related to income taxes	(67,910		)	(66,352		)
	CTC	(19,352		)	(22,262		)
	Pension	(66,498		)	(58,780		)
	Other	(115,282		)	(115,458		)
	Total deferred tax liabilities	(1,220,758		)	(1,103,378		)
	Net accumulated deferred income tax liabilities	(864,728		)	(768,582		)
	Current accumulated deferred income tax (asset) liability	(26,383		)	(58,681		)
	Non-current accumulated deferred income tax liability	$	(891,111	)	$	(827,263	)
	The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2014
		(In thousands)
	Net change in deferred income tax liability per above table	$	96,146
	Change in tax effects of income tax related regulatory assets and liabilities	(6,538		)
	Tax effect of mark-to-market adjustments	(1,612		)
	Tax effect of excess pension liability	3,993
	Adjustment for uncertain income tax positions	(4,858		)
	Reclassification of unrecognized tax benefits	(15,031		)
	Other	381
	Deferred income taxes	$	72,481
	PNM
	PNM’s income taxes consist of the following components:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
Current federal income tax	$	(2,175	)	$	(479	)	$	(12,951	)
Current state income tax	(979		)	(760		)	(1,815		)
Deferred federal income tax	45,890			42,806			56,194
Deferred state income tax	12,061			9,429			11,522
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Total income taxes	$	52,633		$	48,804		$	50,713
PNM’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Federal income tax at statutory rates	$	53,930		$	53,018		$	54,710
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Flow-through of depreciation items	1,325			1,115			1,268
Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
State income tax, net of federal benefit	5,522			6,202			6,500
Impairment of state net operating loss carryforwards	2,145			—			—
Other	(3,180		)	(4,257		)	(4,610		)
Total income taxes	$	52,633		$	48,804		$	50,713
Effective tax rate	34.16		%	32.22		%	32.44		%
The components of PNM’s net accumulated deferred income tax liability were:
	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Net operating loss	$	108,505		$	99,247
Regulatory liabilities related to income taxes	74,293			78,849
Federal tax credit carryforwards	35,259			22,509
Other	35,681			37,008
Total deferred tax assets	253,738			237,613
Deferred tax liabilities:
Depreciation and plant related	(733,519		)	(661,239		)
Investment tax credit	(36,790		)	(25,855		)
Regulatory assets related to income taxes	(57,637		)	(55,844		)
Pension	(58,474		)	(52,104		)
Other	(70,714		)	(75,838		)
Total deferred tax liabilities	(957,134		)	(870,880		)
Net accumulated deferred income tax liabilities	(703,396		)	(633,267		)
Current accumulated deferred income tax (asset) liability	(12,418		)	(43,827		)
Non-current accumulated deferred income tax liability	$	(715,814	)	$	(677,094	)
The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
	Year Ended
	December 31, 2014
	(In thousands)
Net change in deferred income tax liability per above table	$	70,129
Change in tax effects of income tax related regulatory assets and liabilities	(6,349		)
Tax effect of mark-to-market adjustments	(1,470		)
Tax effect of excess pension liability	3,993
Adjustment for uncertain income tax positions	1,155
Reclassification of unrecognized tax benefits	(12,228		)
Other	557
Deferred income taxes	$	55,787
TNMP
TNMP’s income taxes consist of the following components:
	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Current federal income tax	$	35		$	(4,957	)	$	9,152
Current state income tax	1,939			1,916			1,822
Deferred federal income tax	20,577			20,688			4,406
Deferred state income tax	(28		)	(26		)	(28		)
Total income taxes	$	22,523		$	17,621		$	15,352
TNMP’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the periods shown. The differences are attributable to the following factors:
	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Federal income tax at statutory rates	$	21,115		$	16,349		$	14,735
State income tax, net of federal benefit	1,257			1,247			1,185
Other	151			25			(568		)
Total income taxes	$	22,523		$	17,621		$	15,352
Effective tax rate	37.33		%	37.72		%	36.47		%
The components of TNMP’s net accumulated deferred income tax liability at December 31, were:
	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	4,565		$	4,988
Other	13,429			23,479
Total deferred tax assets	17,994			28,467
Deferred tax liabilities:
Depreciation and plant related	(174,510		)	(151,581		)
CTC	(19,352		)	(22,262		)
Regulatory assets related to income taxes	(10,197		)	(10,509		)
Loss on reacquired debt	(12,846		)	(13,516		)
Other	(12,636		)	(14,295		)
Total deferred tax liabilities	(229,541		)	(212,163		)
Net accumulated deferred income tax liabilities	(211,547		)	(183,696		)
Current accumulated deferred income tax (asset)	(6,398		)	(6,501		)
Non-current accumulated deferred income tax liability	$	(217,945	)	$	(190,197	)
The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
	Year Ended
	December 31, 2014
	(In thousands)
Net change in deferred income tax liability per above table	$	27,851
Change in tax effects of income tax related regulatory assets and liabilities	(111		)
Adjustment for uncertain tax positions	(6,796		)
Other	(395		)
Deferred income taxes	$	20,549
Other Disclosures
GAAP requires that the Company recognize only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the taxing authority. A reconciliation of unrecognized tax benefits (expenses) is as follows:
	PNMR			PNM			TNMP
	(In thousands)
Balance at December 31, 2011	$	19,580		$	10,752		$	7,701
Additions based on tax positions related to 2012	2,046			1,152			—
Reductions for tax positions of prior years	(2,428		)	(1,522		)	(905		)
Settlement payments	—			—			—
Balance at December 31, 2012	19,198			10,382			6,796
Additions based on tax positions related to 2013	(54		)	(54		)	—
Additions for tax positions of prior years	745			745			—
Settlement payments	—			—			—
Balance at December 31, 2013	19,889			11,073			6,796
Additions based on tax positions related to 2014	623			623			—
Additions (reductions) for tax positions of prior years	(5,481		)	532			(6,796		)
Settlement payments	—			—			—
Balance at December 31, 2014	$	15,031		$	12,228		$	—
Included in the balance at December 31, 2014 are $4.7 million and $1.9 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate for PNMR and PNM. The Company does not anticipate that any unrecognized tax expenses or unrecognized tax benefits will be reduced or settled in 2015.
Estimated interest income related to refunds the Company expects to receive is included in Other Income and estimated interest expense and penalties related to potential cash settlements are included in interest expense in the Consolidated Statements of Earnings (Loss). Interest income (expense) related to income taxes is as follows:
	PNMR			PNM			TNMP
	(In thousands)
2014	$	146		$	148		$	(2	)
2013	$	242		$	251		$	(2	)
2012	$	243		$	244		$	(3	)
Accumulated accrued interest receivable (payable) related to income taxes is as follows:
	PNMR			PNM			TNMP
	(In thousands)
December 31, 2014:
Accumulated accrued interest receivable	$	3,569		$	3,569		$	—
Accumulated accrued interest payable	$	(1,120	)	$	(24	)	$	(120	)
December 31, 2013:
Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)
The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2011 are closed to examination by either federal or state taxing authorities other than Arizona. The tax years prior to 2009 are closed to examination by Arizona taxing authorities. Other tax years are open to examination by federal and state taxing authorities. At December 31, 2014, the Company has $405.7 million of federal net operating loss carryforwards that expire beginning in 2030 and $54.7 million of federal tax credit carryforwards that expire beginning in 2023. State net operating losses expire beginning in 2015 and vary from federal due to differences between state and federal tax law.
PNMR has New Mexico wind energy production tax credit carry forwards with statutory expiration dates beginning in 2014. In 2012, PNMR impaired $0.7 million, after federal tax benefit, of the New Mexico wind energy production tax credit carry forwards that were not expected to be utilized prior to their expiration due to the Company’s net operating loss position. The impairment is reflected in PNMR’s Corporate and Other segment.
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 year ended December 31, 2013. The impairment is reflected in PNMR’s Corporate and Other segment.
On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment, which was in the year ended December 31, 2013. At that time, the portion of the adjustment related to PNM's regulated activities was recorded as a reduction in deferred tax liabilities, 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 year ended December 31, 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 year ended December 31, 2014, PNM’s deferred tax liabilities were increased by $4.6 million, which reduced regulatory liabilities. Additionally, deferred tax assets not related to PNM’s regulatory activities were increased by $0.1 million, of which $0.2 million increased income tax expense in PNMR's Corporate and Other segment and $0.3 million decreased income tax expense in PNM.
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 year ended December 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment.
On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico for 2014 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits, which after federal income tax benefit, amounted to $0.9 million. The impairment is reflected in PNMR’s Corporate and Other segment. Additionally, the act resulted in an impairment of New Mexico net operating loss carryforwards, which after federal income tax benefit, amounted to $3.1 million. Of this amount, $2.1 million is reflected in PNM and $1.0 million is reflected in PNMR’s Corporate and Other segment. In accordance with GAAP, these impairments were recorded as additional income tax expense during the year ended December 31, 2014. The impairment of the New Mexico net operating loss carryforward is reflected as a valuation allowance against deferred tax assets. No such impairments occurred in prior years. TNMP had no such impairment.
The impairments of the New Mexico wind energy production tax credits discussed above are reflected as a valuation allowance against deferred tax assets. At December 31, 2014, PNMR had a total valuation allowance for these credits of $5.5 million. During the years ended December 31, 2014, 2013, and 2012, the valuation allowance for these credits increased by $0.9 million, $3.9 million, and $0.7 million. PNM and TNMP have no such valuation allowances.
In April 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property.  Adoption of the safe harbor method is elective for years ending on or after December 31, 2012.  On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material due to PNMR’s net operating loss carryforward position.
In September 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material.
In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM.
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 Company adopted the change for 2014.  Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss 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 earnings from adopting the update.
In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the year ended December 31, 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.

Pension_and_Other_Postretireme

Pension and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefits	Pension and Other Postretirement Benefits
	PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. PNM receives a regulated return on the amount it has funded for its pension plan in excess of the periodic cost or income to the extent included in retail rates.
	Participants in the PNM Plans include eligible employees and retirees of PNMR and other subsidiaries of PNMR. Participants in the TNMP Plans include eligible employees and retirees of TNMP. The PNM pension plan was frozen at the end of 1997 with regard to new participants, salary levels, and benefits. Through December 31, 2007, additional credited service could be accrued under the PNM pension plan up to a limit determined by age and service. The TNMP pension plan was frozen at December 31, 2005 with regard to new participants, salary levels, and benefits.
	GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur.
	GAAP requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs is included as pension and postretirement benefit periodic cost or income in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP record the costs as a regulatory asset or regulatory liability.
	For the PNM Plans and TNMP Plans, the Company has in place a policy that defines the investment objectives, establishes performance goals of asset managers, and provides procedures for the manner in which investments are to be reviewed. The plans implement investment strategies to achieve the following objectives:
	•	Maximize the return on assets, commensurate with the risk that the Corporate Investment Committee deems appropriate to meet the obligations of the pension plans and OPEB plans, minimize the volatility of expense, and account for contingencies
	•	Transition asset mix over time to a higher proportion of high quality fixed income investments as the plans’ funded statuses improve
	Management is responsible for the determination of the asset target mix and the expected rate of return. The target asset allocations are determined based on consultations with external investment advisors. The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility. For the PNM Plans and TNMP Plans, the market-related value of assets is equal to the prior year’s market related value of assets adjusted for contributions, benefit payments and investment gains and losses that are within a corridor of plus or minus 4.0% around the expected return on market value. Gains and losses that are outside the corridor are amortized over five years.
	Pension Plans
	For defined benefit pension plans, including the executive retirement plans, the PBO represents the actuarial present value of all benefits attributed by the pension benefit formula to employee service rendered prior to that date using assumptions regarding future compensation levels. The ABO represents the PBO without considering future compensation levels. Since the plans are frozen, the PBO and ABO are equal. The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2014				2013				2014			2013
		(In thousands)
	PBO at beginning of year	$	599,537			$	675,549			$	66,159		$	76,640
	Service cost	—				—				—			—
	Interest cost	30,163				28,142				3,193			3,087
	Plan amendment	—				(6,346		)		—			—
	Actuarial (gain) loss	72,524				(56,533		)		8,466			(7,820		)
	Benefits paid	(44,667		)		(41,275		)		(5,513		)	(5,748		)
	PBO at end of year	657,557				599,537				72,305			66,159
	Fair value of plan assets at beginning of year	556,353				518,095				66,118			66,540
	Actual return on plan assets	76,223				19,533				8,572			4,326
	Employer contributions	—				60,000				—			1,000
	Benefits paid	(44,667		)		(41,275		)		(5,513		)	(5,748		)
	Fair value of plan assets at end of year	587,909				556,353				69,177			66,118
	Funded status – asset (liability) for pension benefits	$	(69,648	)		$	(43,184	)		$	(3,128	)	$	(41	)
	Effective January 1, 2014, the PNM Pension Plan was amended to allow for all participants, terminating after the effective date, to elect a lump sum payment of benefits. This change is reflected in the above table as of December 31, 2013.
	The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2014.
		PNM Plan								TNMP Plan
		December 31, 2014								December 31, 2014
		Prior service				Net actuarial				Net actuarial
		cost				(gain) loss				(gain) loss
		(In thousands)
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$	(2,665	)		$	139,256			$	—
	Experience loss (gain)	—				34,345				4,420
	Regulatory asset (liability) adjustment	—				(19,920		)		(4,420		)
	Amortization recognized in net periodic benefit cost (income)	405				(5,469		)		—
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,260	)		$	148,212			$	—
	Amortization expected to be recognized in 2015	$	(405	)		$	6,224			$	—
	The following table presents the components of net periodic benefit cost (income):
		Year Ended December 31,
		2014				2013				2012
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	30,163				28,142				32,232
	Expected return on plan assets	(38,044		)		(41,930		)		(41,301		)
	Amortization of net (gain) loss	13,020				14,840				10,516
	Amortization of prior service cost	(965		)		76				317
	Net periodic benefit cost	$	4,174			$	1,128			$	1,764
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	3,193				3,087				3,635
	Expected return on plan assets	(4,526		)		(4,849		)		(5,324		)
	Amortization of net (gain) loss	665				1,049				462
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost (income)	$	(668	)		$	(713	)		$	(1,227	)
	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.
		Year Ended December 31,
	PNM Plan	2014			2013			2012
	Discount rate for determining December 31 PBO	4.48	%		5.27	%		4.3	%
	Discount rate for determining net periodic benefit cost (income)	5.27	%		4.3	%		5.67	%
Expected return on plan assets	7.2	%		7.65	%		8.25	%
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.39	%		5.06	%		4.19	%
Discount rate for determining net periodic benefit cost (income)	5.06	%		4.19	%		5.69	%
Expected return on plan assets	7.2	%		7.65	%		8.25	%
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in discount rates resulted in an increase in the PNM PBO of $50.6 million at December 31, 2014 and a decrease of $60.9 million at December 31, 2013. Changes in discount rates resulted in an increase in the TNMP PBO of $5.1 million at December 31, 2014 and a decrease of $6.4 million at December 31, 2013. Changes in demographic experience resulted in actuarial losses in the PNM PBO of $0.2 million and $4.4 million at December 31, 2014 and 2013. Changes in demographic experience resulted in actuarial gains in the TNMP PBO of $0.4 million at December 31, 2014 and $1.4 million at December 31, 2013. Changes in other assumptions and experience resulted in actuarial gains in the PNM PBO of $0.2 million at December 31, 2014 and less than $0.1 million at December 31, 2013. Changes in other assumptions and experience resulted in actuarial losses in the TNMP PBO of $1.3 million and less than $0.1 million at December 31, 2014 and 2013. These changes are reflected as actuarial (gain) loss above.
In late 2014, the Society of Actuaries issued revised mortality tables that include changes in assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates.  This change impacts 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 actuarial valuation performed as of December 31, 2014 incorporated the impacts of the revised mortality tables.  Utilizing the revised mortality tables increased the PNM PBO by $21.9 million and the TNMP PBO by $2.5 million, which are reflected as the actuarial losses above.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the PBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates) and current and target asset allocations between asset categories. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2015 net periodic cost to increase $5.8 million and $0.6 million (analogous changes would result from a 1% increase). The actual rate of return for the PNM and TNMP pension plans was 14.3% and 13.5% for the year ended December 31, 2014.
The Company’s long-term pension investment strategy is to invest in assets whose interest rate sensitivity is correlated with the pension liability. The Company has chosen to implement this strategy known as Liability Driven Investing (“LDI”) by increasing the liability matching investments as the funded status of the pension plans improves. These liability matching investments are currently fixed income securities. The pension plans current targeted asset allocation is 21% equities, 65% fixed income, and 14% alternative investments. Equity investments are primarily in domestic securities that include large, mid, and small capitalization companies. The pension plans have a 6% targeted allocation to equities of companies domiciled primarily in developed countries outside of the United States. This category includes actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries, and government securities. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. The hedge funds and private equity funds are structured as multi-manager multi-strategy fund of funds to achieve a diversified position in these asset classes. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, buy-outs, and venture capital. The real estate investment is structured as an open-ended, commingled private real estate portfolio that invests in a diversified portfolio of assets including commercial property and multi-family housing. See Note 8 for fair value information concerning assets held by the pension plans.
The following pension benefit payments are expected to be paid:
	PNM				TNMP
	Plan				Plan
	(In thousands)
2015	$	53,472			$	5,997
2016	53,468				5,667
2017	51,241				5,351
2018	49,640				5,585
2019	48,560				5,188
2020 – 2024	213,759				23,600
Due to declines during the recent recession in the general price levels of marketable equity securities held by the pension plans, PNM and TNMP have been making contributions to the pension plans since 2010. In January 2015, the Company made a contribution of to the PNM pension plan of $30.0 million. The Company does not anticipate making any additional contributions to the pension plans in 2015. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the pension plan trust for 2016-2019 are estimated to total $22.0 million for PNM and none for TNMP. These anticipated contributions were developed using current funding assumptions with discount rates of 4.8% to 5.5%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate.
Other Postretirement Benefit Plans
For postretirement benefit plans, the APBO is the actuarial present value of all future benefits attributed under the terms of the postretirement benefit plan to employee service rendered to date.
The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:
	PNM Plan								TNMP Plan
	Year Ended December 31,								Year Ended December 31,
	2014				2013				2014			2013
	(In thousands)
APBO at beginning of year	$	92,165			$	99,613			$	12,266		$	13,678
Service cost	181				260				237			299
Interest cost	4,630				4,113				619			566
Participant contributions	2,582				2,537				366			373
Actuarial (gain) loss	4,455				(4,566		)		1,639			(1,080		)
Benefits paid	(8,838		)		(9,792		)		(1,057		)	(1,570		)
APBO at end of year	95,175				92,165				14,070			12,266
Fair value of plan assets at beginning of year	73,565				64,464				9,601			8,643
Actual return on plan assets	7,334				12,780				841			1,813
Employer contributions	3,532				3,576				343			342
Participant contributions	2,582				2,537				366			373
Benefits paid	(8,838		)		(9,792		)		(1,057		)	(1,570		)
Fair value of plan assets at end of year	78,175				73,565				10,094			9,601
Funded status – asset (liability)	$	(17,000	)		$	(18,600	)		$	(3,976	)	$	(2,665	)
In the year ended December 31, 2014, actuarial losses of $2.8 million and $1.3 million were recorded in regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2014.
The following table presents the components of net periodic benefit cost:
	Year Ended December 31,
	2014				2013				2012
	(In thousands)
PNM Plan
Service cost	$	181			$	260			$	217
Interest cost	4,630				4,113				5,293
Expected return on plan assets	(5,638		)		(5,043		)		(4,901		)
Amortization of net (gain) loss	2,225				4,242				3,888
Amortization of prior service credit	(1,343		)		(1,343		)		(1,343		)
Net periodic benefit cost	$	55			$	2,229			$	3,154
TNMP Plan
Service cost	$	237			$	299			$	244
Interest cost	619				566				624
Expected return on plan assets	(534		)		(503		)		(516		)
Amortization of net (gain) loss	(122		)		—				(209		)
Amortization of prior service cost	32				57				57
Net periodic benefit cost	$	232			$	419			$	200
The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.
	Year Ended December 31,
PNM Plan	2014			2013			2012
Discount rate for determining December 31 APBO	4.45	%		5.21	%		4.26	%
Discount rate for determining net periodic benefit cost	5.21	%		4.26	%		5.7	%
Expected return on plan assets	8.5	%		8.5	%		8.5	%
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 APBO	4.45	%		5.21	%		4.26	%
Discount rate for determining net periodic benefit cost	5.21	%		4.26	%		5.7	%
Expected return on plan assets	6.5	%		6.5	%		6.5	%
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the APBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in the discount rates resulted in an increase in the PNM APBO of $6.7 million at December 31, 2014 and a decrease of $8.8 million at December 31, 2013. Changes in discount rates resulted in an increase in the TNMP APBO of $1.1 million at December 31, 2014 and a decrease of $1.3 million at December 31, 2013. Changes in claims, contributions, medical trends, and demographic experience resulted in an actuarial gain in the PNM plan of $5.4 million at December 31, 2014 and an actuarial loss of $4.2 million at December 31, 2013. Changes in claims, contributions, and demographic experience resulted in actuarial losses in the TNMP plan of less than $0.1 million at December 31, 2014 and $0.2 million at December 31, 2013. These changes are reflected as actuarial (gain) loss above.
The actuarial valuation performed as of December 31, 2014 incorporated the impacts of the revised mortality tables discussed above.  Utilizing the revised mortality tables increased the PNM APBO by $3.2 million and the TNMP APBO by $0.5 million, which are reflected as actuarial losses above.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the APBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates), and current and target asset allocations between asset categories. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2015 postretirement benefit cost to increase $0.7 million and $0.1 million (analogous changes would result from a 1% increase). The actual rate of return for the PNM and TNMP postretirement benefit plans was 10.2% and 8.9% for the year ended December 31, 2014.
The following table shows the assumed health care cost trend rates for the PNM postretirement benefit plan:
	PNM Plan
	December 31,
	2014			2013
Health care cost trend rate assumed for next year	7	%		7.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5	%		5	%
Year that the rate reaches the ultimate trend rate	2023			2019
The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:
	PNM Plan
	1-Percentage-				1-Percentage-
	Point  Increase				Point  Decrease
	(In thousands)
Effect on total of service and interest cost	$	350			$	(281	)
Effect on APBO	$	5,305			$	(4,622	)
TNMP’s exposure to cost increases in the postretirement benefit plan is minimized by a provision that limits TNMP’s share of costs under the plan. Costs of the plan in excess of the limit are wholly borne by the participants. TNMP reached the cost limit at the end of 2001. As a result, a one-percentage-point change in assumed health care cost trend rates would have no effect on either the net periodic expense or the year-end APBO.
The Company’s other postretirement benefit plans invest in a portfolio that is diversified by asset class and style strategies. The other postretirement benefit plans generally use the same pension fixed income and equity investment managers and utilize the same overall investment strategy as described above for the pension plans, except there is no allocation to alternative investments. The other postretirement benefit plans have a target asset allocation of 70% equities and 30% fixed income. See Note 8 for fair value information concerning assets held by the other postretirement benefit plans.
The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:
	PNM Plan				TNMP Plan
	(In thousands)
2015	$	6,560			$	801
2016	6,635				822
2017	6,718				838
2018	6,875				860
2019	6,950				882
2020 - 2024	34,585				4,717
PNM expects to make contributions to the PNM postretirement benefit plan totaling $3.5 million in 2015 and $14.0 million for 2016-2019. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.3 million in 2015 and $1.4 million for 2016-2019 .
Executive Retirement Programs
For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:
	PNM Plan								TNMP Plan
	Year Ended								Year Ended
	December 31,								December 31,
	2014				2013				2014			2013
	(In thousands)
PBO at beginning of year	$	16,363			$	17,467			$	823		$	902
Service cost	—				—				—			—
Interest cost	822				720				39			36
Actuarial (gain) loss	2,040				(330		)		110			(21		)
Benefits paid	(1,495		)		(1,494		)		(94		)	(94		)
PBO at end of year – funded status	17,730				16,363				878			823
Less current liability	1,528				1,536				94			94
Non-current liability	$	16,202			$	14,827			$	784		$	729
The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2014.
	December 31, 2014
	PNM Plan				TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	1,833			$	—
Experience loss (gain)	2,040				(110		)
Regulatory asset (liability) adjustment	(1,183		)		110
Amortization recognized in net periodic benefit cost (income)	(88		)		—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,602			$	—
Amortization expected to be recognized in 2015	$	136			$	—
The following table presents the components of net periodic benefit:
	Year Ended December 31,
	2014				2013				2012
	(In thousands)
PNM Plan
Service cost	$	—			$	—			$	—
Interest cost	822				720				876
Amortization of net (gain) loss	210				232				83
Amortization of prior service cost	—				—				—
Net periodic benefit cost	$	1,032			$	952			$	959
TNMP Plan
Service cost	$	—			$	—			$	—
Interest cost	39				36				45
Amortization of net (gain) loss	—				—				—
Amortization of prior service cost	—				—				—
Net periodic benefit cost	$	39			$	36			$	45
The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.
	Year Ended December 31,
PNM Plan	2014			2013			2012
Discount rate for determining December 31 PBO	4.48	%		5.27	%		4.3	%
Discount rate for determining net periodic benefit cost	5.27	%		4.3	%		5.67	%
Long-term rate of return on plan assets	N/A			N/A			N/A
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.39	%		5.06	%		4.19	%
Discount rate for determining net periodic benefit cost	5.06	%		4.19	%		5.69	%
Long-term rate of return on plan assets	N/A			N/A			N/A
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The impacts of changes in assumptions or experience were not significant.
The following executive retirement plan payments, which reflect expected future service, are expected:
	PNM				TNMP
	Plan				Plan
	(In thousands)
2015	$	1,528			$	93
2016	1,510				92
2017	1,490				91
2018	1,468				89
2019	1,445				86
2020 – 2024	6,722				384
Other Retirement Plans
PNMR sponsors a 401(k) defined contribution plan for eligible employees, including those of its subsidiaries. PNMR’s contributions to the 401(k) plan consist of a discretionary matching contribution equal to 75% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. PNMR also makes a non-matching contribution ranging from 3% to 10% of eligible compensation based on the eligible employee’s age.
PNMR also provides executive deferred compensation benefits through an unfunded, non-qualified plan. The purpose of this plan is to permit certain key employees of PNMR who participate in the 401(k) defined contribution plan to defer compensation and receive credits without reference to the certain limitations on contributions. Eligible employees are allowed to save on an after-tax basis. This plan has been amended and the after-tax provision will be eliminated on June 30, 2015.
A summary of expenses for these other retirement plans is as follows:
	Year Ended December 31,
	2014				2013				2012
	(In thousands)
PNMR
401(k) plan	$	16,703			$	16,785			$	16,185
Non-qualified plan	$	2,257			$	2,204			$	1,491
PNM
401(k) plan	$	12,745			$	12,952			$	12,427
Non-qualified plan	$	1,722			$	1,691			$	1,143
TNMP
401(k) plan	$	3,958			$	3,953			$	3,739
Non-qualified plan	$	535			$	513			$	327

StockBased_Compensation_Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation Plans	Stock-Based Compensation Plans
	PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements.
	Performance Equity Plan
	The PEP provides for the granting of non-qualified stock options, restricted stock rights, performance shares, performance units, and stock appreciation rights to officers, key employees, and non-employee board members. 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 total number of shares of PNMR common stock subject to all awards under the PEP, as approved by PNMR’s shareholders in May 2014, may not exceed 13.5 million shares, subject to adjustment and certain share counting rules set forth in the PEP. This current share pool is charged five shares for each share subject to restricted stock or other full value award. Re-pricing of stock options is prohibited unless specific shareholder approval is obtained.
	Source of Shares
	The source of shares for exercised stock options and vested restricted stock is shares acquired on the open market by an independent agent, rather than newly issued shares.
	Accounting for 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.
	In June 2014, the FASB issued 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, 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 FASB issued ASU 2012-12 to eliminate diversity in practice. The Company currently treats the performance targets covered by the standard as performance conditions, so this ASU has no impact on the Company.
	Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2014, 2013, and 2012 was $5.9 million, $5.3 million, and $3.6 million. Stock compensation expense of $4.2 million, $3.8 million, and $2.7 million was charged to PNM and $1.7 million, $1.5 million, and $1.0 million was charged to TNMP.
	PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date.
	At December 31, 2014, PNMR had unrecognized compensation expense of $4.7 million related to restricted stock and performance-based shares and $1.8 million related to market-based shares, which are expected to be recognized over an average of 1.8 years.
	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:
		Year Ended December 31,
	Restricted Shares and Performance-Based Shares	2014				2013				2012
	Expected quarterly dividends per share	$	0.185			$	0.165			$	0.145
	Risk-free interest rate	0.62		%		0.34		%		1.22		%
	Market-Based Shares
	Dividend yield	2.82		%		2.86		%		3.45		%
	Expected volatility	25.11		%		25.11		%		43.98		%
	Risk-free interest rate	0.64		%		0.36		%		1.04		%
	The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options:
		Restricted Stock						Stock Options
		Shares			Weighted-Average Grant Date Fair Value			Shares			Weighted
											Average
											Exercise
											Price
	Outstanding at December 31, 2013	315,305			$	17.87		1,343,666			$	20.63
	Granted	242,164			$	21.27		—			$	—
	Exercised	(295,423	)		$	16.7		(345,426	)		$	20.04
	Forfeited	(3,276	)		$	22.46		(17,151	)		$	26.43
	Expired	—			—			(60,584	)		$	27.98
	Outstanding at December 31, 2014	258,770			$	22.31		920,505			$	20.39
	Included as restricted stock granted and exercised 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 2011 through 2013 performance period.
	As of December 31, 2014, PNMR’s stock-based compensation program provides for performance and market targets through 2016. Excluded from the above table are 179,845 shares approved by the Board in February 2015 (based upon achieving market targets, weighted at 60%, at target levels and performance targets, weighted at 40%, at maximum levels for the 2012 through 2014 performance period), as well as maximums of 179,811 and 163,152 shares for the three-year performance periods ending in 2015 and 2016 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.
	In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015. 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 this retention award agreement.
	Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.
	At December 31, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $8.9 million with a weighted-average remaining contract life of 2.83 years. At December 31, 2014, the exercise price of 254,050 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:
		Year Ended December 31,
	Restricted Stock	2014				2013				2012
	Weighted-average grant date fair value	$	21.27			$	20.03			$	16.75
	Total fair value of restricted shares that vested (in thousands)	$	4,933			$	4,395			$	5,099
	Stock Options
	Weighted-average grant date fair value of options granted	$	—			$	—			$	—
	Total fair value of options that vested (in thousands)	$	—			$	625			$	1,054
	Total intrinsic value of options exercised (in thousands)	$	2,473			$	2,721			$	6,356

Construction_Program_and_Joint

Construction Program and Jointly-Owned Electric Generating Plants	12 Months Ended
	Dec. 31, 2014
Construction Program and Jointly-Owned Electric Generating Plants [Abstract]
Construction Program and Jointly-Owned Electric Generating Plants	Construction Program and Jointly-Owned Electric Generating Plants
	PNM is a participant in several jointly-owned power plant projects. The primary operating or participation agreements for the joint projects expire in July 2016 for Four Corners, July 2022 for SJGS, December 2046 for Luna, and November 2047 for PVNGS.
	PNM’s expenditures for additions to utility plant were $316.8 million in 2014, including expenditures on jointly-owned projects. TNMP does not participate in the ownership or operation of any generating plants, but incurred expenditures for additions to utility plant of $127.2 million during 2014. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $460.7 million in 2014.
	Joint Projects
	Under the agreements for the jointly-owned projects, PNM has an undivided interest in each asset and liability of the project and records its pro-rata share of each item in the corresponding asset and liability account on PNM’s Consolidated Balance Sheets. Likewise, PNM records its pro-rata share of each item of operating and maintenance expenses for its jointly-owned plants within the corresponding operating expense account in its Consolidated Statements of Earnings. PNM is responsible for financing its share of the capital and operating costs of the joint projects.
	At December 31, 2014, PNM’s interests and investments in jointly-owned generating facilities are:
	Station (Fuel Type)	Plant in		Accumulated			Construction			Composite
		Service		Depreciation			Work in			Interest
							Progress
		(In thousands)
	SJGS (Coal)	$	1,009,378	$	(423,364	)	$	25,551		46.3	%
	PVNGS (Nuclear) (1)	$	533,702	$	(152,273	)	$	42,334		10.2	%
	Four Corners Units 4 and 5 (Coal)	$	162,111	$	(101,007	)	$	8,253		13	%
	Luna (Gas)	$	66,169	$	(20,297	)	$	(136	)	33.33	%
	(1)	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.
	San Juan Generating Station
	PNM operates and jointly owns SJGS. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri-State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by M-S-R Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the potential restructuring of SJGS ownership.
	Palo Verde Nuclear Generating Station
	PNM is a participant in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA, and The Department of Water and Power of the City of Los Angeles. PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. See Note 7 for additional information concerning the PVNGS leases, including PNM’s notices that it will exercise its option to purchase the assets underlying certain of the leases at the expiration of the leases on January 15, 2016.
	Operation of each of the three PVNGS units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power operating licenses were originally for a period of 40 years and authorize APS, as operating agent for PVNGS, to operate the three PVNGS units. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through June 2045 for Unit 1, April 2046 for Unit 2, and November 2047 for Unit 3. In April 2010, APS entered into a Municipal Effluent Purchase and Sale Agreement that provides effluent water rights necessary for cooling purposes at PVNGS through 2050.
	Four Corners Power Plant
	PNM is a participant in two units of Four Corners with APS (the operating agent), EPE, SRP, and Tucson. PNM has a 13.0% undivided interest in Units 4 and 5 of Four Corners. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. 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 addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014.  PNM cannot predict whether the 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 PNM and the other Four Corners owners. See Note 16 for additional information about Four Corners.
	Luna Energy Facility
	Luna is a combined-cycle power plant near Deming, New Mexico. Luna is owned equally by PNM, Tucson, and Samchully Power & Utilities 1, LLC. The operation and maintenance of the facility has been contracted to North American Energy Services.
	Construction Program
	The Company anticipates making substantial capital expenditures for the construction and acquisition of utility plant and other property and equipment. An unaudited summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, and nuclear fuel, is as follows:
		2015		2016			2017			2018		2019		Total
							(In millions)
	PNM	$	423.9	$	402.3		$	334.8		$	180.6	$	260.3	$	1,601.90
	TNMP	121.3		92.8			93.3			105.9		105		518.3
	Corporate and Other	24		19.3			15.4			13.7		14.7		87.1
	Total PNMR	$	569.2	$	514.4		$	443.5		$	300.2	$	380	$	2,207.30
	The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $70.7 million related to environmental upgrades at SJGS to address regional haze and $268.4 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners estimated to be $80.0 million, the purchase of the leased portion of the EIP, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations
	AROs are recorded based on the determination of underlying assumptions, such as discount rates, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Any changes in these assumptions underlying the required calculations may require revisions to the estimated AROs when identified. A reconciliation of the ARO liability is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Liability at December 31, 2011	$	79,233		$	78,425		$	699
	Liabilities incurred	—			—			—
	Liabilities settled	(25		)	—			(25		)
	Accretion expense	6,685			6,617			58
	Liability at December 31, 2012	85,893			85,042			732
	Liabilities incurred	—			—			—
	Liabilities settled	(79		)	(67		)	(12		)
	Accretion expense	7,245			7,174			62
	Revisions to estimated cash flows(1)	3,076			3,076			—
	Liability at December 31, 2013	96,135			95,225			782
	Liabilities incurred	—			—			—
	Liabilities settled	—			—			—
	Accretion expense	7,984			7,906			66
	Revisions to estimated cash flows	51			51			—
	Liability at December 31, 2014	$	104,170		$	103,182		$	848
	(1)	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2013, a new decommissioning study for PVNGS was implemented reflecting updated cash flow estimates, including the extended operating licenses. The new study resulted in an increase of $0.5 million to the ARO. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 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 17) 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. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.
	Commitments and Contingencies Related to the Environment
	PVNGS Decommissioning Funding
	PNM has a program for funding its share of decommissioning costs for PVNGS, including portions held under leases. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. PNM funded $4.9 million, $4.9 million, and $2.6 million for the years ended December 31, 2014, 2013, and 2012 into the qualified and non-qualified trust funds. The estimated market value of the trusts at December 31, 2014 and 2013 was $244.6 million and $222.5 million.
	Nuclear Spent Fuel and Waste Disposal
	Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement is $5.9 million, substantially all of which is credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 30, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a $42.5 million claim for costs paid between July 1, 2011, and June 30, 2014. PNM’s share of the settlement would amount to $4.3 million, will be recorded when a final determination of the claim is made, which is anticipated to be in March 2015, and would primarily be credited back to PNM’s customers. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.
	PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At December 31, 2014 and 2013, PNM had a liability for interim storage costs of $12.3 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 and temporary storage rule (“Waste Confidence Decision”).
	The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions.  The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA.
	On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision.  The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.
	In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012, decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals.
	PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.  Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047.  If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
	In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. The fee applicable to PVNGS Units 1 and 2 is being recovered by PNM in its retail rates. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.
	The Clean Air Act
	Regional Haze
	In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.
	SJGS
	BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.
	PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties.
	During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP.
	In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement. NMED developed a RSIP and submitted it to the EIB for approval in May 2013. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.
	Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”
	Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.
	Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS.
	The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would be about 46.3%.
	Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract.
	NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:
	•	Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs
	•	A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018
	•	An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million
	•	A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS
	The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 17. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $268.4 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment.
	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 RSIP. 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. In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements are memorialized in the resolution and term sheet described below.
	On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by other intervenors.
	Under the terms of the stipulation, PNM:
	•	Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017
	•	Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million
	•	Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at December 31, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $282 million
	•	Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at December 31, 2014, PNM’s net book value of PVNGS Unit 3 was approximately $144 million
	•	Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million
	•	Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA
	A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:
	•	PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below
	•	PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval
	•	PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015
	PNM expects a decision from the NMPRC in the second quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.
	SJGS Ownership Restructuring Matters – 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.
	The SJGS participants have engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring have also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.
	On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS, the resolution of which is necessary for continued operation of SJGS after December 31, 2017. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations.
	In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014. The Fuel and Capital Funding Agreement provides that the SJGS participants will return to the prior arrangement if a binding restructuring agreement is not reached.
	On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, a scenario is being evaluated in which PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS and mediated discussions regarding remaining issues have continued, including matters that were addressed in the Fuel and Capital Funding Agreement.
	The participants continue to negotiate other definitive agreements that would formalize the matters contained in the Resolution, as amended. 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 impact of the above developments on negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained, but expects negotiations to proceed consistent with the time frames described in NMPRC Filing above.
	Other Developments and Current Status – 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 described below, 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. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014, $6.4 million on June 27, 2014, and total project expenses of $76.6 million (including the two prior requests) on January 22, 2015. The Unit 4 owners did not approve these requests.
	PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA 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. Therefore, on March 10, 2014 and July 14, 2014, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.
	As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3. Obtaining NMPRC approval will likely require that final binding agreements be reached among the SJGS owners on a revised ownership structure to facilitate the retirement of these two units. In turn, reaching agreement on ownership restructuring, will likely require that agreement be reached regarding the supply of coal for SJGS for periods after December 31, 2017. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.
	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.
	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 shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 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.
	SCE, a participant in Four Corners, indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. A principal condition to closing was the execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below.
	On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.
	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.  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.  A final EIS is expected to be issued in March 2015. In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014. PNM cannot predict whether the 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 $80.0 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. On September 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.
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. On October 21, 2014, the Tenth Circuit denied the petitions for review and affirmed EPA’s actions. On December 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.
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 NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. The revised permit, requires the reduction of SO2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to require the installation of BDT 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. 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 60-70 parts per billion (“ppb”). On December 17, 2014, EPA published a proposed rule that would revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA is proposing a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA is proposing to set an 8-hour secondary standard at a level within the range of 65 to 70 ppb. According to EPA, 2011-2013 ozone ambient air monitoring data indicates that Bernalillo, Dona Ana, Eddy, and San Juan counties in New Mexico exceed a 70 ppb ozone concentration. In addition, Lea, Luna Santa Fe, and Valencia counties exceed the 65 ppb ozone concentration. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. 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 controls to meet a new ozone NAAQS. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation. EPA is under a court order to finalize the ozone standard by October 1, 2015.
Citizen Suit Under the Clean Air Act
The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.
In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought 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. Under the stipulated order, PNM was required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions 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 completed stack testing and submitted the study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. NMED and the plaintiffs are evaluating the study and PNM’s recommendation. 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 parties have recently agreed on terms of a settlement. The terms of the settlement do not have a material impact on PNM.  PNM recorded the impact of its share of the proposed settlement in 2014. A final consent decree has not yet been executed.
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 NEPA 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 a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, 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. Legal briefing is complete and the matter is ready for a ruling from the court. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.
Navajo Nation Environmental Issues
Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.
Cooling Water Intake Structures
EPA issued its final cooling water intake structures rule on May 19, 2013, 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 was published on August 15, 2014 and became effective October 14, 2014.
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. The renewal date for the SJGS NPDES permit is March 31, 2016; however, additional time to submit the application may be allowed by the NPDES permit writer. 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. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.
Effluent Limitation Guidelines
On June 7, 2013, EPA published proposed revised 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. 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 conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property.  This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels.  Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation.  PNM is unable to predict the outcome of these matters.
Coal Combustion Byproducts Waste Disposal
Regulation
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 included two options for waste designation of coal ash. One option was 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 was 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 is developing a proposed rule governing the placement of CCBs at coal mining and reclamation operations.
On January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, and industry group members, the court issued 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.
On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non- compliance with the new requirements.
PNM is reviewing the rule to fully understand its implications. The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCR rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows.
Sierra Club Consent Decree
In April 2010, the Sierra Club filed suit against PNMR, PNM, SJCC, and BHP in the United States District Court for the District of New Mexico. In the complaint, as amended, Sierra Club alleged that activities at SJGS and SJCC’s San Juan mine were causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan mine constituted “open dumping” in violation of RCRA.  The suit also included claims against SJCC and BHP under the Surface Mine Control and Reclamation Act. The complaint requested judgment for injunctive relief, payment of civil penalties, and an award of plaintiffs’ attorney’s fees and costs.
On March 28, 2012, the parties filed an executed consent decree with the court, which was approved by the court on April 12, 2012, settling the litigation. Under the terms of the consent decree, the SJGS owners and SJCC will construct and operate a slurry wall and recovery trench, fund other environmental projects, and pay Sierra Club’s attorneys’ and experts’ fees. The total estimated cost of the settlement is $10.2 million, of which about $4.5 million is PNM’s share. Substantially all of the income statement impact related to this settlement was recorded in 2011. The consent decree also includes a release of claims and a covenant not to sue by Sierra Club. PNM is complying with the requirements of the consent decree.
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 must comply with the MATS rule by April 16, 2015, unless the facility has been granted a 1-year extension under CAA section 112(i)(3). PNM has not requested an extension and will begin complying with the MATS rule by the date specified in the 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 requested and received a 1-year extension until April 16, 2016 for Four Corners to comply with the MATS rule. However, 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 December 31, 2014 and 2013, prepayments for coal, which are included in other current assets, amounted to $37.3 million and $12.3 million. 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. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants will need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the coal sales agreement. The parties to the coal sales agreement and the amendment are SJCC, PNM, and Tucson. The amendment provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. The amendment, which was effective as of October 2, 2014, also released the parties from the obligation to negotiate an extension of the coal sales agreement, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed. On February 12, 2015, the SJGS Coordination Committee approved a resolution authorizing the modification of the amendment to extend the date for negotiation of a transaction until May 1, 2015 and to allow for a direct sale of the SJCC mining operations by BHP to a third-party mining company. PNM anticipates that in connection with a consummated purchase transaction, the third-party mining company would enter into an agreement to supply coal to SJGS. The parties to the amendment also entered into an agreement in October 2014 providing the SJGS participants with access to data necessary to evaluate the mine assets and liabilities. This agreement has terminated and was not renewed in order to allow the parties to focus on the direct sales process. Currently, PNM cannot predict the outcome of these negotiations or if a transaction will be consummated.
APS purchased 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, beginning in July 2016 and 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 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. 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 current 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 2014 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $57.3 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of December 31, 2014. At December 31, 2014 and 2013, liabilities, in current dollars, of $25.7 million and $23.8 million for surface mine reclamation and $8.6 million and $7.8 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the coal sales agreement. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $1.0 million in 2014, $0.3 million in 2013, and $3.5 million in 2012. Future funding requirements are currently expected to approximate $0.6 million annually.
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 (Note 4) 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, which was performed in 2013, 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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. How costs would be divided among the owners of SJGS has not been finalized. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible 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 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. Coal inventories have been restored to pre-incident levels and SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal 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 17.
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 was 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 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 9.4%, 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 cannot predict the timing or outcome of this litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.
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.
Natural Gas Supply
PNM procures gas supplies for its power plants from third-party sources and contracts with third party transportation providers.
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, Rio Bravo, 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. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment of one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached a standstill 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 challenges to the ordinance are 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.  On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested.  The letter indicated that the renewals were not processed because the necessary consent was not met.  It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners.  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	12 Months Ended
	Dec. 31, 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 16.
	PNM
	2014 Electric Rate Case
	On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future year test period. The application proposes a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE is 10.5%. The requested base rate increase, combined with other rate changes, represent an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, is related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs is a contributing factor to the decline in PNM’s energy sales since the last rate case and accounts for the balance of the rate increase after accounting for offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals include increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing photovoltaic systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. A public hearing on the rate case is expected to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015.
	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.
	The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges.
	PNM’s renewable energy procurement plan for 2012 requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM’s 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of the Lightning Dock Geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM’s voluntary renewable energy tariff. The plan enabled PNM to comply with the statutory RPS in 2013, but required a variance from the NMPRC’s diversity requirements in 2013 while the proposed geothermal facilities were being constructed. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. In 2013, PNM made renewable procurements consistent with the 2013 plan approved by the NMPRC. Construction of the solar PV facilities was completed in 2013 at a cost of $48.9 million. The geothermal facility began providing power to PNM in January 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity.
	PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements 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. The NMPRC approved the plan on December 18, 2013.
	PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 16). On September 25, 2014, a stipulated settlement was filed by PNM, staff of the NMPRC, the NMAG, NMIEC, Coalition for Clean Affordable Energy, and Western Resource Advocates. The stipulation proposed approval of PNM’s procurement proposals; however, the costs for the 40 MW of solar would be included in base rates to be set in PNM’s next general rate case rather than through PNM’s renewable energy rider. Under the agreement, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. A public hearing on the stipulation was held on October 27, 2014. On November 26, 2014, the NMPRC issued an order approving the stipulation with a modification that revised the not-to-exceed price from $4.25 per MWh to $3.00 per MWh for any additional necessary procurements to meet the RPS requirement in 2013 or 2014. In December 2014, PNM procured an additional 44,000 MWh of renewable resources to meet the 2013 RPS requirement at an average cost of $1.75 per MWh.
	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. Preliminary calculations indicate PNM’s jurisdictional equity return did not exceed 10.5% in 2014.
	PNM recorded revenues from the rider of $34.3 million, $23.7 million, and $6.4 million in 2014, 2013, and 2012. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015.
	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.
	On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. If approved, the stipulation would establish program budgets and incentive amounts, assuming a threshold level of energy savings are achieved, for 2015 and 2016. Two parties filed statements in opposition to the stipulation. A public hearing on the stipulation was held in February 2015.
	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.
	In June 2011, the NMPRC approved PNM-specific incentives for savings. PNM collected approximately $1.3 million, on an annual basis, in incentive revenues through November 2013 consistent with this order. On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013. In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved. A public hearing was held in February 2015. The NMPRC has not yet acted upon PNM’s application.
	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. The NMPRC issued an order on October 8, 2014, adopting the proposed rule.
	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. 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 mine fire incident discussed in Note 16, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, required PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and required 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.
	The NMPRC approval of the amended stipulation in PNM’s 2010 Electric Rate Case limited the amount that could be recovered on an annual basis for fuel costs during certain years. Costs in excess of the limits were deferred, without carrying costs, for recovery in future periods. The fuel cost caps were $38.8 million for the FPPAC year beginning July 1, 2012 and $36.2 million for the FPPAC year beginning July 1, 2013. The fuel cost caps ended on June 30, 2014. The resulting under-recovery as of April 30, 2014 was $63.5 million. Consistent with the order approved in PNM’s FPPAC Continuation Application, PNM is recovering this under-collection, net of the write-off agreed to in the settlement, over an 18 month period beginning July 1, 2014.
	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 16) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.
	San Juan Generating Station Units 2 and 3 Retirement
	On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation is set forth in Note 16. A public hearing in the NMPRC case was held in January 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.
	Four Corners Right of First Refusal
	On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM intends to inform the NMPRC about receipt of the notice and advise the NMPRC that PNM does not intend to exercise its rights under the ROFR. If not exercised, the ROFR will expire 120 days from the date of the notice.
	Transmission Rate Case
	In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  In December 2010, FERC issued an order accepting PNM’s filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM’s wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM’s transmission system to transmit power at the wholesale level.  The rate increase did not impact PNM’s retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC’s approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013, concluding this matter.
	Formula Transmission Rate Case
	On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. 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. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013.
	On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its 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. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. The parties have engaged in settlement negotiations and PNM anticipates that a settlement will be filed with FERC in the near future. There is no required time frame for FERC to act upon a settlement. PNM is unable to predict the outcome of this proceeding.
	Firm-Requirements Wholesale Customers
	Navopache Electric Cooperative, Inc. Rate Case
	In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement provided for an annual increase of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter.
	City of Gallup, New Mexico Contract
	PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On 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 revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014 and totaled $11.7 million during 2013.  PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.
	TNMP
	Advanced Meter System Deployment
	In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.
	In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.
	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 annual 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 annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of February 20, 2015, 89 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.
	Remand of ERCOT Transmission Rates for 1999 and 2000
	Following various appeals, the ERCOT transmission rates approved for the fourth quarter of 1999 and 2000 were remanded back to the PUCT. In October 2011, TNMP joined in a non-unanimous settlement relating to resettlement of the fourth quarter of 1999. In January 2012, the PUCT approved the non-unanimous settlement awarding TNMP $1.6 million. In June 2012, TNMP filed its transmission cost recovery factor filing (“TCRF”) seeking $3.2 million in additional transmission costs. The PUCT staff requested a hearing asserting the settlement proceeds from the 1999 remand settlement must be credited against the costs TNMP requested in its TCRF. After further discussion, PUCT staff agreed that no credit was required since TNMP had not recovered those costs in 1999. The PUCT staff agreed to interim rate relief permitting TNMP to add $1.6 million in uncontested costs to its existing TCRF. TNMP implemented the interim rates on September 1, 2012. On November 19, 2012, the PUCT ordered that the $1.6 million in interim rates were final and authorized TNMP to institute a surcharge in March 2013 to collect the additional $1.6 million in initially disputed costs plus interest.
	Energy Efficiency
	TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). In September 2011, the PUCT approved a settlement that allows TNMP to collect the estimated 2012 energy efficiency program costs of $3.4 million and a $0.3 million bonus for 2010. TNMP’s new rates were effective January 1, 2012. 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, including a performance bonus for 2012 of $0.7 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 request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014 permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP recorded the $1.5 million incentive bonus for 2013 upon approval by the PUCT.
	Transmission Cost of Service Rates
	TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s most recent interim transmission cost rate increases:
	Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
		(in millions)
	27-Sep-12	$	26.4	$	2.5
	20-Mar-13	21.9		2.9
	17-Sep-13	18.1		2.8
	13-Mar-14	18.2		2.9
8-Sep-14	25.2		4.2
In January 2015, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $27.1 million, which would increase revenues by $4.4 million annually. The application is pending before the PUCT.
Periodic Distribution Rate Adjustment
In September 2011, the PUCT approved a new rule permitting interim rate adjustments to reflect changes in investments in distribution assets. The rule permits distribution utilities to file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data.
Consolidated Tax Savings Adjustment
On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment (“CTSA”) from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 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. These services are billed at cost on a monthly basis to the business units.
	PNMR files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PNMR and each of its affiliated companies. These agreements provide that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PNMR. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PNMR to the extent that PNMR is able to utilize those benefits.
	See Note 6 for information on intercompany borrowing arrangements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:
		Year Ended December 31,
		2014		2013		2012
				(In thousands)
	Services billings:
	PNMR to PNM	$	86,871	$	92,597	$	99,986
	PNMR to TNMP	28,349		28,937		29,110
	PNM to TNMP	524		562		595
	TNMP to PNMR	31		7		15
	Income tax sharing payments:
	PNMR to TNMP	—		—		1,951
	PNMR to PNM	—		77,433		63,114
	TNMP to PNMR	—		3,643		—
	Interest payments:
	PNM to PNMR	65		4		1
	TNMP to PNMR	309		481		137

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss)
	AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNMR
	Balance at December 31, 2011	$	15,634		$	(82,432	)	$	(58	)	$	(66,856	)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			182			(32,476		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	(65		)	12,865
	Other OCI changes (pre-tax)	38,548			(30,084		)	(428		)	8,036
	Income tax impact of other OCI changes	(15,262		)	11,910			153			(3,199		)
	Net change after income taxes	772			(15,388		)	(158		)	(14,774		)
	Balance at December 31, 2012	16,406			(97,820		)	(216		)	(81,630		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			207			(5,385		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	(73		)	2,137
	Other OCI changes (pre-tax)	27,419			17,136			(279		)	44,276
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	98			(17,538		)
	Net change after income taxes	9,342			14,195			(47		)	23,490
	Balance at December 31, 2013	25,748			(83,625		)	(263		)	(58,140		)
	Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			558			(8,152		)
	Income tax impact of amounts reclassified	5,461			(2,032		)	(195		)	3,234
	Other OCI changes (pre-tax)	17,473			(15,282		)	(153		)	2,038
	Income tax impact of other OCI changes	(6,812		)	6,024			53			(735		)
	Net change after income taxes	2,260			(6,138		)	263			(3,615		)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—		$	(61,755	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNM
	Balance at December 31, 2011	$	15,634		$	(82,432	)	$	—		$	(66,798	)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			—			(32,658		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	—			12,930
	Other OCI changes (pre-tax)	38,548			(30,084		)	—			8,464
	Income tax impact of other OCI changes	(15,262		)	11,910			—			(3,352		)
	Net change after income taxes	772			(15,388		)	—			(14,616		)
	Balance at December 31, 2012	16,406			(97,820		)	—			(81,414		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			—			(5,592		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	—			2,210
	Other OCI changes (pre-tax)	27,419			17,136			—			44,555
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	—			(17,636		)
	Net change after income taxes	9,342			14,195			—			23,537
	Balance at December 31, 2013	25,748			(83,625		)	—			(57,877		)
	Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			—			(8,710		)
	Income tax impact of amounts reclassified	5,461			(2,032		)	—			3,429
	Other OCI changes (pre-tax)	17,473			(15,282		)	—			2,191
	Income tax impact of other OCI changes	(6,812		)	6,024			—			(788		)
	Net change after income taxes	2,260			(6,138		)	—			(3,878		)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—		$	(61,755	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	TNMP
	Balance at December 31, 2011	$	—		$	—		$	(58	)	$	(58	)
	Amounts reclassified from AOCI (pre-tax)	—			—			182			182
	Income tax impact of amounts reclassified	—			—			(65		)	(65		)
	Other OCI changes (pre-tax)	—			—			(428		)	(428		)
	Income tax impact of other OCI changes	—			—			153			153
	Net change after income taxes	—			—			(158		)	(158		)
Balance at December 31, 2012	—			—			(216		)	(216		)
Amounts reclassified from AOCI (pre-tax)	—			—			207			207
Income tax impact of amounts reclassified	—			—			(73		)	(73		)
Other OCI changes (pre-tax)	—			—			(279		)	(279		)
Income tax impact of other OCI changes	—			—			98			98
Net change after income taxes	—			—			(47		)	(47		)
Balance at December 31, 2013	—			—			(263		)	(263		)
Amounts reclassified from AOCI (pre-tax)	—			—			558			558
Income tax impact of amounts reclassified	—			—			(195		)	(195		)
Other OCI changes (pre-tax)	—			—			(153		)	(153		)
Income tax impact of other OCI changes	—			—			53			53
Net change after income taxes	—			—			263			263
Balance at December 31, 2014	$	—		$	—		$	—		$	—
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 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 Consolidated Statements of Earnings. For the years ended December 31, 2014 and 2013, approximately 24.4% and 18.7% of the amount reclassified were capitalized into construction work in process and approximately 2.0% and 3.0% were 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 Consolidated Statements of Earnings. An insignificant amount is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in Income Taxes in the Consolidated Statements of Earnings.

Goodwill_Impairments

Goodwill; Impairments	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill; Impairments	Goodwill; Impairments
	The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.
	GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. The Company evaluates goodwill impairment as of April 1st of each year. 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 considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in 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 requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.
	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. Prior to 2013, the Company performed qualitative analyses for all reporting units having goodwill. 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 in the quantitative analysis to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.
	The April 1, 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%. An increase of 0.5% in the expected return on equity capital utilized in discounting the forecasted cash flows, would have reduced the excess of PNM’s fair value over carrying value to approximately 23% and 20% at April 1, 2014 and 2013. The 2014 and 2013 qualitative analysis for the TNMP reporting unit, which has goodwill of $226.7 million, included the consideration of various reporting unit specific factors as well as industry and macroeconomic factors to determine whether these factors were reasonably likely to have a material impact on the fair value of the reporting unit. Factors considered included the results of the April 1, 2012 quantitative analysis, which indicated that fair value exceeded carrying value of the reporting unit by approximately 26%, current and long-term forecasted financial results, regulatory environment, credit rating, interest rate environment, absolute and relative price of PNMR’s common stock, and operating strategy. TNMP believes it is operating within a generally favorable regulatory environment, its historical and forecasted financial results are positive, and its credit is perceived positively. Based on the analysis of the relevant factors, PNMR concluded that it is more likely than not that the fair value of the TNMP reporting unit exceeds its carrying value. 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. 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.
	Prior annual evaluations have not indicated impairments of any of PNMR’s reporting units, except in 2008. During 2008, the market capitalization of PNMR’s common stock was significantly below book value. In addition, First Choice, a PNMR reporting unit that was sold in 2011, was significantly impacted by depressed economic conditions and changes in the market in which it operated. As a result, goodwill impairments of $51.1 million for PNM, $34.5 million for TNMP, and an aggregate of $174.4 million for PNMR were recorded in 2008. Since 2008, the price of PNMR’s common stock has increased, improving the relationship between PNMR’s market capitalization and book value. In addition, improved regulatory treatment has been experienced by PNM in New Mexico and by TNMP in Texas. These factors resulted in more predictable earnings and increased fair values of the reporting units. Since 2008, the annual evaluations have not indicated that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

Quarterly_Operating_Results_Un

Quarterly Operating Results (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Quarterly Operating Results (Unaudited)	Quarterly Operating Results (Unaudited)
	Unaudited operating results by quarters for 2014 and 2013 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included.
		Quarter Ended
		March 31		June 30		September 30		December 31
		(In thousands, except per share amounts)
	PNMR
	2014
	Operating revenues	$	328,897	$	346,160	$	413,951	$	346,845
	Operating income	48,753		71,296		116,799		62,849
	Net earnings	16,131		33,181		59,486		22,111
	Net earnings attributable to PNMR	12,468		29,141		55,653		18,992
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.16		0.37		0.7		0.24
	Diluted	0.16		0.36		0.69		0.24
	2013
	Operating revenues	$	317,665	$	347,599	$	399,730	$	322,929
	Operating income	50,704		77,867		117,739		40,532
	Net earnings	13,962		31,383		58,814		11,397
	Net earnings attributable to PNMR	10,626		27,678		54,555		7,648
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.13		0.35		0.68		0.1
	Diluted	0.13		0.34		0.68		0.1
	PNM
	2014
	Operating revenues	$	262,736	$	275,704	$	334,993	$	274,481
	Operating income	31,304		49,806		90,615		40,988
	Net earnings	11,205		24,254		49,052		16,942
	Net earnings attributable to PNM	7,674		20,346		45,351		13,955
	2013
	Operating revenues	$	257,894	$	279,690	$	326,026	$	252,702
	Operating income	37,239		58,302		95,217		18,427
	Net earnings	14,773		29,697		51,950		6,256
	Net earnings attributable to PNM	11,569		26,124		47,823		2,639
	TNMP
	2014
	Operating revenues	$	66,161	$	70,456	$	78,958	$	72,364
	Operating income	17,262		21,265		25,873		21,188
	Net earnings	6,803		9,534		12,355		9,115
	2013
	Operating revenues	$	59,771	$	67,909	$	73,704	$	70,227
	Operating income	13,054		19,667		22,254		17,210
	Net earnings	3,726		8,339		10,106		6,919

Schedule_I_Condensed_Financial

Schedule I - Condensed Financial Information of Parent Company	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I - Condensed Financial Information of Parent Company	SCHEDULE I
	PNM RESOURCES, INC.
	CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
	STATEMENTS OF EARNINGS
		Year ended December 31,
		2014			2013			2012
		(In thousands)
	Operating Revenues	$	—		$	—		$	—
	Operating Expenses	650			941			3,287
	Operating income (loss)	(650		)	(941		)	(3,287		)
	Other Income and Deductions:
	Equity in earnings of subsidiaries	124,543			116,634			117,900
	Other income	622			769			670
	Other deductions	(13,650		)	(22,825		)	(20,904		)
	Net other income (deductions)	111,515			94,578			97,666
	Earnings Before Income Taxes	110,865			93,637			94,379
	Income Tax Expense (Benefit)	(5,389		)	(6,870		)	(11,168		)
	Net Earnings	$	116,254		$	100,507		$	105,547
	SCHEDULE I
	PNM RESOURCES, INC.
	CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
	STATEMENTS OF CASH FLOWS
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Cash Flows From Operating Activities:
	Net earnings	$	116,254		$	100,507		$	105,547
	Adjustments to reconcile net earnings to net cash flows from operating activities:
	Depreciation and amortization	680			4,192			5,000
	Deferred income tax expense	(69,442		)	(51,820		)	(46,632		)
	Equity in (earnings) of subsidiaries	(124,543		)	(116,634		)	(117,900		)
	Loss on reacquired debt	—			3,253			—
	Stock based compensation expense	5,931			5,320			3,585
	Changes in certain assets and liabilities:
	Other current assets	22,955			28,460			(43,638		)
	Other assets	51,644			46,558			34,096
	Accounts payable	(88		)	620			8
	Accrued interest and taxes	(7,683		)	(9,266		)	(28,855		)
	Other current liabilities	(1,668		)	(146		)	3,876
	Other liabilities	28,704			(27,756		)	(29,601		)
	Net cash flows from operating activities	22,744			(16,712		)	(114,514		)
	Cash Flows From Investing Activities:
	Utility plant additions	(474		)	(960		)	(7,524		)
	Investments in subsidiaries	—			(13,800		)	—
	Cash dividends from subsidiaries	46,599			158,772			61,406
	Net cash flows from investing activities	46,125			144,012			53,882
	Cash Flows From Financing Activities:
	Short-term borrowings (repayments), net	600			(37,600		)	120,900
	Repayment of long-term debt	—			(29,468		)	(2,387		)
	Proceeds from stock option exercise	6,999			4,618			11,684
	Purchases to satisfy awards of common stock	(17,319		)	(13,807		)	(25,168		)
	Dividends paid	(58,940		)	(50,980		)	(44,609		)
	Other, net	81			—			—
	Net cash flows from financing activities	(68,579		)	(127,237		)	60,420
	Change in Cash and Cash Equivalents	290			63			(212		)
	Cash and Cash Equivalents at Beginning of Period	92			29			241
	Cash and Cash Equivalents at End of Period	$	382		$	92		$	29
	Supplemental Cash Flow Disclosures:
	Interest paid	$	12,152		$	14,510		$	15,007
	Income taxes paid (refunded), net	$	(2,014	)	$	22,378		$	1,501
	SCHEDULE I
	PNM RESOURCES, INC.
	CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
	BALANCE SHEETS
	December 31,
	2014			2013
	(In thousands)
Assets
Cash and cash equivalents	$	382		$	92
Intercompany receivables	107,619			136,387
Income taxes receivable	29			14,989
Other, net	8,115			8,544
Total current assets	116,145			160,012
Property, plant and equipment, net of accumulated depreciation of $10,251 and $9,167	27,076			26,601
Investment in subsidiaries	1,757,650			1,683,321
Other long-term assets	70,939			53,892
Total long-term assets	1,855,665			1,763,814
	$	1,971,810		$	1,923,826
Liabilities and Stockholders’ Equity
Short-term debt	$	100,600		$	100,000
Short-term debt-affiliate	8,819			8,819
Current maturities of long-term debt	118,766			—
Accrued interest and taxes	2,816			2,797
Other current liabilities	16,320			16,876
Total current liabilities	247,321			128,492
Long-term debt	—			118,766
Other long-term liabilities	2,943			2,999
Total liabilities	250,264			250,257
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,173,845			1,178,369
Accumulated other comprehensive income (loss), net of tax	(61,755		)	(58,140		)
Retained earnings	609,456			553,340
Total common stockholders’ equity	1,721,546			1,673,569
	$	1,971,810		$	1,923,826
See Notes 6, 7, 14, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	SCHEDULE II
	PNM RESOURCES, INC. AND SUBSIDIARIES
	VALUATION AND QUALIFYING ACCOUNTS
							Additions						Deductions
		Description		Balance at			Charged to			Charged to			Write-offs and other			Balance at
				beginning of			costs and			other						end of year
				year			expenses			accounts
							(In thousands)
		Allowance for doubtful accounts, year ended December 31:
		2012		$	1,778		$	3,367		$	—		$	3,394		$	1,751
		2013		$	1,751		$	2,849		$	—		$	3,177		$	1,423
		2014		$	1,423		$	3,267		$	—		$	3,224		$	1,466
	SCHEDULE II
	PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY
	A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
	VALUATION AND QUALIFYING ACCOUNTS
							Additions						Deductions
		Description		Balance at			Charged to			Charged to			Write-offs			Balance at
				beginning of			costs and			other						end of year
				year			expenses			accounts
							(In thousands)
		Allowance for doubtful accounts, year ended December 31:
		2012		$	1,778		$	3,384		$	—		$	3,411		$	1,751
		2013		$	1,751		$	2,864		$	—		$	3,192		$	1,423
		2014		$	1,423		$	3,275		$	—		$	3,232		$	1,466
	SCHEDULE II
	TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
	A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
	VALUATION AND QUALIFYING ACCOUNTS
						Additions						Deductions
	Description		Balance at			Charged to			Charged to			Write-offs			Balance at
			beginning of			costs and			other						end of year
			year			expenses			accounts
						(In thousands)
	Allowance for doubtful accounts, year ended December 31:
	2012		$	—		$	(17	)	$	—		$	(17	)	$	—
	2013		$	—		$	(15	)	$	—		$	(15	)	$	—
	2014		$	—		$	(8	)	$	—		$	(8	)	$	—

Summary_of_the_Business_and_Si1

Summary of the Business and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Principles of Consolidation	The 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 (Note 9). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.
	PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated.
Accounting for the Effects of Certain Types of Regulation	The Company maintains its accounting records in accordance with the uniform system of accounts prescribed by FERC and adopted by the NMPRC and PUCT.
	Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to the regulated operations. Regulators may assign costs to accounting periods that differ from accounting methods applied by non-regulated utilities.  When it is probable that regulators will permit recovery of costs through future rates, costs that otherwise would be expensed are deferred as regulatory assets.  Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred.  Regulatory assets and liabilities are amortized into earnings over the authorized recovery period. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the NMPRC, PUCT, and FERC. Information on regulatory assets and regulatory liabilities is contained in Note 4.
	In some circumstances, regulators allow a requested increase in rates to be implemented, subject to refund, before the regulatory process has been completed and a decision rendered by the regulator. When this occurs, the Company assesses the possible outcomes of the rate proceeding. The Company records a provision for refund to the extent the amounts being collected, subject to refund, exceed the amount the Company determines is probable of ultimately being allowed by the regulator.
Cash and Cash Equivalents	Investments in highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.
Utility Plant	Utility plant is stated at cost, which includes capitalized payroll-related costs such as taxes, pension, and other fringe benefits, administrative costs, and AFUDC where authorized by rate regulation.
	Repairs, including major maintenance activities, and minor replacements of property are expensed when incurred, except as required by regulators for ratemaking purposes. Major replacements are charged to utility plant. Gains or losses resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to accumulated depreciation.
Allowance for Funds Used During Construction	As provided by the FERC uniform systems of accounts, AFUDC is charged to regulated utility plant for construction projects. This allowance is a non-cash item designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). The allowance for borrowed funds used during construction is recorded in interest charges and the allowance for equity funds used during construction is recorded in other income on the Consolidated Statements of Earnings.
Capitalized Interest	The Company capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC.
Materials, Supplies, and Fuel Stock	Materials and supplies relate to transmission, distribution, and generating assets. Materials and supplies are charged to inventory when purchased and are expensed or capitalized as appropriate when issued. Materials and supplies are valued using an average costing method.
	Coal is valued using a rolling weighted average costing method that is updated based on the current period cost per ton. Periodic aerial surveys are performed on the coal piles and adjustments are made.
Investments	PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). All of these investments are classified as available-for-sale. PNM evaluates the securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2014, 2013, and 2012, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $4.8 million, $3.5 million, and $4.8 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI.
Goodwill and Other Intangible Assets	Under GAAP, the Company does not amortize goodwill. Goodwill is evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill might be impaired.
Asset Impairment	Tangible long-lived assets are evaluated in relation to the estimated future undiscounted cash flows to assess recoverability when events and circumstances indicate that the assets might be impaired.
Revenue Recognition	Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience.
	PNM’s wholesale electricity sales are recorded as electric operating revenues and the wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are net settled or “booked-out” are recorded net in earnings. A book-out is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.
	Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold.
Accounts Receivable and Allowance for Uncollectible Accounts	Accounts receivable consists primarily of trade receivables from customers. In the normal course of business, credit is extended to customers on a short-term basis. The Company calculates the allowance for uncollectible accounts based on historical experience and estimated default rates. The accounts receivable balances are reviewed monthly and adjustments to the allowance for uncollectible accounts and bad debt expense are made as necessary. Amounts that are deemed uncollectible are written off.
Depreciation and Amortization	PNM’s provision for depreciation and amortization of utility plant, other than nuclear fuel, is based upon composite straight-line rates approved by the NMPRC. Amortization of nuclear fuel is based on units-of-production. TNMP’s provision for depreciation and amortization of utility plant is based upon straight-line rates approved by the PUCT. Depreciation of non-utility property is computed based on the straight-line method. The provision for depreciation of certain equipment is allocated between operating expenses and construction projects based on the use of the equipment.
Amortization of Debt Acquisition Costs	Discount, premium, and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. Gains and losses incurred upon the early retirement of long-term debt are recognized in other income or other deductions, except for amounts attributable to NMPRC, FERC, or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues.
Derivatives	The Company records derivative instruments, including energy contracts, other than those designated as normal purchases or normal sales, in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or normal sale criteria are met. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.
	The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity. GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances.
	Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the years ended December 31, 2014 and 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.
Decommissioning Costs	PNM owns and leases nuclear and fossil-fuel generating facilities. In accordance with GAAP, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Nuclear decommissioning costs and related accruals are based on periodic site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions, including estimates of future decommissioning costs at current price levels, inflation rates, and discount rates. PNM’s accruals for PVNGS Units 1, 2, and 3, including portions held under leases, have been made based on such estimates, the guidelines of the NRC, and the extended PVNGS license periods. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 is currently excluded. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fueled generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. See Note 15 and Note 16.
	In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation, as well as the costs for final reclamation of the coal mines. The reclamation costs are based on periodic site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions, including estimates of future reclamation costs at current price levels, inflation rates, and discount rates. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for a discussion of the final reclamation costs.
Environmental Costs	The normal operations of the Company involve activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred.
	The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process.
Income Taxes	Income taxes are recognized using the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current NMPRC, FERC, and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC, FERC, and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets.
Excise Taxes	The Company pays certain fees or taxes which are either considered to be an excise tax or similar to an excise tax. Substantially all of these taxes are recorded on a net basis in the Consolidated Statements of Earnings.
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.
Fair Value Derivatives	ures
	The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the years ended December 31, 2014 and 2013.
	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 serv
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.
Pension and Other Postretirement Benefits	GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur.
	GAAP requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs is included as pension and postretirement benefit periodic cost or income in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP record the costs as a regulatory asset or regulatory liability.
	The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility.
Commitments and Contingencies	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 17) 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. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Summary_of_the_Business_and_Si2

Summary of the Business and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Inventory, Current	Inventories consisted of the following at December 31:
		PNMR							PNM				TNMP
		2014			2013				2014		2013		2014		2013
		(In thousands)
	Coal	$	17,525		$	24,872			$	17,525	$	24,872	$	—	$	—
	Materials and supplies	46,103			42,351				43,334		39,648		2,769		2,703
		$	63,628		$	67,223			$	60,859	$	64,520	$	2,769	$	2,703
Schedule of Average Rates Used Allocated Between Depreciation Expense and Construction Expense Projects Based on Use of Equipment	Average straight-line rates used were as follows:
		Year ended December 31
		2014		2013			2012
	PNM
	Electric plant	2.26	%	2.27	%		2.25	%
	Common, intangible, and general plant	4.64	%	4.87	%		5.35	%
	TNMP	3.59	%	3.66	%		3.56	%

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	PNMR SEGMENT INFORMATION
	2014	PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Electric operating revenues	$	1,147,914		$	287,939		$	—		$	1,435,853
	Cost of energy	403,626			67,930			—			471,556
	Margin	744,288			220,009			—			964,297
	Other operating expenses	422,051			84,365			(14,450		)	491,966
	Depreciation and amortization	109,524			50,056			13,054			172,634
	Operating income	212,713			85,588			1,396			299,697
	Interest income	8,557			—			(74		)	8,483
	Other income (deductions)	12,258			2,138			(2,302		)	12,094
	Interest charges	(79,442		)	(27,396		)	(12,789		)	(119,627		)
	Segment earnings (loss) before income taxes	154,086			60,330			(13,769		)	200,647
	Income taxes (benefit)	52,633			22,523			(5,418		)	69,738
	Segment earnings (loss)	101,453			37,807			(8,351		)	130,909
	Valencia non-controlling interest	(14,127		)	—			—			(14,127		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	86,798		$	37,807		$	(8,351	)	$	116,254
	Gross property additions	$	316,800		$	127,191		$	16,667		$	460,658
	At December 31, 2014:
	Total Assets	$	4,473,652		$	1,240,241		$	115,432		$	5,829,325
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2013	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,116,312		$	271,611		$	—		$	1,387,923
	Cost of energy	374,710			57,606			—			432,316
	Margin	741,602			214,005			—			955,607
	Other operating expenses	428,591			91,601			(18,308		)	501,884
	Depreciation and amortization	103,826			50,219			12,836			166,881
	Operating income	209,185			72,185			5,472			286,842
	Interest income	10,182			—			(139		)	10,043
	Other income (deductions)	11,288			1,919			(13,575		)	(368		)
	Interest charges	(79,175		)	(27,393		)	(14,880		)	(121,448		)
	Segment earnings (loss) before income taxes	151,480			46,711			(23,122		)	175,069
	Income taxes (benefit)	48,804			17,621			(6,912		)	59,513
	Segment earnings (loss)	102,676			29,090			(16,210		)	115,556
	Valencia non-controlling interest	(14,521		)	—			—			(14,521		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	87,627		$	29,090		$	(16,210	)	$	100,507
	Gross property additions	$	239,906		$	89,117		$	19,016		$	348,039
	At December 31, 2013:
	Total Assets	$	4,227,616		$	1,162,431		$	110,163		$	5,500,210
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2012	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,092,264		$	250,140		$	(1	)	$	1,342,403
	Cost of energy	353,649			46,201			—			399,850
	Margin	738,615			203,939			(1		)	942,553
	Other operating expenses	435,442			87,079			(17,862		)	504,659
	Depreciation and amortization	97,291			49,340			17,542			164,173
	Operating income	205,882			67,520			319			273,721
	Interest income	13,243			1			(172		)	13,072
	Gain on sale of First Choice	—			—			1,012			1,012
	Other income (deductions)	13,290			2,739			(7,954		)	8,075
	Interest charges	(76,101		)	(28,161		)	(16,583		)	(120,845		)
	Segment earnings (loss) before income taxes	156,314			42,099			(23,378		)	175,035
	Income taxes (benefit)	50,713			15,352			(11,155		)	54,910
	Segment earnings (loss)	105,601			26,747			(12,223		)	120,125
	Valencia non-controlling interest	(14,050		)	—			—			(14,050		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	91,023		$	26,747		$	(12,223	)	$	105,547
	Gross property additions	$	196,800		$	92,973		$	19,136		$	308,909
	At December 31, 2012:
Total Assets	$	4,163,907		$	1,086,229		$	122,447		$	5,372,583
Goodwill	$	51,632		$	226,665		$	—		$	278,297

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Public Service Company of New Mexico [Member]
Regulatory Assets [Line Items]
Regulatory Assets and Liabilities [Table Text Block]	Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below.
	PNM
		December 31,
		2014			2013
	Assets:	(In thousands)
	Current:
	FPPAC	$	43,980		$	19,394
	Non-Current:
	Coal mine reclamation costs	34,224			40,144
	Deferred income taxes	63,645			61,850
	Loss on reacquired debt	25,439			27,490
	Pension and OPEB	222,545			206,691
	FPPAC	—			25,386
	Renewable energy costs	5,263			13,311
	Other	5,929			9,345
		357,045			384,217
	Total regulatory assets	$	401,025		$	403,611
	Liabilities:
	Current:
	Other	$	(1,703	)	$	(1,081	)
	Non-Current:
	Cost of removal	(277,148		)	(266,075		)
	Deferred income taxes	(75,941		)	(80,495		)
	AROs	(35,834		)	(37,567		)
	Renewable energy tax benefits	(24,854		)	(26,011		)
	Other	(11,704		)	(4,463		)
		(425,481		)	(414,611		)
	Total regulatory liabilities	$	(427,184	)	$	(415,692	)
Texas-New Mexico Power Company [Member]
Regulatory Assets [Line Items]
Regulatory Assets and Liabilities [Table Text Block]	TNMP
		December 31,
		2014			2013
	Assets:	(In thousands)
	Current:
	Transmission cost recovery factor	$	2,482		$	4,250
	Other	1,393			772
		3,875			5,022
	Non-Current:
	CTC, including carrying charges	55,292			63,606
	Deferred income taxes	10,556			10,868
	Pension	23,803			19,938
	Loss on reacquired debt	36,703			38,616
	AMS retirement costs	6,453			5,083
	Other	1,155			1,627
		133,962			139,738
	Total regulatory assets	$	137,837		$	144,760
	Liabilities:
	Non-Current:
	Cost of removal	$	(29,391	)	$	(30,863	)
	Deferred income taxes	(3,923		)	(4,563		)
	AMS surcharge	(5,227		)	(7,251		)
	OPEB	(2,121		)	(3,361		)
	Total regulatory liabilities	$	(40,662	)	$	(46,038	)

Financing_Tables

Financing (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Short-term Debt	Short-term debt outstanding consists of:
			December 31,
	Short-term Debt		2014				2013
			(In thousands)
	PNM:
	Revolving Credit Facility		$	—			$	49,200
	PNM New Mexico Credit Facility		—				—
	TNMP Revolving Credit Facility		5,000				—
	PNMR
	Revolving Credit Facility		600				—
	PNMR Term Loan Agreement		100,000				100,000
			$	105,600			$	149,200
Schedule of Long-term Debt Instruments	Information concerning long-term debt outstanding is as follows:
			December 31,
	Long-term Debt		2014				2013
			(In thousands)
	PNM Debt
	Senior Unsecured Notes, Pollution Control Revenue Bonds:
	4.875% due 2033		$	146,000			$	146,000
	6.25% due 2038		36,000				36,000
	4.75% due 2040, mandatory tender at June 1, 2017		37,000				37,000
	5.20% due 2040, mandatory tender at June 1, 2020		40,045				40,045
	5.90% due 2040		255,000				255,000
	6.25% due 2040		11,500				11,500
	2.54% due 2042, mandatory tender at June 1, 2017		20,000				20,000
	4.00% due 2043, mandatory tender at June 1, 2015		39,300				39,300
	5.20% due 2043, mandatory tender at June 1, 2020		21,000				21,000
	Senior Unsecured Notes:
	7.95% due 2018		350,000				350,000
	7.50% due 2018		100,025				100,025
	5.35% due 2021		160,000				160,000
	PNM Term Loan Agreement due 2014		—				75,000
	PNM Term Loan Agreement due 2015		175,000				—
	PNM Multi-draw Term Loan due 2016		100,000				—
	Unamortized premiums (discounts)		(213		)		(252		)
			1,490,657				1,290,618
	Less current maturities		214,300				75,000
			1,276,357				1,215,618
	TNMP Debt
	First Mortgage Bonds:
	2011 Term Loan Agreement, due 2014		—				50,000
	9.50% due 2019, Series 2009A		172,302				172,302
	6.95% due 2043, Series 2013A		93,198				93,198
	4.03% due 2024, Series 2014A		80,000				—
	Unamortized premiums (discounts)		20,167				20,536
			365,667				336,036
	Less current maturities		—				—
			365,667				336,036
	PNMR Debt
	Senior unsecured notes, 9.25% due 2015		118,766				118,766
	Less current maturities		118,766				—
			—				118,766
	Total Consolidated PNMR Debt		1,975,090				1,745,420
	Less current maturities		333,066				75,000
			$	1,642,024			$	1,670,420
Schedule of Maturities of Long-term Debt	Reflecting mandatory tender dates, long-term debt matures as follows:
		PNMR				PNM				TNMP		PNMR Consolidated
		(In thousands)
	2015	$	118,766			$	214,300			$	—	$	333,066
	2016	—				100,000				—		100,000
	2017	—				57,000				—		57,000
	2018	—				450,025				—		450,025
	2019	—				—				172,302		172,302
	Thereafter	—				669,545				173,198		842,743
	Total	$	118,766			$	1,490,870			$	345,500	$	1,955,136
	Borrowing Arrangements Between PNMR and its Subsidiaries
	PNMR has one-year intercompany loan agreements with its subsidiaries. Individual subsidiary loan agreements vary in amount up to $100.0 million and have either reciprocal or non-reciprocal terms. Interest charged to the subsidiaries is equivalent to interest paid by PNMR on its short-term borrowings. As of December 31, 2014 and 2013, PNM had outstanding borrowings of zero and $32.5 million and TNMP had outstanding borrowings of $22.7 million and $29.4 million from PNMR. At February 20, 2015, PNM and TNMP had borrowings of zero and $17.3 million from PNMR.

Lease_Commitments_Lease_Commit

Lease Commitments Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Schedule of Rent Expense	Operating lease expense, including the PVNGS and EIP leases, was:
		PNMR		PNM		TNMP
		(In thousands)
	2014	$	82,756	$	76,745	$	3,932
	2013	$	82,882	$	78,306	$	2,663
	2012	$	84,794	$	78,483	$	2,871
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum operating lease payments at December 31, 2014 shown below have been reduced by payments on the PVNGS lessor notes of $24.0 million in 2015 and $9.0 million in 2016 that will be returned in cash to PNM:
		PNMR		PNM		TNMP
		(In thousands)
	2015	$	36,350	$	33,144	$	1,186
	2016	28,892		27,986		636
	2017	25,185		24,907		—
	2018	25,194		24,907		—
	2019	25,203		24,907		—
	Later years	134,068		133,842		—
	Total minimum lease payments	$	274,892	$	269,693	$	1,822

Fair_Value_of_Derivative_and_O1

Fair Value of Derivative and Other Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value of Derivative and Other Financial Instruments [Abstract]
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
		December 31,
		2014				2013
		(In thousands)
	PNM and PNMR
	Current assets	$	11,232			$	4,064
	Deferred charges	—				3,002
		11,232				7,066
	Current liabilities	(1,209		)		(2,699		)
	Long-term liabilities	(477		)		(1,094		)
		(1,686		)		(3,793		)
	Net	$	9,546			$	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
		Year Ended
		December 31,
		2014				2013			2012
		(In thousands)
	PNMR and PNM
	Electric operating revenues	$	4,491			$	1,727		$	6,168
	Cost of energy	593				1,109			(460		)
	Total gain	$	5,084			$	2,836		$	5,708
Schedule of Notional Amounts of Outstanding Derivative Positions	The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
		Economic Hedges
		MMBTU			MWh
	December 31, 2014
	PNMR and PNM	650,000			(1,919,000	)
	December 31, 2013
	PNMR and PNM	905,000			(3,343,783	)
Schedule of Collateral Related to Derivative
	Contingent Feature –		Contractual				Existing Cash			Net Exposure
	Credit Rating Downgrade		Liability				Collateral
			(In thousands)
	December 31, 2014
	PNMR and PNM		$	1,686			$	—		$	167
	December 31, 2013
	PNMR and PNM		$	2,398			$	—		$	2,152
Available-for-sale Securities	The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2014 and 2013, the fair value of available-for-sale securities included $244.6 million and $222.5 million for the NDT and $5.5 million and $4.4 million for the mine reclamation trust.
		December 31, 2014							December 31, 2013
		Unrealized				Fair Value			Unrealized			Fair Value
		Gains							Gains
	PNMR and PNM					(In thousands)
	Cash and cash equivalents	$	—			$	8,276		$	—		$	3,356
	Equity securities:
	Domestic value	17,418				45,340			14,523			39,460
	Domestic growth	21,354				74,053			25,656			76,292
	International and other	156				16,599			1,040			16,633
	Fixed income securities:
	U.S. Government	903				22,563			158			21,941
	Municipals	5,851				68,973			1,018			58,568
	Corporate and other	666				14,341			207			10,605
		$	46,348			$	250,145		$	42,602		$	226,855
Schedule of Realized Gain (Loss)	Gross realized losses shown below exclude the change in realized impairment losses of $(0.7) million, $0.6 million, and $5.2 million.
		Year Ended December 31,
		2014				2013			2012
		(In thousands)
	Proceeds from sales	$	117,989			$	271,140		$	167,330
	Gross realized gains	$	15,162			$	14,308		$	15,907
	Gross realized (losses)	$	(3,964	)		$	(4,298	)	$	(8,170	)
Investments Classified by Contractual Maturity Date	At December 31, 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	$	3,946			$	8,019		$	8,019
	After 1 year through 5 years	20,275				25,430			24,817
	After 5 years through 10 years	13,422				—			—
	After 10 years through 15 years	10,367				—			—
	After 15 years through 20 years	11,539				—			—
	After 20 years	46,328				—			—
		$	105,877			$	33,449		$	32,836
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	Items recorded at fair value on the Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at December 31, 2014 and 2013 for items recorded at fair value.
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active Market for Identical Assets (Level 1)			Significant Other Observable Inputs
									(Level 2)
	December 31, 2014					(In thousands)
	PNMR and PNM
	Available-for-sale securities
	Cash and cash equivalents	$	8,276			$	8,276		$	—
	Equity securities:
	Domestic value	45,340				45,340			—
	Domestic growth	74,053				74,053			—
	International and other	16,599				16,599			—
	Fixed income securities:
	U.S. Government	22,563				20,808			1,755
	Municipals	68,973				—			68,973
	Corporate and other	14,341				4,843			9,498
		$	250,145			$	169,919		$	80,226
	Commodity derivative assets	$	11,232			$	—		$	11,232
	Commodity derivative liabilities	(1,686		)		—			(1,686		)
	Net	$	9,546			$	—		$	9,546
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active Market for Identical Assets (Level 1)			Significant Other Observable Inputs
									(Level 2)
	December 31, 2013					(In thousands)
	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
Fair Value, by Balance Sheet Grouping	The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt are presented below:
									GAAP Fair Value Hierarchy
		Carrying				Fair Value			Level 1			Level 2			Level 3
		Amount
	December 31, 2014	(In thousands)
	PNMR
	Long-term debt	$	1,975,090			$	2,173,117		$	—		$	2,173,117		$	—
	Investment in PVNGS lessor notes	$	31,232			$	32,836		$	—		$	—		$	32,836
	Other investments	$	1,762			$	2,375		$	639		$	—		$	1,736
	PNM
	Long-term debt	$	1,490,657			$	1,624,222		$	—		$	1,624,222		$	—
	Investment in PVNGS lessor notes	$	31,232			$	32,836		$	—		$	—		$	32,836
	Other investments	$	397			$	397		$	397		$	—		$	—
	TNMP
	Long-term debt	$	365,667			$	427,356		$	—		$	427,356		$	—
	Other investments	$	242			$	242		$	242		$	—		$	—
	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		$	—		$	—
Fair Value, Assets Measured on Recurring Basis	The fair values of investments held by the employee benefit plans are as follows:
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active Market for Identical Assets			Significant			Significant
						(Level 1)			Other			Unobservable
									Observable			Inputs
									Inputs			(Level 3)
									(Level 2)
	December 31, 2014					(In thousands)
	PNM Pension Plan
	Participation in PNMR Master Trust Total Plan Investments	$	588,112			$	123,668		$	398,819		$	65,625
	TNMP Pension Plan
	Participation in PNMR Master Trust Total Plan Investments	$	69,207			$	14,823		$	44,425		$	9,959
	PNM OPEB Plan
	Cash and cash equivalents	$	1,242			$	1,242		$	—		$	—
	Equity securities:
	International funds	10,332				—			10,332			—
	Domestic value	8,365				8,365			—			—
	Domestic growth	5,960				5,960			—			—
	Other funds	30,997				—			30,997			—
	Fixed income securities:
	Mutual funds	22,122				22,122			—			—
		$	79,018			$	37,689		$	41,329		$	—
	TNMP OPEB Plan
	Cash and cash equivalents	$	168			$	168		$	—		$	—
	Equity securities:
	International funds	1,277				—			1,277			—
	Domestic value	403				403			—			—
	Domestic growth	1,024				1,024			—			—
	Other funds	3,790				—			3,790			—
	Fixed income securities:
	Mutual funds	3,549				3,549			—			—
		$	10,211			$	5,144		$	5,067		$	—
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active			Significant			Significant
						Market for Identical Assets			Other			Unobservable
						(Level 1)			Observable			Inputs
									Inputs			(Level 3)
									(Level 2)
	December 31, 2013	(In thousands)
	PNM Pension Plan
	Participation in PNMR Master Trust	$	557,258			$	145,364		$	330,903		$	80,991
	TNMP Pension Plan
	Participation in PNMR Master Trust	$	66,285			$	18,657		$	32,620		$	15,008
	PNM OPEB Plan
	Cash and cash equivalents	$	1,152			$	1,152		$	—		$	—
	Equity securities:
	International funds	11,634				—			11,634			—
	Domestic value	6,388				6,388			—			—
	Domestic growth	24,135				7,094			17,041			—
	Other funds	14,028				—			14,028			—
	Fixed income securities:
	Mutual funds	16,796				16,796			—			—
		$	74,133			$	31,430		$	42,703		$	—
	TNMP OPEB Plan
	Cash and cash equivalents	$	302			$	302		$	—		$	—
	Equity securities:
	International funds	1,334				—			1,334			—
	Domestic value	381				381			—			—
	Domestic growth	4,171				1,848			2,323			—
	Other funds	1,844				—			1,844			—
	Fixed income securities:
	Mutual funds	1,702				1,702			—			—
		$	9,734			$	4,233		$	5,501		$	—
	The fair values of investments in the PNMR Master Trust are as follows:
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in			Significant			Significant
					Active Market for			Other			Unobservable
					Identical Assets			Observable			Inputs
					(Level 1)			Inputs			(Level 3)
								(Level 2)
December 31, 2014	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	15,645			$	15,645		$	—		$	—
Equity securities:
International	23,282				—			23,282			—
Domestic value	41,778				41,778			—			—
Domestic growth	28,370				28,370			—			—
Other funds	29,719				—			29,719			—
Fixed income securities:
Corporate	242,742				—			242,015			727
U.S. Government	106,634				52,537			54,097			—
Municipals	20,156				—			20,156			—
Other funds	74,136				161			73,975			—
Alternative investments:
Private equity funds	37,220				—			—			37,220
Hedge funds	23,876				—			—			23,876
Real estate funds	13,761				—			—			13,761
	$	657,319			$	138,491		$	443,244		$	75,584
December 31, 2013
PNMR Master Trust
Cash and cash equivalents	$	16,281			$	16,281		$	—		$	—
Equity securities:
International	24,471				24,471			—			—
Domestic value	41,451				41,451			—			—
Domestic growth	36,805				36,805			—			—
Other funds	22,522				—			22,522			—
Fixed income securities:
Corporate	202,897				363			202,358			176
U.S. Government	99,748				44,541			55,207			—
Municipals	17,259				—			17,259			—
Other funds	66,286				109			66,177			—
Alternative investments:
Private equity funds	39,122				—			—			39,122
Hedge funds	34,912				—			—			34,912
Real estate funds	21,789				—			—			21,789
	$	623,543			$	164,021		$	363,523		$	95,999
Schedule of Defined Benefit Plans Disclosures	A reconciliation of the changes in Level 3 fair value measurements is as follows:
		Year Ended December 31,
		2014				2013
	Level 3 Fair Value Assets and Liabilities	(In thousands)
	PNM Pension	Master				Master
		Trust				Trust
	Balance at beginning of period	$	80,991			$	79,017
	Actual return on assets sold during the period	10,376				3,303
	Actual return on assets still held at period end	(5,731		)		3,361
	Purchases	8,832				15,110
	Sales	(28,843		)		(19,800		)
	Balance at end of period	65,625				80,991
	TNMP Pension
	Balance at beginning of period	$	15,008			$	14,171
	Actual return on assets sold during the period	3,409				1,400
	Actual return on assets still held at period end	(1,883		)		1,425
	Purchases	2,902				6,408
	Sales	(9,477		)		(8,396		)
	Balance at end of period	9,959				15,008
	Total	$	75,584			$	95,999
	Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
	Level 3 Fair Value Assets and Liabilities
	PNMR Master Trust	Private				Hedge			Real			Fixed income - corporate			Total
		equity				funds			estate
		funds							funds
						(In thousands)
	Balance at December 31, 2012	$	38,212			$	31,277		$	23,699		$	—		$	93,188
	Actual return on assets sold during the period	4,677				135			(109		)	1			4,704
	Actual return on assets still held at period end	1,162				3,500			123			—			4,785
	Purchases	3,117				16,151			2,076			175			21,519
	Sales	(8,046		)		(16,151		)	(4,000		)	—			(28,197		)
	Balance at December 31, 2013	39,122				34,912			21,789			176			95,999
	Actual return on assets sold during the period	5,355				8,667			(236		)	—			13,786
	Actual return on assets still held at period end	(296		)		(7,536		)	237			(20		)	(7,615		)
	Purchases	3,656				5,500			1,971			608			11,735
	Sales	(10,617		)		(17,667		)	(10,000		)	(37		)	(38,321		)
	Balance at December 31, 2014	$	37,220			$	23,876		$	13,761		$	727		$	75,584

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entities [Abstract]
Noncontrolling Interest Summarized Financial Information	Summarized financial information for Valencia is as follows:
	Results of Operations
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Operating revenues	$	20,247		$	20,166		$	19,585
	Operating expenses	(6,120		)	(5,645		)	(5,535		)
	Earnings attributable to non-controlling interest	$	14,127		$	14,521		$	14,050
	Financial Position
		December 31,
		2014			2013
		(In thousands)
	Current assets	$	2,513		$	2,658
	Net property, plant and equipment	72,321			75,137
	Total assets	74,834			77,795
	Current liabilities	1,288			766
	Owners’ equity – non-controlling interest	$	73,546		$	77,029

Earnings_and_Dividends_Per_Sha1

Earnings and Dividends Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Information regarding the computation of earnings per share and dividends per share is as follows:
		Year Ended December 31,
		2014		2013		2012
		(In thousands, except per share amounts)
	Earnings Attributable to PNMR	$	116,254	$	100,507	$	105,547
	Average Number of Common Shares:
	Outstanding during year	79,654		79,654		79,654
	Vested awards of restricted stock	134		191		145
	Average Shares – Basic	79,788		79,845		79,799
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	491		586		618
	Average Shares – Diluted	80,279		80,431		80,417
	Net Earnings Per Share of Common Stock:
	Basic	$	1.46	$	1.26	$	1.32
	Diluted	$	1.45	$	1.25	$	1.31
	Dividends Declared per Common Share	$	0.755	$	0.68	0.58
	(1)	Excludes out-of-the-money options for 254,050 shares of common stock at December 31, 2014. See Note 13.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	PNMR’s income taxes consist of the following components:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current federal income tax	$	(2,015	)	$	—		$	(1,296	)
	Current state income tax	(728		)	(917		)	(37		)
	Deferred federal income tax	59,814			50,044			51,559
	Deferred state income tax	14,831			12,578			6,921
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Total income taxes	$	69,738		$	59,513		$	54,910
Schedule of Effective Income Tax Rate Reconciliation	PNMR’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Federal income tax at statutory rates	$	70,226		$	61,274		$	61,262
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Flow-through of depreciation items	1,344			1,132			1,284
	Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
	State income tax, net of federal benefit	5,723			3,818			4,646
	Impairment of state net operating loss carryforwards	3,129			—			—
	Impairment of state production tax credits, net of federal benefit	894			3,880			718
	Other	(4,469		)	(3,317		)	(5,845		)
	Total income taxes	$	69,738		$	59,513		$	54,910
	Effective tax rate	34.76		%	33.99		%	31.37		%
Schedule of Deferred Tax Assets and Liabilities	The components of PNMR’s net accumulated deferred income tax liability were:
		December 31,
		2014			2013
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	153,858		$	134,418
	Regulatory liabilities related to income taxes	78,858			83,838
	Federal tax credit carryforwards	54,748			40,708
	Other	68,566			75,832
	Total deferred tax assets	356,030			334,796
	Deferred tax liabilities:
	Depreciation and plant related	(914,926		)	(814,671		)
	Investment tax credit	(36,790		)	(25,855		)
	Regulatory assets related to income taxes	(67,910		)	(66,352		)
	CTC	(19,352		)	(22,262		)
	Pension	(66,498		)	(58,780		)
	Other	(115,282		)	(115,458		)
	Total deferred tax liabilities	(1,220,758		)	(1,103,378		)
	Net accumulated deferred income tax liabilities	(864,728		)	(768,582		)
	Current accumulated deferred income tax (asset) liability	(26,383		)	(58,681		)
	Non-current accumulated deferred income tax liability	$	(891,111	)	$	(827,263	)
Schedule of Deferred Income Tax Components	The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2014
		(In thousands)
	Net change in deferred income tax liability per above table	$	96,146
	Change in tax effects of income tax related regulatory assets and liabilities	(6,538		)
	Tax effect of mark-to-market adjustments	(1,612		)
	Tax effect of excess pension liability	3,993
	Adjustment for uncertain income tax positions	(4,858		)
	Reclassification of unrecognized tax benefits	(15,031		)
	Other	381
	Deferred income taxes	$	72,481
Summary of Income Tax Contingencies	A reconciliation of unrecognized tax benefits (expenses) is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Balance at December 31, 2011	$	19,580		$	10,752		$	7,701
	Additions based on tax positions related to 2012	2,046			1,152			—
	Reductions for tax positions of prior years	(2,428		)	(1,522		)	(905		)
	Settlement payments	—			—			—
	Balance at December 31, 2012	19,198			10,382			6,796
	Additions based on tax positions related to 2013	(54		)	(54		)	—
	Additions for tax positions of prior years	745			745			—
	Settlement payments	—			—			—
	Balance at December 31, 2013	19,889			11,073			6,796
	Additions based on tax positions related to 2014	623			623			—
	Additions (reductions) for tax positions of prior years	(5,481		)	532			(6,796		)
	Settlement payments	—			—			—
	Balance at December 31, 2014	$	15,031		$	12,228		$	—
Interest Income (Expense) Related to Income Taxes	Interest income (expense) related to income taxes is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	2014	$	146		$	148		$	(2	)
	2013	$	242		$	251		$	(2	)
	2012	$	243		$	244		$	(3	)
Accumulated Accrued Interest Receivable (Payable) Related to Income Taxes	Accumulated accrued interest receivable (payable) related to income taxes is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	December 31, 2014:
	Accumulated accrued interest receivable	$	3,569		$	3,569		$	—
	Accumulated accrued interest payable	$	(1,120	)	$	(24	)	$	(120	)
	December 31, 2013:
	Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
	Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	PNM’s income taxes consist of the following components:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current federal income tax	$	(2,175	)	$	(479	)	$	(12,951	)
	Current state income tax	(979		)	(760		)	(1,815		)
	Deferred federal income tax	45,890			42,806			56,194
	Deferred state income tax	12,061			9,429			11,522
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Total income taxes	$	52,633		$	48,804		$	50,713
Schedule of Effective Income Tax Rate Reconciliation	The differences are attributable to the following factors:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Federal income tax at statutory rates	$	53,930		$	53,018		$	54,710
	Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
	Flow-through of depreciation items	1,325			1,115			1,268
	Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
	State income tax, net of federal benefit	5,522			6,202			6,500
	Impairment of state net operating loss carryforwards	2,145			—			—
	Other	(3,180		)	(4,257		)	(4,610		)
	Total income taxes	$	52,633		$	48,804		$	50,713
	Effective tax rate	34.16		%	32.22		%	32.44		%
Schedule of Deferred Tax Assets and Liabilities	The components of PNM’s net accumulated deferred income tax liability were:
		December 31,
		2014			2013
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	108,505		$	99,247
	Regulatory liabilities related to income taxes	74,293			78,849
	Federal tax credit carryforwards	35,259			22,509
	Other	35,681			37,008
	Total deferred tax assets	253,738			237,613
	Deferred tax liabilities:
	Depreciation and plant related	(733,519		)	(661,239		)
	Investment tax credit	(36,790		)	(25,855		)
	Regulatory assets related to income taxes	(57,637		)	(55,844		)
	Pension	(58,474		)	(52,104		)
	Other	(70,714		)	(75,838		)
	Total deferred tax liabilities	(957,134		)	(870,880		)
	Net accumulated deferred income tax liabilities	(703,396		)	(633,267		)
	Current accumulated deferred income tax (asset) liability	(12,418		)	(43,827		)
	Non-current accumulated deferred income tax liability	$	(715,814	)	$	(677,094	)
Schedule of Deferred Income Tax Components	The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2014
		(In thousands)
	Net change in deferred income tax liability per above table	$	70,129
	Change in tax effects of income tax related regulatory assets and liabilities	(6,349		)
	Tax effect of mark-to-market adjustments	(1,470		)
	Tax effect of excess pension liability	3,993
	Adjustment for uncertain income tax positions	1,155
	Reclassification of unrecognized tax benefits	(12,228		)
	Other	557
	Deferred income taxes	$	55,787
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	TNMP’s income taxes consist of the following components:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Current federal income tax	$	35		$	(4,957	)	$	9,152
	Current state income tax	1,939			1,916			1,822
	Deferred federal income tax	20,577			20,688			4,406
	Deferred state income tax	(28		)	(26		)	(28		)
	Total income taxes	$	22,523		$	17,621		$	15,352
Schedule of Effective Income Tax Rate Reconciliation	The differences are attributable to the following factors:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Federal income tax at statutory rates	$	21,115		$	16,349		$	14,735
	State income tax, net of federal benefit	1,257			1,247			1,185
	Other	151			25			(568		)
	Total income taxes	$	22,523		$	17,621		$	15,352
	Effective tax rate	37.33		%	37.72		%	36.47		%
Schedule of Deferred Tax Assets and Liabilities	The components of TNMP’s net accumulated deferred income tax liability at December 31, were:
		December 31,
		2014			2013
		(In thousands)
	Deferred tax assets:
	Regulatory liabilities related to income taxes	$	4,565		$	4,988
	Other	13,429			23,479
	Total deferred tax assets	17,994			28,467
	Deferred tax liabilities:
	Depreciation and plant related	(174,510		)	(151,581		)
	CTC	(19,352		)	(22,262		)
	Regulatory assets related to income taxes	(10,197		)	(10,509		)
	Loss on reacquired debt	(12,846		)	(13,516		)
	Other	(12,636		)	(14,295		)
	Total deferred tax liabilities	(229,541		)	(212,163		)
	Net accumulated deferred income tax liabilities	(211,547		)	(183,696		)
	Current accumulated deferred income tax (asset)	(6,398		)	(6,501		)
	Non-current accumulated deferred income tax liability	$	(217,945	)	$	(190,197	)
Schedule of Deferred Income Tax Components	The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2014
		(In thousands)
	Net change in deferred income tax liability per above table	$	27,851
	Change in tax effects of income tax related regulatory assets and liabilities	(111		)
	Adjustment for uncertain tax positions	(6,796		)
	Other	(395		)
	Deferred income taxes	$	20,549

Pension_and_Other_Postretireme1

Pension and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Schedule of Defined Benefit Plans Disclosures	A reconciliation of the changes in Level 3 fair value measurements is as follows:
		Year Ended December 31,
		2014				2013
	Level 3 Fair Value Assets and Liabilities	(In thousands)
	PNM Pension	Master				Master
		Trust				Trust
	Balance at beginning of period	$	80,991			$	79,017
	Actual return on assets sold during the period	10,376				3,303
	Actual return on assets still held at period end	(5,731		)		3,361
	Purchases	8,832				15,110
	Sales	(28,843		)		(19,800		)
	Balance at end of period	65,625				80,991
	TNMP Pension
	Balance at beginning of period	$	15,008			$	14,171
	Actual return on assets sold during the period	3,409				1,400
	Actual return on assets still held at period end	(1,883		)		1,425
	Purchases	2,902				6,408
	Sales	(9,477		)		(8,396		)
	Balance at end of period	9,959				15,008
	Total	$	75,584			$	95,999
	Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
	Level 3 Fair Value Assets and Liabilities
	PNMR Master Trust	Private				Hedge				Real			Fixed income - corporate			Total
		equity				funds				estate
		funds								funds
						(In thousands)
	Balance at December 31, 2012	$	38,212			$	31,277			$	23,699		$	—		$	93,188
	Actual return on assets sold during the period	4,677				135				(109		)	1			4,704
	Actual return on assets still held at period end	1,162				3,500				123			—			4,785
	Purchases	3,117				16,151				2,076			175			21,519
	Sales	(8,046		)		(16,151		)		(4,000		)	—			(28,197		)
	Balance at December 31, 2013	39,122				34,912				21,789			176			95,999
	Actual return on assets sold during the period	5,355				8,667				(236		)	—			13,786
	Actual return on assets still held at period end	(296		)		(7,536		)		237			(20		)	(7,615		)
	Purchases	3,656				5,500				1,971			608			11,735
	Sales	(10,617		)		(17,667		)		(10,000		)	(37		)	(38,321		)
	Balance at December 31, 2014	$	37,220			$	23,876			$	13,761		$	727		$	75,584
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:
		PNM Plan
		1-Percentage-				1-Percentage-
		Point  Increase				Point  Decrease
		(In thousands)
	Effect on total of service and interest cost	$	350			$	(281	)
	Effect on APBO	$	5,305			$	(4,622	)
Schedule of Net Funded Status	For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended								Year Ended
		December 31,								December 31,
		2014				2013				2014			2013
		(In thousands)
	PBO at beginning of year	$	16,363			$	17,467			$	823		$	902
	Service cost	—				—				—			—
	Interest cost	822				720				39			36
	Actuarial (gain) loss	2,040				(330		)		110			(21		)
	Benefits paid	(1,495		)		(1,494		)		(94		)	(94		)
	PBO at end of year – funded status	17,730				16,363				878			823
	Less current liability	1,528				1,536				94			94
	Non-current liability	$	16,202			$	14,827			$	784		$	729
Schedule of Defined Contribution Plan Expenses	A summary of expenses for these other retirement plans is as follows:
		Year Ended December 31,
		2014				2013				2012
		(In thousands)
	PNMR
	401(k) plan	$	16,703			$	16,785			$	16,185
	Non-qualified plan	$	2,257			$	2,204			$	1,491
	PNM
	401(k) plan	$	12,745			$	12,952			$	12,427
	Non-qualified plan	$	1,722			$	1,691			$	1,143
	TNMP
	401(k) plan	$	3,958			$	3,953			$	3,739
	Non-qualified plan	$	535			$	513			$	327
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Defined Benefit Plans Disclosures	The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2014				2013				2014			2013
		(In thousands)
	PBO at beginning of year	$	599,537			$	675,549			$	66,159		$	76,640
	Service cost	—				—				—			—
	Interest cost	30,163				28,142				3,193			3,087
	Plan amendment	—				(6,346		)		—			—
	Actuarial (gain) loss	72,524				(56,533		)		8,466			(7,820		)
	Benefits paid	(44,667		)		(41,275		)		(5,513		)	(5,748		)
	PBO at end of year	657,557				599,537				72,305			66,159
	Fair value of plan assets at beginning of year	556,353				518,095				66,118			66,540
	Actual return on plan assets	76,223				19,533				8,572			4,326
	Employer contributions	—				60,000				—			1,000
	Benefits paid	(44,667		)		(41,275		)		(5,513		)	(5,748		)
	Fair value of plan assets at end of year	587,909				556,353				69,177			66,118
	Funded status – asset (liability) for pension benefits	$	(69,648	)		$	(43,184	)		$	(3,128	)	$	(41	)
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2014.
		PNM Plan								TNMP Plan
		December 31, 2014								December 31, 2014
		Prior service				Net actuarial				Net actuarial
		cost				(gain) loss				(gain) loss
		(In thousands)
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$	(2,665	)		$	139,256			$	—
	Experience loss (gain)	—				34,345				4,420
	Regulatory asset (liability) adjustment	—				(19,920		)		(4,420		)
	Amortization recognized in net periodic benefit cost (income)	405				(5,469		)		—
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,260	)		$	148,212			$	—
	Amortization expected to be recognized in 2015	$	(405	)		$	6,224			$	—
Schedule of Net Benefit Costs	The following table presents the components of net periodic benefit cost (income):
		Year Ended December 31,
		2014				2013				2012
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	30,163				28,142				32,232
	Expected return on plan assets	(38,044		)		(41,930		)		(41,301		)
	Amortization of net (gain) loss	13,020				14,840				10,516
	Amortization of prior service cost	(965		)		76				317
	Net periodic benefit cost	$	4,174			$	1,128			$	1,764
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	3,193				3,087				3,635
	Expected return on plan assets	(4,526		)		(4,849		)		(5,324		)
	Amortization of net (gain) loss	665				1,049				462
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost (income)	$	(668	)		$	(713	)		$	(1,227	)
Schedule of Assumptions Used	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.
		Year Ended December 31,
	PNM Plan	2014			2013			2012
	Discount rate for determining December 31 PBO	4.48	%		5.27	%		4.3	%
	Discount rate for determining net periodic benefit cost (income)	5.27	%		4.3	%		5.67	%
	Expected return on plan assets	7.2	%		7.65	%		8.25	%
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 PBO	4.39	%		5.06	%		4.19	%
	Discount rate for determining net periodic benefit cost (income)	5.06	%		4.19	%		5.69	%
	Expected return on plan assets	7.2	%		7.65	%		8.25	%
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments	The following pension benefit payments are expected to be paid:
		PNM				TNMP
		Plan				Plan
		(In thousands)
	2015	$	53,472			$	5,997
	2016	53,468				5,667
	2017	51,241				5,351
	2018	49,640				5,585
	2019	48,560				5,188
	2020 – 2024	213,759				23,600
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Defined Benefit Plans Disclosures	The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2014				2013				2014			2013
		(In thousands)
	APBO at beginning of year	$	92,165			$	99,613			$	12,266		$	13,678
	Service cost	181				260				237			299
	Interest cost	4,630				4,113				619			566
	Participant contributions	2,582				2,537				366			373
	Actuarial (gain) loss	4,455				(4,566		)		1,639			(1,080		)
	Benefits paid	(8,838		)		(9,792		)		(1,057		)	(1,570		)
	APBO at end of year	95,175				92,165				14,070			12,266
	Fair value of plan assets at beginning of year	73,565				64,464				9,601			8,643
	Actual return on plan assets	7,334				12,780				841			1,813
	Employer contributions	3,532				3,576				343			342
	Participant contributions	2,582				2,537				366			373
	Benefits paid	(8,838		)		(9,792		)		(1,057		)	(1,570		)
	Fair value of plan assets at end of year	78,175				73,565				10,094			9,601
	Funded status – asset (liability)	$	(17,000	)		$	(18,600	)		$	(3,976	)	$	(2,665	)
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	In the year ended December 31, 2014, actuarial losses of $2.8 million and $1.3 million were recorded in regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2014.
Schedule of Net Benefit Costs	The following table presents the components of net periodic benefit cost:
		Year Ended December 31,
		2014				2013				2012
		(In thousands)
	PNM Plan
	Service cost	$	181			$	260			$	217
	Interest cost	4,630				4,113				5,293
	Expected return on plan assets	(5,638		)		(5,043		)		(4,901		)
	Amortization of net (gain) loss	2,225				4,242				3,888
	Amortization of prior service credit	(1,343		)		(1,343		)		(1,343		)
	Net periodic benefit cost	$	55			$	2,229			$	3,154
	TNMP Plan
	Service cost	$	237			$	299			$	244
	Interest cost	619				566				624
	Expected return on plan assets	(534		)		(503		)		(516		)
	Amortization of net (gain) loss	(122		)		—				(209		)
	Amortization of prior service cost	32				57				57
	Net periodic benefit cost	$	232			$	419			$	200
Schedule of Assumptions Used	The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.
		Year Ended December 31,
	PNM Plan	2014			2013			2012
	Discount rate for determining December 31 APBO	4.45	%		5.21	%		4.26	%
	Discount rate for determining net periodic benefit cost	5.21	%		4.26	%		5.7	%
	Expected return on plan assets	8.5	%		8.5	%		8.5	%
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 APBO	4.45	%		5.21	%		4.26	%
	Discount rate for determining net periodic benefit cost	5.21	%		4.26	%		5.7	%
	Expected return on plan assets	6.5	%		6.5	%		6.5	%
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments	The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:
		PNM Plan				TNMP Plan
		(In thousands)
	2015	$	6,560			$	801
	2016	6,635				822
	2017	6,718				838
	2018	6,875				860
	2019	6,950				882
	2020 - 2024	34,585				4,717
Schedule of Health Care Cost Trend Rates	The following table shows the assumed health care cost trend rates for the PNM postretirement benefit plan:
		PNM Plan
		December 31,
		2014			2013
	Health care cost trend rate assumed for next year	7	%		7.5	%
	Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5	%		5	%
	Year that the rate reaches the ultimate trend rate	2023			2019
Executive Retirement Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2014.
		December 31, 2014
		PNM Plan				TNMP Plan
		(In thousands)
	Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	1,833			$	—
	Experience loss (gain)	2,040				(110		)
	Regulatory asset (liability) adjustment	(1,183		)		110
	Amortization recognized in net periodic benefit cost (income)	(88		)		—
	Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,602			$	—
	Amortization expected to be recognized in 2015	$	136			$	—
Schedule of Net Benefit Costs	The following table presents the components of net periodic benefit:
		Year Ended December 31,
		2014				2013				2012
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	822				720				876
	Amortization of net (gain) loss	210				232				83
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost	$	1,032			$	952			$	959
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	39				36				45
	Amortization of net (gain) loss	—				—				—
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost	$	39			$	36			$	45
Schedule of Assumptions Used	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.
		Year Ended December 31,
	PNM Plan	2014			2013			2012
	Discount rate for determining December 31 PBO	4.48	%		5.27	%		4.3	%
	Discount rate for determining net periodic benefit cost	5.27	%		4.3	%		5.67	%
	Long-term rate of return on plan assets	N/A			N/A			N/A
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 PBO	4.39	%		5.06	%		4.19	%
	Discount rate for determining net periodic benefit cost	5.06	%		4.19	%		5.69	%
	Long-term rate of return on plan assets	N/A			N/A			N/A
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments	The following executive retirement plan payments, which reflect expected future service, are expected:
		PNM				TNMP
		Plan				Plan
		(In thousands)
	2015	$	1,528			$	93
	2016	1,510				92
	2017	1,490				91
	2018	1,468				89
	2019	1,445				86
	2020 – 2024	6,722				384

StockBased_Compensation_Plans_

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	The following table provides additional information concerning stock options, and restricted stock activity including performance-based and market-based shares:
		Year Ended December 31,
	Restricted Stock	2014				2013				2012
	Weighted-average grant date fair value	$	21.27			$	20.03			$	16.75
	Total fair value of restricted shares that vested (in thousands)	$	4,933			$	4,395			$	5,099
	Stock Options
	Weighted-average grant date fair value of options granted	$	—			$	—			$	—
	Total fair value of options that vested (in thousands)	$	—			$	625			$	1,054
	Total intrinsic value of options exercised (in thousands)	$	2,473			$	2,721			$	6,356
	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
		Year Ended December 31,
	Restricted Shares and Performance-Based Shares	2014				2013				2012
	Expected quarterly dividends per share	$	0.185			$	0.165			$	0.145
	Risk-free interest rate	0.62		%		0.34		%		1.22		%
	Market-Based Shares
	Dividend yield	2.82		%		2.86		%		3.45		%
	Expected volatility	25.11		%		25.11		%		43.98		%
	Risk-free interest rate	0.64		%		0.36		%		1.04		%
	The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options:
		Restricted Stock						Stock Options
		Shares			Weighted-Average Grant Date Fair Value			Shares			Weighted
											Average
											Exercise
											Price
	Outstanding at December 31, 2013	315,305			$	17.87		1,343,666			$	20.63
	Granted	242,164			$	21.27		—			$	—
	Exercised	(295,423	)		$	16.7		(345,426	)		$	20.04
	Forfeited	(3,276	)		$	22.46		(17,151	)		$	26.43
	Expired	—			—			(60,584	)		$	27.98
	Outstanding at December 31, 2014	258,770			$	22.31		920,505			$	20.39

Construction_Program_and_Joint1

Construction Program and Jointly-Owned Electric Generating Plants Schedule of Jointly Owned Utility Plants (Tables)	12 Months Ended
	Dec. 31, 2014
Construction Program and Jointly-Owned Electric Generating Plants [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2014, PNM’s interests and investments in jointly-owned generating facilities are:
	Station (Fuel Type)	Plant in		Accumulated			Construction			Composite
		Service		Depreciation			Work in			Interest
							Progress
		(In thousands)
	SJGS (Coal)	$	1,009,378	$	(423,364	)	$	25,551		46.3	%
	PVNGS (Nuclear) (1)	$	533,702	$	(152,273	)	$	42,334		10.2	%
	Four Corners Units 4 and 5 (Coal)	$	162,111	$	(101,007	)	$	8,253		13	%
	Luna (Gas)	$	66,169	$	(20,297	)	$	(136	)	33.33	%
	(1)	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.
Summary of budgeted construction expenditures	An unaudited summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, and nuclear fuel, is as follows:
		2015		2016			2017			2018		2019		Total
							(In millions)
	PNM	$	423.9	$	402.3		$	334.8		$	180.6	$	260.3	$	1,601.90
	TNMP	121.3		92.8			93.3			105.9		105		518.3
	Corporate and Other	24		19.3			15.4			13.7		14.7		87.1
	Total PNMR	$	569.2	$	514.4		$	443.5		$	300.2	$	380	$	2,207.30

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	A reconciliation of the ARO liability is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Liability at December 31, 2011	$	79,233		$	78,425		$	699
	Liabilities incurred	—			—			—
	Liabilities settled	(25		)	—			(25		)
	Accretion expense	6,685			6,617			58
	Liability at December 31, 2012	85,893			85,042			732
	Liabilities incurred	—			—			—
	Liabilities settled	(79		)	(67		)	(12		)
	Accretion expense	7,245			7,174			62
	Revisions to estimated cash flows(1)	3,076			3,076			—
	Liability at December 31, 2013	96,135			95,225			782
	Liabilities incurred	—			—			—
	Liabilities settled	—			—			—
	Accretion expense	7,984			7,906			66
	Revisions to estimated cash flows	51			51			—
	Liability at December 31, 2014	$	104,170		$	103,182		$	848
	(1)	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2013, a new decommissioning study for PVNGS was implemented reflecting updated cash flow estimates, including the extended operating licenses. The new study resulted in an increase of $0.5 million to the ARO. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:
		Year Ended December 31,
		2014		2013		2012
				(In thousands)
	Services billings:
	PNMR to PNM	$	86,871	$	92,597	$	99,986
	PNMR to TNMP	28,349		28,937		29,110
	PNM to TNMP	524		562		595
	TNMP to PNMR	31		7		15
	Income tax sharing payments:
	PNMR to TNMP	—		—		1,951
	PNMR to PNM	—		77,433		63,114
	TNMP to PNMR	—		3,643		—
	Interest payments:
	PNM to PNMR	65		4		1
	TNMP to PNMR	309		481		137

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNMR
	Balance at December 31, 2011	$	15,634		$	(82,432	)	$	(58	)	$	(66,856	)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			182			(32,476		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	(65		)	12,865
	Other OCI changes (pre-tax)	38,548			(30,084		)	(428		)	8,036
	Income tax impact of other OCI changes	(15,262		)	11,910			153			(3,199		)
	Net change after income taxes	772			(15,388		)	(158		)	(14,774		)
	Balance at December 31, 2012	16,406			(97,820		)	(216		)	(81,630		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			207			(5,385		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	(73		)	2,137
	Other OCI changes (pre-tax)	27,419			17,136			(279		)	44,276
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	98			(17,538		)
	Net change after income taxes	9,342			14,195			(47		)	23,490
	Balance at December 31, 2013	25,748			(83,625		)	(263		)	(58,140		)
	Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			558			(8,152		)
	Income tax impact of amounts reclassified	5,461			(2,032		)	(195		)	3,234
	Other OCI changes (pre-tax)	17,473			(15,282		)	(153		)	2,038
	Income tax impact of other OCI changes	(6,812		)	6,024			53			(735		)
	Net change after income taxes	2,260			(6,138		)	263			(3,615		)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—		$	(61,755	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNM
	Balance at December 31, 2011	$	15,634		$	(82,432	)	$	—		$	(66,798	)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			—			(32,658		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	—			12,930
	Other OCI changes (pre-tax)	38,548			(30,084		)	—			8,464
	Income tax impact of other OCI changes	(15,262		)	11,910			—			(3,352		)
	Net change after income taxes	772			(15,388		)	—			(14,616		)
	Balance at December 31, 2012	16,406			(97,820		)	—			(81,414		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			—			(5,592		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	—			2,210
	Other OCI changes (pre-tax)	27,419			17,136			—			44,555
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	—			(17,636		)
	Net change after income taxes	9,342			14,195			—			23,537
	Balance at December 31, 2013	25,748			(83,625		)	—			(57,877		)
	Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			—			(8,710		)
	Income tax impact of amounts reclassified	5,461			(2,032		)	—			3,429
	Other OCI changes (pre-tax)	17,473			(15,282		)	—			2,191
	Income tax impact of other OCI changes	(6,812		)	6,024			—			(788		)
	Net change after income taxes	2,260			(6,138		)	—			(3,878		)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—		$	(61,755	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	TNMP
	Balance at December 31, 2011	$	—		$	—		$	(58	)	$	(58	)
	Amounts reclassified from AOCI (pre-tax)	—			—			182			182
	Income tax impact of amounts reclassified	—			—			(65		)	(65		)
	Other OCI changes (pre-tax)	—			—			(428		)	(428		)
	Income tax impact of other OCI changes	—			—			153			153
	Net change after income taxes	—			—			(158		)	(158		)
	Balance at December 31, 2012	—			—			(216		)	(216		)
Amounts reclassified from AOCI (pre-tax)	—			—			207			207
Income tax impact of amounts reclassified	—			—			(73		)	(73		)
Other OCI changes (pre-tax)	—			—			(279		)	(279		)
Income tax impact of other OCI changes	—			—			98			98
Net change after income taxes	—			—			(47		)	(47		)
Balance at December 31, 2013	—			—			(263		)	(263		)
Amounts reclassified from AOCI (pre-tax)	—			—			558			558
Income tax impact of amounts reclassified	—			—			(195		)	(195		)
Other OCI changes (pre-tax)	—			—			(153		)	(153		)
Income tax impact of other OCI changes	—			—			53			53
Net change after income taxes	—			—			263			263
Balance at December 31, 2014	$	—		$	—		$	—		$	—

Quarterly_Operating_Results_Un1

Quarterly Operating Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	Unaudited operating results by quarters for 2014 and 2013 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included.
		Quarter Ended
		March 31		June 30		September 30		December 31
		(In thousands, except per share amounts)
	PNMR
	2014
	Operating revenues	$	328,897	$	346,160	$	413,951	$	346,845
	Operating income	48,753		71,296		116,799		62,849
	Net earnings	16,131		33,181		59,486		22,111
	Net earnings attributable to PNMR	12,468		29,141		55,653		18,992
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.16		0.37		0.7		0.24
	Diluted	0.16		0.36		0.69		0.24
	2013
	Operating revenues	$	317,665	$	347,599	$	399,730	$	322,929
	Operating income	50,704		77,867		117,739		40,532
	Net earnings	13,962		31,383		58,814		11,397
	Net earnings attributable to PNMR	10,626		27,678		54,555		7,648
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.13		0.35		0.68		0.1
	Diluted	0.13		0.34		0.68		0.1
	PNM
	2014
	Operating revenues	$	262,736	$	275,704	$	334,993	$	274,481
	Operating income	31,304		49,806		90,615		40,988
	Net earnings	11,205		24,254		49,052		16,942
	Net earnings attributable to PNM	7,674		20,346		45,351		13,955
	2013
	Operating revenues	$	257,894	$	279,690	$	326,026	$	252,702
	Operating income	37,239		58,302		95,217		18,427
	Net earnings	14,773		29,697		51,950		6,256
	Net earnings attributable to PNM	11,569		26,124		47,823		2,639
	TNMP
	2014
	Operating revenues	$	66,161	$	70,456	$	78,958	$	72,364
	Operating income	17,262		21,265		25,873		21,188
	Net earnings	6,803		9,534		12,355		9,115
	2013
	Operating revenues	$	59,771	$	67,909	$	73,704	$	70,227
	Operating income	13,054		19,667		22,254		17,210
	Net earnings	3,726		8,339		10,106		6,919

Schedule_I_Condensed_Financial1

Schedule I - Condensed Financial Information of Parent Company (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Income Statement
		Year ended December 31,
		2014			2013			2012
		(In thousands)
	Operating Revenues	$	—		$	—		$	—
	Operating Expenses	650			941			3,287
	Operating income (loss)	(650		)	(941		)	(3,287		)
	Other Income and Deductions:
	Equity in earnings of subsidiaries	124,543			116,634			117,900
	Other income	622			769			670
	Other deductions	(13,650		)	(22,825		)	(20,904		)
	Net other income (deductions)	111,515			94,578			97,666
	Earnings Before Income Taxes	110,865			93,637			94,379
	Income Tax Expense (Benefit)	(5,389		)	(6,870		)	(11,168		)
	Net Earnings	$	116,254		$	100,507		$	105,547
Condensed Cash Flow Statement
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Cash Flows From Operating Activities:
	Net earnings	$	116,254		$	100,507		$	105,547
	Adjustments to reconcile net earnings to net cash flows from operating activities:
	Depreciation and amortization	680			4,192			5,000
	Deferred income tax expense	(69,442		)	(51,820		)	(46,632		)
	Equity in (earnings) of subsidiaries	(124,543		)	(116,634		)	(117,900		)
	Loss on reacquired debt	—			3,253			—
	Stock based compensation expense	5,931			5,320			3,585
	Changes in certain assets and liabilities:
	Other current assets	22,955			28,460			(43,638		)
	Other assets	51,644			46,558			34,096
	Accounts payable	(88		)	620			8
	Accrued interest and taxes	(7,683		)	(9,266		)	(28,855		)
	Other current liabilities	(1,668		)	(146		)	3,876
	Other liabilities	28,704			(27,756		)	(29,601		)
	Net cash flows from operating activities	22,744			(16,712		)	(114,514		)
	Cash Flows From Investing Activities:
	Utility plant additions	(474		)	(960		)	(7,524		)
	Investments in subsidiaries	—			(13,800		)	—
	Cash dividends from subsidiaries	46,599			158,772			61,406
	Net cash flows from investing activities	46,125			144,012			53,882
	Cash Flows From Financing Activities:
	Short-term borrowings (repayments), net	600			(37,600		)	120,900
	Repayment of long-term debt	—			(29,468		)	(2,387		)
	Proceeds from stock option exercise	6,999			4,618			11,684
	Purchases to satisfy awards of common stock	(17,319		)	(13,807		)	(25,168		)
	Dividends paid	(58,940		)	(50,980		)	(44,609		)
	Other, net	81			—			—
	Net cash flows from financing activities	(68,579		)	(127,237		)	60,420
	Change in Cash and Cash Equivalents	290			63			(212		)
	Cash and Cash Equivalents at Beginning of Period	92			29			241
	Cash and Cash Equivalents at End of Period	$	382		$	92		$	29
	Supplemental Cash Flow Disclosures:
	Interest paid	$	12,152		$	14,510		$	15,007
	Income taxes paid (refunded), net	$	(2,014	)	$	22,378		$	1,501
Condensed Balance Sheet
		December 31,
		2014			2013
		(In thousands)
	Assets
	Cash and cash equivalents	$	382		$	92
	Intercompany receivables	107,619			136,387
	Income taxes receivable	29			14,989
	Other, net	8,115			8,544
	Total current assets	116,145			160,012
	Property, plant and equipment, net of accumulated depreciation of $10,251 and $9,167	27,076			26,601
	Investment in subsidiaries	1,757,650			1,683,321
	Other long-term assets	70,939			53,892
	Total long-term assets	1,855,665			1,763,814
		$	1,971,810		$	1,923,826
	Liabilities and Stockholders’ Equity
	Short-term debt	$	100,600		$	100,000
	Short-term debt-affiliate	8,819			8,819
	Current maturities of long-term debt	118,766			—
	Accrued interest and taxes	2,816			2,797
	Other current liabilities	16,320			16,876
	Total current liabilities	247,321			128,492
	Long-term debt	—			118,766
	Other long-term liabilities	2,943			2,999
	Total liabilities	250,264			250,257
	Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,173,845			1,178,369
	Accumulated other comprehensive income (loss), net of tax	(61,755		)	(58,140		)
	Retained earnings	609,456			553,340
	Total common stockholders’ equity	1,721,546			1,673,569
		$	1,971,810		$	1,923,826
	See Notes 6, 7, 14, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

Summary_of_the_Business_and_Si3

Summary of the Business and Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 1986	Dec. 31, 2004	Dec. 31, 2003	Dec. 31, 1985
				Operating_Leases			Operating_Leases
Accounting Policies Disclosures [Line Items]
Debt, Weighted Average Interest Rate	6.60%	6.90%	6.60%
Interest costs incurred, capitalized	$1.60	$1.50	$1.20
Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Allowance for funds used during construction, capitalized interest	4.2	3.3	3.5
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	5.6	4.4	3.8
Interest costs incurred, capitalized	1.1	1.1	0.8
Impairment losses on securities held in the NDT	4.8	3.5	4.8
Texas-New Mexico Power Company [Member]
Accounting Policies Disclosures [Line Items]
Allowance for funds used during construction, capitalized interest	0.5	0.4	0.7
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	0	0	0.6
Interest costs incurred, capitalized	$0.10	$0	$0
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Number of operating leases (in ones)	8			11
EIP Transmission Line [Member] | Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Number of operating leases (in ones)							2
Ownership percentage acquired (as a percent)					40.00%	60.00%
10.3% Lessor Notes [Member] | Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Notes receivable, stated percentage rate (as a percent)	10.30%
10.15% Lessor Notes [Member] | Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Notes receivable, stated percentage rate (as a percent)	10.15%
10.25% EIP Lessor Note Maturing in 2012 [Member] | EIP Transmission Line [Member] | Public Service Company of New Mexico [Member]
Accounting Policies Disclosures [Line Items]
Notes receivable, stated percentage rate (as a percent)	10.25%

Summary_of_the_Business_and_Si4

Summary of the Business and Significant Accounting Policies (Inventories/Depreciation and Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Inventory [Line Items]
Inventory, Net	63,628	67,223
Coal [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	17,525	24,872
Materials and supplies [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	46,103	42,351
Public Service Company of New Mexico [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	60,859	64,520
Public Service Company of New Mexico [Member] | Coal [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	17,525	24,872
Public Service Company of New Mexico [Member] | Materials and supplies [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	43,334	39,648
Public Service Company of New Mexico [Member] | Electric plant [Member]
Public Utilities, Inventory [Line Items]
Depreciation average rates used (as a percent)	2.26%	2.27%	2.25%
Public Service Company of New Mexico [Member] | Common, intangible, and general plant [Member]
Public Utilities, Inventory [Line Items]
Depreciation average rates used (as a percent)	4.64%	4.87%	5.35%
Texas-New Mexico Power Company [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	2,769	2,703
Depreciation average rates used (as a percent)	3.59%	3.66%	3.56%
Texas-New Mexico Power Company [Member] | Coal [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	0	0
Texas-New Mexico Power Company [Member] | Materials and supplies [Member]
Public Utilities, Inventory [Line Items]
Inventory, Net	2,769	2,703

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	$346,845	$413,951	$346,160	$328,897	$322,929	$399,730	$347,599	$317,665	$1,435,853	$1,387,923	$1,342,403
Cost of energy									471,556	432,316	399,850
Margin									964,297	955,607	942,553
Other operating expenses									491,966	501,884	504,659
Depreciation and amortization									172,634	166,881	164,173
Operating income	62,849	116,799	71,296	48,753	40,532	117,739	77,867	50,704	299,697	286,842	273,721
Interest income									8,483	10,043	13,072
Gain on sale of First Choice									0	0	1,012
Other income (deductions)									12,094	-368	8,075
Interest charges									-119,627	-121,448	-120,845
Earnings before Income Taxes									200,647	175,069	175,035
Income Taxes									69,738	59,513	54,910
Net Earnings	22,111	59,486	33,181	16,131	11,397	58,814	31,383	13,962	130,909	115,556	120,125
Valencia non-controlling interest									-14,127	-14,521	-14,050
Preferred Stock Dividend Requirements of Subsidiary									-528	-528	-528
Segment earnings (loss) attributable to PNMR									116,254	100,507	105,547
Gross property additions									460,658	348,039	308,909
Total Assets	5,829,325				5,500,210				5,829,325	5,500,210	5,372,583
Goodwill	278,297				278,297				278,297	278,297	278,297
PNM [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues									1,147,914	1,116,312	1,092,264
Cost of energy									403,626	374,710	353,649
Margin									744,288	741,602	738,615
Other operating expenses									422,051	428,591	435,442
Depreciation and amortization									109,524	103,826	97,291
Operating income									212,713	209,185	205,882
Interest income									8,557	10,182	13,243
Gain on sale of First Choice											0
Other income (deductions)									12,258	11,288	13,290
Interest charges									-79,442	-79,175	-76,101
Earnings before Income Taxes									154,086	151,480	156,314
Income Taxes									52,633	48,804	50,713
Net Earnings									101,453	102,676	105,601
Valencia non-controlling interest									-14,127	-14,521	-14,050
Preferred Stock Dividend Requirements of Subsidiary									-528	-528	-528
Segment earnings (loss) attributable to PNMR									86,798	87,627	91,023
Gross property additions									316,800	239,906	196,800
Total Assets	4,473,652				4,227,616				4,473,652	4,227,616	4,163,907
Goodwill	51,632				51,632				51,632	51,632	51,632
TNMP [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues									287,939	271,611	250,140
Cost of energy									67,930	57,606	46,201
Margin									220,009	214,005	203,939
Other operating expenses									84,365	91,601	87,079
Depreciation and amortization									50,056	50,219	49,340
Operating income									85,588	72,185	67,520
Interest income									0	0	1
Gain on sale of First Choice											0
Other income (deductions)									2,138	1,919	2,739
Interest charges									-27,396	-27,393	-28,161
Earnings before Income Taxes									60,330	46,711	42,099
Income Taxes									22,523	17,621	15,352
Net Earnings									37,807	29,090	26,747
Valencia non-controlling interest									0	0	0
Preferred Stock Dividend Requirements of Subsidiary									0	0	0
Segment earnings (loss) attributable to PNMR									37,807	29,090	26,747
Gross property additions									127,191	89,117	92,973
Total Assets	1,240,241				1,162,431				1,240,241	1,162,431	1,086,229
Goodwill	226,665				226,665				226,665	226,665	226,665
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues									0	0	-1
Cost of energy									0	0	0
Margin									0	0	-1
Other operating expenses									-14,450	-18,308	-17,862
Depreciation and amortization									13,054	12,836	17,542
Operating income									1,396	5,472	319
Interest income									-74	-139	-172
Gain on sale of First Choice											1,012
Other income (deductions)									-2,302	-13,575	-7,954
Interest charges									-12,789	-14,880	-16,583
Earnings before Income Taxes									-13,769	-23,122	-23,378
Income Taxes									-5,418	-6,912	-11,155
Net Earnings									-8,351	-16,210	-12,223
Valencia non-controlling interest									0	0	0
Preferred Stock Dividend Requirements of Subsidiary									0	0	0
Segment earnings (loss) attributable to PNMR									-8,351	-16,210	-12,223
Gross property additions									16,667	19,016	19,136
Total Assets	115,432				110,163				115,432	110,163	122,447
Goodwill	$0				$0				$0	$0	$0

Segment_Information_Narrative_

Segment Information (Narrative and Major Customers) (Details) (Electric operating revenues [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
First Choice [Member]
Concentration Risk [Line Items]
Operating revenues from continuing operations (as a percent)	15.00%	17.00%
Unaffiliated Customer of Texas-New Mexico Power Company One [Member]
Concentration Risk [Line Items]
Operating revenues from continuing operations (as a percent)	15.00%	16.00%	17.00%
Unaffiliated Customer of Texas-New Mexico Power Company Two [Member]
Concentration Risk [Line Items]
Operating revenues from continuing operations (as a percent)	11.00%	10.00%	10.00%
PNMR and PNM [Member] | Maximum [Member]
Concentration Risk [Line Items]
Number of Customers that make up 10 percent of total revenue	0
Operating revenues from continuing operations (as a percent)	10.00%
Texas-New Mexico Power Company [Member] | Maximum [Member]
Concentration Risk [Line Items]
Number of Customers that make up 10 percent of total revenue	2

Sale_of_First_Choice_Details

Sale of First Choice (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of First Choice	$0	$0	$1,012
Other Income [Member] | First Choice [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of First Choice			$1,000

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Regulatory Assets
Regulatory Assets, Current	$47,855	$24,416
Regulatory Assets, Noncurrent	491,007	523,955
Regulatory Liabilities
Regulatory Liability, Current	-1,703	-1,081
Regulatory liabilities, Noncurrent	-466,143	-460,649
Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Current	43,980	19,394
Regulatory Assets, Noncurrent	357,045	384,217
Regulatory Assets	401,025	403,611
Regulatory Liabilities
Regulatory Liability, Current	-1,703	-1,081
Regulatory liabilities, Noncurrent	-425,481	-414,611
Regulatory Liabilities	-427,184	-415,692
Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Current	3,875	5,022
Regulatory Assets, Noncurrent	133,962	139,738
Regulatory Assets	137,837	144,760
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-40,662	-46,038
Removal Costs [Member] | Public Service Company of New Mexico [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-277,148	-266,075
Removal Costs [Member] | Texas-New Mexico Power Company [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-29,391	-30,863
Deferred Income Tax Charge [Member] | Public Service Company of New Mexico [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-75,941	-80,495
Deferred Income Tax Charge [Member] | Texas-New Mexico Power Company [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-3,923	-4,563
Asset Retirement Obligation Costs [Member] | Public Service Company of New Mexico [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-35,834	-37,567
Renewable Energy Program [Member] | Public Service Company of New Mexico [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-24,854	-26,011
Other Regulatory Assets (Liabilities) [Member] | Public Service Company of New Mexico [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-11,704	-4,463
Other Regulatory Assets (Liabilities) [Member] | Texas-New Mexico Power Company [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-2,121	-3,361
Advanced Metering Infrastructure Costs [Member] | Texas-New Mexico Power Company [Member]
Regulatory Liabilities
Regulatory liabilities, Noncurrent	-5,227	-7,251
Regulatory Assets, Transmission Cost Recovery [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Current	2,482	4,250
Other Regulatory Assets (Liabilities) [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	5,929	9,345
Other Regulatory Assets (Liabilities) [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Current	1,393	772
Regulatory Assets, Noncurrent	1,155	1,627
Stranded costs [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	55,292	63,606
Environmental Restoration Costs [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	34,224	40,144
Deferred Income Tax Charge [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	63,645	61,850
Deferred Income Tax Charge [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	10,556	10,868
Loss on reacquired debt [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	25,439	27,490
Loss on reacquired debt [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	36,703	38,616
Pension and Other Postretirement Plans Costs [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	222,545	206,691
Pension and Other Postretirement Plans Costs [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	23,803	19,938
Fuel and purchased power adjustment clause [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	0	25,386
Renewable Energy Program [Member] | Public Service Company of New Mexico [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	5,263	13,311
Advanced Metering Infrastructure Costs [Member] | Texas-New Mexico Power Company [Member]
Regulatory Assets
Regulatory Assets, Noncurrent	$6,453	$5,083

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Preferred stock, cumulative shares authorized (in shares)	10,000,000
Texas-New Mexico Power Company [Member]
Class of Stock [Line Items]
Equity contribution from parent		$13,800,000
Amount available for dividend distribution without prior approval from regulators or financial counterparties	203,000,000
Preferred stock, cumulative shares authorized (in shares)	1,000,000
Public Service Company of New Mexico [Member]
Class of Stock [Line Items]
Amount available for dividend distribution without prior approval from regulators or financial counterparties	223,000,000
Preferred stock, dividend rate (as a percent)	4.58%
Preferred stock, redemption percent (as a percent)	102.00%
Preferred Stock, Shares Outstanding	115,293	115,293
Preferred stock, cumulative shares authorized (in shares)	10,000,000	10,000,000
PNMR and TNMP [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding	0
Affiliated Entity [Member] | Texas-New Mexico Power Company [Member]
Class of Stock [Line Items]
Cash dividends paid to parent company by consolidated subsidiaries	16,300,000	3,700,000	26,000,000
Affiliated Entity [Member] | Public Service Company of New Mexico [Member]
Class of Stock [Line Items]
Cash dividends paid to parent company by consolidated subsidiaries	$30,300,000	$155,000,000	$34,400,000
Line of Credit [Member] | Texas-New Mexico Power Company [Member]
Class of Stock [Line Items]
Ratio of debt to capital, maximum (as a percent)	65.00%

Financing_Details

Financing (Details) (USD $)

12 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Apr. 03, 2013

Sep. 30, 2011

Dec. 27, 2012

Apr. 22, 2013

Mar. 05, 2014

Dec. 22, 2014

Mar. 06, 2013

Dec. 14, 2012

Sep. 30, 2012

Dec. 09, 2013

Feb. 20, 2015

Debt Instrument [Line Items]

Repayments of Unsecured Debt

$26,900,000

Loss on reacquired debt

0

3,253,000

0

Short-term debt

105,600,000

149,200,000

Proceeds from Short-term Debt

100,000,000

Long-term Debt

1,975,090,000

1,745,420,000

Unsecured Debt [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

9.25%

Public Service Company of New Mexico [Member]

Debt Instrument [Line Items]

Long-term Debt

1,490,657,000

1,290,618,000

Short-term debt - affiliate

0

32,500,000

Public Service Company of New Mexico [Member] | Unsecured Debt [Member]

Debt Instrument [Line Items]

Debt Instrument, Shelf Registration Statement for Unsecured Debt

500,000,000

Public Service Company of New Mexico [Member] | PNM 2014 Term Loan Agreement [Member]

Debt Instrument [Line Items]

Long-term Debt

175,000,000

Debt Instrument, Interest Rate, Effective Percentage

1.11%

Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member]

Debt Instrument [Line Items]

Long-term Debt

125,000,000

Debt Instrument, Interest Rate, Effective Percentage

0.75%

Proceeds from (Repayments of) Debt

100,000,000

Debt Instrument, Unused Borrowing Capacity, Amount

25,000,000

Texas-New Mexico Power Company [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

1,000

Long-term Debt

365,667,000

336,036,000

Debt Instrument, Cash Offered for Debt Exchanged

140

Repayments of Debt

30,000,000

Short-term debt - affiliate

22,700,000

29,400,000

Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Cash Paid for Debt Exchanged

13,000,000

Texas-New Mexico Power Company [Member] | 2011 Term Loan Agreement [Member]

Debt Instrument [Line Items]

Proceeds from Bank Debt

50,000,000

Repayments of Debt

50,000,000

Senior unsecured notes, 9.25% due 2015 [Member] | Senior unsecured notes, 9.25% due 2015 [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

23,800,000

PNMR Term Loan Agreement [Member]

Debt Instrument [Line Items]

Short-term debt

100,000,000

100,000,000

PNMR Term Loan Agreement [Member] | Notes Payable to Banks [Member]

Debt Instrument [Line Items]

Short-term debt

100,000,000

Proceeds from Short-term Debt

100,000,000

Repayments of Lines of Credit

100,000,000

2.54% Maturing of September First, 2042 with a Mandatory Tender on June First, 2017 [Member] | Public Service Company of New Mexico [Member] | Pollution Control Revenue Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

20,000,000

Debt Instrument, Interest Rate, Stated Percentage

2.54%

5.15% Percent Maturing in 2037 [Member] | Public Service Company of New Mexico [Member] | Pollution Control Revenue Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.15%

Debt Instrument, Refunded Amount Redeemed at Par and Retired

20,000,000

PNM Term Loan Agreement [Member] | Notes Payable to Banks [Member]

Debt Instrument [Line Items]

Short-term debt

75,000,000

Repayments of Lines of Credit

75,000,000

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

265,500,000

Debt Instrument, Interest Rate, Stated Percentage

9.50%

9.50%

9.50%

9.50%

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

93,200,000

Debt Instrument, Interest Rate, Stated Percentage

6.95%

6.95%

6.95%

6.95%

Debt Instrument, Unamortized Premium

23,200,000

First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member] | Texas-New Mexico Power Company [Member] | Pollution Control Revenue Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

80,000,000

Debt Instrument, Interest Rate, Stated Percentage

4.03%

First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

4.03%

Borrowings from PNMR [Member] | Public Service Company of New Mexico [Member]

Debt Instrument [Line Items]

Short-term debt - affiliate

0

Borrowings from PNMR [Member] | Texas-New Mexico Power Company [Member]

Debt Instrument [Line Items]

Short-term debt - affiliate

17,300,000

Subsequent Event [Member] | Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member]

Debt Instrument [Line Items]

Debt Instrument, Unused Borrowing Capacity, Amount

25,000,000

Maximum [Member]

Debt Instrument [Line Items]

Short-term debt - affiliate

100,000,000

Fair Value, Inputs, Level 2 [Member] | Cash Flow Hedging [Member] | Texas-New Mexico Power Company [Member] | 2011 Term Loan Agreement [Member]

Debt Instrument [Line Items]

Interest Rate Derivative Liabilities, at Fair Value

$200,000

Financing_Shortterm_Debt_Detai

Financing Short-term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 20, 2015	Apr. 30, 2009
Short-term Debt [Line Items]
Line of Credit Facility, Extension Option, Years	1 year
Debt, Weighted Average Interest Rate	6.60%	6.90%	6.60%
Short-term debt	$105,600,000	$149,200,000
Letters of Credit Outstanding, Amount	7,700,000
Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	3,200,000
Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member]
Short-term Debt [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	25,000,000
Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Letters of Credit Outstanding, Amount	100,000
New Mexico Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50,000,000
PNMR Term Loan Agreement [Member]
Short-term Debt [Line Items]
Debt, Weighted Average Interest Rate	1.02%
Short-term debt	100,000,000	100,000,000
Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				291,500,000
Invested Cash and Cash Equivalents				1,900,000
Subsequent Event [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				386,800,000
Invested Cash and Cash Equivalents				42,500,000
Subsequent Event [Member] | Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member]
Short-term Debt [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount				25,000,000
Subsequent Event [Member] | Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				54,900,000
Invested Cash and Cash Equivalents				0
Available Borrowing Capacity [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				768,200,000
PNMR Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300,000,000
Debt, Weighted Average Interest Rate	1.67%
Short-term debt	600,000	0
PNM Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400,000,000
Short-term debt	0	49,200,000
TNMP Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Debt, Weighted Average Interest Rate	1.17%
TNMP Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	75,000,000
Short-term debt	5,000,000	0
TNMP Revolving Credit Facility [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member] | Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Securities Received as Collateral					75,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Ratio of debt to capital, maximum (as a percent)	65.00%
New Mexico Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Short-term debt	0	0
New Mexico Revolving Credit Facility [Member] | Subsequent Event [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity				$35,000,000

Financing_Schedule_of_Longterm

Financing Schedule of Long-term Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Apr. 03, 2013	Mar. 06, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Long-term Debt	$1,975,090	$1,745,420
Less current maturities	333,066	75,000
Long-term Debt, Excluding Current Maturities	1,642,024	1,670,420
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.25%
Unsecured Debt [Member] | Senior unsecured notes, 9.25% due 2015 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	118,766	118,766
Public Service Company of New Mexico [Member]
Debt Instrument [Line Items]
Long-term Debt	1,490,657	1,290,618
Less current maturities	214,300	75,000
Long-term Debt, Excluding Current Maturities	1,276,357	1,215,618
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 4.875% due 2033 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	146,000	146,000
Debt Instrument, Interest Rate, Stated Percentage	4.88%	4.88%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 6.25% due 2038 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	36,000	36,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%	6.25%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 4.75% due 2040, mandatory tender at June 1, 2017 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	37,000	37,000
Debt Instrument, Interest Rate, Stated Percentage	4.75%	4.75%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 5.20% due 2040, mandatory tender at June 1, 2020 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	40,045	40,045
Debt Instrument, Interest Rate, Stated Percentage	5.20%	5.20%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 5.90% due 2040 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	255,000	255,000
Debt Instrument, Interest Rate, Stated Percentage	5.90%	5.90%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 6.25% due 2040 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	11,500	11,500
Debt Instrument, Interest Rate, Stated Percentage	6.25%	6.25%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 2.54% due 2042, mandatory tender at June 1, 2017 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	20,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 4.00% due 2043, mandatory tender at June 1, 2015 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	39,300	39,300
Debt Instrument, Interest Rate, Stated Percentage	4.00%	4.00%
Public Service Company of New Mexico [Member] | Senior Unsecured Notes, Pollution Control Revenue Bonds [Member] | 5.20% due 2043, mandatory tender at June 1, 2020 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	21,000	21,000
Debt Instrument, Interest Rate, Stated Percentage	5.20%	5.20%
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | 7.95% due 2018 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	350,000	350,000
Debt Instrument, Interest Rate, Stated Percentage	7.95%	7.95%
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | 7.50% due 2018 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	100,025	100,025
Debt Instrument, Interest Rate, Stated Percentage	7.50%	7.50%
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | 5.35% due 2021 [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	160,000	160,000
Debt Instrument, Interest Rate, Stated Percentage	5.35%	5.35%
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | PNM 2014 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt	0	75,000
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | PNM Term Loan Agreement due 2015 [Member]
Debt Instrument [Line Items]
Long-term Debt	175,000	0
Public Service Company of New Mexico [Member] | Unsecured Debt [Member] | PNM Multi-Draw Term Loan Agreement due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt	100,000	0
Public Service Company of New Mexico [Member] | Other [Member]
Debt Instrument [Line Items]
Unamortized premiums (discounts)	-213	-252
Texas-New Mexico Power Company [Member]
Debt Instrument [Line Items]
Long-term Debt	365,667	336,036
Less current maturities	0	0
Long-term Debt, Excluding Current Maturities	365,667	336,036
Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member] | 2011 Term Loan Agreement, due 2014 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	50,000
Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	172,302	172,302
Debt Instrument, Interest Rate, Stated Percentage	9.50%	9.50%	9.50%	9.50%
Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	93,198	93,198
Debt Instrument, Interest Rate, Stated Percentage	6.95%	6.95%	6.95%	6.95%
Texas-New Mexico Power Company [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member]
Debt Instrument [Line Items]
Unsecured Long-term Debt, Noncurrent	80,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.03%
Texas-New Mexico Power Company [Member] | Other [Member]
Debt Instrument [Line Items]
Unamortized premiums (discounts)	-20,167	-20,536
PNMR [Member]
Debt Instrument [Line Items]
Less current maturities	118,766	0
Long-term Debt, Excluding Current Maturities	$0	$118,766
PNMR [Member] | Unsecured Debt [Member] | Senior unsecured notes, 9.25% due 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.25%	9.25%

Financing_Schedule_of_Longterm1

Financing Schedule of Long-term Debt Maturities (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Long-term Debt, by Maturity [Abstract]
2015	$333,066
2016	100,000
2017	57,000
2018	450,025
2019	172,302
Thereafter	842,743
Total	1,955,136
PNMR [Member]
Long-term Debt, by Maturity [Abstract]
2015	118,766
2016	0
2017	0
2018	0
2019	0
Thereafter	0
Total	118,766
Public Service Company of New Mexico [Member]
Long-term Debt, by Maturity [Abstract]
2015	214,300
2016	100,000
2017	57,000
2018	450,025
2019	0
Thereafter	669,545
Total	1,490,870
Texas-New Mexico Power Company [Member]
Long-term Debt, by Maturity [Abstract]
2015	0
2016	0
2017	0
2018	0
2019	172,302
Thereafter	173,198
Total	$345,500

Lease_Commitments_Narratives_D

Lease Commitments Narratives (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	1-May-14	Jan. 15, 2015	Jan. 15, 2016
				MW		MW
Lease commitments
Operating Lease, Extended Term	2 years
Operating Leases, Renewal Options After Original Lease Term	6 years
Administrative and General Expense [Member]
Lease commitments
Abandonment expense		($7,400,000)
Corporate Headquarters [Member]
Lease commitments
Operating Leases, Rent Expense, Net	1,900,000
Public Service Company of New Mexico [Member]
Lease commitments
Operating Leases, Renewal Options After Original Lease Term	2 years
Public Utilities, Option to Purchase Leased Capacity At Fair Value	7,700,000
Operating Leases, Rent Expense, Net	76,745,000	78,483,000	78,306,000
Public Service Company of New Mexico [Member] | Navajo Nation [Member]
Lease commitments
Operating Leases, Number of leases set to expire	0
Operating Leases, Period to expiration of the lease	5 years
Annual lease payments	6,000,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Lease commitments
Rental Payments, Fixed renewal option period during original terms of leases	50.00%
Operating Lease, Extended Term, Notice Period to Retain Leased Assets	3 years
Operating Lease, Extended Term, Notice Period to Purchase or Renewal Options	2 years
Lease Covenant, Restriction on Conveying, Transferring, Leasing, & Dividends	5.00%
Loss Contingency, Range of Possible Loss, Portion Not Accrued	122,200,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 1 Leases [Member]
Lease commitments
Annual lease payments	33,000,000
Annual Lease Payments During Renewal Period	16,500,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Lease commitments
Annual lease payments	23,700,000
Annual Lease Payments During Renewal Period	1,600,000
Leased Capacity to be Purchased				32.76
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Lease commitments
Purchase Price of Leased Asset to be paid January 15, 2016				85,200,000
Early Purchase Price of Leased Asset effective June 1, 2014				79,900,000
Early Purchase Price of Leased Asset currently in effect	81,800,000
Public Service Company of New Mexico [Member] | Administrative and General Expense [Member]
Lease commitments
Abandonment expense		-6,200,000
Public Service Company of New Mexico [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Lease commitments
Public Utilities, Lease ownership percentage in EIP	60.00%
Operating Lease, Notice Period to Purchase Leased Assets	24 months
Public Service Company of New Mexico [Member] | Maximum [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Lease commitments
Additional consideration for early purchase of leased asset effective June 1, 2014				5,800,000
Additional consideration for early purchase of leased asset currently effective	4,500,000
Public Service Company of New Mexico [Member] | Minimum [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Lease commitments
Additional consideration for early purchase of leased asset effective June 1, 2014				1,200,000
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | Palo Verde Nuclear Generating Station [Member]
Lease commitments
Loss Contingency, Range of Possible Loss, Portion Not Accrued					217,300,000
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Lease commitments
Estimated Purchase Price of Leased Asset						78,100,000
Leased Capacity to be Purchased						31.25
Tortoise Capital Resources Corporation [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Lease commitments
Public Utilities, Lease ownership percentage in EIP	40.00%
Texas-New Mexico Power Company [Member]
Lease commitments
Operating Leases, Rent Expense, Net	3,932,000	2,871,000	2,663,000
Texas-New Mexico Power Company [Member] | Administrative and General Expense [Member]
Lease commitments
Abandonment expense		($1,200,000)

Lease_Commitments_Schedule_of_

Lease Commitments Schedule of Rent Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
PNMR [Member]
Operating lease expense [Line Items]
Operating Leases, Rent Expense, Net	$82,756	$82,882	$84,794
Public Service Company of New Mexico [Member]
Operating lease expense [Line Items]
Operating Leases, Rent Expense, Net	76,745	78,306	78,483
Texas-New Mexico Power Company [Member]
Operating lease expense [Line Items]
Operating Leases, Rent Expense, Net	$3,932	$2,663	$2,871

Lease_Commitments_Schedule_of_1

Lease Commitments Schedule of Future Minimum Rental Payments for Operating Leases (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
PNMR [Member]
Lease commitments
2015	$36,350
2016	28,892
2017	25,185
2018	25,194
2019	25,203
Later years	134,068
Total minimum lease payments	274,892
Public Service Company of New Mexico [Member]
Lease commitments
2015	33,144
2016	27,986
2017	24,907
2018	24,907
2019	24,907
Later years	133,842
Total minimum lease payments	269,693
Texas-New Mexico Power Company [Member]
Lease commitments
2015	1,186
2016	636
2017	0
2018	0
2019	0
Later years	0
Total minimum lease payments	1,822
Palo Verde Nuclear Generating Station, Unit 2 Leases [Member] | Public Service Company of New Mexico [Member]
Lease commitments
2015	24,000
2016	$9,000

Fair_Value_of_Derivative_and_O2

Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	$11,232,000	$4,064,000
Commodity derivative instruments, Deferred charges	0	3,002,000
Commodity derivative instruments, Current liabilities	-1,209,000	-2,699,000
Commodity derivative instruments, Long-term liabilities	-477,000	-1,094,000
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Derivative, Collateral, Right to Reclaim Cash	0
Margin Deposit Assets	3,800,000	2,800,000
Derivative, Collateral, Obligation to Return Cash	200,000	200,000
PNMR and PNM [Member] | Economic hedges [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	11,232,000	4,064,000
Commodity derivative instruments, Deferred charges	0	3,002,000
Commodity derivative instruments, Assets	11,232,000	7,066,000
Commodity derivative instruments, Current liabilities	-1,209,000	-2,699,000
Commodity derivative instruments, Long-term liabilities	-477,000	-1,094,000
Commodity derivative instruments, Liabilities	-1,686,000	-3,793,000
Commodity derivative instruments, Net	9,546,000	3,273,000
PNMR and PNM [Member] | Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Palo Verde Nuclear Generating Station [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	3,000,000	3,000,000
Commodity derivative instruments, Deferred charges		3,000,000
Public Service Company of New Mexico [Member] | Economic hedges [Member] | Commodity Contract [Member] | Fuel and purchased power adjustment clause [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	0	400,000
Commodity derivative instruments, Current liabilities		($100,000)

Fair_Value_of_Derivative_and_O3

Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (Commodity Contract [Member], Economic hedges [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$5,084	$2,836	$5,708
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	4,491	1,727	6,168
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$593	$1,109	($460)

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 $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]
Contractual Liability	$1,686	$2,398
Existing Cash Collateral	0	0
Net Exposure	$167	$2,152
Long [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivative [Line Items]
Volume positions (MMBTU/ MWh)	650,000,000	905,000,000
Short [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivative [Line Items]
Volume positions (MMBTU/ MWh)	1,919,000,000	3,343,783,000

Fair_Value_of_Derivative_and_O5

Fair Value of Derivative and Other Financial Instruments, Sale of Power (Details) (Palo Verde Nuclear Generating Station Unit 3 [Member], PNMR and PNM [Member])	Dec. 31, 2014
	MW
Sale of Power [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation	134
Percentage of Electric Power Plant Output Sold for 2014 and 2015	100.00%
Commodity Contract [Member]
Sale of Power [Line Items]
Derivative, Average Forward Price	37

Fair_Value_of_Derivative_and_O6

Fair Value of Derivative and Other Financial Instruments, Available for Sale Securities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Realized impairment (loss) gain	$700,000	($600,000)	($5,200,000)
PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	250,145,000	226,855,000
Available-for-sale securities, Unrealized gains	46,348,000	42,602,000
Proceeds from sales	117,989,000	271,140,000	167,330,000
Gross realized gains	15,162,000	14,308,000	15,907,000
Gross realized (losses)	-3,964,000	-4,298,000	-8,170,000
Other than Temporary Impairment Losses, Investments, Portion in Other Comprehensive Loss, before Tax, Portion Attributable to Parent	0
Cash and equivalents [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	8,276,000	3,356,000
Available-for-sale securities, Unrealized gains	0	0
Domestic value [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	45,340,000	39,460,000
Available-for-sale securities, Unrealized gains	17,418,000	14,523,000
Domestic growth [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	74,053,000	76,292,000
Available-for-sale securities, Unrealized gains	21,354,000	25,656,000
International and other [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	16,599,000	16,633,000
Available-for-sale securities, Unrealized gains	156,000	1,040,000
U.S. Government [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	22,563,000	21,941,000
Available-for-sale securities, Unrealized gains	903,000	158,000
Municipals [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	68,973,000	58,568,000
Available-for-sale securities, Unrealized gains	5,851,000	1,018,000
Corporate and other [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	14,341,000	10,605,000
Available-for-sale securities, Unrealized gains	666,000	207,000
Measured on a recurring basis [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	250,145,000	226,855,000
Measured on a recurring basis [Member] | Nuclear Decommissioning Trust [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	244,600,000	222,500,000
Measured on a recurring basis [Member] | Mine Reclamation Trust [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	5,500,000	4,400,000
Measured on a recurring basis [Member] | Cash and equivalents [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	8,276,000	3,356,000
Measured on a recurring basis [Member] | Domestic value [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	45,340,000	39,460,000
Measured on a recurring basis [Member] | Domestic growth [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	74,053,000	76,292,000
Measured on a recurring basis [Member] | International and other [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	16,599,000	16,633,000
Measured on a recurring basis [Member] | U.S. Government [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	22,563,000	21,941,000
Measured on a recurring basis [Member] | Municipals [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	68,973,000	58,568,000
Measured on a recurring basis [Member] | Corporate and other [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$14,341,000	$10,605,000

Fair_Value_of_Derivative_and_O7

Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
PNMR and PNM [Member]
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale debt securities, Within 1 year	$3,946
Available-for-sale debt securities, After 1 year through 5 years	20,275
Available-for-sale debt securities, After 5 years through 10 years	13,422
Available-for-sale debt securities, After 10 years through 15 years	10,367
Available-for-sale debt securities, After 15 years through 20 years	11,539
Available-for-sale debt securities, After 20 years	46,328
Available-for-sale debt securities	105,877
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]
Held-to-maturity debt securities, Due within 1 year	8,019
Held-to-maturity debt securities, After 1 year through 5 years	25,430
Held-to-maturity debt securities, After 5 years through 10 years	0
Held to Maturity Securities, Debt Maturities, after Ten Years Through Fifteen Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Fifteen Years Through Twenty Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Twenty Years, Fair Value	0
Held-to-maturity debt securities	33,449
Public Service Company of New Mexico [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]
Held-to-maturity debt securities, Due within 1 year	8,019
Held-to-maturity debt securities, After 1 year through 5 years	24,817
Held-to-maturity debt securities, After 5 years through 10 years	0
Held to Maturity Securities, Debt Maturities, after Ten Years Through Fifteen Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Fifteen Years Through Twenty Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Twenty Years, Fair Value	0
Held-to-maturity debt securities	$32,836

Fair_Value_of_Derivative_and_O8

Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (PNMR and PNM [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	$250,145	$226,855
Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	250,145	226,855
Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	169,919	158,180
Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	80,226	68,675
Cash and equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	8,276	3,356
Cash and equivalents [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	8,276	3,356
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	8,276	3,356
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	0	0
Domestic value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	45,340	39,460
Domestic value [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	45,340	39,460
Domestic value [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	45,340	39,460
Domestic value [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	0	0
Domestic growth [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	74,053	76,292
Domestic growth [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	74,053	76,292
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	74,053	76,292
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	0	0
International and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	16,599	16,633
International and other [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	16,599	16,633
International and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	16,599	16,633
International and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	0	0
U.S. Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	22,563	21,941
U.S. Government [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	22,563	21,941
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	20,808	20,194
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	1,755	1,747
Municipals [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	68,973	58,568
Municipals [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	68,973	58,568
Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	0	0
Municipals [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	68,973	58,568
Corporate and other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	14,341	10,605
Corporate and other [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	14,341	10,605
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	4,843	2,245
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale securities, Fair value	9,498	8,360
Commodity Contract [Member] | Measured on a recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	11,232	7,066
Commodity derivative instruments, Liabilities	-1,686	-3,793
Commodity derivative instruments, Net	9,546	3,273
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	0	0
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	11,232	7,066
Commodity derivative instruments, Liabilities	-1,686	-3,793
Commodity derivative instruments, Net	$9,546	$3,273

Fair_Value_of_Derivative_and_O9

Fair Value of Derivative and Other Financial Instruments, Defined Benefit Plans Disclosure (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	$2,173,117	$1,905,230
Investment in PVNGS lessor notes	32,836	57,279
Other investments	2,375	3,196
Fair value of plan assets at end of year	657,319	623,543
Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	1,624,222	1,382,938
Investment in PVNGS lessor notes	32,836	57,279
Other investments	397	445
Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	427,356	390,814
Other investments	242	245
Cash and Cash Equivalents [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	15,645	16,281
Equity Securities, International Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	23,282	24,471
Equity Securities, Domestic Value [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	41,778	41,451
Equity Securities, Domestic Growth [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	28,370	36,805
Equity Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	29,719	22,522
Fixed Income Securities, Corporate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	242,742	202,897
Fixed Income Securities, U.S. Government [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	106,634	99,748
Fixed Income Securities, Municipals [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	20,156	17,259
Fixed Income Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	74,136	66,286
Private Equity Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	37,220	39,122
Hedge Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	23,876	34,912
Real Estate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	13,761	21,789
Fair Value, Inputs, Level 1 [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes	0	0
Other investments	639	690
Fair value of plan assets at end of year	138,491	164,021
Fair Value, Inputs, Level 1 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes	0	0
Other investments	397	445
Fair Value, Inputs, Level 1 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Other investments	242	245
Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	15,645	16,281
Fair Value, Inputs, Level 1 [Member] | Equity Securities, International Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	24,471
Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Value [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	41,778	41,451
Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Growth [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	28,370	36,805
Fair Value, Inputs, Level 1 [Member] | Equity Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities, Corporate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	363
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities, U.S. Government [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	52,537	44,541
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities, Municipals [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Income Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	161	109
Fair Value, Inputs, Level 1 [Member] | Private Equity Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 1 [Member] | Hedge Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 1 [Member] | Real Estate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	2,173,117	1,905,230
Investment in PVNGS lessor notes	0	0
Other investments	0	0
Fair value of plan assets at end of year	443,244	363,523
Fair Value, Inputs, Level 2 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	1,624,222	1,382,938
Investment in PVNGS lessor notes	0	0
Other investments	0	0
Fair Value, Inputs, Level 2 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	427,356	390,814
Other investments	0	0
Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | Equity Securities, International Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	23,282	0
Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Value [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Growth [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | Equity Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	29,719	22,522
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities, Corporate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	242,015	202,358
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities, U.S. Government [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	54,097	55,207
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities, Municipals [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	20,156	17,259
Fair Value, Inputs, Level 2 [Member] | Fixed Income Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	73,975	66,177
Fair Value, Inputs, Level 2 [Member] | Private Equity Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | Hedge Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 2 [Member] | Real Estate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes	32,836	57,279
Other investments	1,736	2,506
Fair value of plan assets at end of year	75,584	95,999
Fair Value, Inputs, Level 3 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Investment in PVNGS lessor notes	32,836	57,279
Other investments	0	0
Fair Value, Inputs, Level 3 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	0	0
Other investments	0	0
Fair Value, Inputs, Level 3 [Member] | PNMR Master Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	75,584	95,999
Fair Value, Inputs, Level 3 [Member] | PNMR Master Trust [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	80,991	79,017
Actual return on assets sold during the period	10,376	3,303
Actual return on assets still held at period end	-5,731	3,361
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	8,832	15,110
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-28,843	-19,800
Fair value of plan assets at end of year	65,625	80,991
Fair Value, Inputs, Level 3 [Member] | PNMR Master Trust [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	15,008	14,171
Actual return on assets sold during the period	3,409	1,400
Actual return on assets still held at period end	-1,883	1,425
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	2,902	6,408
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-9,477	-8,396
Fair value of plan assets at end of year	9,959	15,008
Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Equity Securities, International Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Value [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Growth [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Equity Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities, Corporate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	176	0
Actual return on assets sold during the period	0	1
Actual return on assets still held at period end	-20	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	608	175
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-37	0
Fair value of plan assets at end of year	727	176
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities, U.S. Government [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities, Municipals [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Securities, Other Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Fair Value, Inputs, Level 3 [Member] | Private Equity Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	39,122	38,212
Actual return on assets sold during the period	5,355	4,677
Actual return on assets still held at period end	-296	1,162
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	3,656	3,117
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-10,617	-8,046
Fair value of plan assets at end of year	37,220	39,122
Fair Value, Inputs, Level 3 [Member] | Hedge Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	34,912	31,277
Actual return on assets sold during the period	8,667	135
Actual return on assets still held at period end	-7,536	3,500
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	5,500	16,151
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-17,667	-16,151
Fair value of plan assets at end of year	23,876	34,912
Fair Value, Inputs, Level 3 [Member] | Real Estate [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	21,789	23,699
Actual return on assets sold during the period	-236	-109
Actual return on assets still held at period end	237	123
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	1,971	2,076
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-10,000	-4,000
Fair value of plan assets at end of year	13,761	21,789
Fair Value, Inputs, Level 3 [Member] | Private Equity, Hedge and Real Estate Funds [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	95,999	93,188
Actual return on assets sold during the period	13,786	4,704
Actual return on assets still held at period end	-7,615	4,785
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	11,735	21,519
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	-38,321	-28,197
Fair value of plan assets at end of year	75,584	95,999
Pension Plan [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year			518,095
Fair value of plan assets at end of year	587,909	556,353	518,095
Pension Plan [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year			66,540
Fair value of plan assets at end of year	69,177	66,118	66,540
Pension Plan [Member] | PNMR Master Trust [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	588,112	557,258
Pension Plan [Member] | PNMR Master Trust [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	69,207	66,285
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | PNMR Master Trust [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	123,668	145,364
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | PNMR Master Trust [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	14,823	18,657
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | PNMR Master Trust [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	398,819	330,903
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | PNMR Master Trust [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	44,425	32,620
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | PNMR Master Trust [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	65,625	80,991
Pension Plan [Member] | Fair Value, Inputs, Level 3 [Member] | PNMR Master Trust [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	9,959	15,008
Other Postretirement Benefits [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	79,018	74,133
Fair value of plan assets at beginning of year			64,464
Fair value of plan assets at end of year	78,175	73,565	64,464
Other Postretirement Benefits [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	10,211	9,734
Fair value of plan assets at beginning of year			8,643
Fair value of plan assets at end of year	10,094	9,601	8,643
Other Postretirement Benefits [Member] | Cash and Cash Equivalents [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,242	1,152
Other Postretirement Benefits [Member] | Cash and Cash Equivalents [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	168	302
Other Postretirement Benefits [Member] | Equity Securities, International Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	10,332	11,634
Other Postretirement Benefits [Member] | Equity Securities, International Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,277	1,334
Other Postretirement Benefits [Member] | Equity Securities, Domestic Value [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	8,365	6,388
Other Postretirement Benefits [Member] | Equity Securities, Domestic Value [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	403	381
Other Postretirement Benefits [Member] | Equity Securities, Domestic Growth [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	5,960	24,135
Other Postretirement Benefits [Member] | Equity Securities, Domestic Growth [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,024	4,171
Other Postretirement Benefits [Member] | Equity Securities, Other Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	30,997	14,028
Other Postretirement Benefits [Member] | Equity Securities, Other Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	3,790	1,844
Other Postretirement Benefits [Member] | Fixed income securities, Mutual funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	22,122	16,796
Other Postretirement Benefits [Member] | Fixed income securities, Mutual funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	3,549	1,702
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	37,689	31,430
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	5,144	4,233
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,242	1,152
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	168	302
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, International Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, International Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Value [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	8,365	6,388
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Value [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	403	381
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Growth [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	5,960	7,094
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Domestic Growth [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,024	1,848
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Other Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities, Other Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed income securities, Mutual funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	22,122	16,796
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member] | Fixed income securities, Mutual funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	3,549	1,702
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	41,329	42,703
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	5,067	5,501
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, International Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	10,332	11,634
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, International Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	1,277	1,334
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Value [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Value [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Growth [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	17,041
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Domestic Growth [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	2,323
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Other Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	30,997	14,028
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities, Other Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	3,790	1,844
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed income securities, Mutual funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member] | Fixed income securities, Mutual funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Cash and Cash Equivalents [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, International Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, International Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Value [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Value [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Growth [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Domestic Growth [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Other Funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities, Other Funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed income securities, Mutual funds [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member] | Fixed income securities, Mutual funds [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at end of year	0	0
Carrying (Reported) Amount, Fair Value Disclosure [Member] | PNMR [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	1,975,090	1,745,420
Investment in PVNGS lessor notes	31,232	52,958
Other investments	1,762	1,835
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	1,490,657	1,290,618
Investment in PVNGS lessor notes	31,232	52,958
Other investments	397	445
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Long-term debt	365,667	336,036
Other investments	$242	$245

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	3 Months Ended								12 Months Ended			6 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 16, 2014	Oct. 08, 2013	30-May-08	Jul. 17, 2014
														MW
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings Attributable to non-controlling interest									$14,127,000	$14,521,000	$14,050,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Total current assets	432,817,000				401,539,000				432,817,000	401,539,000
Total Assets	5,829,325,000				5,500,210,000				5,829,325,000	5,500,210,000	5,372,583,000
Current liabilities	704,282,000				492,671,000				704,282,000	492,671,000
Owners' equity - non-controlling interest	73,546,000				77,029,000				73,546,000	77,029,000
Operating Leases, renewal options after original lease term									6 years
Earnings Attributable to PNMR	18,992,000	55,653,000	29,141,000	12,468,000	7,648,000	54,555,000	27,678,000	10,626,000	116,254,000	100,507,000	105,547,000
Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Currently active with trusts	8								8
Operating Leases, trust lessors	8								8
Operating Leases, Different institutional investors of trust lessors	5								5
Operating Leases, renewal options after original lease term									2 years
Operating Leases, Extended lease term option									6 years
Operating leases, future minimum payments due	269,693,000								269,693,000
Operating Leases, Future Minimum Payments Due, Current	33,144,000								33,144,000
Earnings Attributable to PNMR	13,955,000	45,351,000	20,346,000	7,674,000	2,639,000	47,823,000	26,124,000	11,569,000
Valencia [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Number of mega watts purchased (in megawatts)														158
Power plant total construction costs														90,000,000
Long term contract for purchase of electric power fixed costs									19,100,000	18,900,000	18,800,000
Long term contract for purchase of electric power variable charges									1,200,000	1,200,000	900,000
Variable Interest Entity, Statement Of Operation [Abstract]
Electric Revenue									20,247,000	20,166,000	19,585,000
Operating expenses									-6,120,000	-5,645,000	-5,535,000
Earnings Attributable to non-controlling interest									-14,127,000	-14,521,000	-14,050,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Total current assets	2,513,000				2,658,000				2,513,000	2,658,000
Net property, plant and equipment	72,321,000				75,137,000				72,321,000	75,137,000
Total Assets	74,834,000				77,795,000				74,834,000	77,795,000
Current liabilities	1,288,000				766,000				1,288,000	766,000
Owners' equity - non-controlling interest	73,546,000				77,029,000				73,546,000	77,029,000
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, estimated purchase price													85,000,000
Long term contract option to purchase, approximate approval period									15 months
Long term contract option to purchase, ownership percentage									50.00%
Long Term Contract For Purchase of Power Term of Contract									20 years
Valencia [Member] | Maximum [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Jointly owned utility plant, option to purchase proportionate ownership share	50.00%								50.00%
Delta [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long term contract for purchase of electric power fixed costs												3,500,000
Long term contract for purchase of electric power variable charges												600,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Period of Long Term Contract For Purchase of Electric Power Fixed Costs									20 years
PVNGS [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating leases, future minimum payments due	20,300,000								20,300,000
Operating leases, future minimum payments due, renewal term	145,200,000								145,200,000
Delta [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long term contract for purchase of electric power fixed costs										6,400,000	6,200,000
Long term contract for purchase of electric power variable charges										1,800,000	800,000
Delta [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Payments to acquire businesses, net												22,800,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt															14,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment															58,100,000
Business Combination, recognized identifiable assets acquired, accumulated amort															23,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets															3,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets															3,400,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities															300,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities															3,400,000
Palo Verde Nuclear Generating Station [Member] | PVNGS [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Current	$26,000,000				$26,000,000				$26,000,000	$26,000,000

Earnings_and_Dividends_Per_Sha2

Earnings and Dividends Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings Per Share [Abstract]
Earnings Attributable to PNMR	$18,992	$55,653	$29,141	$12,468	$7,648	$54,555	$27,678	$10,626	$116,254		$100,507		$105,547
Average Number of Common Shares:
Outstanding during year									79,654,000		79,654,000		79,654,000
Vested awards of restricted stock									134,000		191,000		145,000
Average Shares b Basic									79,788,000		79,845,000		79,799,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock									491,000	[1]	586,000	[1]	618,000	[1]
Average Shares b Diluted									80,279,000	[1]	80,431,000	[1]	80,417,000	[1]
Net Earnings Per Share of Common Stock:
Basic (dollars per share)	$0.24	$0.70	$0.37	$0.16	$0.10	$0.68	$0.35	$0.13	$1.46		$1.26		$1.32
Diluted (dollars per share)	$0.24	$0.69	$0.36	$0.16	$0.10	$0.68	$0.34	$0.13	$1.45		$1.25		$1.31
Common Stock, Dividends, Per Share, Declared									$0.76		$0.68		$0.58
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)									254,050
[1]	Excludes out-of-the-money options for 254,050 shares of common stock at DecemberB 31, 2014. See Note 13.

Income_Taxes_Schedule_of_Compo

Income Taxes Schedule of Components of Income Tax Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Current federal income tax	($2,015)	$0	($1,296)
Current state income tax	-728	-917	-37
Deferred federal income tax	59,814	50,044	51,559
Deferred state income tax	14,831	12,578	6,921
Amortization of accumulated investment tax credits	-2,164	-2,192	-2,237
Total income taxes	69,738	59,513	54,910
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Current federal income tax	-2,175	-479	-12,951
Current state income tax	-979	-760	-1,815
Deferred federal income tax	45,890	42,806	56,194
Deferred state income tax	12,061	9,429	11,522
Amortization of accumulated investment tax credits	-2,164	-2,192	-2,237
Total income taxes	52,633	48,804	50,713
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Current federal income tax	35	-4,957	9,152
Current state income tax	1,939	1,916	1,822
Deferred federal income tax	20,577	20,688	4,406
Deferred state income tax	-28	-26	-28
Total income taxes	$22,523	$17,621	$15,352

Income_Taxes_Schedule_of_Effec

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Federal income tax at statutory rates	$70,226	$61,274	$61,262
Amortization of accumulated investment tax credits	-2,164	-2,192	-2,237
Flow-through of depreciation items	1,344	1,132	1,284
Earnings attributable to non-controlling interest in Valencia	-4,945	-5,082	-4,918
State income tax, net of federal benefit	5,723	3,818	4,646
Impairment of state net operating loss carryforwards	3,129	0	0
Impairment of state production tax credits, net of federal benefit	894	3,880	718
Other	-4,469	-3,317	-5,845
Total income taxes	69,738	59,513	54,910
Effective tax rate	34.76%	33.99%	31.37%
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Federal income tax at statutory rates	53,930	53,018	54,710
Amortization of accumulated investment tax credits	-2,164	-2,192	-2,237
Flow-through of depreciation items	1,325	1,115	1,268
Earnings attributable to non-controlling interest in Valencia	-4,945	-5,082	-4,918
State income tax, net of federal benefit	5,522	6,202	6,500
Impairment of state net operating loss carryforwards	2,145	0	0
Other	-3,180	-4,257	-4,610
Total income taxes	52,633	48,804	50,713
Effective tax rate	34.16%	32.22%	32.44%
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Federal income tax at statutory rates	21,115	16,349	14,735
State income tax, net of federal benefit	1,257	1,247	1,185
Other	151	25	-568
Total income taxes	$22,523	$17,621	$15,352
Effective tax rate	37.33%	37.72%	36.47%

Income_Taxes_Schedule_of_Defer

Income Taxes Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred tax assets:
Net operating loss	$153,858	$134,418
Regulatory liabilities related to income taxes	78,858	83,838
Deferred Tax Assets, Tax Credit Carryforwards	54,748	40,708
Other	68,566	75,832
Total deferred tax assets	356,030	334,796
Deferred tax liabilities:
Depreciation and plant related	-914,926	-814,671
Investment tax credit	-36,790	-25,855
Regulatory assets related to income taxes	-67,910	-66,352
Stranded costs	-19,352	-22,262
Pension	-66,498	-58,780
Other	-115,282	-115,458
Total deferred tax liabilities	-1,220,758	-1,103,378
Current accumulated deferred income tax (asset) liability	-864,728	-768,582
Deferred Tax Assets (Liabilities), Net [Abstract]
Current accumulated deferred income tax (asset) liability	-26,383	-58,681
Non-current accumulated deferred income tax liability	-891,111	-827,263
Public Service Company of New Mexico [Member]
Deferred tax assets:
Net operating loss	108,505	99,247
Regulatory liabilities related to income taxes	74,293	78,849
Deferred Tax Assets, Tax Credit Carryforwards	35,259	22,509
Other	35,681	37,008
Total deferred tax assets	253,738	237,613
Deferred tax liabilities:
Depreciation and plant related	-733,519	-661,239
Investment tax credit	-36,790	-25,855
Regulatory assets related to income taxes	-57,637	-55,844
Pension	-58,474	-52,104
Other	-70,714	-75,838
Total deferred tax liabilities	-957,134	-870,880
Current accumulated deferred income tax (asset) liability	-703,396	-633,267
Deferred Tax Assets (Liabilities), Net [Abstract]
Current accumulated deferred income tax (asset) liability	-12,418	-43,827
Non-current accumulated deferred income tax liability	-715,814	-677,094
Texas-New Mexico Power Company [Member]
Deferred tax assets:
Regulatory liabilities related to income taxes	4,565	4,988
Other	13,429	23,479
Total deferred tax assets	17,994	28,467
Deferred tax liabilities:
Depreciation and plant related	-174,510	-151,581
Regulatory assets related to income taxes	-10,197	-10,509
Loss on reacquired debt	-12,846	-13,516
Stranded costs	-19,352	-22,262
Other	-12,636	-14,295
Total deferred tax liabilities	-229,541	-212,163
Current accumulated deferred income tax (asset) liability	-211,547	-183,696
Deferred Tax Assets (Liabilities), Net [Abstract]
Current accumulated deferred income tax (asset) liability	-6,398	-6,501
Non-current accumulated deferred income tax liability	($217,945)	($190,197)

Income_Taxes_Schedule_of_Defer1

Income Taxes Schedule of Deferred Income Tax Components (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Net change in deferred income tax liability per above table	$96,146
Change in tax effects of income tax related regulatory assets and liabilities	-6,538
Tax effect of mark-to-market adjustments	-1,612
Tax effect of excess pension liability	3,993
Reclassification of unrecognized tax benefits	-4,858
Unrecognized Tax Benefits	15,031
Other	381
Deferred income taxes	72,481	60,430	56,243
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Net change in deferred income tax liability per above table	70,129
Change in tax effects of income tax related regulatory assets and liabilities	-6,349
Tax effect of mark-to-market adjustments	-1,470
Tax effect of excess pension liability	3,993
Reclassification of unrecognized tax benefits	1,155
Unrecognized Tax Benefits	12,228
Other	557
Deferred income taxes	55,787
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Net change in deferred income tax liability per above table	27,851
Change in tax effects of income tax related regulatory assets and liabilities	-111
Reclassification of unrecognized tax benefits	-6,796
Other	-395
Deferred income taxes	$20,549

Income_Taxes_Summary_of_Income

Income Taxes Summary of Income Tax Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning	$19,889,000	$19,198,000	$19,580,000
Additions based on tax positions	623,000	-54,000	2,046,000
Additions (reductions) for tax positions of prior years	-5,481,000		-2,428,000
Additions for tax positions of prior years		745,000
Settlement payments	0	0	0
Unrecognized Tax Benefits - End	15,031,000	19,889,000	19,198,000
Public Service Company of New Mexico [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning	11,073,000	10,382,000	10,752,000
Additions based on tax positions	623,000	-54,000	1,152,000
Additions (reductions) for tax positions of prior years			-1,522,000
Additions for tax positions of prior years	532,000	745,000
Settlement payments	0	0	0
Unrecognized Tax Benefits - End	12,228,000	11,073,000	10,382,000
Unrecognized tax benefits that would impact effective tax rate	1,900,000
Texas-New Mexico Power Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits - Beginning	6,796,000	6,796,000	7,701,000
Additions based on tax positions	0	0	0
Additions (reductions) for tax positions of prior years	-6,796,000		-905,000
Additions for tax positions of prior years		0
Settlement payments	0	0	0
Unrecognized Tax Benefits - End	0	6,796,000	6,796,000
PNMR [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits that would impact effective tax rate	$4,700,000

Income_Taxes_Interest_Expense_

Income Taxes Interest Expense (Income) Related to Income Taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Interest income related to income taxes	$146	$242	$243
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Interest income related to income taxes	148	251	244
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Interest income related to income taxes	($2)	($2)	($3)

Income_Taxes_Accumulated_Accru

Income Taxes Accumulated Accrued Interest Receivable (Payable) Related to Income Taxes (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
PNMR [Member]
Income Taxes [Line Items]
Accumulated accrued interest receivable	$3,569	$4,048
Accumulated accrued interest payable	-1,120	-1,118
Public Service Company of New Mexico [Member]
Income Taxes [Line Items]
Accumulated accrued interest receivable	3,569	4,048
Accumulated accrued interest payable	-24	-24
Texas-New Mexico Power Company [Member]
Income Taxes [Line Items]
Accumulated accrued interest receivable	0	0
Accumulated accrued interest payable	($120)	($118)

Income_Taxes_Carryforwards_Det

Income Taxes Carryforwards (Details) (USD $)	1 Months Ended	12 Months Ended
	31-May-13	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Additional Income Tax Expense, Impairment of NM Wind Credits			$2,400,000	$700,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease			1,500,000
New Mexico Corporate tax rate, current		7.60%
New Mexico Corporate tax rate, 2014		5.90%
Increase in regulatory liabilities due to change in state corporate tax rate			23,900,000
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
Investment tax credit, Impairment		900,000
State Net Operating Loss Carryforward, Impairment		3,100,000
Deferred Tax Assets, Valuation Allowance		5,500,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount		900,000	3,900,000	700,000
Federal Tax Refund	96,200,000
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset			19,900,000
Income Taxes		69,738,000	59,513,000	54,910,000
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Federal Net Operating Loss Carryforwards to Expire in 2030		405,700,000
Federal Tax Credit Carryforwards that Expire Beginning in 2023		54,700,000
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Income Taxes		-1,300,000
Public Service Company of New Mexico [Member]
Operating Loss Carryforwards [Line Items]
Increase in deferred tax asset not related to regulatory activity, as a result of tax rate change		100,000
Decrease in income tax expense due to tax rate change		300,000
State Net Operating Loss Carryforward, Impairment		1,000,000
Federal Tax Refund	77,400,000
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset			11,200,000
Income Taxes		52,633,000	48,804,000	50,713,000
Public Service Company of New Mexico [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Income Taxes		1,100,000
PNM and TNMP [Domain]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Valuation Allowance		0
Other Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
State Net Operating Loss Carryforward, Impairment		2,100,000
Texas-New Mexico Power Company [Member]
Operating Loss Carryforwards [Line Items]
New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset			6,800,000
Income Taxes		22,523,000	17,621,000	15,352,000
PNM Resources [Member]
Operating Loss Carryforwards [Line Items]
Income Taxes		-5,389,000	-6,870,000	-11,168,000
PNM Resources [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority		-2,000,000
Income Taxes		($200,000)

Pension_and_Other_Postretireme2

Pension and Other Postretirement Benefits Narrative (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets	4.00%
Defined Benefit Plans, Gains and losses that lie outside the corridor, amortized (in years)	5 years
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	6.00%
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return resulting from effect of one-percentage point decrease (as a percent)	1.00%
Expected long-term return resulting from effect of one-percentage point increase (as a percent)	1.00%
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return resulting from effect of one-percentage point decrease (as a percent)	1.00%
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets	7.20%	7.65%	8.25%
Defined Benefit Plan, Other Changes	50,600,000	($60,900,000)
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	-200,000	-4,400,000
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in other assumptions and experience	200,000	100,000
Actual plan asset allocations (as a percent)	14.30%
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	5,800,000
Employer contributions	0	60,000,000
Estimated future employer contributions from 2013-2017	22,000,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	-34,345,000
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets	8.50%	8.50%	8.50%
Defined Benefit Plan, Other Changes	6,700,000	-8,800,000
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	5,400,000	-4,200,000
Actual plan asset allocations (as a percent)	10.20%
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	700,000
Employer contributions	3,532,000	3,576,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	-2,800,000
Estimated future employer contributions in next fiscal year	3,500,000
Defined Benefit Plan, Estimated Future Employer Contributions in Year Two Through Year Five	14,000,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets	7.20%	7.65%	8.25%
Defined Benefit Plan, Other Changes	5,100,000	-6,400,000
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	400,000	1,400,000
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in other assumptions and experience	-1,300,000	-100,000
Actual plan asset allocations (as a percent)	13.50%
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	600,000
Employer contributions	0	1,000,000
Estimated future employer contributions from 2013-2017	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	-4,420,000
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected return on plan assets	6.50%	6.50%	6.50%
Defined Benefit Plan, Other Changes	1,100,000	-1,300,000
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	-100,000	-200,000
Actual plan asset allocations (as a percent)	8.90%
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	100,000
Employer contributions	343,000	342,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	-1,300,000
Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates, Net periodic expense and APBO	0
Estimated future employer contributions in next fiscal year	300,000
Defined Benefit Plan, Estimated Future Employer Contributions in Year Two Through Year Five	1,400,000
PNM and TNMP [Domain] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	0
Equity Securities [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	21.00%
Equity Securities [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	70.00%
Debt Securities [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	65.00%
Debt Securities [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	30.00%
Alternative Investments [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	14.00%
Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, non matching contribution of eligible compensation based on eligible employee's age	3.00%
Minimum [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average discount rate related to anticipated contributions (as a percent)	4.80%
Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, non matching contribution of eligible compensation based on eligible employee's age	10.00%
Maximum [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average discount rate related to anticipated contributions (as a percent)	5.50%
Developed Countries Outside of United States [Member] | Equity Securities [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target plan asset allocations (as a percent)	6.00%
Revised Mortality Tables [Member] | Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Changes	21,900,000
Revised Mortality Tables [Member] | Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Changes	3,200,000
Revised Mortality Tables [Member] | Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Changes	2,500,000
Revised Mortality Tables [Member] | Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Changes	500,000
Revised Mortality Tables [Member] | Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions				$30,000,000

Pension_and_Other_Postretireme3

Pension and Other Postretirement Benefits APBO, PBO, Fair Value of Plan Assets, and Funded Status of the Plans (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Non-current liability	$110,738	$80,046
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	599,537	675,549
Service cost	0	0	0
Interest cost	30,163	28,142	32,232
Plan amendment	0	-6,346
Actuarial (gain) loss	72,524	-56,533
Benefits paid	-44,667	-41,275
Benefit Obligation at end of year	657,557	599,537	675,549
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	556,353	518,095
Actual return on plan assets	76,223	19,533
Employer contributions	0	60,000
Benefits paid	-44,667	-41,275
Fair value of plan assets at end of year	587,909	556,353	518,095
Funded status b asset (liability) for pension benefits	-69,648	-43,184
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	92,165	99,613
Service cost	181	260	217
Interest cost	4,630	4,113	5,293
Participant contributions	-2,582	-2,537
Actuarial (gain) loss	4,455	-4,566
Benefits paid	-8,838	-9,792
Benefit Obligation at end of year	95,175	92,165	99,613
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	73,565	64,464
Actual return on plan assets	7,334	12,780
Employer contributions	3,532	3,576
Participant contributions	2,582	2,537
Benefits paid	-8,838	-9,792
Fair value of plan assets at end of year	78,175	73,565	64,464
Funded status b asset (liability) for pension benefits	-17,000	-18,600
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	16,363	17,467
Service cost	0	0	0
Interest cost	822	720	876
Actuarial (gain) loss	2,040	-330
Benefits paid	-1,495	-1,494
Benefit Obligation at end of year	17,730	16,363	17,467
Less current liability	1,528	1,536
Non-current liability	16,202	14,827
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefits paid	-1,495	-1,494
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	66,159	76,640
Service cost	0	0	0
Interest cost	3,193	3,087	3,635
Plan amendment	0	0
Actuarial (gain) loss	8,466	-7,820
Benefits paid	-5,513	-5,748
Benefit Obligation at end of year	72,305	66,159	76,640
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	66,118	66,540
Actual return on plan assets	8,572	4,326
Employer contributions	0	1,000
Benefits paid	-5,513	-5,748
Fair value of plan assets at end of year	69,177	66,118	66,540
Funded status b asset (liability) for pension benefits	-3,128	-41
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	12,266	13,678
Service cost	237	299	244
Interest cost	619	566	624
Participant contributions	-366	-373
Actuarial (gain) loss	1,639	-1,080
Benefits paid	-1,057	-1,570
Benefit Obligation at end of year	14,070	12,266	13,678
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	9,601	8,643
Actual return on plan assets	841	1,813
Employer contributions	343	342
Participant contributions	366	373
Benefits paid	-1,057	-1,570
Fair value of plan assets at end of year	10,094	9,601	8,643
Funded status b asset (liability) for pension benefits	-3,976	-2,665
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at beginning of year	823	902
Service cost	0	0	0
Interest cost	39	36	45
Actuarial (gain) loss	110	-21
Benefits paid	-94	-94
Benefit Obligation at end of year	878	823	902
Less current liability	94	94
Non-current liability	784	729
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefits paid	($94)	($94)

Pension_and_Other_Postretireme4

Pension and Other Postretirement Benefits Pre-Tax Information about Prior Service Cost and Net Actuarial (Gain) loss in AOCI (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit) - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	($2,665)
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	139,256
Prior service cost (credit) - Experience loss (gain)	0
Net actuarial (gain) loss - Experience loss (gain)	34,345
Prior service cost (credit) - Regulatory asset (liability) adjustment	0
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	-19,920
Prior service cost (credit) - Amortization recognized in net periodic benefit cost (income)	405
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	-5,469
Prior service cost (credit) - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	-2,260
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	148,212
Prior service cost (credit) - Amortization expected to be recognized in in 2015	-405
Net actuarial (gain) loss - Amortization expected to be recognized in in 2015	6,224
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss - Experience loss (gain)	2,800
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	1,833
Net actuarial (gain) loss - Experience loss (gain)	2,040
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	-1,183
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	-88
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	2,602
Net actuarial (gain) loss - Amortization expected to be recognized in in 2015	136
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	0
Net actuarial (gain) loss - Experience loss (gain)	4,420
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	-4,420
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	0
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	0
Net actuarial (gain) loss - Amortization expected to be recognized in in 2015	0
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss - Experience loss (gain)	1,300
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	0
Net actuarial (gain) loss - Experience loss (gain)	-110
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	110
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	0
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	0
Net actuarial (gain) loss - Amortization expected to be recognized in in 2015	$0

Pension_and_Other_Postretireme5

Pension and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Income) Recognized (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$0	$0	$0
Interest cost	30,163	28,142	32,232
Expected return on plan assets	-38,044	-41,930	-41,301
Amortization of net (gain) loss	13,020	14,840	10,516
Amortization of prior service cost (credit)	-965	76	317
Net periodic benefit cost	4,174	1,128	1,764
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0
Interest cost	822	720	876
Amortization of net (gain) loss	210	232	83
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	1,032	952	959
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	181	260	217
Interest cost	4,630	4,113	5,293
Expected return on plan assets	-5,638	-5,043	-4,901
Amortization of net (gain) loss	2,225	4,242	3,888
Amortization of prior service cost (credit)	-1,343	-1,343	-1,343
Net periodic benefit cost	55	2,229	3,154
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0
Interest cost	3,193	3,087	3,635
Expected return on plan assets	-4,526	-4,849	-5,324
Amortization of net (gain) loss	665	1,049	462
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	-668	-713	-1,227
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0
Interest cost	39	36	45
Amortization of net (gain) loss	0	0	0
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	39	36	45
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	237	299	244
Interest cost	619	566	624
Expected return on plan assets	-534	-503	-516
Amortization of net (gain) loss	-122	0	-209
Amortization of prior service cost (credit)	32	57	57
Net periodic benefit cost	$232	$419	$200

Pension_and_Other_Postretireme6

Pension and Other Postretirement Benefits Assumptions Used (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	4.00%
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.48%	5.27%	4.30%
Discount rate for determining net periodic benefit cost (income)	5.27%	4.30%	5.67%
Expected return on plan assets	7.20%	7.65%	8.25%
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.45%	5.21%	4.26%
Discount rate for determining net periodic benefit cost (income)	5.21%	4.26%	5.70%
Expected return on plan assets	8.50%	8.50%	8.50%
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.48%	5.27%	4.30%
Discount rate for determining net periodic benefit cost (income)	5.27%	4.30%	5.67%
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.39%	5.06%	4.19%
Discount rate for determining net periodic benefit cost (income)	5.06%	4.19%	5.69%
Expected return on plan assets	7.20%	7.65%	8.25%
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.45%	5.21%	4.26%
Discount rate for determining net periodic benefit cost (income)	5.21%	4.26%	5.70%
Expected return on plan assets	6.50%	6.50%	6.50%
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate for determining December 31	4.39%	5.06%	4.19%
Discount rate for determining net periodic benefit cost (income)	5.06%	4.19%	5.69%

Pension_and_Other_Postretireme7

Pension and Other Postretirement Benefits Pension Benefit Payments are Expected to be Paid (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	$53,472
2016	53,468
2017	51,241
2018	49,640
2019	48,560
Years 2019 - 2023	213,759
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	6,560
2016	6,635
2017	6,718
2018	6,875
2019	6,950
Years 2019 - 2023	34,585
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	1,528
2016	1,510
2017	1,490
2018	1,468
2019	1,445
Years 2019 - 2023	6,722
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	5,997
2016	5,667
2017	5,351
2018	5,585
2019	5,188
Years 2019 - 2023	23,600
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	801
2016	822
2017	838
2018	860
2019	882
Years 2019 - 2023	4,717
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2015	93
2016	92
2017	91
2018	89
2019	86
Years 2019 - 2023	$384

Pension_and_Other_Postretireme8

Pension and Other Postretirement Benefits Assumed Health Care Cost Trend Rates and Impact of a One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Details) (Public Service Company of New Mexico [Member], Other Postretirement Benefits [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year (as a percent)	7.00%	7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) (as a percent)	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2023	2019
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$350
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	-281
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	5,305
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	($4,622)

Pension_and_Other_Postretireme9

Pension and Other Postretirement Benefits Other Postretirement Benefits (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Retirement Plans, 401 (k) plan [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Expenses recognized	$16,703	$16,785	$16,185
Other Retirement Plans, 401 (k) plan [Member] | Public Service Company of New Mexico [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Expenses recognized	12,745	12,952	12,427
Other Retirement Plans, 401 (k) plan [Member] | Texas-New Mexico Power Company [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Expenses recognized	3,958	3,953	3,739
Other Retirement Plans, Key Employees, Non-qualified Plan [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Compensation expense	2,257	2,204	1,491
Other Retirement Plans, Key Employees, Non-qualified Plan [Member] | Public Service Company of New Mexico [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Compensation expense	1,722	1,691	1,143
Other Retirement Plans, Key Employees, Non-qualified Plan [Member] | Texas-New Mexico Power Company [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Compensation expense	$535	$513	$327

StockBased_Compensation_Plans_1

Stock-Based Compensation Plans Performance Equity Plan/ Accounting for Stock Awards and ESPP (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$5.90	$5.30	$3.60
Public Service Company of New Mexico [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	4.2	3.8	2.7
Texas-New Mexico Power Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	1.7	1.5	1
Restricted Stock and Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	4.7
Market-Based Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$1.80
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition (years)	1 year 9 months 19 days
Performance Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate	100.00%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized, Shares	13,500,000

StockBased_Compensation_Plans_2

Stock-Based Compensation Plans Weighted Average Assumptions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock and Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected quarterly dividends per share, in dollars per share	$0.19	$0.17	$0.14
Risk-free interest rates, percentage	0.62%	0.34%	1.22%
Market-Based Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rates, percentage	0.64%	0.36%	1.04%
Dividend yield	2.82%	2.86%	3.45%
Expected volatility	25.11%	25.11%	43.98%

StockBased_Compensation_Plans_3

Stock-Based Compensation Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 01, 2015	Feb. 28, 2014	Feb. 26, 2015
Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | Chairman, President, and Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	135,000
Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | Chairman, President, and Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	35,000
Subsequent Event [Member] | Achieved performance target for 2015 and 2016 [Member] | Common Stock [Member] | Executive Vice President and Chief Financial Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock				$100,000
Subsequent Event [Member] | Achieved performance target for 2015, 2016 and 2017 [Member] | Common Stock [Member] | Executive Vice President and Chief Financial Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock				275,000
Performance Shares [Member] | Executive [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Excluded from Shares Outstanding, Number	179,845	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 2013	179,811
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in 2014	163,152
Performance Shares [Member] | Subsequent Event [Member] | Executive [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share based Compensation, weighted percentage assigned to achieving market targets						60.00%
Share based Compensation, weighted percentage assigned to achieving performance targets						40.00%
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Restricted Stock, at Beginning of period, Shares	315,305
Restricted Stock, at Beginning of period, Weighted-Average Grant-Date Fair Value, in dollars per share	$17.87
Restricted Stock, Granted, Shares	242,164
Restricted Stock, Granted, Fair Value, in dollars per share	$21.27	$20.03	$16.75
Restricted Stock, Vested, Shares	-295,423
Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value, in dollars per share	$16.70
Restricted Stock, Forfeited, Shares	-3,276
Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value, in dollars per share	$22.46
Restricted Stock, at end of period, Shares	258,770	315,305
Restricted Stock, at end of period, Weighted-Average Grant-Date Fair Value, in dollars per share	$22.31	$17.87
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value	$21.27	$20.03	$16.75
Total fair value of restricted shares that vested (in thousands)	4,933,000	4,395,000	5,099,000
Stock Options [Member]
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	-345,426
Options, Exercised, Weighted-Average Exercise Price, in dollars per share	$20.04
Options, Forfeited, Shares	-17,151
Options, Forfeited, Weighted-Average Exercise Price, in dollars per share	$26.43
Options, Expired, Shares	-60,584
Options, Expired, Weighted-Average Exercise Price, in dollars per share	$27.98
Options, Outstanding at end of period, Shares	920,505	1,343,666
Options, Outstanding at end of period, Weighted-Average Exercise Price, in dollars per share	$20.39	$20.63
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Outstanding at end of period, Aggregate Intrinsic Value	8,900,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	2 years 9 months 29 days
Options, Outstanding at end of period, No intrinsic value	254,050,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value options granted, in dollars per share	$0	$0	$0
Total fair value of options that vested	0	625,000	1,054,000
Total intrinsic value of options exercised	$2,473,000	$2,721,000	$6,356,000

Construction_Program_and_Joint2

Construction Program and Jointly-Owned Electric Generating Plants Construction Program and Jointly-Owned Electric Generating Plants (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Construction Expenditures	$460,658		$348,039	$308,909
Public Utilities, Property, Plant and Equipment, Plant in Service	5,941,581		5,563,061
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-1,939,760		-1,838,832
Operating Lease, Extended Term	2 years
Joint Projects [Member] | Public Service Company of New Mexico [Member]
Construction Expenditures	316,800
Joint Projects [Member] | Texas-New Mexico Power Company [Member]
Construction Expenditures	127,200
Joint Projects [Member] | PNMR [Member]
Construction Expenditures	460,700
Four Corners Units 4 and 5 (Coal) [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service	162,111
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-101,007
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	8,253
Jointly Owned Utility Plant, Proportionate Ownership Share	13.00%
Luna (Gas) [Member] | Other Unrelated Entities 9 [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	33.30%
Luna (Gas) [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service	66,169
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-20,297
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	136
Jointly Owned Utility Plant, Proportionate Ownership Share	33.33%
SJGS Units 1 and 2 [Member] | Public Service Company of New Mexico [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
SJGS (Coal) [Member] | Unit 3 [Member] | Other Unrelated Entities 1 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	41.80%
SJGS (Coal) [Member] | Unit 3 [Member] | Other Unrelated Entities 2 [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	8.20%
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 3 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	28.80%
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 4 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	10.04%
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 5 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	8.48%
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 6 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	7.20%
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 7 [Member]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	7.03%
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service	1,009,378
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-423,364
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	25,551
Jointly Owned Utility Plant, Proportionate Ownership Share	46.30%
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member] | Unit 3 [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member] | Unit 4 [Member]
Jointly Owned Utility Plant, Proportionate Ownership Share	38.46%
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service	533,702	[1]
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-152,273	[1]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	$42,334	[1]
Jointly Owned Utility Plant, Proportionate Ownership Share	10.20%	[1]
Operating Lease, Original term	40 years
Number of operating units	3
Operating Lease, Extended Term	20 years
[1]	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.

Summary_of_Budgeted_Constructi

Summary of Budgeted Construction Expenditures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Summary of Budgeted Construction Expenditures [Line Items]
2015	$569.20
2016	514.4
2017	443.5
2018	300.2
2019	380
Total	2,207.30
Public Service Company of New Mexico [Member]
Summary of Budgeted Construction Expenditures [Line Items]
2015	423.9
2016	402.3
2017	334.8
2018	180.6
2019	260.3
Total	1,601.90
Texas-New Mexico Power Company [Member]
Summary of Budgeted Construction Expenditures [Line Items]
2015	121.3
2016	92.8
2017	93.3
2018	105.9
2019	105
Total	518.3
Other Subsidiaries [Member]
Summary of Budgeted Construction Expenditures [Line Items]
2015	24
2016	19.3
2017	15.4
2018	13.7
2019	14.7
Total	87.1
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member]
Summary of Budgeted Construction Expenditures [Line Items]
Environmental Upgrades Requirement Estimates	70.7
Budgeted Construction Expenditures Related to Replacement Capacity	268.4
Four Corners Units 4 and 5 (Coal) [Member] | Public Service Company of New Mexico [Member]
Summary of Budgeted Construction Expenditures [Line Items]
Environmental Upgrades Requirement Estimates	$80

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability Beginning Balance	$96,135,000		$85,893,000		$79,233,000
Liabilities incurred	0		0		0
Liabilities settled	0		-79,000		-25,000
Accretion expense	7,984,000		7,245,000		6,685,000
Revisions to estimated cash flows	51,000	[1]	3,076,000	[1]
Liability Ending Balance	104,170,000		96,135,000		85,893,000
Public Service Company of New Mexico [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability Beginning Balance	95,225,000		85,042,000		78,425,000
Liabilities incurred	0		0		0
Liabilities settled	0		-67,000		0
Accretion expense	7,906,000		7,174,000		6,617,000
Revisions to estimated cash flows	51,000	[1]	3,076,000	[1]
Liability Ending Balance	103,182,000		95,225,000		85,042,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Period Increase (Decrease)	500,000
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Period Increase (Decrease)	2,500,000
Texas-New Mexico Power Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability Beginning Balance	782,000		732,000		699,000
Liabilities incurred	0		0		0
Liabilities settled	0		-12,000		-25,000
Accretion expense	66,000		62,000		58,000
Revisions to estimated cash flows	0	[1]	0	[1]
Liability Ending Balance	$848,000		$782,000		$732,000
[1]	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2013, a new decommissioning study for PVNGS was implemented reflecting updated cash flow estimates, including the extended operating licenses. The new study resulted in an increase of $0.5 million to the ARO. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)

12 Months Ended

0 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 01, 2014

Dec. 20, 2013

Dec. 21, 2011

Jun. 26, 2014

Oct. 31, 2014

Oct. 31, 2012

Sep. 30, 2014

Nov. 25, 2014

Jan. 31, 2010

Apr. 12, 2012

Jun. 27, 2014

Mar. 11, 2014

23-May-13

Jan. 06, 2014

Sep. 01, 2012

Nov. 08, 2013

Jan. 07, 2015

Jan. 15, 2015

Jan. 22, 2015

MW

mw

opp

opp

Allotment_Parcel

Allotment_Parcel

MW

MW

Loss Contingencies [Line Items]

Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Merucy and Air Toxics Standards

25

Other current assets

$58,471,000

$34,590,000

San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Mercury Removal Rate, Percentage

99.00%

Four Corners [Member]

Loss Contingencies [Line Items]

Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage

48.00%

Public Service Company of New Mexico [Member]

Loss Contingencies [Line Items]

Regulatory Assets

401,025,000

403,611,000

Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Jointly Owned Utility Plan, Proposed Proportionate Ownership Share

64.50%

Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]

Loss Contingencies [Line Items]

Payments to Acquire Investments to be Held in Decommissioning Trust Fund

4,900,000

4,900,000

2,600,000

Decommissioning Fund Investments, Fair Value

244,600,000

222,500,000

Jointly Owned Utility Plant, Proportionate Ownership Share

10.20%

[1]

Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Nuclear Spent Fuel And Waste Disposal [Member]

Loss Contingencies [Line Items]

Loss Contingency, Estimate of Possible Loss

58,000,000

Annual Fee, Nuclear Waste Disposal

0

3,000,000

Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Department of energy, spent nuclear fuel removal July 2011 - June 2014 [Member]

Loss Contingencies [Line Items]

Lawsuit settlement, Third party settlement claim

42,500,000

PNMs share of third party settlement claim

4,300,000

Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share

46.30%

Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member]

Loss Contingencies [Line Items]

Net book value

282,000,000

Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member]

Loss Contingencies [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share

13.00%

Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Net book value

144,000,000

Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member]

Loss Contingencies [Line Items]

Jointly Owned Utility Plan, Proposed Proportionate Ownership Share

58.70%

Public Service Company of New Mexico [Member] | Other Deferred Credits [Member] | Palo Verde Nuclear Generating Station [Member] | Nuclear Spent Fuel And Waste Disposal [Member]

Loss Contingencies [Line Items]

Mine Reclamation and Closing Liability, Noncurrent

12,300,000

11,900,000

Public Service Company of New Mexico [Member] | Minimum [Member] | San Juan Generating Station And Four Corners [Member]

Loss Contingencies [Line Items]

Public Utilities, Proposed Government Standard Emission Limit

65

60

Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station And Four Corners [Member]

Loss Contingencies [Line Items]

Public Utilities, Government Standard Emission Limit (pounds per MMBTU, parts per million)

75

Public Utilities, Proposed Government Standard Emission Limit

70

70

Public Service Company of New Mexico [Member] | Coal Supply [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Other current assets

37,300,000

12,300,000

Public Utilities, Estimated Increase in Coal Cost, Percentage

30.00%

Public Service Company of New Mexico [Member] | Surface [Member]

Loss Contingencies [Line Items]

Regulatory Assets

100,000,000

Public Service Company of New Mexico [Member] | Surface [Member] | Loss on Long-term Purchase Commitment [Member]

Loss Contingencies [Line Items]

Mine Reclamation and Closing Liability, Noncurrent

25,700,000

23,800,000

Final Reclamation, capped amount to be collected

100,000,000

Public Service Company of New Mexico [Member] | Surface [Member] | San Juan Generating Station [Member] | Loss on Long-term Purchase Commitment [Member]

Loss Contingencies [Line Items]

Loss Contingency, Estimate of Possible Loss

57,300,000

Public Service Company of New Mexico [Member] | Underground [Member] | Loss on Long-term Purchase Commitment [Member]

Loss Contingencies [Line Items]

Mine Reclamation and Closing Liability, Noncurrent

8,600,000

7,800,000

Public Service Company of New Mexico [Member] | Underground [Member] | San Juan Generating Station [Member] | Loss on Long-term Purchase Commitment [Member]

Loss Contingencies [Line Items]

Loss Contingency, Estimate of Possible Loss

93,300,000

Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Ownership Percentage in Nuclear Reactor

10.20%

Public Utilities, Maximum Potential Assessment Per Incident

38,900,000

Public Utilities, Annual Payment Limitation Related to Incident

5,700,000

Public Utilities, Aggregate Amount of All Risk Insurance

2,750,000,000

Public Utilities, Sublimit Amount under Nuclear Electric Insurance Limited

2,250,000,000

Public Utilities, Maximum Amount under Nuclear Electic Insurance Limited

4,800,000

Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Maximum [Member] | Palo Verde Nuclear Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Liability Insurance Coverage

13,600,000,000

Public Service Company of New Mexico [Member] | Commercial Providers [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Liability Insurance Coverage

375,000,000

Public Service Company of New Mexico [Member] | Industry Wide Retrospective Assessment Program [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Liability Insurance Coverage

13,200,000,000

Pnm Electric [Member] | San Juan Generating Station Units 2 and 3 [Member]

Loss Contingencies [Line Items]

Estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units

268,400,000

PNMR and PNM [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities, Number of Megawatts Nuclear Generation

134

Fuel and purchased power adjustment clause [Member] | Public Service Company of New Mexico [Member] | Minimum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Preliminary estimate increased deferral related to mine fire incident

17,400,000

Fuel and purchased power adjustment clause [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Preliminary estimate increased deferral related to mine fire incident

21,600,000

Clean Air Act related to Regional Haze [Member]

Loss Contingencies [Line Items]

Public Utilities, Number of States To Address Regional Haze

50

Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum

250

Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Public Utilities, Estimated rate base value at 1/1/2018

26,000,000

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Public Utilities, Additional Ownership To Be Obtained, in Megawatts

132

78

132

Percentage of ownership held by exiting owners

38.80%

Public Utilities, Ownership Percentage

38.50%

Public Utilities, Costs to obtain additional ownership

0

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Overall Reduction Of Ownership, in Megawatts

340

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Units 2 and 3 [Member]

Loss Contingencies [Line Items]

Public Utilities, Requested Time Period to Recover Retired Units NBV

20 years

20 years

Public Utilities, Number of Mega Watts of Gas-fired Generation

177

Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013

40

Public Utilities, Recovery Percentage of Estimated undepreciated value at 12/31/17

50.00%

Public Utilities, Estimated undepreciated value at 12/31/17

231,000,000

Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17

50.00%

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities, Proposed value per Kilowatt effective January 1, 2018

1,650

Public Utilities, Estimated rate base value at 1/1/2018

221,100,000

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities, Ownership To Be Exchanged, in Megawatts

78

Public Utilities, Proposed reduction in carrying value

26,000,000

Public Utilities,Estimated unrecoverable increase in operations and maintenance

20,000,000

Percentage of ownership held by exiting owners

50.00%

Public Utilities, Ownership Percentage

50.00%

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Minimum [Member] | San Juan Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities,Estimated pre-tax regulatory disallowance

60,000,000

Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities,Estimated pre-tax regulatory disallowance

70,000,000

Clean Air Act, SNCR [Member] | PNMR and PNM [Member] | Palo Verde Nuclear Generating Station Unit 3 [Member]

Loss Contingencies [Line Items]

Public Utilities, Number of Megawatts Nuclear Generation

134

134

Public Utilities, Proposed value per Kilowatt effective January 1, 2018

2,500

Public Utilities, Percentage capacity factor 7-year performance threshold

75.00%

Public Utilities, Period over which to measure capacity performance

7 years

Clean Air Act related to Post-Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member]

Loss Contingencies [Line Items]

Loss Contingency, Estimate of Possible Loss

80,000,000

Public Utilities, Number of Compliance alternatives

2

Public Utilities, Government Standard Emission Limit (pounds per MMBTU, parts per million)

0.015

Public Utilitites, Plant Requirment 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%

Clean Air Act related to Post-Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member]

Loss Contingencies [Line Items]

Public Utilities, Ownership Percentage

13.00%

Mercury Control [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Current Annual Mercury Control Costs

700,000

Mercury Control [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Contingent Estimated Annual Mercury Control Cost

6,600,000

Sierra Club Allegations [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Total Litigation Settlement Cost

10,200,000

Sierra Club Allegations [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Company Share Litigation Settlement Cost

4,500,000

Loss on Long-term Purchase Commitment [Member] | Public Service Company of New Mexico [Member]

Loss Contingencies [Line Items]

Public Utilities, Annual Funding

1,000,000

300,000

3,500,000

Public Utilities, Expected Funding Annual Requirements

600,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SCR [Member] | Public Service Company of New Mexico [Member] | Minimum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Total Capital Cost If Requirement Occurred

824,000,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SCR [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Total Capital Cost If Requirement Occurred

910,000,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Requested Expenditure, Installation Capital Costs

1,900,000

Requested Additional Expenditure, Installation Capital Costs

6,400,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Minimum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Installation Capital Costs

85,000,000

Estimated Portion of Total Capital Costs if Requirement Occured

105,000,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Estimated Installation Capital Costs

90,000,000

Estimated Portion of Total Capital Costs if Requirement Occured

110,000,000

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | Maximum [Member] | San Juan Generating Station Units 1 and 4 [Member]

Loss Contingencies [Line Items]

Estimated Installation Capital Costs

90,600,000

82,000,000

San Juan Underground Mine Fire [Member] | Fuel and purchased power adjustment clause [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station [Member]

Loss Contingencies [Line Items]

Public Utilities, Insurance Recovery

18,700,000

NMTRD Coal Severance Tax [Member] | Four Corners [Member]

Loss Contingencies [Line Items]

Public Utilities, Assessed Coal Severance Surtax Penalty and Interest

30,000,000

NMTRD Coal Severance Tax [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member]

Loss Contingencies [Line Items]

Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC

9.40%

Navajo Nation Allottee Matters [Member] | Public Service Company of New Mexico [Member]

Loss Contingencies [Line Items]

Number of landowners claiming to be Navajo allottees

43

Number of allotment parcels' appraisal requested for review

58

San Juan Generating Station [Member] | National Ambient Air Quality Standards [Member] | Public Service Company of New Mexico [Member]

Loss Contingencies [Line Items]

Public Utilities, Revised SO2 Emissions Agreed Upon

0.1

San Juan Generating Station [Member] | Continuous Highwall Mining [Member]

Loss Contingencies [Line Items]

Public Utilities, Proposed Retroactive Surface Mining Royalty Rate

12.50%

Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003

8.00%

Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change

5,000,000

Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change

46.30%

San Juan Generating Station [Member] | SJCC Arbitration [Member]

Loss Contingencies [Line Items]

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

San Juan Generating Station [Member] | SJCC Arbitration [Member] | Public Service Company of New Mexico [Member]

Loss Contingencies [Line Items]

Public Utilities, PNM Share of arbitration ruling

46.30%

Public Utilities, FFPAC Percentage of mining costs overbilled or unbilled ruled by arbitration

33.00%

Settled Litigation [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Department of energy, spent nuclear fuel removal January 2007 - June 2011 [Member]

Loss Contingencies [Line Items]

Lawsuit settlement, third party receipt

57,400,000

Settled Litigation [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Nuclear Spent Fuel And Waste Disposal [Member]

Loss Contingencies [Line Items]

PNMs share of lawsuit settlement, third party receipt

5,900,000

Subsequent Event [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Public Utilities, Unsubscribed Ownership in Megawatts

65

Subsequent Event [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Public Utilities, Ownership in Megawatts PNM has agreed not to obtain

65

Subsequent Event [Member] | Clean Air Act, SNCR [Member] | PNMR [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Public Utilities, Potential Acquisition of Ownership in Megawatts

65

Subsequent Event [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Clean Air Act, SNCR [Member] | Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]

Loss Contingencies [Line Items]

Requested Expenditure, Installation Capital Costs

$76,600,000

[1]

Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.

Regulatory_and_Rate_Matters_De

Regulatory and Rate Matters (Details) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

4 Months Ended

Dec. 31, 2014

Dec. 31, 2011

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 05, 2012

Oct. 06, 2014

Dec. 31, 2011

Dec. 06, 2012

Jul. 31, 2011

Jun. 30, 2012

Sep. 07, 2014

Mar. 12, 2014

Sep. 16, 2013

Mar. 19, 2013

Dec. 31, 2015

Sep. 15, 2015

Mar. 15, 2015

Jun. 17, 2015

Jan. 31, 2012

Feb. 20, 2015

Feb. 17, 2015

MW

customer

Public Service Company of New Mexico [Member] | 2014 Electric Rate Case [Member]

Rate Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$107,400,000

Public Utilities, Requested Return on Equity, Percentage

10.50%

Public Utilities, Average customer bill increase percentage

7.69%

Public Utilities, Percentage of requested rate increase pertaining to infrastructure investments

92.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member]

Rate Matters [Line Items]

Public Utilites, Additional Renewable Procurements Spending Required by NMPRC

900,000

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

20

20

Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity

45,500,000

Public Utilities, Final Cost of Solar Photovoltaic Capacity

48,900,000

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity, Current Output

4

4

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity, Expected Output

10

10

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Reasonable Cost Threshold

3.00%

3.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Maximum [Member]

Rate Matters [Line Items]

Public Utilities, Reasonable Cost Threshold

3.00%

3.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Wind Energy [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Diversification

30.00%

30.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Solar Energy [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Diversification

20.00%

20.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Renewable Technologies [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Diversification

5.00%

5.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Distributed Generation [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Diversification

1.50%

1.50%

Public Utilities, Future Required Percentage of Diversification

3.00%

3.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2011 [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales

10.00%

10.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2015 [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales

15.00%

15.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard [Member] | Required Percentage by 2020 [Member]

Rate Matters [Line Items]

Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales

20.00%

20.00%

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard Supplemental Procurement [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

2

2

Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity

4,500,000

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard Supplemental Procurement Reduction [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

1.5

1.5

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard Supplemental Procurement Reduction [Member] | Maximum [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

2

2

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard 2014 [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

23

23

Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity

46,700,000

Public Utilities, Wind Capacity Planned Purchase Agreement Term

20 years

Public Utilities, Number of Mega Watts of Wind Energy Capacity

102

Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement

5,800,000

Public Service Company of New Mexico [Member] | Renewable Portfolio Standard 2015 [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

40

40

Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity

79,300,000

Public Utilities, Approved cost per MWh for additional necessary procurements to comply with RPS

4.25

Public Utilities, Approved Revised cost per MWh for additional necessary procurements to comply with RPS

3

Public Utilities, Number of MegaWatt Hours of renewable resources

44,000

Public Utilities, Actual cost per MWh for additional necessary procurements to comply with RPS

1.75

Public Service Company of New Mexico [Member] | 2014 Wind generated Renewable Energy Credits [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watt Hours of Wind Generation

50,000

Public Service Company of New Mexico [Member] | 2015 Wind generated Renewable Energy Credits [Member]

Rate Matters [Line Items]

Public Utilities, Number of Mega Watt Hours of Wind Generation

120,000

Public Service Company of New Mexico [Member] | Renewable Energy Rider [Member]

Rate Matters [Line Items]

Public Utilities, Revenue from Renewable energy rider

34,300,000

23,700,000

6,400,000

Public Service Company of New Mexico [Member] | Renewable Energy Rider [Member] | Maximum [Member]

Rate Matters [Line Items]

Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013

10.50%

Public Utilities, Annual Revenue To be Collected Under 2015 Rider Rate

44,700,000

44,700,000

Public Service Company of New Mexico [Member] | Energy Efficient and Load Management [Member] | Disincentives / Incentives Adder [Member]

Rate Matters [Line Items]

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

Public Utilities, Energy Efficiency Incentive adder collected

1,300,000

Public Service Company of New Mexico [Member] | FPPAC Continuation Application [Member]

Rate Matters [Line Items]

Public Utilities, Retention Percentage of Sales Margins

10.00%

Public Utilities, Under-collected balance write-off

10,500,000

Public Utilities, Under-recovery expected to be collected

63,500,000

63,500,000

Public Service Company of New Mexico [Member] | FPPAC Continuation Application [Member] | Maximum [Member]

Rate Matters [Line Items]

Public Utilities, Fuel Costs to be Collected

36,200,000

38,800,000

Public Service Company of New Mexico [Member] | 2014 Energy Efficiency and Load Management Program [Member] | Disincentives / Incentives Adder [Member]

Rate Matters [Line Items]

Public Utilities, Program Costs Related To Energy Efficiency

25,800,000

Public Utilities, Proposed Profit Incentive Adder Revenues Related To Energy Efficiency Program

2,100,000

Public Utilities, Anticipated future profit incentive 2015

1,700,000

1,700,000

Public Utilities, Anticipated future profit incentive 2016

1,800,000

1,800,000

Public Service Company of New Mexico [Member] | Nmprc Rulemaking on Disincentives to Energy Efficiency Programs [Member]

Rate Matters [Line Items]

Public Utilities, Rate Rider Net Over-Recovery

200,000

Public Utilities, Rate Rider Program Costs Over-Recovery

1,000,000

Public Utilities, Rate Rider Incentives Under-Recovery

800,000

Public Utilities, Rate Rider Estimated Incentives Under-Recovery

500,000

Public Service Company of New Mexico [Member] | 2011 Integrated Resource Plan [Member]

Rate Matters [Line Items]

Public Utilities, Planning Period Covered of IRP

20 years

Public Service Company of New Mexico [Member] | Transmission Rate Case [Member]

Rate Matters [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

11,100,000

Public Utilities, Approved Return on Equity, Percentage

12.25%

Public Utilities, Increase Annual Transmission Service Revenue

2,900,000

Public Service Company of New Mexico [Member] | Wholesale Electric Transmission Rate Case [Member] [Member]

Rate Matters [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

2,900,000

3,200,000

Public Utilities, Approved Return on Equity, Percentage

10.81%

Public Utilities, Lease ownership percentage in EIP

60.00%

Public Utilities, Approved additional rate increase, Amount

500,000

1,300,000

Public Service Company of New Mexico [Member] | Firm Requirements Wholesale Power Rate Case, Navopache [Member] [Member]

Rate Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

8,700,000

Public Utilities, Approved Rate Increase (Decrease), Amount

5,300,000

Public Utilities, Regulatory Rate Increase

39.80%

Public Service Company of New Mexico [Member] | Firm Requirements Wholesale Power Rate Case [Member]

Rate Matters [Line Items]

Public Utilities, Contract Extension

10 years

Public Service Company of New Mexico [Member] | Firm Requirements Wholesale Power Contract, Gallup [Member]

Rate Matters [Line Items]

Public Utilities, Revenue For Power Sold Under Specific Contract

6,100,000

11,700,000

Texas-New Mexico Power Company [Member] | Advanced Meter System Deployment and Surcharge Request [Member]

Rate Matters [Line Items]

Public Utilities, Approved Deployment Costs

113,400,000

Public Utilities, Collection of Deployment Costs Through Surcharge Period

12 years

Public Utilities, Completion Period of Advanced Meter Deployment

5 years

Public Utilities, Non-standard metering service cost total to be borne by opt-out customers

200,000

Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers

500,000

Public Utilities, Non-standard metering ongoing expenses monthly charge

38.99

Public Utilities, Non-standard metering service cost total to be borne by opt-out customers

200,000

200,000

Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers

500,000

500,000

Public Utilities, Non-standard metering ongoing expenses monthly charge

36.78

36.78

Presumed number of customers that will elect non-standard meter service

1,081

1,081

Texas-New Mexico Power Company [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Minimum [Member]

Rate Matters [Line Items]

Public Utilities, Non-standard metering service cost, Proposed initial fee range

142.84

Public Utilities, Non-standard metering service cost initial fee range

63.97

63.97

Texas-New Mexico Power Company [Member] | Advanced Meter System Deployment and Surcharge Request [Member] | Maximum [Member]

Rate Matters [Line Items]

Public Utilities, Non-standard metering service cost, Proposed initial fee range

247.48

Public Utilities, Non-standard metering service cost initial fee range

168.61

168.61

Texas-New Mexico Power Company [Member] | Ercot Transmission Rates [Member]

Rate Matters [Line Items]

Public Utilities, Eliminated Recovery of Adder Revenue

1,600,000

Public Utilities, Additional Transmission Costs Requested

3,200,000

Texas-New Mexico Power Company [Member] | Ercot Transmission Rates [Member] | PUCT staff agreed to interim rate relief that will permit TNMP to add uncontested costs to its existing TCRF [Member]

Rate Matters [Line Items]

Public Utilities, Approved Additional Transmission Costs

1,600,000

Texas-New Mexico Power Company [Member] | Energy Efficiency [Member]

Rate Matters [Line Items]

Public Utilities, Approved Program Implementation Costs

5,600,000

5,200,000

3,400,000

Public Utilities, Approved Program Implementation Costs, Bonus

1,500,000

300,000

Public Utilities, Unapproved 2015 Program Implementation Costs, Bonus

700,000

700,000

1,500,000

Public Utilities, Unapproved 2015 Program Implementation Costs

5,700,000

5,700,000

Texas-New Mexico Power Company [Member] | Transmission Cost of Service Rates [Member]

Rate Matters [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

18,200,000

18,100,000

21,900,000

26,400,000

Public Utilities, Increase Annual Transmission Service Revenue

2,900,000

2,800,000

2,900,000

2,500,000

Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Advanced Meter System Deployment and Surcharge Request [Member]

Rate Matters [Line Items]

Current number of customers that have elected non-standard meter service

89

Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Energy Efficiency [Member]

Rate Matters [Line Items]

Public Utilities, Approved Program Implementation Costs

5,700,000

Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Transmission Cost of Service Rates [Member]

Rate Matters [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

27,100,000

Public Utilities, Approved Rate Increase (Decrease), Amount

25,200,000

Public Utilities, Increase Annual Transmission Service Revenue

4,200,000

Public Utilities, Requested Increase Annual Transmission Service Revenue

$4,400,000

Four Corners [Member] | Public Service Company of New Mexico [Member] | Subsequent Event [Member]

Rate Matters [Line Items]

Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities

7.00%

Period of time to file a waiver of rights of first refusal

120 days

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$86,871	$92,597	$99,986
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	28,349	28,937	29,110
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	524	562	595
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	31	7	15
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	77,433	63,114
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	1,951
Income tax sharing payments [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	3,643	0
Interest charges [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	309	481	137
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$65	$4	$1

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	($58,140)	($81,630)	($66,856)
Amounts reclassified from AOCI (pre-tax)	-8,152	-5,385	-32,476
Income tax impact of amounts reclassified	3,234	2,137	12,865
Other OCI changes (pre-tax)	2,038	44,276	8,036
Income tax impact of other OCI changes	-735	-17,538	-3,199
Total Other Comprehensive Income (Loss)	-3,615	23,490	-14,774
Ending Balance	-61,755	-58,140	-81,630
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process	24.40%	18.70%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts	2.00%	3.00%
Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-57,877	-81,414	-66,798
Amounts reclassified from AOCI (pre-tax)	-8,710	-5,592	-32,658
Income tax impact of amounts reclassified	3,429	2,210	12,930
Other OCI changes (pre-tax)	2,191	44,555	8,464
Income tax impact of other OCI changes	-788	-17,636	-3,352
Total Other Comprehensive Income (Loss)	-3,878	23,537	-14,616
Ending Balance	-61,755	-57,877	-81,414
Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-263	-216	-58
Amounts reclassified from AOCI (pre-tax)	558	207	182
Income tax impact of amounts reclassified	-195	-73	-65
Other OCI changes (pre-tax)	-153	-279	-428
Income tax impact of other OCI changes	53	98	153
Total Other Comprehensive Income (Loss)	263	-47	-158
Ending Balance	0	-263	-216
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	25,748	16,406	15,634
Amounts reclassified from AOCI (pre-tax)	-13,862	-11,956	-37,269
Income tax impact of amounts reclassified	5,461	4,734	14,755
Other OCI changes (pre-tax)	17,473	27,419	38,548
Income tax impact of other OCI changes	-6,812	-10,855	-15,262
Total Other Comprehensive Income (Loss)	2,260	9,342	772
Ending Balance	28,008	25,748	16,406
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	25,748	16,406	15,634
Amounts reclassified from AOCI (pre-tax)	-13,862	-11,956	-37,269
Income tax impact of amounts reclassified	5,461	4,734	14,755
Other OCI changes (pre-tax)	17,473	27,419	38,548
Income tax impact of other OCI changes	-6,812	-10,855	-15,262
Total Other Comprehensive Income (Loss)	2,260	9,342	772
Ending Balance	28,008	25,748	16,406
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	0	0	0
Amounts reclassified from AOCI (pre-tax)	0	0	0
Income tax impact of amounts reclassified	0	0	0
Other OCI changes (pre-tax)	0	0	0
Income tax impact of other OCI changes	0	0	0
Total Other Comprehensive Income (Loss)	0	0	0
Ending Balance	0	0	0
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-83,625	-97,820	-82,432
Amounts reclassified from AOCI (pre-tax)	5,152	6,364	4,611
Income tax impact of amounts reclassified	-2,032	-2,524	-1,825
Other OCI changes (pre-tax)	-15,282	17,136	-30,084
Income tax impact of other OCI changes	6,024	-6,781	11,910
Total Other Comprehensive Income (Loss)	-6,138	14,195	-15,388
Ending Balance	-89,763	-83,625	-97,820
Accumulated Defined Benefit Plans Adjustment [Member] | Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-83,625	-97,820	-82,432
Amounts reclassified from AOCI (pre-tax)	5,152	6,364	4,611
Income tax impact of amounts reclassified	-2,032	-2,524	-1,825
Other OCI changes (pre-tax)	-15,282	17,136	-30,084
Income tax impact of other OCI changes	6,024	-6,781	11,910
Total Other Comprehensive Income (Loss)	-6,138	14,195	-15,388
Ending Balance	-89,763	-83,625	-97,820
Accumulated Defined Benefit Plans Adjustment [Member] | Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	0	0	0
Amounts reclassified from AOCI (pre-tax)	0	0	0
Income tax impact of amounts reclassified	0	0	0
Other OCI changes (pre-tax)	0	0	0
Income tax impact of other OCI changes	0	0	0
Total Other Comprehensive Income (Loss)	0	0	0
Ending Balance	0	0	0
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-263	-216	-58
Amounts reclassified from AOCI (pre-tax)	558	207	182
Income tax impact of amounts reclassified	-195	-73	-65
Other OCI changes (pre-tax)	-153	-279	-428
Income tax impact of other OCI changes	53	98	153
Total Other Comprehensive Income (Loss)	263	-47	-158
Ending Balance	0	-263	-216
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Public Service Company of New Mexico [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	0	0	0
Amounts reclassified from AOCI (pre-tax)	0	0	0
Income tax impact of amounts reclassified	0	0	0
Other OCI changes (pre-tax)	0	0	0
Income tax impact of other OCI changes	0	0	0
Total Other Comprehensive Income (Loss)	0	0	0
Ending Balance	0	0	0
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Texas-New Mexico Power Company [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-263	-216	-58
Amounts reclassified from AOCI (pre-tax)	558	207	182
Income tax impact of amounts reclassified	-195	-73	-65
Other OCI changes (pre-tax)	-153	-279	-428
Income tax impact of other OCI changes	53	98	153
Total Other Comprehensive Income (Loss)	263	-47	-158
Ending Balance	$0	($263)	($216)

Goodwill_Impairments_Details

Goodwill; Impairments (Details) (USD $)	12 Months Ended
	Dec. 31, 2008	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 01, 2014	Apr. 01, 2013	Apr. 01, 2012
Schedule of Goodwill and Other Intangible Assets [Line Items]
Goodwill		$278,297,000	$278,297,000	$278,297,000
Goodwill, Impairment Loss	174,400,000
Public Service Company of New Mexico [Member]
Schedule of Goodwill and Other Intangible Assets [Line Items]
Goodwill		51,600,000	51,600,000
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount					30.00%	27.00%
Goodwill, Reporting Unit, Sensitivity analysis, Percentage Increase in Expected Return on Equity					0.50%
Goodwill, Reporting Unit, Sensitivity analysis, Reduced Percentage of Fair Value in Excess of Carrying Value					23.00%	20.00%
Goodwill, Impairment Loss	51,100,000
Texas-New Mexico Power Company [Member]
Schedule of Goodwill and Other Intangible Assets [Line Items]
Goodwill		226,700,000	226,700,000
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount							26.00%
Goodwill, Impairment Loss	$34,500,000

Quarterly_Operating_Results_Un2

Quarterly Operating Results (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$346,845	$413,951	$346,160	$328,897	$322,929	$399,730	$347,599	$317,665	$1,435,853	$1,387,923	$1,342,403
Operating income	62,849	116,799	71,296	48,753	40,532	117,739	77,867	50,704	299,697	286,842	273,721
Net earnings	22,111	59,486	33,181	16,131	11,397	58,814	31,383	13,962	130,909	115,556	120,125
Earnings Attributable to PNMR	18,992	55,653	29,141	12,468	7,648	54,555	27,678	10,626	116,254	100,507	105,547
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$0.24	$0.70	$0.37	$0.16	$0.10	$0.68	$0.35	$0.13	$1.46	$1.26	$1.32
Diluted (dollars per share)	$0.24	$0.69	$0.36	$0.16	$0.10	$0.68	$0.34	$0.13	$1.45	$1.25	$1.31
Public Service Company of New Mexico [Member]
Segment Reporting Information [Line Items]
Operating revenues	274,481	334,993	275,704	262,736	252,702	326,026	279,690	257,894
Operating income	40,988	90,615	49,806	31,304	18,427	95,217	58,302	37,239
Net earnings	16,942	49,052	24,254	11,205	6,256	51,950	29,697	14,773
Earnings Attributable to PNMR	13,955	45,351	20,346	7,674	2,639	47,823	26,124	11,569
Texas-New Mexico Power Company [Member]
Segment Reporting Information [Line Items]
Operating income	21,188	25,873	21,265	17,262	17,210	22,254	19,667	13,054
Earnings Attributable to PNMR	9,115	12,355	9,534	6,803	6,919	10,106	8,339	3,726
Electric Domestic Regulated Revenue	$72,364	$78,958	$70,456	$66,161	$70,227	$73,704	$67,909	$59,771

Schedule_I_Condensed_Financial2

Schedule I - Condensed Financial Information of Parent Company (Statements of Earnings) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Operating Expenses									$1,136,156	$1,101,081	$1,068,682
Operating income	62,849	116,799	71,296	48,753	40,532	117,739	77,867	50,704	299,697	286,842	273,721
Other Income and Deductions:
Other income									12,048	10,572	12,746
Other (deductions)									-10,481	-21,552	-17,636
Net other income and deductions									20,577	9,675	22,159
Earnings before Income Taxes									200,647	175,069	175,035
Income Taxes									69,738	59,513	54,910
Net Earnings Attributable to Company	18,992	55,653	29,141	12,468	7,648	54,555	27,678	10,626	116,254	100,507	105,547
PNM Resources [Member]
Condensed Financial Statements, Captions [Line Items]
Non-affiliates									0	0	0
Operating Expenses									650	941	3,287
Operating income									-650	-941	-3,287
Other Income and Deductions:
Equity in earnings of subsidiaries									124,543	116,634	117,900
Other income									622	769	670
Other (deductions)									-13,650	-22,825	-20,904
Net other income and deductions									111,515	94,578	97,666
Earnings before Income Taxes									110,865	93,637	94,379
Income Taxes									-5,389	-6,870	-11,168
Net Earnings Attributable to Company									$116,254	$100,507	$105,547

Schedule_I_Condensed_Financial3

Schedule I - Condensed Financial Information of Parent Company (Statement of Cash flow) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows From Operating Activities:
Net earnings (loss)	$116,254	$100,507	$105,547
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	209,867	208,173	206,499
Deferred income tax expense	72,481	60,430	56,243
Loss on reacquired debt	0	3,253	0
Stock based compensation expense	5,931	5,320	3,585
Changes in certain assets and liabilities:
Other current assets	-30,436	8,577	-2,598
Other assets	290	-12,801	-30,778
Accounts payable	-2,311	4,484	14,020
Accrued interest and taxes	2,040	91,537	255
Other current liabilities	-2,453	-19,648	-19,905
Other liabilities	45,516	-61,262	-70,743
Net cash flows from operating activities	414,876	386,587	281,349
Cash Flows From Investing Activities:
Utility plant additions	-460,658	-348,039	-308,909
Net cash flows from investing activities	-485,329	-331,446	-285,895
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	-43,600	-9,500	-24,000
Repayment of long-term debt	-125,000	-29,468	-22,387
Proceeds from stock option exercise	6,999	4,618	11,684
Dividends paid	-59,468	-51,508	-45,137
Other, net	-2,808	-5,545	-922
Net cash flows from financing activities	96,194	-61,593	-1,560
Change in Cash and Cash Equivalents	25,741	-6,452	-6,106
Cash and Cash Equivalents at Beginning of Year	2,533	8,985	15,091
Cash and Cash Equivalents at End of Year	28,274	2,533	8,985
Supplemental Cash Flow Disclosures:
Interest paid	108,741	110,768	113,265
Income taxes paid (refunded), net	-2,597	-95,327	5,302
PNM Resources [Member]
Cash Flows From Operating Activities:
Net earnings (loss)	116,254	100,507	105,547
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	680	4,192	5,000
Deferred income tax expense	-69,442	-51,820	-46,632
Equity in (earnings) loss of subsidiaries	-124,543	-116,634	-117,900
Loss on reacquired debt	0	3,253	0
Stock based compensation expense	5,931	5,320	3,585
Changes in certain assets and liabilities:
Other current assets	22,955	28,460	-43,638
Other assets	51,644	46,558	34,096
Accounts payable	-88	620	8
Accrued interest and taxes	-7,683	-9,266	-28,855
Other current liabilities	-1,668	-146	3,876
Other liabilities	28,704	-27,756	-29,601
Net cash flows from operating activities	22,744	-16,712	-114,514
Cash Flows From Investing Activities:
Utility plant additions	-474	-960	-7,524
Investments in subsidiaries	0	-13,800	0
Cash dividends from subsidiaries	46,599	158,772	61,406
Net cash flows from investing activities	46,125	144,012	53,882
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	600	-37,600	120,900
Repayment of long-term debt	0	-29,468	-2,387
Proceeds from stock option exercise	6,999	4,618	11,684
Purchases to satisfy awards of common stock	-17,319	-13,807	-25,168
Dividends paid	-58,940	-50,980	-44,609
Other, net	81	0	0
Net cash flows from financing activities	-68,579	-127,237	60,420
Change in Cash and Cash Equivalents	290	63	-212
Cash and Cash Equivalents at Beginning of Year	92	29	241
Cash and Cash Equivalents at End of Year	382	92	29
Supplemental Cash Flow Disclosures:
Interest paid	12,152	14,510	15,007
Income taxes paid (refunded), net	($2,014)	$22,378	$1,501

Schedule_I_Condensed_Financial4

Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Assets
Cash and cash equivalents	$28,274	$2,533	$8,985	$15,091
Income taxes receivable	6,360	7,066
Other, net	58,471	34,590
Total current assets	432,817	401,539
Property, plant and equipment, net of accumulated depreciation of $10,251 and $9,167	4,270,006	3,933,911
Other long-term assets	1,762	1,835
Total Assets	5,829,325	5,500,210	5,372,583
Liabilities and Stockholdersb Equity
Short-term debt	105,600	149,200
Current maturities of long-term debt	333,066	75,000
Accrued interest and taxes	53,863	49,600
Other current liabilities	70,194	77,105
Total current liabilities	704,282	492,671
Long-term Debt	1,642,024	1,670,420
Total liabilities	4,022,704	3,738,083
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,173,845	1,178,369
Accumulated other comprehensive income (loss), net of tax	-61,755	-58,140	-81,630	-66,856
Retained earnings	609,456	553,340
Total PNMR common stockholdersb equity	1,721,546	1,673,569
Total liabilities and stockholders' equity	5,829,325	5,500,210
PNM Resources [Member]
Assets
Cash and cash equivalents	382	92	29	241
Intercompany receivables	107,619	136,387
Income taxes receivable	29	14,989
Other, net	8,115	8,544
Total current assets	116,145	160,012
Property, plant and equipment, net of accumulated depreciation of $10,251 and $9,167	27,076	26,601
Investment in subsidiaries	1,757,650	1,683,321
Other long-term assets	70,939	53,892
Total long-term assets	1,855,665	1,763,814
Total Assets	1,971,810	1,923,826
Liabilities and Stockholdersb Equity
Short-term debt	100,600	100,000
Short-term debt-affiliate	8,819	8,819
Current maturities of long-term debt	118,766	0
Accrued interest and taxes	2,816	2,797
Other current liabilities	16,320	16,876
Total current liabilities	247,321	128,492
Long-term Debt	0	118,766
Other long-term liabilities	2,943	2,999
Total liabilities	250,264	250,257
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,173,845	1,178,369
Accumulated other comprehensive income (loss), net of tax	-61,755	-58,140
Retained earnings	609,456	553,340
Total PNMR common stockholdersb equity	1,721,546	1,673,569
Total liabilities and stockholders' equity	$1,971,810	$1,923,826

Schedule_I_Condensed_Financial5

Schedule I - Condensed Financial Information of Parent Company (Parenthetical) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Condensed Financial Statements, Captions [Line Items]
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
PNM Resources [Member]
Condensed Financial Statements, Captions [Line Items]
Accumulated Depreciation	$10,251	$9,167
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

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year	$1,423	$1,751	$1,778
Charged to costs and expenses	3,267	2,849	3,367
Charged to other accounts	0	0	0
Write-offs and other	3,224	3,177	3,394
Balance at end of year	1,466	1,423	1,751
Public Service Company of New Mexico [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year	1,423	1,751	1,778
Charged to costs and expenses	3,275	2,864	3,384
Charged to other accounts	0	0	0
Write-offs and other	3,232	3,192	3,411
Balance at end of year	1,466	1,423	1,751
Texas-New Mexico Power Company [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at beginning of year	0	0	0
Charged to costs and expenses	-8	-15	-17
Charged to other accounts	0	0	0
Write-offs and other	-8	-15	-17
Balance at end of year	$0	$0	$0