Public Service Company of New Mexico PFD 4.58% (PNMXO) 10-Q 1 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 24, 2015
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-Q
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		79,653,624
Public Service Company of New Mexico [Member]
Document Information [Line Items]
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Central Index Key	81023
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,117,799
Texas-New Mexico Power Company [Member]
Document Information [Line Items]
Entity Registrant Name	TEXAS NEW MEXICO POWER CO
Entity Central Index Key	22767
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		6,358

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Earnings (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Electric Operating Revenues	$332,868	$328,897
Operating Expenses:
Cost of energy	115,645	112,614
Administrative and general	43,859	43,859
Energy production costs	42,669	47,288
Regulatory disallowances	215	0
Depreciation and amortization	45,461	41,965
Transmission and distribution costs	16,487	16,906
Taxes other than income taxes	18,963	17,512
Total operating expenses	283,299	280,144
Operating income	49,569	48,753
Other Income and Deductions:
Interest income	1,750	2,117
Gains on available-for-sale securities	4,024	2,573
Other income	4,961	1,574
Other (deductions)	-3,662	-2,931
Net other income and deductions	7,073	3,333
Interest Charges	30,273	29,535
Earnings before Income Taxes	26,369	22,551
Income Taxes	8,517	6,420
Net Earnings	17,852	16,131
(Earnings) Attributable to Valencia Non-controlling Interest	-3,380	-3,531
Preferred Stock Dividend Requirements of Subsidiary	-132	-132
Net Earnings Attributable to PNMR	14,340	12,468
Net Earnings Available for PNM Common Stock	14,340	12,468
Net Earnings Attributable to PNMR per Common Share:
Basic (dollars per share)	$0.18	$0.16
Diluted (dollars per share)	$0.18	$0.16
Dividends Declared per Common Share (dollars per share)	$0.20	$0.19
Public Service Company of New Mexico [Member]
Electric Operating Revenues	261,940	262,736
Operating Expenses:
Cost of energy	97,866	96,626
Administrative and general	39,567	38,609
Energy production costs	42,669	47,288
Regulatory disallowances	215	0
Depreciation and amortization	28,403	27,082
Transmission and distribution costs	10,769	11,327
Taxes other than income taxes	10,796	10,500
Total operating expenses	230,285	231,432
Operating income	31,655	31,304
Other Income and Deductions:
Interest income	1,771	2,128
Gains on available-for-sale securities	4,024	2,573
Other income	3,392	1,113
Other (deductions)	-1,606	-2,018
Net other income and deductions	7,581	3,796
Interest Charges	19,959	19,812
Earnings before Income Taxes	19,277	15,288
Income Taxes	5,775	4,083
Net Earnings	13,502	11,205
(Earnings) Attributable to Valencia Non-controlling Interest	-3,380	-3,531
Preferred Stock Dividend Requirements of Subsidiary	-132	-132
Net Earnings Attributable to PNMR	10,122	7,674
Net Earnings Available for PNM Common Stock	9,990	7,542
Texas-New Mexico Power Company [Member]
Electric Operating Revenues	70,928	66,161
Operating Expenses:
Cost of energy	17,779	15,988
Administrative and general	9,833	9,840
Depreciation and amortization	13,458	11,842
Transmission and distribution costs	5,718	5,579
Taxes other than income taxes	6,209	5,650
Total operating expenses	52,997	48,899
Operating income	17,931	17,262
Other Income and Deductions:
Interest income	0	0
Other income	1,540	420
Other (deductions)	-249	-231
Net other income and deductions	1,291	189
Interest Charges	6,925	6,598
Earnings before Income Taxes	12,297	10,853
Income Taxes	4,603	4,050
Net Earnings	7,694	6,803
(Earnings) Attributable to Valencia Non-controlling Interest	0	0
Preferred Stock Dividend Requirements of Subsidiary	0	0
Net Earnings Attributable to PNMR	7,694	6,803
Net Earnings Available for PNM Common Stock	$7,694	$6,803

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Net Earnings	$17,852	$16,131
Net earnings	14,340	12,468
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	4,157	2,047
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	-2,537	-1,972
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	905	780
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	-100
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	0	36
Net change after income taxes	2,525	791
Comprehensive Income	20,377	16,922
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-3,380	-3,531
Preferred Stock Dividend Requirements of Subsidiary	-132	-132
Comprehensive Income Attributable to PNMR	16,865	13,259
Public Service Company of New Mexico [Member]
Net Earnings	13,502	11,205
Net earnings	10,122	7,674
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	4,157	2,047
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	-2,537	-1,972
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit)	905	780
Fair Value Adjustment for Cash Flow Hedges:
Net change after income taxes	2,525	855
Comprehensive Income	16,027	12,060
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-3,380	-3,531
Comprehensive Income Attributable to PNMR	12,647	8,529
Texas-New Mexico Power Company [Member]
Net Earnings	7,694	6,803
Net earnings	7,694	6,803
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	-100
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	0	36
Net change after income taxes	0	-64
Comprehensive Income Attributable to PNMR	$7,694	$6,739

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Unrealized holding gains (losses) arising during the period, income tax (expense)	($2,679)	($1,332)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,635	1,283
Pension liability adjustment, income tax (expense) benefit	-583	-508
Change in fair market value, income tax (expense)	0	53
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	0	-19
Public Service Company of New Mexico [Member]
Unrealized holding gains (losses) arising during the period, income tax (expense)	-2,679	-1,332
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	1,635	1,283
Pension liability adjustment, income tax (expense) benefit	-583	-508
Texas-New Mexico Power Company [Member]
Change in fair market value, income tax (expense)	0	53
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$0	($19)

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash Flows From Operating Activities:
Net Earnings	$17,852	$16,131
Net earnings	14,340	12,468
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	55,062	51,949
Deferred income tax expense	8,326	6,276
Net unrealized (gains) losses on commodity derivatives	1,720	2,761
Realized (gains) on available-for-sale securities	-4,024	-2,573
Stock based compensation expense	2,214	2,131
Regulatory disallowances	215	0
Other, net	148	1,005
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	12,170	17,207
Materials, supplies, and fuel stock	-2,657	5,894
Other current assets	3,817	8,344
Other assets	4,220	6,386
Accounts payable	-2,639	-34,373
Accrued interest and taxes	24,811	25,813
Other current liabilities	-21,223	-30,359
Other liabilities	-33,278	-199
Net cash flows from operating activities	66,734	76,393
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-100,214	-83,838
Proceeds from sales of available-for-sale securities	31,852	22,804
Purchases of available-for-sale securities	-32,661	-23,612
Return of principal on PVNGS lessor notes	14,188	10,231
Other, net	144	13
Net cash flows from investing activities	-86,691	-74,402
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	-5,600	-49,200
Long-term borrowings	150,000	175,000
Repayment of long-term debt	0	-75,000
Proceeds from stock option exercise	6,847	3,258
Awards of common stock	-17,140	-11,639
Dividends paid	-16,063	-14,868
Valencia’s transactions with its owner	-4,160	-4,369
Other, net	194	-539
Net cash flows from financing activities	114,078	22,643
Change in Cash and Cash Equivalents	94,121	24,634
Cash and Cash Equivalents at Beginning of Period	28,274	2,533
Cash and Cash Equivalents at End of Period	122,395	27,167
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	6,191	4,718
Income taxes paid (refunded), net	-1,450	-1,419
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	5,186	-13,095
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net Earnings	13,502	11,205
Net earnings	10,122	7,674
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	37,470	35,950
Deferred income tax expense	5,908	4,185
Net unrealized (gains) losses on commodity derivatives	1,720	2,761
Realized (gains) on available-for-sale securities	-4,024	-2,573
Regulatory disallowances	215	0
Other, net	-974	1,042
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	12,385	15,018
Materials, supplies, and fuel stock	-2,558	5,974
Other current assets	5,110	6,809
Other assets	4,479	6,042
Accounts payable	4,622	-31,847
Accrued interest and taxes	22,832	22,362
Other current liabilities	-18,836	-29,609
Other liabilities	-30,178	-806
Net cash flows from operating activities	51,673	46,513
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-81,988	-51,594
Proceeds from sales of available-for-sale securities	31,852	22,804
Purchases of available-for-sale securities	-32,661	-23,612
Return of principal on PVNGS lessor notes	14,188	10,231
Other, net	144	-1
Net cash flows from investing activities	-68,465	-42,172
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	0	-49,200
Short-term borrowings (repayments), affiliate, net	0	-32,500
Long-term borrowings	0	175,000
Repayment of long-term debt	0	-75,000
Dividends paid	-132	-132
Valencia’s transactions with its owner	-4,160	-4,369
Other, net	-144	-409
Net cash flows from financing activities	-4,436	13,390
Change in Cash and Cash Equivalents	-21,228	17,731
Cash and Cash Equivalents at Beginning of Period	25,480	21
Cash and Cash Equivalents at End of Period	4,252	17,752
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	4,287	4,222
Income taxes paid (refunded), net	-1,450	-215
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	7,421	-8,133
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net Earnings	7,694	6,803
Net earnings	7,694	6,803
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	13,831	12,851
Deferred income tax expense	4,170	3,665
Other, net	0	-36
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	-215	2,189
Materials, supplies, and fuel stock	-99	-81
Other current assets	981	2,446
Other assets	-139	302
Accounts payable	-7,640	-2,551
Accrued interest and taxes	-2,006	335
Other current liabilities	368	-1,768
Other liabilities	-3,631	1,465
Net cash flows from operating activities	13,314	25,620
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	-13,763	-27,420
Net cash flows from investing activities	-13,763	-27,420
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	-5,000	0
Short-term borrowings (repayments), affiliate, net	5,800	1,800
Net cash flows from financing activities	800	1,800
Change in Cash and Cash Equivalents	351	0
Cash and Cash Equivalents at Beginning of Period	1	1
Cash and Cash Equivalents at End of Period	352	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	1,664	73
Income taxes paid (refunded), net	0	-1,204
Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	($2,537)	($1,109)

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current Assets:
Cash and cash equivalents	$122,395	$28,274
Accounts receivable, net of allowance for uncollectible accounts	89,844	87,038
Unbilled revenues	48,042	63,719
Other receivables	37,898	39,857
Materials, supplies, and fuel stock	66,284	63,628
Regulatory assets	33,550	47,855
Commodity derivative instruments	9,342	11,232
Income taxes receivable	4,719	6,360
Current portion of accumulated deferred income taxes	26,383	26,383
Other current assets	65,264	58,471
Total current assets	503,721	432,817
Other Property and Investments:
Investment in PVNGS lessor notes	0	9,538
Available-for-sale securities	257,464	250,145
Other investments	509	1,762
Non-utility property	3,406	3,406
Total other property and investments	261,379	264,851
Utility Plant:
Plant in service and plant held for future use	5,982,387	5,941,581
Less accumulated depreciation and amortization	1,971,832	1,939,760
Net plant in service and plant held for future use	4,010,555	4,001,821
Construction work in progress	230,014	190,389
Nuclear fuel, net of accumulated amortization	79,208	77,796
Net utility plant	4,319,777	4,270,006
Deferred Charges and Other Assets:
Regulatory assets	481,057	491,007
Goodwill	278,297	278,297
Other deferred charges	95,108	92,347
Total deferred charges and other assets	854,462	861,651
Total assets	5,939,339	5,829,325
Current Liabilities:
Short-term debt	100,000	105,600
Current installments of long-term debt	333,066	333,066
Accounts payable	102,204	110,029
Customer deposits	12,791	12,555
Accrued interest and taxes	77,234	53,863
Regulatory liabilities	178	1,703
Commodity derivative instruments	1,235	1,209
Dividends declared	16,063	16,063
Other current liabilities	50,263	70,194
Total current liabilities	693,034	704,282
Long-term Debt	1,791,941	1,642,024
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	902,901	891,111
Regulatory liabilities	470,180	466,143
Asset retirement obligations	106,267	104,170
Accrued pension liability and postretirement benefit cost	75,236	110,738
Commodity derivative instruments	277	477
Other deferred credits	100,816	103,759
Total deferred credits and other liabilities	1,655,677	1,676,398
Total liabilities	4,140,652	4,022,704
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	11,529	11,529
Company common stockholders’ equity:
Common stock outstanding	1,165,757	1,173,845
Accumulated other comprehensive income (loss), net of income taxes	-59,230	-61,755
Retained earnings	607,865	609,456
Total Company common stockholders' equity	1,714,392	1,721,546
Non-controlling interest in Valencia	72,766	73,546
Total equity	1,787,158	1,795,092
Total liabilities and stockholders' equity	5,939,339	5,829,325
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	4,252	25,480
Accounts receivable, net of allowance for uncollectible accounts	67,420	67,622
Unbilled revenues	41,255	54,140
Other receivables	33,636	37,622
Affiliate receivables	8,819	8,853
Materials, supplies, and fuel stock	63,416	60,859
Regulatory assets	29,932	43,980
Commodity derivative instruments	9,342	11,232
Income taxes receivable	4,788	6,105
Current portion of accumulated deferred income taxes	12,418	12,418
Other current assets	60,399	53,095
Total current assets	335,677	381,406
Other Property and Investments:
Investment in PVNGS lessor notes	0	9,538
Available-for-sale securities	257,464	250,145
Other investments	267	397
Non-utility property	96	96
Total other property and investments	257,827	260,176
Utility Plant:
Plant in service and plant held for future use	4,614,218	4,581,066
Less accumulated depreciation and amortization	1,506,576	1,486,406
Net plant in service and plant held for future use	3,107,642	3,094,660
Construction work in progress	199,367	169,673
Nuclear fuel, net of accumulated amortization	79,208	77,796
Net utility plant	3,386,217	3,342,129
Deferred Charges and Other Assets:
Regulatory assets	349,295	357,045
Goodwill	51,632	51,632
Other deferred charges	83,839	81,264
Total deferred charges and other assets	484,766	489,941
Total assets	4,464,487	4,473,652
Current Liabilities:
Current installments of long-term debt	214,300	214,300
Accounts payable	83,257	86,055
Affiliate payables	15,812	18,232
Customer deposits	12,791	12,555
Accrued interest and taxes	51,015	29,298
Regulatory liabilities	178	1,703
Commodity derivative instruments	1,235	1,209
Dividends declared	132	132
Other current liabilities	36,923	52,053
Total current liabilities	415,643	415,537
Long-term Debt	1,276,366	1,276,357
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	725,130	715,814
Regulatory liabilities	429,698	425,481
Asset retirement obligations	105,258	103,182
Accrued pension liability and postretirement benefit cost	67,706	102,850
Commodity derivative instruments	277	477
Other deferred credits	84,743	86,023
Total deferred credits and other liabilities	1,412,812	1,433,827
Total liabilities	3,104,821	3,125,721
Commitments and Contingencies (See Note 11)
Cumulative preferred stock of subsidiary without mandatory redemption requirements	11,529	11,529
Company common stockholders’ equity:
Common stock outstanding	1,061,776	1,061,776
Accumulated other comprehensive income (loss), net of income taxes	-59,230	-61,755
Retained earnings	272,825	262,835
Total Company common stockholders' equity	1,275,371	1,262,856
Non-controlling interest in Valencia	72,766	73,546
Total equity	1,348,137	1,336,402
Total liabilities and stockholders' equity	4,464,487	4,473,652
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	352	1
Accounts receivable, net of allowance for uncollectible accounts	22,424	19,416
Unbilled revenues	6,787	9,579
Other receivables	1,220	2,063
Materials, supplies, and fuel stock	2,868	2,769
Regulatory assets	3,618	3,875
Current portion of accumulated deferred income taxes	6,398	6,398
Other current assets	1,057	938
Total current assets	44,724	45,039
Other Property and Investments:
Other investments	242	242
Non-utility property	2,240	2,240
Total other property and investments	2,482	2,482
Utility Plant:
Plant in service and plant held for future use	1,188,967	1,182,112
Less accumulated depreciation and amortization	383,711	375,407
Net plant in service and plant held for future use	805,256	806,705
Construction work in progress	23,427	16,538
Net utility plant	828,683	823,243
Deferred Charges and Other Assets:
Regulatory assets	131,762	133,962
Goodwill	226,665	226,665
Other deferred charges	9,094	8,850
Total deferred charges and other assets	367,521	369,477
Total assets	1,243,410	1,240,241
Current Liabilities:
Short-term debt	0	5,000
Short-term debt – affiliate	28,500	22,700
Accounts payable	9,101	14,203
Affiliate payables	2,120	2,469
Accrued interest and taxes	26,568	28,574
Other current liabilities	2,986	2,271
Total current liabilities	69,275	75,217
Long-term Debt	365,575	365,667
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	222,171	217,945
Regulatory liabilities	40,482	40,662
Asset retirement obligations	866	848
Accrued pension liability and postretirement benefit cost	7,530	7,888
Other deferred credits	5,152	7,349
Total deferred credits and other liabilities	276,201	274,692
Total liabilities	711,051	715,576
Commitments and Contingencies (See Note 11)
Company common stockholders’ equity:
Common stock outstanding	64	64
Paid-in-capital	404,166	404,166
Retained earnings	128,129	120,435
Total Company common stockholders' equity	532,359	524,665
Total liabilities and stockholders' equity	$1,243,410	$1,240,241

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, except Share data, unless otherwise specified
Allowance for uncollectible accounts	$1,466	$1,466
Accumulated depreciation, nuclear fuel	51,203	44,507
Cumulative preferred stock of subsidiary, stated value	$100	$100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares authorized	115,293	115,293
Common stock, par value	$0	$0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	79,653,624	79,653,624
Common stock, shares outstanding	79,653,624	79,653,624
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,466	1,466
Accumulated depreciation, nuclear fuel	$51,203	$44,507
Cumulative preferred stock, stated value	$100	$100
Cumulative preferred stock, shares authorized	10,000,000	10,000,000
Cumulative preferred stock, shares issued	115,293	115,293
Cumulative preferred stock, shares outstanding	115,293	115,293
Common stock, par value	$0	$0
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	39,117,799	39,117,799
Common stock, shares outstanding	39,117,799	39,117,799
Texas-New Mexico Power Company [Member]
Common stock, par value	$10	$10
Common stock, shares authorized	12,000,000	12,000,000
Common stock, shares issued	6,358	6,358
Common stock, shares outstanding	6,358	6,358

Condensed_Consolidated_Stateme4

Condensed Consolidated Statement of Changes in Equity (USD $)	Total	Parent [Member]	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Non-controlling Interest in Valencia [Member]	Public Service Company of New Mexico [Member]	Public Service Company of New Mexico [Member]	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]
In Thousands, unless otherwise specified								Parent [Member]	Common Stock [Member]	AOCI [Member]	Retained Earnings [Member]	Non-controlling Interest in Valencia [Member]		Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]
Balance TNMP at Dec. 31, 2014	$1,721,546						$1,262,856						$524,665	$64	$404,166	$120,435
Balance at Dec. 31, 2014	1,795,092	1,721,546	1,173,845	-61,755	609,456	73,546	1,336,402	1,262,856	1,061,776	-61,755	262,835	73,546
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from stock option exercise	6,847	6,847	6,847
Awards of common stock	-17,140	-17,140	-17,140
Excess tax (shortfall) from stock-based payment arrangements	-9	-9	-9
Stock based compensation expense	2,214	2,214	2,214
Valencia’s transactions with its owner	-4,160					-4,160	-4,160	0	0	0	0	-4,160
Net Earnings	17,852	14,472			14,472	3,380	13,502	10,122	0	0	10,122	3,380	7,694
Net earnings	14,340						10,122						7,694			7,694
Subsidiary preferred stock dividends	-132	-132			-132
Total other comprehensive income	2,525	2,525		2,525			2,525	2,525	0	2,525	0	0	0
Dividends declared on common stock	-15,931	-15,931			-15,931
Dividends declared on preferred stock							-132	-132	0	0	-132	0
Balance TNMP at Mar. 31, 2015	1,714,392						1,275,371						532,359	64	404,166	128,129
Balance at Mar. 31, 2015	$1,787,158	$1,714,392	$1,165,757	($59,230)	$607,865	$72,766	$1,348,137	$1,275,371	$1,061,776	($59,230)	$272,825	$72,766

Significant_Accounting_Policie

Significant Accounting Policies and Responsibility for Financial Statements	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies and Responsibility for Financial Statements	Significant Accounting Policies and Responsibility for Financial Statements
	Financial Statement Preparation
	In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at March 31, 2015 and December 31, 2014 and the consolidated results of operations, comprehensive income, and the cash flows for the three months ended March 31, 2015 and 2014. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.
	The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2014 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 financial statement presentation.
	These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2014 Annual Reports on Form 10-K.
	GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.
	Principles of Consolidation
	The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.
	PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14.
	New Accounting Pronouncements
	Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.
	Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)
	On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard 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. On April 1, 2015, the FASB announced that it intends to propose a one-year delay in the effective date of ASU 2014-09. 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.
	Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
	On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is in process of evaluating the impacts of the ASU. Currently, unamortized debt issuance costs are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at March 31, 2015, amounted to $17.7 million for PNMR, $10.7 million for PNM, and $5.4 million for TNMP.

Earnings_Per_Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share
	In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:
		Three Months Ended
		March 31,
		2015		2014
		(In thousands, except per share amounts)
	Net Earnings Attributable to PNMR	$	14,340	$	12,468
	Average Number of Common Shares:
	Outstanding during period	79,654		79,654
	Vested awards of restricted stock	112		182
	Average Shares – Basic	79,766		79,836
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	387		551
	Average Shares – Diluted	80,153		80,387
	Net Earnings Per Share of Common Stock:
	Basic	$	0.18	$	0.16
	Diluted	$	0.18	$	0.16
	(1)	Excludes the effect of out-of-the-money options for 248,750 shares of common stock at March 31, 2015.

Segment_Information

Segment Information	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Information	Segment Information
	The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.
	PNM
	PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates.
	TNMP
	TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT.
	Corporate and Other
	The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.
	The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.
	PNMR SEGMENT INFORMATION
		PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Three Months Ended March 31, 2015
	Electric operating revenues	$	261,940		$	70,928		$	—		$	332,868
	Cost of energy	97,866			17,779			—			115,645
	Margin	164,074			53,149			—			217,223
	Other operating expenses	104,016			21,760			(3,583		)	122,193
	Depreciation and amortization	28,403			13,458			3,600			45,461
	Operating income (loss)	31,655			17,931			(17		)	49,569
	Interest income	1,771			—			(21		)	1,750
	Other income (deductions)	5,810			1,291			(1,778		)	5,323
	Net interest charges	(19,959		)	(6,925		)	(3,389		)	(30,273		)
	Segment earnings (loss) before income taxes	19,277			12,297			(5,205		)	26,369
	Income taxes (benefit)	5,775			4,603			(1,861		)	8,517
	Segment earnings (loss)	13,502			7,694			(3,344		)	17,852
	Valencia non-controlling interest	(3,380		)	—			—			(3,380		)
	Subsidiary preferred stock dividends	(132		)	—			—			(132		)
	Segment earnings (loss) attributable to PNMR	$	9,990		$	7,694		$	(3,344	)	$	14,340
	At March 31, 2015:
	Total Assets	$	4,464,487		$	1,243,410		$	231,442		$	5,939,339
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
		PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Three Months Ended March 31, 2014
	Electric operating revenues	$	262,736		$	66,161		$	—		$	328,897
	Cost of energy	96,626			15,988			—			112,614
	Margin	166,110			50,173			—			216,283
	Other operating expenses	107,724			21,069			(3,228		)	125,565
	Depreciation and amortization	27,082			11,842			3,041			41,965
	Operating income	31,304			17,262			187			48,753
	Interest income	2,128			—			(11		)	2,117
	Other income (deductions)	1,668			189			(641		)	1,216
	Net interest charges	(19,812		)	(6,598		)	(3,125		)	(29,535		)
	Segment earnings (loss) before income taxes	15,288			10,853			(3,590		)	22,551
	Income taxes (benefit)	4,083			4,050			(1,713		)	6,420
	Segment earnings (loss)	11,205			6,803			(1,877		)	16,131
	Valencia non-controlling interest	(3,531		)	—			—			(3,531		)
	Subsidiary preferred stock dividends	(132		)	—			—			(132		)
	Segment earnings (loss) attributable to PNMR	$	7,542		$	6,803		$	(1,877	)	$	12,468
	At March 31, 2014:
	Total Assets	$	4,219,635		$	1,173,028		$	114,363		$	5,507,026
	Goodwill	$	51,632		$	226,665		$	—		$	278,297

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss)
	Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2015 and 2014 is as follows:
		Accumulated Other Comprehensive Income (Loss)
		PNM									TNMP			PNMR
		Unrealized									Fair Value
		Gain on			Pension						Adjustment
		Available-for-			Liability						for Cash Flow
		Sale Securities			Adjustment			Total			Hedges			Total
		(In thousands)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—		$	(61,755	)
	Amounts reclassified from AOCI (pre-tax)	(4,172		)	1,488			(2,684		)	—			(2,684		)
	Income tax impact of amounts reclassified	1,635			(583		)	1,052			—			1,052
	Other OCI changes (pre-tax)	6,836			—			6,836			—			6,836
	Income tax impact of other OCI changes	(2,679		)	—			(2,679		)	—			(2,679		)
	Net change after income taxes	1,620			905			2,525			—			2,525
	Balance at March 31, 2015	$	29,628		$	(88,858	)	$	(59,230	)	$	—		$	(59,230	)
		Accumulated Other Comprehensive Income (Loss)
		PNM									TNMP			PNMR
		Unrealized									Fair Value
		Gain on			Pension						Adjustment
		Available-for-			Liability						for Cash Flow
		Sale Securities			Adjustment			Total			Hedges			Total
		(In thousands)
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
	Amounts reclassified from AOCI (pre-tax)	(3,255		)	1,288			(1,967		)	55			(1,912		)
	Income tax impact of amounts reclassified	1,283			(508		)	775			(19		)	756
	Other OCI changes (pre-tax)	3,379			—			3,379			(153		)	3,226
	Income tax impact of other OCI changes	(1,332		)	—			(1,332		)	53			(1,279		)
	Net change after income taxes	75			780			855			(64		)	791
	Balance at March 31, 2014	$	25,823		$	(82,845	)	$	(57,022	)	$	(327	)	$	(57,349	)
	Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the three months ended March 31, 2015 and 2014, approximately 22.8% and 23.2% of the amount reclassified was capitalized into construction work in process and approximately 2.9% and 2.7% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.

Variable_Interest_Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2015
Variable Interest Entities [Abstract]
Variable Interest Entities	Variable Interest Entities
	GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	Valencia
	PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three months ended March 31, 2015, PNM paid $4.8 million and $0.1 million for fixed and variable charges. For the three months ended March 31, 2014, PNM paid $4.8 million and $0.2 million for fixed and variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.
	Summarized financial information for Valencia is as follows:
	Results of Operations
		Three Months Ended March 31,
		2015			2014
		(In thousands)
	Operating revenues	$	4,904		$	4,931
	Operating expenses	(1,524		)	(1,400		)
	Earnings attributable to non-controlling interest	$	3,380		$	3,531
	Financial Position
		March 31,			December 31,
		2015			2014
		(In thousands)
	Current assets	$	2,839		$	2,513
	Net property, plant, and equipment	71,679			72,321
	Total assets	74,518			74,834
	Current liabilities	1,752			1,288
	Owners’ equity – non-controlling interest	$	72,766		$	73,546
	During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. PNM is discussing these issues with the owner of Valencia. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.
	PVNGS Leases
	PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provided PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provided PNM with options to renew the leases at fixed rates set forth in the leases for 2 years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional 6 years if the appraised remaining useful lives and fair value of the leased assets were greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 6, for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.
	PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of March 31, 2015, these payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $150.5 million, including the renewal terms of the leases that PNM has elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of March 31, 2015, PNM could have been required to pay the beneficial owners up to $217.3 million on July 15, 2015 in addition to the regularly scheduled lease payments. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $8.4 million at March 31, 2015 and $26.0 million at December 31, 2014, which are included in other current liabilities on the Condensed Consolidated Balance Sheets.
	PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to renewal and purchase options, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP.
	Rio Bravo, formerly known as Delta
	PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM 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. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. PNM changed the name of the facility to Rio Bravo.
	PNM made fixed and variable payments to Delta under the PPA. For the three months ended March 31, 2014, PNM incurred fixed capacity charges of $1.6 million and variable energy charges of $0.2 million. PNM recovered the variable energy charges through its FPPAC. Delta informed PNM that for the three months ended March 31, 2014 its revenue was $1.8 million and its net earnings were $0.3 million.
	PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

Lease_Commitments

Lease Commitments	3 Months Ended
	Mar. 31, 2015
Leases [Abstract]
Lease Commitments	Lease Commitments
	The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and, through April 1, 2015, an interest in the EIP transmission line. All of the Company’s leases are accounted for as operating leases. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, including information regarding renewal and purchase options, and actions taken by PNM, under the PVNGS leases.
	The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM elected to purchase the assets underlying those leases on the expiration date of the original leases and has entered into agreements with the lessors that establish the purchase prices, representing the fair market value, to be paid on January 15, 2016 by PNM for the assets underlying the leases. The leases remain in existence and PNM will record the purchases at the termination of the leases on January 15, 2016.
	PNM will pay $78.1 million for the assets underlying one of the Unit 2 leases, which is for 31.25 MW of the entitlement from PVNGS Unit 2. PNM will pay $85.2 million for the assets underlying the other two Unit 2 leases, which are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the agreement regarding these two leases, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014, $82.5 million on March 31, 2015, and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014, $2.7 million on March 31, 2015, and declines to $1.2 million on January 14, 2016. Currently, PNMR does not anticipate that PNMR Development will exercise the early purchase option.
	At March 31, 2015, PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. Following procedures set forth in the lease, PNM and the lessor entered into a definitive agreement for PNM to exercise its option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. PNM closed on the purchase on April 1, 2015 and will record the purchase at that date.

Fair_Value_of_Derivative_and_O

Fair Value of Derivative and Other Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value of Derivative and Other Financial Instruments [Abstract]
Fair Value of Derivative and Other Financial Instruments	Fair Value of Derivative and Other Financial Instruments
	Energy Related Derivative Contracts
	Overview
	The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	Commodity Risk
	Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.
	Accounting for Derivatives
	Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the three months ended March 31, 2015 and the year ended December 31, 2014, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.
	Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.
	Commodity Derivatives
	Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:
		Economic Hedges
		March 31,			December 31,
		2015			2014
	PNMR and PNM	(In thousands)
	Current assets	$	9,342		$	11,232
	Deferred charges	—			—
		9,342			11,232
	Current liabilities	(1,235		)	(1,209		)
	Long-term liabilities	(277		)	(477		)
		(1,512		)	(1,686		)
	Net	$	7,830		$	9,546
	Included in the above table are $2.2 million of current assets at March 31, 2015 and $3.0 million of current assets at December 31, 2014 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at March 31, 2015 and December 31, 2014.
	At March 31, 2015 and December 31, 2014, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at March 31, 2015 and December 31, 2014, amounts posted as cash collateral under margin arrangements were $2.8 million and $3.8 million for both PNMR and PNM. At March 31, 2015 and December 31, 2014, obligations to return cash collateral were $0.2 million and $0.2 million, for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets.
	PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes less than $0.1 million of current assets at March 31, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.
	The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.
		Economic Hedges
		Three Months Ended
		March 31,
		2015			2014
	PNMR and PNM	(In thousands)
	Electric operating revenues	$	(472	)	$	(4,151	)
	Cost of energy	(50		)	189
	Total gain (loss)	$	(522	)	$	(3,962	)
	Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
			Economic Hedges
			MMBTU		MWh
	PNMR and PNM
	March 31, 2015		575,000		(1,417,913	)
	December 31, 2014		650,000		(1,919,000	)
	In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral.
	The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.
	Contingent Feature –		Contractual Liability			Existing Cash Collateral			Net Exposure
	Credit Rating Downgrade
			(In thousands)
	PNMR and PNM
	March 31, 2015		$	1,512		$	—		$	117
	December 31, 2014		$	1,686		$	—		$	167
	Sale of Power from PVNGS Unit 3
	Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of March 31, 2015, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales.
	Non-Derivative Financial Instruments
	The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 11). The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At March 31, 2015 and December 31, 2014, the fair value of available-for-sale securities included $251.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust.
		March 31, 2015						December 31, 2014
		Unrealized Gains			Fair Value			Unrealized Gains			Fair Value
	PNMR and PNM				(In thousands)
	Cash and cash equivalents	$	—		$	5,142		$	—		$	8,276
	Equity securities:
	Domestic value	16,786			46,129			17,418			45,340
	Domestic growth	22,849			78,013			21,354			74,053
	International and other	995			17,478			156			16,599
	Fixed income securities:
	U.S. Government	1,256			21,912			903			22,563
	Municipals	6,198			73,554			5,851			68,973
	Corporate and other	758			15,236			666			14,341
	$	48,842		$	257,464		$	46,348		$	250,145
The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the change in realized impairment losses of $0.4 million and $0.5 million for the three months ended March 31, 2015 and 2014.
	Three Months Ended
	March 31,
	2015			2014
	(In thousands)
Proceeds from sales	$	31,852		$	22,804
Gross realized gains	$	5,135		$	3,118
Gross realized (losses)	$	(1,541	)	$	(1,039	)
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 March 31, 2015, the available-for-sale and held-to-maturity debt securities had the following final maturities:
	Fair Value
	Available-for-Sale			Held-to-Maturity
	PNMR and PNM			PNMR			PNM
	(In thousands)
Within 1 year	$	5,108		$	17,173		$	17,173
After 1 year through 5 years	17,210			626			—
After 5 years through 10 years	14,006			—			—
After 10 years through 15 years	10,705			—			—
After 15 years through 20 years	12,048			—			—
After 20 years	51,625			—			—
	$	110,702		$	17,799		$	17,173
Fair Value Disclosures
The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the three months ended March 31, 2015 and the year ended December 31, 2014.
For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services.
Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at March 31, 2015 and December 31, 2014 for items recorded at fair value.
				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)
March 31, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	5,142		$	5,142		$	—
Equity securities:
Domestic value	46,129			46,129			—
Domestic growth	78,013			78,013			—
International and other	17,478			17,478			—
Fixed income securities:
U.S. Government	21,912			20,603			1,309
Municipals	73,554			—			73,554
Corporate and other	15,236			4,901			10,335
	$	257,464		$	172,266		$	85,198
Commodity derivative assets	$	9,342		$	—		$	9,342
Commodity derivative liabilities	(1,512		)	—			(1,512		)
Net	$	7,830		$	—		$	7,830
December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276		$	—
Equity securities:
Domestic value	45,340			45,340			—
Domestic growth	74,053			74,053			—
International and other	16,599			16,599			—
Fixed income securities:
U.S. Government	22,563			20,808			1,755
Municipals	68,973			—			68,973
Corporate and other	14,341			4,843			9,498
	$	250,145		$	169,919		$	80,226
Commodity derivative assets	$	11,232		$	—		$	11,232
Commodity derivative liabilities	(1,686		)	—			(1,686		)
Net	$	9,546		$	—		$	9,546
The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:
							GAAP Fair Value Hierarchy
	Carrying Amount			Fair Value			Level 1			Level 2		Level 3
March 31, 2015	(In thousands)
PNMR
Long-term debt	$	2,125,007		$	2,322,072		$	—		$	2,322,072	$	—
Investment in PVNGS lessor notes	$	16,806		$	17,173		$	—		$	—	$	17,173
Other investments	$	509		$	1,135		$	509		$	—	$	626
PNM
Long-term debt	$	1,490,666		$	1,627,751		$	—		$	1,627,751	$	—
Investment in PVNGS lessor notes	$	16,806		$	17,173		$	—		$	—	$	17,173
Other investments	$	267		$	267		$	267		$	—	$	—
TNMP
Long-term debt	$	365,575		$	427,356		$	—		$	427,356	$	—
Other investments	$	242		$	242		$	242		$	—	$	—
December 31, 2014
PNMR
Long-term debt	$	1,975,090		$	2,173,117		$	—		$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232		$	32,836		$	—		$	—	$	32,836
Other investments	$	1,762		$	2,375		$	639		$	—	$	1,736
PNM
Long-term debt	$	1,490,657		$	1,624,222		$	—		$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232		$	32,836		$	—		$	—	$	32,836
Other investments	$	397		$	397		$	397		$	—	$	—
TNMP
Long-term debt	$	365,667		$	427,356		$	—		$	427,356	$	—
Other investments	$	242		$	242		$	242		$	—	$	—

StockBased_Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation
	PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards.
	The stock-based compensation expense related to restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At March 31, 2015 and December 31, 2014, PNMR had unrecognized expense related to stock awards of $8.3 million and $6.5 million.
	The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.
	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
			Three Months Ended March 31,
	Restricted Shares and Performance Based Shares		2015				2014
	Expected quarterly dividends per share		$	0.2			$	0.185
	Risk-free interest rate		1.07		%		0.71		%
	Market-Based Shares
	Dividend yield		2.87		%		2.82		%
	Expected volatility		18.73		%		25.11		%
	Risk-free interest rate		1		%		0.64		%
	The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the three months ended March 31, 2015:
		Restricted Stock							Stock Options
		Shares			Weighted-				Shares		Weighted-
					Average						Average
					Grant Date Fair Value						Exercise Price
	Outstanding at December 31, 2014	258,770			$	22.31			920,505		$	20.39
	Granted	317,756			$	19.93			—		$	—
	Exercised	(327,479	)		$	18.34			(149,277	)	$	21.34
	Forfeited	—			$	—			(5,300	)	$	30.5
	Expired	—			$	—			—		$	—
	Outstanding at March 31, 2015	249,047			$	24.48			765,928		$	19.97
	PNMR’s stock-based compensation program provides for performance and market targets through 2016. Included as granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012 through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets, weighted at 60%, at target award levels and performance targets, weighted at 40%, at maximum award levels. Excluded from the above table, are maximums of 179,811, 163,152, and 168,258 shares for the three-year performance periods ending in 2015, 2016, and 2017 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.
	In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015, which shares are included as granted and exercised in the above table. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.
	Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.
	In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement.
	At March 31, 2015, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $7.4 million with a weighted-average remaining contract life of 2.53 years. At March 31, 2015, the exercise price of 248,750 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:
			Three Months Ended March 31,
	Restricted Stock		2015				2014
	Weighted-average grant date fair value		$	19.93			$	20.79
	Total fair value of restricted shares that vested (in thousands)		$	6,005			$	4,336
	Stock Options
	Weighted-average grant date fair value of options granted		$	—			$	—
	Total fair value of options that vested (in thousands)		$	—			$	—
	Total intrinsic value of options exercised (in thousands)		$	1,138			$	1,469

Financing

Financing	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Financing	Financing
	Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	Financing Activities
	On March 5, 2014, PNM entered into a $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM 2013 Term Loan Agreement and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.13% at March 31, 2015, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Condensed Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.
	On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.18% at March 31, 2015, and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNMR 2015 Term Loan Agreement has a cross default provision and a change of control provision.
	Short-term Debt
	The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. Both of these facilities mature on October 31, 2019 and provide for an additional one-year extension option, subject to approval by a majority of the lenders. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At March 31, 2015, there were no borrowings under any of these facilities. At March 31, 2015, TNMP had $28.5 million in borrowings from PNMR under its intercompany loan agreement. At March 31, 2015, the weighted average interest rate was 1.03% for borrowings outstanding under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of:
		March 31,		December 31,
	Short-term Debt	2015		2014
		(In thousands)
	PNM:
	Revolving credit facility	$	—	$	—
	PNM New Mexico Credit Facility	—		—
	TNMP – Revolving credit facility	—		5,000
	PNMR:
	Revolving credit facility	—		600
	PNMR Term Loan Agreement	100,000		100,000
		$	100,000	$	105,600
	At April 24, 2015, PNMR, PNM, and TNMP had $292.3 million, $396.8 million, and $74.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at April 24, 2015, on a consolidated basis, was $814.0 million for PNMR. As of April 24, 2015, PNM had $26.4 million and TNMP had $38.4 million in borrowings from PNMR under their intercompany loan agreements. At April 24, 2015, PNMR, PNM and TNMP had consolidated invested cash of $87.4 million, none, and none. The availability amounts do not include remaining capacity of $25.0 million available under the PNM Multi-draw Term Loan at April 24, 2015.

Pension_and_Other_Postretireme

Pension and Other Postretirement Benefit Plans	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefit Plans	Pension and Other Postretirement Benefit Plans
	PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.
	Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.
	PNM Plans
	The following tables present the components of the PNM Plans’ net periodic benefit cost:
		Three Months Ended March 31,
		Pension Plan						OPEB Plan						Executive Retirement Program
		2015			2014			2015			2014			2015		2014
		(In thousands)
	Components of Net Periodic
	Benefit Cost
	Service cost	$	—		$	—		$	51		$	45		$	—	$	—
	Interest cost	7,064			7,541			1,022			1,159			190		205
	Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
	Amortization of net (gain) loss	3,705			3,255			491			556			81		52
	Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
	Net periodic benefit cost	$	697		$	1,044		$	1		$	14		$	271	$	257
	PNM made contributions to its pension plan trust of $30.0 million and zero in the three months ended March 31, 2015 and 2014. PNM does not anticipate making additional contributions to its pension trust in 2015.  Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2016-2019 are estimated to total $22.0 million. These anticipated contributions were developed using current funding assumptions, with discount rates of 4.8% to 5.5%. Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $0.8 million in the three months ended March 31, 2015 and 2014. PNM expects to make contributions to the OPEB trust totaling $3.5 million in 2015 and $14.0 million for 2016-2019.  Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.5 million and $0.4 million in the three months ended March 31, 2015 and 2014 and are expected to total $1.5 million during 2015.
	TNMP Plans
	The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):
		Three Months Ended March 31,
		Pension Plan						OPEB Plan						Executive Retirement Program
		2015			2014			2015			2014			2015		2014
		(In thousands)
	Components of Net Periodic
	Benefit Cost (Income)
	Service cost	$	—		$	—		$	62		$	59		$	—	$	—
	Interest cost	761			798			152			155			9		10
	Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
	Amortization of net (gain) loss	195			166			—			(31		)	1		—
	Amortization of prior service cost	—			—			—			8			—		—
	Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10
	TNMP does not anticipate making any contributions to its pension trust in 2015-2019 based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These expectations were developed using current funding assumptions, including discount rates of 4.8% and 5.5%. Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made no contributions to the OPEB trust in the three months ended March 31, 2015 and 2014. TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2015 and $1.4 million for 2016-2019. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three months ended March 31, 2015 and 2014 and are expected to total $0.1 million during 2015.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Overview
	There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.
	With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.
	Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	Commitments and Contingencies Related to the Environment
	Nuclear Spent Fuel and Waste Disposal
	Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement 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 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a claim for costs paid between July 1, 2011 and June 30, 2014 and agreed to a settlement amount of $42.0 million in March 2015. PNM’s share of the settlement, which amounted to $4.3 million, including $3.1 million credited back to PNM’s customers, was recorded in the three months ended March 31, 2015. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.
	PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At March 31, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.4 million and $12.3 million included in other deferred credits.
	On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision. The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.
	In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel.  The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter.
	PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027.  Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047.  If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
	In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.
	The Clean Air Act
	Regional Haze
	In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.
	SJGS
	BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.
	PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties.
	During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP.
	In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.
	Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”
	Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.
	Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS.
	The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3%.
	Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP.
	NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:
	•	Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs
	•	A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018
	•	An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million
	•	A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS
	The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. 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 $212.5 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment.
	PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements 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 March 31, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $280 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 March 31, 2015, PNM’s net book value of PVNGS Unit 3 was approximately $145 million
	•	Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million
	•	Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA
	A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:
	•	PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below
	•	PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval
	•	PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015
	If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.
	On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at a value of $143.5 million ($1,071/KW), approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The certification recommends that the parties be given seven days to decide whether to accept any modifications after the NMPRC issues an order. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million. The NMPRC has not yet acted on the certification. Although PNM expects a decision from the NMPRC in the second or third quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.
	On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below.
	SJGS Ownership Restructuring Matters – As discussed in the 2014 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.
	The SJGS participants engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.
	On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants have negotiated substantially final, unexecuted agreements regarding coal supply for SJGS through June 30, 2022. 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.
	On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS.
	It is anticipated that PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 would enter into a Capacity Option and Funding Agreement (“COFA”), which would provide PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR would guarantee the obligations of PNMR Development under the COFA. The COFA would terminate on the earliest of January 1, 2016, the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because another SJGS owner has given notice that it will no longer participate in the restructuring process. If the COFA is terminated, the California owners would not be obligated to repay amounts funded by PNM and PNMR Development.
	On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the Resolution. PNMR Development would also be a party to the RA and would acquire an ownership interest in SJGS Unit 4 when the California owners exit, but would have obligations related to Unit 4 before then. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity, as contemplated by the COFA. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. The new coal supply agreement is currently anticipated to be effective on January 1, 2016. It is currently anticipated that the coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. The RA sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 and December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNM’s notice also included submittal of confidential, substantially final, unexecuted copies of documents related to coal supply for SJGS beginning January 1, 2016 (see “Coal Supply” below). The participants continue to negotiate agreements for reclamation of the mines supplying coal to SJGS, decommissioning obligations and funding for the SJGS plant, and related amendments to the SJPPA. PNM and the other SJGS owners are working toward finalizing the reclamation agreement by June 1, 2015 and the decommissioning agreement by July 1, 2015 and to have final execution of all the restructuring agreements completed by August 31, 2015.
	PNM is unable to predict whether all required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.
	Other SJGS Matters – 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 BDT requirements described above, 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, July 14, 2014, and March 20, 2015, 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 and the agreements for restructuring and a new coal supply becoming effective. 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. Failure to implement the RSIP or an agreed to alternative could jeopardize the economic viability of SJGS. 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 permanently close Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 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.
	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. 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 $83.9 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.
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.  On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule.  SJGS and Four Corners SO2 emissions are below the tonnages set forth in 1) above. EPA regions sent out letters to state environmental agencies explaining how EPA plans to implement the consent decree.  The letters outline the schedule that EPA expects states to follow in moving forward with new SO2 non-attainment designations. To date, NMED has not received a letter.
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. The BDT equipment modifications are to 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 those counties 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 would 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. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. PNM has applied for the necessary modifications to the SJGS air quality permit to include this operational parameter as a permit condition.
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.
Four Corners Coal Mine
In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that NTEC, the owner of the mine and supplier of coal to Four Corners, does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. PNM cannot predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.
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 signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule 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 (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and 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. Because of the discretion afforded to EPA with respect to entrainment requirements, PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. However, the costs are not expected to be material. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.
Effluent Limitation Guidelines
On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants.  EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations.  The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions. 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 PNM’s 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
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. EPA published the final CCB rule in the Federal Register on April 17. 2015.
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 CCB 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.
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 were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM did not request an extension and began 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 March 31, 2015 and December 31, 2014, prepayments for coal, which are included in other current assets, amounted to $38.9 million and $37.3 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. The parties to the coal sales agreement are SJCC, PNM, and Tucson. 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.
In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS 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 would 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 began 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 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.
Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, substantially final, unexecuted forms of agreements have been negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new Coal Supply Agreement (“CSA”) with SJCC on or about January 1, 2016. Under the CSA, SJCC would supply all of the coal requirements for SJGS from January 1, 2016 through June 30, 2022. Pricing under the CSA would primarily be fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM would have the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. However, since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners, which is discussed above, will be passed through to PNM’s customers. PNM and SJCC would enter into additional agreements, under which SJCC would perform all CCB disposal activities for SJGS over the term of the CSA and all reclamation obligations of the mines that have supplied coal for SJGS through the completion of final reclamation following closure of the mine. On May 1, 2015, PNM filed a notice of submittal of confidential, substantially final, unexecuted copies of the CSA, reclamation, and ash disposal agreements with the NMPRC. Effectiveness of the agreements will be dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals are necessary for the restructuring of ownership in SJGS to be consummated. It is currently anticipated that the coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. Currently, PNM cannot predict if all of the necessary requirements will be satisfied and all approvals obtained in order for these agreements to become effective.
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 $57.0 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of March 31, 2015. At March 31, 2015 and December 31, 2014, liabilities, in current dollars, of $25.6 million and $25.7 million for surface mine reclamation and $8.8 million and $8.6 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 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.
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 although the BLM has indicated that final action on the proposed rule is scheduled for October 2015.
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.
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. NMTRD denied the refund claim. 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 $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.
Water Supply
Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, 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 approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. .  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 allottees’ appeal, and is therefore unable at this time to predict the likely outcome of this matter.

Regulatory_and_Rate_Matters

Regulatory and Rate Matters	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
Regulatory and Rate Matters	Regulatory and Rate Matters
	The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.
	PNM
	2014 Electric Rate Case
	On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future 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 distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which allege that PNM’s application is incomplete and challenge the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters.
	On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the future test year rule. The Hearing Examiner cites procedural defects in the filing including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and providing other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute.  PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the NMPRC. PNM expects a decision from the NMPRC in the second quarter of 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016.
	A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015. However, the schedule could be delayed by the NMPRC when they take action on the Hearing Examiner’s Initial Recommended Decision.
	Renewable Portfolio Standard
	The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and 3% distributed generation.
	The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges.
	PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million.
	PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the 2014 Electric Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In 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 does not anticipate that the acquisition of renewable resources, if any, needed to meet the RPS requirement for 2014 will be significant. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans.
	PNM 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 2014 Electric Rate Case discussed above unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million, reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015.
	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.
	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 the incentive amounts discussed below. Two parties filed statements in opposition to the stipulation. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 that recommends that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification.
	Disincentives/Incentives
	The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing the NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million.
	In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved.
	Energy Efficiency Rulemaking
	On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.
	On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs.
	Integrated Resource Plan
	NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.
	San Juan Generating Station Units 2 and 3 Retirement
	On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification is set forth in Note 11. 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 notified the NMPRC about receipt of the notice and advised 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.
	Formula Transmission Rate Case
	In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.
	On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.
	Firm-Requirements Wholesale Customers
	Navopache Electric Cooperative, Inc.
	In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement.
	On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. FERC has established a May 8, 2015 comment date for responses. PNM will intervene in this matter and protest NEC’s petition. PNM is unable to predict the outcome of this matter.
	City of Gallup, New Mexico Contract
	PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement.
	On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility.  PNM’s contract with Gallup ended on June 29, 2014.  PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.
	TNMP
	Advanced Meter System Deployment
	In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.
	In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.
	The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of April 24, 2015, 91 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.
	Energy Efficiency
	TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a settlement that 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 records incentive bonuses upon approval by the PUCT.
	Transmission Cost of Service Rates
	TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s most recent interim transmission cost rate increases:
	Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
		(in millions)
	17-Sep-13	$	18.1	$	2.8
	13-Mar-14	18.2		2.9
	8-Sep-14	25.2		4.2
	16-Mar-15	27.1		4.4

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.
	On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law.  Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:
		Three Months Ended
		March 31,
		2015		2014
		(In thousands)
	Services billings:
	PNMR to PNM	$	22,727	$	21,066
	PNMR to TNMP	7,078		7,261
	PNM to TNMP	92		109
	TNMP to PNMR	10		—
	Interest billings:
	PNMR to TNMP	79		96
	PNMR to PNM	6		53
	PNM to PNMR	29		26
	Income tax sharing payments:
	PNMR to PNM	—		—
	PNMR to TNMP	—		—

Significant_Accounting_Policie1

Significant Accounting Policies and Responsibility for Financial Statements (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation
	The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM began consolidating Rio Bravo, formerly known as Delta, upon its acquisition on July 17, 2014. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.
	PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14.
New Accounting Pronouncements	New Accounting Pronouncements
	Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.
	Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)
	On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard 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. On April 1, 2015, the FASB announced that it intends to propose a one-year delay in the effective date of ASU 2014-09. 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.
	Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
	On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is in process of evaluating the impacts of the ASU.
Consolidation, Variable Interest Entity	GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Information regarding the computation of earnings per share is as follows:
		Three Months Ended
		March 31,
		2015		2014
		(In thousands, except per share amounts)
	Net Earnings Attributable to PNMR	$	14,340	$	12,468
	Average Number of Common Shares:
	Outstanding during period	79,654		79,654
	Vested awards of restricted stock	112		182
	Average Shares – Basic	79,766		79,836
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	387		551
	Average Shares – Diluted	80,153		80,387
	Net Earnings Per Share of Common Stock:
	Basic	$	0.18	$	0.16
	Diluted	$	0.18	$	0.16
	(1)	Excludes the effect of out-of-the-money options for 248,750 shares of common stock at March 31, 2015.

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.
	PNMR SEGMENT INFORMATION
		PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Three Months Ended March 31, 2015
	Electric operating revenues	$	261,940		$	70,928		$	—		$	332,868
	Cost of energy	97,866			17,779			—			115,645
	Margin	164,074			53,149			—			217,223
	Other operating expenses	104,016			21,760			(3,583		)	122,193
	Depreciation and amortization	28,403			13,458			3,600			45,461
	Operating income (loss)	31,655			17,931			(17		)	49,569
	Interest income	1,771			—			(21		)	1,750
	Other income (deductions)	5,810			1,291			(1,778		)	5,323
	Net interest charges	(19,959		)	(6,925		)	(3,389		)	(30,273		)
	Segment earnings (loss) before income taxes	19,277			12,297			(5,205		)	26,369
	Income taxes (benefit)	5,775			4,603			(1,861		)	8,517
	Segment earnings (loss)	13,502			7,694			(3,344		)	17,852
	Valencia non-controlling interest	(3,380		)	—			—			(3,380		)
	Subsidiary preferred stock dividends	(132		)	—			—			(132		)
	Segment earnings (loss) attributable to PNMR	$	9,990		$	7,694		$	(3,344	)	$	14,340
	At March 31, 2015:
	Total Assets	$	4,464,487		$	1,243,410		$	231,442		$	5,939,339
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
		PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Three Months Ended March 31, 2014
	Electric operating revenues	$	262,736		$	66,161		$	—		$	328,897
	Cost of energy	96,626			15,988			—			112,614
	Margin	166,110			50,173			—			216,283
	Other operating expenses	107,724			21,069			(3,228		)	125,565
	Depreciation and amortization	27,082			11,842			3,041			41,965
	Operating income	31,304			17,262			187			48,753
	Interest income	2,128			—			(11		)	2,117
	Other income (deductions)	1,668			189			(641		)	1,216
	Net interest charges	(19,812		)	(6,598		)	(3,125		)	(29,535		)
	Segment earnings (loss) before income taxes	15,288			10,853			(3,590		)	22,551
	Income taxes (benefit)	4,083			4,050			(1,713		)	6,420
	Segment earnings (loss)	11,205			6,803			(1,877		)	16,131
	Valencia non-controlling interest	(3,531		)	—			—			(3,531		)
	Subsidiary preferred stock dividends	(132		)	—			—			(132		)
	Segment earnings (loss) attributable to PNMR	$	7,542		$	6,803		$	(1,877	)	$	12,468
	At March 31, 2014:
	Total Assets	$	4,219,635		$	1,173,028		$	114,363		$	5,507,026
	Goodwill	$	51,632		$	226,665		$	—		$	278,297

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Information regarding accumulated other comprehensive income (loss) for the three months ended March 31, 2015 and 2014 is as follows:
		Accumulated Other Comprehensive Income (Loss)
		PNM									TNMP			PNMR
		Unrealized									Fair Value
		Gain on			Pension						Adjustment
		Available-for-			Liability						for Cash Flow
		Sale Securities			Adjustment			Total			Hedges			Total
		(In thousands)
	Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—		$	(61,755	)
	Amounts reclassified from AOCI (pre-tax)	(4,172		)	1,488			(2,684		)	—			(2,684		)
	Income tax impact of amounts reclassified	1,635			(583		)	1,052			—			1,052
	Other OCI changes (pre-tax)	6,836			—			6,836			—			6,836
	Income tax impact of other OCI changes	(2,679		)	—			(2,679		)	—			(2,679		)
	Net change after income taxes	1,620			905			2,525			—			2,525
	Balance at March 31, 2015	$	29,628		$	(88,858	)	$	(59,230	)	$	—		$	(59,230	)
		Accumulated Other Comprehensive Income (Loss)
		PNM									TNMP			PNMR
		Unrealized									Fair Value
		Gain on			Pension						Adjustment
		Available-for-			Liability						for Cash Flow
		Sale Securities			Adjustment			Total			Hedges			Total
		(In thousands)
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
	Amounts reclassified from AOCI (pre-tax)	(3,255		)	1,288			(1,967		)	55			(1,912		)
	Income tax impact of amounts reclassified	1,283			(508		)	775			(19		)	756
	Other OCI changes (pre-tax)	3,379			—			3,379			(153		)	3,226
	Income tax impact of other OCI changes	(1,332		)	—			(1,332		)	53			(1,279		)
	Net change after income taxes	75			780			855			(64		)	791
	Balance at March 31, 2014	$	25,823		$	(82,845	)	$	(57,022	)	$	(327	)	$	(57,349	)

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables) (Public Service Company of New Mexico [Member])	3 Months Ended
	Mar. 31, 2015
Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Noncontrolling Interest Summarized Financial Information	Summarized financial information for Valencia is as follows:
	Results of Operations
		Three Months Ended March 31,
		2015			2014
		(In thousands)
	Operating revenues	$	4,904		$	4,931
	Operating expenses	(1,524		)	(1,400		)
	Earnings attributable to non-controlling interest	$	3,380		$	3,531
	Financial Position
		March 31,			December 31,
		2015			2014
		(In thousands)
	Current assets	$	2,839		$	2,513
	Net property, plant, and equipment	71,679			72,321
	Total assets	74,518			74,834
	Current liabilities	1,752			1,288
	Owners’ equity – non-controlling interest	$	72,766		$	73,546

Fair_Value_of_Derivative_and_O1

Fair Value of Derivative and Other Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value of Derivative and Other Financial Instruments [Line Items]
Fair Value, by Balance Sheet Grouping	The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:
								GAAP Fair Value Hierarchy
		Carrying Amount			Fair Value			Level 1			Level 2		Level 3
	March 31, 2015	(In thousands)
	PNMR
	Long-term debt	$	2,125,007		$	2,322,072		$	—		$	2,322,072	$	—
	Investment in PVNGS lessor notes	$	16,806		$	17,173		$	—		$	—	$	17,173
	Other investments	$	509		$	1,135		$	509		$	—	$	626
	PNM
	Long-term debt	$	1,490,666		$	1,627,751		$	—		$	1,627,751	$	—
	Investment in PVNGS lessor notes	$	16,806		$	17,173		$	—		$	—	$	17,173
	Other investments	$	267		$	267		$	267		$	—	$	—
	TNMP
	Long-term debt	$	365,575		$	427,356		$	—		$	427,356	$	—
	Other investments	$	242		$	242		$	242		$	—	$	—
	December 31, 2014
	PNMR
	Long-term debt	$	1,975,090		$	2,173,117		$	—		$	2,173,117	$	—
	Investment in PVNGS lessor notes	$	31,232		$	32,836		$	—		$	—	$	32,836
	Other investments	$	1,762		$	2,375		$	639		$	—	$	1,736
	PNM
	Long-term debt	$	1,490,657		$	1,624,222		$	—		$	1,624,222	$	—
	Investment in PVNGS lessor notes	$	31,232		$	32,836		$	—		$	—	$	32,836
	Other investments	$	397		$	397		$	397		$	—	$	—
	TNMP
	Long-term debt	$	365,667		$	427,356		$	—		$	427,356	$	—
	Other investments	$	242		$	242		$	242		$	—	$	—
PNMR and PNM [Member]
Fair Value of Derivative and Other Financial Instruments [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:
		Economic Hedges
		March 31,			December 31,
		2015			2014
	PNMR and PNM	(In thousands)
	Current assets	$	9,342		$	11,232
	Deferred charges	—			—
		9,342			11,232
	Current liabilities	(1,235		)	(1,209		)
	Long-term liabilities	(277		)	(477		)
		(1,512		)	(1,686		)
	Net	$	7,830		$	9,546
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.
		Economic Hedges
		Three Months Ended
		March 31,
		2015			2014
	PNMR and PNM	(In thousands)
	Electric operating revenues	$	(472	)	$	(4,151	)
	Cost of energy	(50		)	189
	Total gain (loss)	$	(522	)	$	(3,962	)
Schedule of Notional Amounts of Outstanding Derivative Positions	The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
			Economic Hedges
			MMBTU		MWh
	PNMR and PNM
	March 31, 2015		575,000		(1,417,913	)
	December 31, 2014		650,000		(1,919,000	)
Schedule of Collateral Related to Derivative	The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.
	Contingent Feature –		Contractual Liability			Existing Cash Collateral			Net Exposure
	Credit Rating Downgrade
			(In thousands)
	PNMR and PNM
	March 31, 2015		$	1,512		$	—		$	117
	December 31, 2014		$	1,686		$	—		$	167
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 March 31, 2015 and December 31, 2014, the fair value of available-for-sale securities included $251.8 million and $244.6 million for the NDT and $5.7 million and $5.5 million for the mine reclamation trust.
		March 31, 2015						December 31, 2014
		Unrealized Gains			Fair Value			Unrealized Gains			Fair Value
	PNMR and PNM				(In thousands)
	Cash and cash equivalents	$	—		$	5,142		$	—		$	8,276
	Equity securities:
	Domestic value	16,786			46,129			17,418			45,340
	Domestic growth	22,849			78,013			21,354			74,053
	International and other	995			17,478			156			16,599
	Fixed income securities:
	U.S. Government	1,256			21,912			903			22,563
	Municipals	6,198			73,554			5,851			68,973
	Corporate and other	758			15,236			666			14,341
		$	48,842		$	257,464		$	46,348		$	250,145
	The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the change in realized impairment losses of $0.4 million and $0.5 million for the three months ended March 31, 2015 and 2014.
		Three Months Ended
		March 31,
		2015			2014
		(In thousands)
	Proceeds from sales	$	31,852		$	22,804
	Gross realized gains	$	5,135		$	3,118
	Gross realized (losses)	$	(1,541	)	$	(1,039	)
Investments Classified by Contractual Maturity Date	At March 31, 2015, the available-for-sale and held-to-maturity debt securities had the following final maturities:
		Fair Value
		Available-for-Sale			Held-to-Maturity
		PNMR and PNM			PNMR			PNM
		(In thousands)
	Within 1 year	$	5,108		$	17,173		$	17,173
	After 1 year through 5 years	17,210			626			—
	After 5 years through 10 years	14,006			—			—
	After 10 years through 15 years	10,705			—			—
	After 15 years through 20 years	12,048			—			—
	After 20 years	51,625			—			—
		$	110,702		$	17,799		$	17,173
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis	Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at March 31, 2015 and December 31, 2014 for items recorded at fair value.
					GAAP Fair Value Hierarchy
		Total			Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)
	March 31, 2015	(In thousands)
	PNMR and PNM
	Available-for-sale securities
	Cash and cash equivalents	$	5,142		$	5,142		$	—
	Equity securities:
	Domestic value	46,129			46,129			—
	Domestic growth	78,013			78,013			—
	International and other	17,478			17,478			—
	Fixed income securities:
	U.S. Government	21,912			20,603			1,309
	Municipals	73,554			—			73,554
	Corporate and other	15,236			4,901			10,335
		$	257,464		$	172,266		$	85,198
	Commodity derivative assets	$	9,342		$	—		$	9,342
	Commodity derivative liabilities	(1,512		)	—			(1,512		)
	Net	$	7,830		$	—		$	7,830
	December 31, 2014
	PNMR and PNM
	Available-for-sale securities
	Cash and cash equivalents	$	8,276		$	8,276		$	—
	Equity securities:
	Domestic value	45,340			45,340			—
	Domestic growth	74,053			74,053			—
	International and other	16,599			16,599			—
	Fixed income securities:
	U.S. Government	22,563			20,808			1,755
	Municipals	68,973			—			68,973
	Corporate and other	14,341			4,843			9,498
		$	250,145		$	169,919		$	80,226
	Commodity derivative assets	$	11,232		$	—		$	11,232
	Commodity derivative liabilities	(1,686		)	—			(1,686		)
	Net	$	9,546		$	—		$	9,546

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
			Three Months Ended March 31,
	Restricted Shares and Performance Based Shares		2015				2014
	Expected quarterly dividends per share		$	0.2			$	0.185
	Risk-free interest rate		1.07		%		0.71		%
	Market-Based Shares
	Dividend yield		2.87		%		2.82		%
	Expected volatility		18.73		%		25.11		%
	Risk-free interest rate		1		%		0.64		%
	The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the three months ended March 31, 2015:
		Restricted Stock							Stock Options
		Shares			Weighted-				Shares		Weighted-
					Average						Average
					Grant Date Fair Value						Exercise Price
	Outstanding at December 31, 2014	258,770			$	22.31			920,505		$	20.39
	Granted	317,756			$	19.93			—		$	—
	Exercised	(327,479	)		$	18.34			(149,277	)	$	21.34
	Forfeited	—			$	—			(5,300	)	$	30.5
	Expired	—			$	—			—		$	—
	Outstanding at March 31, 2015	249,047			$	24.48			765,928		$	19.97
	The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares:
			Three Months Ended March 31,
	Restricted Stock		2015				2014
	Weighted-average grant date fair value		$	19.93			$	20.79
	Total fair value of restricted shares that vested (in thousands)		$	6,005			$	4,336
	Stock Options
	Weighted-average grant date fair value of options granted		$	—			$	—
	Total fair value of options that vested (in thousands)		$	—			$	—
	Total intrinsic value of options exercised (in thousands)		$	1,138			$	1,469

Financing_Tables

Financing (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Schedule of Short-term Debt	Short-term debt outstanding consisted of:
		March 31,		December 31,
	Short-term Debt	2015		2014
		(In thousands)
	PNM:
	Revolving credit facility	$	—	$	—
	PNM New Mexico Credit Facility	—		—
	TNMP – Revolving credit facility	—		5,000
	PNMR:
	Revolving credit facility	—		600
	PNMR Term Loan Agreement	100,000		100,000
		$	100,000	$	105,600

Pension_and_Other_Postretireme1

Pension and Other Postretirement Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2015
Public Service Company of New Mexico [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Net Benefit Costs	The following tables present the components of the PNM Plans’ net periodic benefit cost:
		Three Months Ended March 31,
		Pension Plan						OPEB Plan						Executive Retirement Program
		2015			2014			2015			2014			2015		2014
		(In thousands)
	Components of Net Periodic
	Benefit Cost
	Service cost	$	—		$	—		$	51		$	45		$	—	$	—
	Interest cost	7,064			7,541			1,022			1,159			190		205
	Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
	Amortization of net (gain) loss	3,705			3,255			491			556			81		52
	Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
	Net periodic benefit cost	$	697		$	1,044		$	1		$	14		$	271	$	257
Texas-New Mexico Power Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Net Benefit Costs	The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):
		Three Months Ended March 31,
		Pension Plan						OPEB Plan						Executive Retirement Program
		2015			2014			2015			2014			2015		2014
		(In thousands)
	Components of Net Periodic
	Benefit Cost (Income)
	Service cost	$	—		$	—		$	62		$	59		$	—	$	—
	Interest cost	761			798			152			155			9		10
	Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
	Amortization of net (gain) loss	195			166			—			(31		)	1		—
	Amortization of prior service cost	—			—			—			8			—		—
	Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10

Regulatory_and_Rate_Matters_Ta

Regulatory and Rate Matters (Tables)	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
Schedule of Rate Increases for Transmission Costs	The following sets forth TNMP’s most recent interim transmission cost rate increases:
	Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
		(in millions)
	17-Sep-13	$	18.1	$	2.8
	13-Mar-14	18.2		2.9
	8-Sep-14	25.2		4.2
	16-Mar-15	27.1		4.4

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:
		Three Months Ended
		March 31,
		2015		2014
		(In thousands)
	Services billings:
	PNMR to PNM	$	22,727	$	21,066
	PNMR to TNMP	7,078		7,261
	PNM to TNMP	92		109
	TNMP to PNMR	10		—
	Interest billings:
	PNMR to TNMP	79		96
	PNMR to PNM	6		53
	PNM to PNMR	29		26
	Income tax sharing payments:
	PNMR to PNM	—		—
	PNMR to TNMP	—		—

Significant_Accounting_Policie2

Significant Accounting Policies and Responsibility for Financial Statements - Narrative (Details) (Adjustments for New Accounting Pronouncement [Member], USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense	$17.70
Public Service Company of New Mexico [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense	10.7
Texas-New Mexico Power Company [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unamortized Debt Issuance Expense	$5.40

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Earnings Per Share [Abstract]
Net Earnings Attributable to PNMR	$14,340		$12,468
Average Number of Common Shares:
Outstanding during period	79,654,000		79,654,000
Vested awards of restricted stock	112,000		182,000
Average Shares – Basic	79,766,000		79,836,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	387,000	[1]	551,000	[1]
Average Shares – Diluted	80,153,000		80,387,000
Net Earnings Per Share of Common Stock:
Basic (dollars per share)	$0.18		$0.16
Diluted (dollars per share)	$0.18		$0.16
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)	248,750
[1]	Excludes the effect of out-of-the-money options for 248,750 shares of common stock at March 31, 2015.

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$332,868	$328,897
Cost of energy	115,645	112,614
Margin	217,223	216,283
Other operating expenses	122,193	125,565
Depreciation and amortization	45,461	41,965
Operating income	49,569	48,753
Interest income	1,750	2,117
Other income (deductions)	5,323	1,216
Net interest charges	-30,273	-29,535
Earnings before Income Taxes	26,369	22,551
Income taxes (benefit)	8,517	6,420
Segment earnings (loss)	17,852	16,131
Valencia non-controlling interest	-3,380	-3,531
Subsidiary preferred stock dividends	-132	-132
Net Earnings Available for PNM Common Stock	14,340	12,468
Total Assets	5,939,339	5,507,026	5,829,325
Goodwill	278,297	278,297	278,297
Public Service Company of New Mexico [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	261,940	262,736
Cost of energy	97,866	96,626
Margin	164,074	166,110
Other operating expenses	104,016	107,724
Depreciation and amortization	28,403	27,082
Operating income	31,655	31,304
Interest income	1,771	2,128
Other income (deductions)	5,810	1,668
Net interest charges	-19,959	-19,812
Earnings before Income Taxes	19,277	15,288
Income taxes (benefit)	5,775	4,083
Segment earnings (loss)	13,502	11,205
Valencia non-controlling interest	-3,380	-3,531
Subsidiary preferred stock dividends	-132	-132
Net Earnings Available for PNM Common Stock	9,990	7,542
Total Assets	4,464,487	4,219,635	4,473,652
Goodwill	51,632	51,632	51,632
Texas-New Mexico Power Company [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	70,928	66,161
Cost of energy	17,779	15,988
Margin	53,149	50,173
Other operating expenses	21,760	21,069
Depreciation and amortization	13,458	11,842
Operating income	17,931	17,262
Interest income	0	0
Other income (deductions)	1,291	189
Net interest charges	-6,925	-6,598
Earnings before Income Taxes	12,297	10,853
Income taxes (benefit)	4,603	4,050
Segment earnings (loss)	7,694	6,803
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	7,694	6,803
Total Assets	1,243,410	1,173,028	1,240,241
Goodwill	226,665	226,665	226,665
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0
Cost of energy	0	0
Margin	0	0
Other operating expenses	-3,583	-3,228
Depreciation and amortization	3,600	3,041
Operating income	-17	187
Interest income	-21	-11
Other income (deductions)	-1,778	-641
Net interest charges	-3,389	-3,125
Earnings before Income Taxes	-5,205	-3,590
Income taxes (benefit)	-1,861	-1,713
Segment earnings (loss)	-3,344	-1,877
Valencia non-controlling interest	0	0
Subsidiary preferred stock dividends	0	0
Net Earnings Available for PNM Common Stock	-3,344	-1,877
Total Assets	231,442	114,363
Goodwill	$0	$0

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Equity [Abstract]
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process	22.80%	23.20%
Percentage of Pension Liability Adjustment Capitalized into Other Accounts	2.90%	2.70%
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	($61,755)
Net change after income taxes	2,525	791
Ending Balance	-59,230
PNMR and PNM [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	28,008	25,748
Amounts reclassified from AOCI (pre-tax)	-4,172	-3,255
Income tax impact of amounts reclassified	1,635	1,283
Other OCI changes (pre-tax)	6,836	3,379
Income tax impact of other OCI changes	-2,679	-1,332
Net change after income taxes	1,620	75
Ending Balance	29,628	25,823
PNMR and PNM [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-89,763	-83,625
Amounts reclassified from AOCI (pre-tax)	1,488	1,288
Income tax impact of amounts reclassified	-583	-508
Net change after income taxes	905	780
Ending Balance	-88,858	-82,845
PNM [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-61,755	-57,877
Amounts reclassified from AOCI (pre-tax)	-2,684	-1,967
Income tax impact of amounts reclassified	1,052	775
Other OCI changes (pre-tax)	6,836	3,379
Income tax impact of other OCI changes	-2,679	-1,332
Net change after income taxes	2,525	855
Ending Balance	-59,230	-57,022
Texas-New Mexico Power Company [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance		-263
Amounts reclassified from AOCI (pre-tax)		55
Income tax impact of amounts reclassified		-19
Other OCI changes (pre-tax)		-153
Income tax impact of other OCI changes		53
Net change after income taxes		-64
Ending Balance		-327
PNMR [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning Balance	-61,755	-58,140
Amounts reclassified from AOCI (pre-tax)	-2,684	-1,912
Income tax impact of amounts reclassified	1,052	756
Other OCI changes (pre-tax)	6,836	3,226
Income tax impact of other OCI changes	-2,679	-1,279
Net change after income taxes	2,525	791
Ending Balance	($59,230)	($57,349)

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Oct. 08, 2013
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings attributable to non-controlling interest	$3,380,000	$3,531,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	503,721,000		432,817,000
Total assets	5,939,339,000	5,507,026,000	5,829,325,000
Current liabilities	693,034,000		704,282,000
Owners’ equity – non-controlling interest	72,766,000		73,546,000
Net earnings	14,340,000	12,468,000
Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Renewal Options After Original Lease Term (in years)	2 years
Operating Leases, Extended Lease Term Option (in years)	6 years
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Next Six Months	8,400,000		26,000,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Property Lease Guarantee [Member] | Maximum [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Loss Contingency, Range of Possible Loss, Portion Not Accrued	217,300,000
Valencia [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs	4,800,000	4,800,000
Long Term Contract For Purchase of Electric Power Variable Charges	100,000	200,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues	4,904,000	4,931,000
Operating expenses	-1,524,000	-1,400,000
Earnings attributable to non-controlling interest	3,380,000	3,531,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current assets	2,839,000		2,513,000
Net property, plant, and equipment	71,679,000		72,321,000
Total assets	74,518,000		74,834,000
Current liabilities	1,752,000		1,288,000
Owners’ equity – non-controlling interest	72,766,000		73,546,000
Long term contract option to purchase, ownership percentage	50.00%
Long term contract option to purchase, purchase price - percentage of adjusted NBV	50.00%
Long term contract option to purchase, purchase price - percentage of FMV	50.00%
Long term contract option to purchase, number of days to set FMV	60 days
Long term contract option to purchase, estimated purchase price				85,000,000
Long term contract option to purchase, approximate approval period	15 months
Valencia [Member] | Public Service Company of New Mexico [Member] | Purchased Through May 30, 2028 [Member]
Variable Interest Entity [Line Items]
Number of mega watts purchased (in megawatts)	158
Variable Interest Entity, Not Primary Beneficiary [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating leases, future minimum payments due, renewal term	150,500,000
Delta [Member] | Public Service Company of New Mexico [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs		1,600,000
Long Term Contract For Purchase of Electric Power Variable Charges		200,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Period of Long Term Contract For Purchase of Electric Power Fixed Costs	20 years
Delta [Member] | Public Service Company of New Mexico [Member] | Delta [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Revenues		1,800,000
Net earnings		$300,000

Lease_Commitments_Details

Lease Commitments (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	1-May-14	Jun. 01, 2014	Jan. 14, 2016
		MW
Public Service Company of New Mexico [Member]
Operating Leased Assets [Line Items]
Public Utilities, Option to Purchase Leased Capacity At Fair Value	7.7
Public Service Company of New Mexico [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Operating Leased Assets [Line Items]
Public Utilities, Lease ownership percentage in EIP	60.00%
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 31.2494 MW [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset to be paid	78.1
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]
Operating Leased Assets [Line Items]
Leased Capacity to be Purchased		32.76
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases, January 15, 2016 [Member]
Operating Leased Assets [Line Items]
Leased Capacity to be Purchased	31.25
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset to be paid	85.2
Early Purchase Price of Leased Asset, Period 1			79.9
Early Purchase Price of Leased Asset	82.5
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Maximum [Member]
Operating Leased Assets [Line Items]
Additional consideration for early purchase of leased asset, Period 1			5.8
Additional consideration for early purchase of leased asset, Period 2	2.7
Tortoise Capital Resources Corporation [Member] | TGP Granada, LLC and its affiliate Complaint [Member]
Operating Leased Assets [Line Items]
Public Utilities, Lease ownership percentage in EIP	40.00%
Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member]
Operating Leased Assets [Line Items]
Purchase Price of Leased Asset, Period 3				85.2
Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station, Unit 2 Leases 32.76 MW [Member] | Minimum [Member]
Operating Leased Assets [Line Items]
Additional consideration for early purchase of leased asset effective June 1, 2014				$1.20

Fair_Value_of_Derivative_and_O2

Fair Value of Derivative and Other Financial Instruments - Derivative Balance Sheet Information (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Current assets	$9,342,000	$11,232,000
Commodity derivative instruments, Current liabilities	-1,235,000	-1,209,000
Commodity derivative instruments, Long-term liabilities	-277,000	-477,000
Assets, Current	503,721,000	432,817,000
PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Derivative, Collateral, Right to Reclaim Cash	0	0
Margin Deposit Assets	2,800,000	3,800,000
Derivative, Collateral, Obligation to Return Cash	200,000	200,000
Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	9,342,000	11,232,000
Deferred charges	0	0
Commodity derivative instruments, Assets	9,342,000	11,232,000
Commodity derivative instruments, Current liabilities	-1,235,000	-1,209,000
Commodity derivative instruments, Long-term liabilities	-277,000	-477,000
Commodity derivative instruments, Liabilities	-1,512,000	-1,686,000
Commodity derivative instruments, Net	7,830,000	9,546,000
Fuel and Purchased Power Adjustment Clause [Member] | Fair Value Hedging [Member] | Commodity Contract [Member] | Public Service Company of New Mexico [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Assets, Current	100,000
Palo Verde Nuclear Generating Station [Member] | Fair Value Hedging [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Derivatives, Fair Value [Line Items]
Current assets	$2,200,000	$3,000,000

Fair_Value_of_Derivative_and_O3

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) (PNMR and PNM [Member], Commodity Contract [Member], Fair Value Hedging [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	($522)	($3,962)
Electric operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	-472	-4,151
Cost of energy [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	($50)	$189

Fair_Value_of_Derivative_and_O4

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) (PNMR and PNM [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative [Line Items]
Contractual Liability	$1,512	$1,686
Existing Cash Collateral	0	0
Net Exposure	$117	$167
Gas related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	575,000	650,000
Power related contract [Member] | Commodity Contract [Member] | Fair Value Hedging [Member] | Derivative Short Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	1,417,913	1,919,000

Fair_Value_of_Derivative_and_O5

Fair Value of Derivative and Other Financial Instruments - Sale of Power (Details)	Mar. 31, 2015	Dec. 31, 2014
	MW
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation	134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, Average Forward Price		37
Firm Contract [Member] | Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Percentage of Electric Power Plant Output Sold for 2014 and 2015	100.00%

Fair_Value_of_Derivative_and_O6

Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Other than Temporary Impairment Losses, Investments, Portion Recognized in Earnings, Net, Available-for-sale Securities	$400,000	$500,000
PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	257,464,000		250,145,000
Available-for-sale Securities, Gross Unrealized Gain	48,842,000		46,348,000
Proceeds from sales	31,852,000	22,804,000
Gross realized gains	5,135,000	3,118,000
Gross realized (losses)	-1,541,000	-1,039,000
PNMR and PNM [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	5,142,000		8,276,000
Available-for-sale Securities, Gross Unrealized Gain	0		0
PNMR and PNM [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	46,129,000		45,340,000
Available-for-sale Securities, Gross Unrealized Gain	16,786,000		17,418,000
PNMR and PNM [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	78,013,000		74,053,000
Available-for-sale Securities, Gross Unrealized Gain	22,849,000		21,354,000
PNMR and PNM [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	17,478,000		16,599,000
Available-for-sale Securities, Gross Unrealized Gain	995,000		156,000
PNMR and PNM [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	21,912,000		22,563,000
Available-for-sale Securities, Gross Unrealized Gain	1,256,000		903,000
PNMR and PNM [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	73,554,000		68,973,000
Available-for-sale Securities, Gross Unrealized Gain	6,198,000		5,851,000
PNMR and PNM [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	15,236,000		14,341,000
Available-for-sale Securities, Gross Unrealized Gain	758,000		666,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	257,464,000		250,145,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Nuclear Decommissioning Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	251,800,000		244,600,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Mine Reclamation Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	5,700,000		5,500,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	5,142,000		8,276,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	46,129,000		45,340,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	78,013,000		74,053,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | International and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	17,478,000		16,599,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	21,912,000		22,563,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	73,554,000		68,973,000
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$15,236,000		$14,341,000

Fair_Value_of_Derivative_and_O7

Fair Value of Derivative and Other Financial Instruments - Debt Maturities (Details) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
PNMR and PNM [Member]
Available-for-sale Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Available-for-sale debt securities, Within 1 year	$5,108
Available-for-sale debt securities, After 1 year through 5 years	17,210
Available-for-sale debt securities, After 5 years through 10 years	14,006
Available-for-sale debt securities, After 10 years through 15 years	10,705
Available-for-sale debt securities, After 15 years through 20 years	12,048
Available-for-sale debt securities, After 20 years	51,625
Available-for-sale debt securities	110,702
PNM Resources [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	17,173
Held-to-maturity debt securities, After 1 year through 5 years	626
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	17,799
Public Service Company of New Mexico [Member]
Held-to-maturity Securities, Debt Maturities, Fair Value, Fiscal Year Maturity [Abstract]
Held-to-maturity debt securities, Due within 1 year	17,173
Held-to-maturity debt securities, After 1 year through 5 years	0
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities	$17,173

Fair_Value_of_Derivative_and_O8

Fair Value of Derivative and Other Financial Instruments - Recurring (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$257,464	$250,145
PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,322,072	2,173,117
Investment In PVNGS lessor notes	17,173	32,836
Other investments	1,135	2,375
PNM Resources [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	0	0
Other investments	509	639
PNM Resources [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,322,072	2,173,117
Investment In PVNGS lessor notes	0	0
Other investments	0	0
PNM Resources [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	17,173	32,836
Other investments	626	1,736
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,627,751	1,624,222
Investment In PVNGS lessor notes	17,173	32,836
Other investments	267	397
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	0	0
Other investments	267	397
Public Service Company of New Mexico [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,627,751	1,624,222
Investment In PVNGS lessor notes	0	0
Other investments	0	0
Public Service Company of New Mexico [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Investment In PVNGS lessor notes	17,173	32,836
Other investments	0	0
Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	427,356	427,356
Other investments	242	242
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	242	242
Texas-New Mexico Power Company [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	427,356	427,356
Other investments	0	0
Texas-New Mexico Power Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	0	0
Other investments	0	0
Reported Value Measurement [Member] | PNM Resources [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	2,125,007	1,975,090
Investment In PVNGS lessor notes	16,806	31,232
Other investments	509	1,762
Reported Value Measurement [Member] | Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	1,490,666	1,490,657
Investment In PVNGS lessor notes	16,806	31,232
Other investments	267	397
Reported Value Measurement [Member] | Texas-New Mexico Power Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt	365,575	365,667
Other investments	242	242
Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	5,142	8,276
Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	46,129	45,340
Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,013	74,053
International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,478	16,599
U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	21,912	22,563
Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	73,554	68,973
Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	15,236	14,341
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	257,464	250,145
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	172,266	169,919
Fair Value, Measurements, Recurring [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	85,198	80,226
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	9,342	11,232
Commodity derivative instruments, Liabilities	-1,512	-1,686
Commodity derivative instruments, Net	7,830	9,546
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	0	0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	9,342	11,232
Commodity derivative instruments, Liabilities	-1,512	-1,686
Commodity derivative instruments, Net	7,830	9,546
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	5,142	8,276
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	5,142	8,276
Fair Value, Measurements, Recurring [Member] | Cash and equivalents [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	46,129	45,340
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	46,129	45,340
Fair Value, Measurements, Recurring [Member] | Domestic value [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,013	74,053
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	78,013	74,053
Fair Value, Measurements, Recurring [Member] | Domestic growth [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,478	16,599
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	17,478	16,599
Fair Value, Measurements, Recurring [Member] | International and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	21,912	22,563
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	20,603	20,808
Fair Value, Measurements, Recurring [Member] | U.S. Government [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,309	1,755
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	73,554	68,973
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Fair Value, Measurements, Recurring [Member] | Municipals [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	73,554	68,973
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	15,236	14,341
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	4,901	4,843
Fair Value, Measurements, Recurring [Member] | Corporate and other [Member] | PNMR and PNM [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$10,335	$9,498

StockBased_Compensation_Detail

Stock-Based Compensation (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$8,300,000		$6,500,000
Options, Outstanding at end of period, No intrinsic value	248,750
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested Restricted Stock, Nonvested at beginning of period, Shares	920,505
Nonvested Restricted Stock, Granted, Shares	0
Nonvested Restricted Stock, Vested, Shares	-149,277
Nonvested Restricted Stock, Forfeited, Shares	-5,300
Nonvested Restricted Stock, Nonvested at end of period, Shares	765,928
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$20.39
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	$0
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value (in dollars per share)	$21.34
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value (in dollars per share)	$30.50
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value (in dollars per share)	$19.97
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value	$0
Weighted-average grant date fair value of options granted	$0	$0
Total fair value of options that vested (in thousands)	0	0
Total intrinsic value of options exercised (in thousands)	1,138,000	1,469,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options, Outstanding at end of period, Aggregate Intrinsic Value	7,400,000
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	2 years 6 months 11 days
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected quarterly dividends per share	$0.20	$0.19
Risk-free interest rate	1.07%	0.71%
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	258,770
Options, Granted, Shares	317,756
Options, Exercised, Shares	-327,479
Options, Forfeited, Shares	0
Options, Expired, Shares	0
Options, Outstanding at end of period, Shares	249,047
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Outstanding at beginning of period, Weighted-Average Exercise Price (in dollars per share)	$22.31
Options, Granted, Weighted-Average Exercise Price (in dollars per share)	$19.93
Options, Exercised, Weighted-Average Exercise Price (in dollars per share)	$18.34
Options, Forfeited, Weighted-Average Exercise Price (in dollars per share)	$0
Options, Expired, Weighted-Average Exercise Price (in dollars per share)	$0
Options, Outstanding at end of period, Weighted-Average Exercise Price (in dollars per share)	$24.48
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value (in dollars per share)	$19.93	$20.79
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value	$19.93	$20.79
Total fair value of restricted shares that vested (in thousands)	6,005,000	4,336,000
Market-Based Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	1.00%	0.64%
Dividend yield	2.87%	2.82%
Expected volatility	18.73%	25.11%
Executive [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Included from Shares Outstanding, Number	179,845
Share based Compensation, weighted percentage assigned to achieving market targets	60.00%
Share based Compensation, weighted percentage assigned to achieving performance targets	40.00%
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year One	179,811
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Two	163,152
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in Year Three	168,258
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	135,000
Chairman, President, and Chief Executive Officer [Member] | Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	35,000
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2019 and she remains an employee [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	53,859
Chairman, President, and Chief Executive Officer [Member] | Achieves a specific performance target by the end of 2017 and she remains an employee [Member] [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return	17,953
Achieved performance target for 2015 and 2016 [Member] | Executive Vice President and Chief Financial Officer [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock	100,000
Achieved performance target for 2015, 2016 and 2017 [Member] | Executive Vice President and Chief Financial Officer [Member] | Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, Purchase price of common stock	$275,000
Performance Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate	100.00%

Financing_Financing_Activities

Financing - Financing Activities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 09, 2015	Mar. 05, 2014	Apr. 22, 2013
Debt Instrument [Line Items]
Short-term debt	$100,000,000	$105,600,000
PNMR 2015 Term Loan Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt			150,000,000
Debt Instrument, Interest Rate at Period End	1.18%
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 at Period End	1.13%
PNM Term Loan Agreement [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Short-term debt					$75,000,000

Financing_Shortterm_Debt_Detai

Financing - Short-term Debt (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Apr. 24, 2015	Jan. 08, 2014
Short-term Debt [Line Items]
Short-term debt	$100,000,000	$105,600,000
Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			814,000,000
PNMR Term Loan Agreement [Member]
Short-term Debt [Line Items]
Short-term debt	100,000,000	100,000,000
Short-term Debt, Weighted Average Interest Rate	1.03%
PNM Resources [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			292,300,000
Restricted Cash and Investments			87,400,000
Public Service Company of New Mexico [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			396,800,000
Restricted Cash and Investments			0
Public Service Company of New Mexico [Member] | Subsequent Event [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Short-term debt – affiliate			26,400,000
Public Service Company of New Mexico [Member] | PNM 2014 Multi-Draw Term Loan Agreement [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount			25,000,000
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member]
Short-term Debt [Line Items]
Debt Instruments, NMPRC Approved credit facility				50,000,000
Short-term debt	0	0
Public Service Company of New Mexico [Member] | Local Lines of Credit [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			50,000,000
Texas-New Mexico Power Company [Member] | Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			74,900,000
Restricted Cash and Investments			0
Texas-New Mexico Power Company [Member] | Subsequent Event [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Short-term debt – affiliate			38,400,000
Texas-New Mexico Power Company [Member] | Intercompany loan agreements [Member]
Short-term Debt [Line Items]
Short-term debt - affiliate	28,500,000
Line of Credit [Member]
Short-term Debt [Line Items]
Short-term debt	100,000,000	105,600,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Short-term debt	0
Revolving Credit Facility [Member] | PNM Resources [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	300,000,000
Short-term debt	0	600,000
Revolving Credit Facility [Member] | Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	400,000,000
Short-term debt	0	0
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	75,000,000
Short-term debt	0	5,000,000
Revolving Credit Facility [Member] | Texas-New Mexico Power Company [Member] | First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]
Short-term Debt [Line Items]
Debt Instrument, Collateral Amount	$75,000,000

Pension_and_Other_Postretireme2

Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$0	$0
Interest cost	7,064,000	7,541,000
Expected return on plan assets	-9,831,000	-9,511,000
Amortization of net (gain) loss	3,705,000	3,255,000
Amortization of prior service cost	-241,000	-241,000
Net Periodic Benefit Cost (Income)	697,000	1,044,000
Defined Benefit Plan, Contributions by Employer	30,000,000	0
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	22,000,000
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	4.80%
Public Service Company of New Mexico [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	5.50%
Public Service Company of New Mexico [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	51,000	45,000
Interest cost	1,022,000	1,159,000
Expected return on plan assets	-1,403,000	-1,410,000
Amortization of net (gain) loss	491,000	556,000
Amortization of prior service cost	-160,000	-336,000
Net Periodic Benefit Cost (Income)	1,000	14,000
Defined Benefit Plan, Contributions by Employer	800,000	800,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	14,000,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	3,500,000
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0
Interest cost	190,000	205,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	81,000	52,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	271,000	257,000
Defined Benefit Plan, Contributions by Employer	500,000	400,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,500,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0
Interest cost	761,000	798,000
Expected return on plan assets	-1,105,000	-1,132,000
Amortization of net (gain) loss	195,000	166,000
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	-149,000	-168,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	0
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	4.80%
Texas-New Mexico Power Company [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate (as a percent)	5.50%
Texas-New Mexico Power Company [Member] | OPEB [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	62,000	59,000
Interest cost	152,000	155,000
Expected return on plan assets	-130,000	-133,000
Amortization of net (gain) loss	0	-31,000
Amortization of prior service cost	0	8,000
Net Periodic Benefit Cost (Income)	84,000	58,000
Defined Benefit Plan, Contributions by Employer	0	0
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	1,400,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	300,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0
Interest cost	9,000	10,000
Expected return on plan assets	0	0
Amortization of net (gain) loss	1,000	0
Amortization of prior service cost	0	0
Net Periodic Benefit Cost (Income)	10,000	10,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	100,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member] | Maximum [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	$100,000	$100,000

Commitments_and_Contingencies_

Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) (Palo Verde Nuclear Generating Station [Member], Public Service Company of New Mexico [Member], USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Nuclear Spent Fuel And Waste Disposal [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$58,000,000
Revised Annual Fee, Nuclear Waste Disposal	0
Nuclear Spent Fuel And Waste Disposal [Member] | Other Deferred Credits [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual	12,400,000	12,300,000
Nuclear Spent Fuel And Waste Disposal [Member] | Settled Litigation [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Lawsuit settlement, third party receipt	57,400,000
PNMs share of lawsuit settlement, third party receipt	5,900,000
Department of energy, spent nuclear fuel removal July 2011 - June 2014 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Lawsuit settlement, third party receipt	42,000,000
PNMs share of third party settlement claim	4,300,000
Litigation Settlement, Portion credited to customers	$3,100,000

Commitments_and_Contingencies_1

Commitments and Contingencies - The Clean Air Act (Details) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Oct. 01, 2014	Dec. 20, 2013	Mar. 31, 2015	Oct. 31, 2012	Jun. 26, 2014
		MW	state		MW
Clean Air Act related to Regional Haze [Member]
Public Utilities, Commitments And 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
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share				46.30%
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Overall Reduction Of Ownership, in Megawatts		340
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Total Capital Cost If Requirement Occurred				824
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs				85
Estimated Portion of Total Capital Costs if Requirement Occured				105
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SCR [Member] [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Total Capital Cost If Requirement Occurred				910
San Juan Generating Station [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs				90
Estimated Portion of Total Capital Costs if Requirement Occured				110
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Requested Time Period to Recover Retired Units NBV	20 years	20 years
Public Utilities, Newly Identified Replacement Gas-fired Generation, in Megawatts, December2013		177
Public Utilities, Newly Identified Replacement Solar Generation, in Megawatts, December2013		40
San Juan Generating Station Units 2 and 3 [Member] | Pnm Electric [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units			212.5
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed value per Kilowatt effective January 1, 2018	1,650
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation			134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation	134	134
Public Utilities, Proposed value per Kilowatt effective January 1, 2018		2,500
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs	90.6	82
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts	132	78	132		132
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership To Be Exchanged, in Megawatts		78

Commitments_and_Contingencies_2

Commitments and Contingencies - Stipulation Filed with the NMPRC (Details) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Apr. 08, 2015	Oct. 01, 2014	Dec. 20, 2013	Mar. 31, 2015	Jan. 15, 2015	Jun. 26, 2014
				MW	MW	MW
San Juan Generating Station Unit 4 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts		132	78	132		132
Public Utilities, Estimated rate base value at 1/1/2018		$26
Public Utilities, Ownership in Megawatts PNM has agreed not to obtain					65
San Juan Generating Station Unit 4 [Member] | Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Additional Ownership To Be Obtained, in Megawatts	132
Period of time to accept or reject modifications in recommendation	7 days
San Juan Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed reduction in carrying value		26
Public Utilities,Estimated unrecoverable increase in operations and maintenance		20
San Juan Generating Station Unit 3 [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities,Estimated pre-tax regulatory disallowance		70
San Juan Generating Station Unit 3 [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities,Estimated pre-tax regulatory disallowance		60
San Juan Generating Station Unit 3 [Member] | Subsequent Event [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities,Estimated pre-tax regulatory disallowance	155
San Juan Generating Station Unit 3 [Member] | Subsequent Event [Member] | Minimum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities,Estimated pre-tax regulatory disallowance	145
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Net book value				280
San Juan Generating Station Units 2 and 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Recovery Percentage of Estimated undepreciated value at 12/31/17		50.00%
Public Utilities, Estimated undepreciated value at 12/31/17		231
Public Utilities, Requested Time Period to Recover Retired Units NBV		20 years	20 years
Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17		50.00%
San Juan Generating Station Units 2 and 3 [Member] | Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated undepreciated value at 12/31/17	128.5
Public Utilities, Write-off Percentage of Estimated undepreciated value at 12/31/17	50.00%
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Net book value				145
Palo Verde Nuclear Generating Station Unit 3 [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated rate base value at 1/1/2018		221.1
Public Utilities, Proposed value per Kilowatt effective January 1, 2018		1,650
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation				134
Palo Verde Nuclear Generating Station Unit 3 [Member] | PNMR and PNM [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Megawatts Nuclear Generation		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
Palo Verde Nuclear Generating Station Unit 3 [Member] | Subsequent Event [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR Hearing Examiner Recommended Denial [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Estimated rate base value at 1/1/2018	143.5
Public Utilities, Proposed value per Kilowatt effective January 1, 2018	1,071
San Juan Generating Station Units 1 and 4 [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | Maximum [Member] | Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Estimated Installation Capital Costs		$90.60	82

Commitments_and_Contingencies_3

Commitments and Contingencies - SJGS Matters (Details) (USD $)	Jan. 07, 2015	Jun. 26, 2014	Mar. 31, 2015	Oct. 01, 2014	Dec. 20, 2013	Jan. 22, 2015	Jun. 27, 2014	Mar. 11, 2014
	MW			MW	MW
Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Unsubscribed Ownership in Megawatts	65
Public Service Company of New Mexico [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share		64.50%
Public Service Company of New Mexico [Member] | San Juan Generating Station Units 1 and 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Jointly Owned Utility Plan, Proposed Proportionate Ownership Share		58.70%
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 3 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Percentage of ownership held by exiting owners			50.00%
Public Utilities, Ownership Percentage			50.00%
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Percentage of ownership held by exiting owners			38.80%
Public Utilities, Ownership Percentage			38.50%
Public Utilities, Additional Ownership To Be Obtained, in Megawatts		132	132	132	78
Public Utilities, Costs to obtain additional ownership		0
Public Service Company of New Mexico [Member] | Clean Air Act, SNCR [Member] | Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Requested Expenditure, Installation Capital Costs						76,600,000		1,900,000
Requested Additional Expenditure, Installation Capital Costs							$6,400,000
PNMR Development [Member] | Clean Air Act, SNCR [Member] | San Juan Generating Station Unit 4 [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Potential Acquisition of Ownership in Megawatts	65		65

Commitments_and_Contingencies_4

Commitments and Contingencies - Four Corners (Details) (USD $)	Dec. 31, 2013	Mar. 31, 2015	Aug. 06, 2012
In Millions, unless otherwise specified			compliance_alternative
Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Jointly Owned Utility Plant, Sale of Ownership Percentage	48.00%
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Number of Compliance alternatives			2
Public Utilities, Plant Requirement to Meet NOx emissions Limit		0.015
Public Utilities, Plant Requirement to Meet Opacity Limit, Percentage		20.00%
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations		20.00%
Loss Contingency, Estimate of Possible Loss		$83.90
Clean Air Act Related to Post Combustion Controls [Member] | Public Service Company of New Mexico [Member] | Four Corners Units 4 and 5 (Coal) [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership Percentage		13.00%

Commitments_and_Contingencies_5

Commitments and Contingencies - National Ambient Air Quality Standards (Details) (Public Service Company of New Mexico [Member])	0 Months Ended
	Mar. 02, 2015	Nov. 25, 2014	Jan. 31, 2010	Mar. 31, 2015	Nov. 08, 2013
		opp	opp	opp
National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Period of time to act on settlement	16 months
Public Utilities, Emissions Tons of SO2 per year	16,000
Minimum [Member] | National Ambient Air Quality Standards, 2015 EPA Legal Settlement [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Emissions Tons of SO2 per year	2,600
Public Utilities, 1-hour SO2 Emissions Rate	0.45
San Juan Generating Station And Four Corners [Member] | Minimum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed Government Standard Emission Limit		65	60
San Juan Generating Station And Four Corners [Member] | Maximum [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed Government Standard Emission Limit		70	70
Public Utilities, Government Standard Emission Limit				75
San Juan Generating Station [Member] | National Ambient Air Quality Standards [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Revised SO2 Emissions Agreed Upon					0.1

Commitments_and_Contingencies_6

Commitments and Contingencies - Litigation and Rulemaking (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 21, 2011
		mw
Public Utilities, Commitments And Contingencies [Line Items]
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Mercury and Air Toxics Standards		25
San Juan Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Mercury Removal Rate, Percentage		99.00%
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Mercury Control [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Current Annual Mercury Control Costs	$0.70
Public Service Company of New Mexico [Member] | San Juan Generating Station [Member] | Maximum [Member] | Mercury Control [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Contingent Estimated Annual Mercury Control Cost	$6.60

Commitments_and_Contingencies_7

Commitments and Contingencies - Coal Supply (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$65,264,000	$58,471,000
Public Service Company of New Mexico [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory Assets	100,000,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual	25,600,000	25,700,000
Final Reclamation, capped amount to be collected	100,000,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency Accrual	8,800,000	8,600,000
Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Annual Funding		1,000,000	300,000	3,500,000
Public Utilities, Expected Funding Annual Requirements	600,000
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Surface [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	57,000,000
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member] | Loss on Long-term Purchase Commitment [Member] | Underground [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	93,300,000
San Juan Generating Station [Member] | Coal Supply [Member] | Public Service Company of New Mexico [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$38,900,000	$37,300,000
Public Utilities, Estimated Increase in Coal Cost, Percentage	30.00%

Commitments_and_Contingencies_8

Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details) (USD $)	Mar. 31, 2015	Apr. 01, 2014	Jan. 22, 2015	Apr. 02, 2014	Jan. 06, 2014	Sep. 30, 2012
			Allotment_Parcel	Allotment_Parcel	Allotment_Parcel	Allotment_Parcel
Continuous Highwall Mining [Member] | San Juan Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Proposed Retroactive Surface Mining Royalty Rate	12.50%
Public Utilities, Current Surface Mining Royalty Rate applied between 2000 and 2003	8.00%
Public Utilities, Estimated Underpaid Surface Mining Royalties under proposed rate change	$5,000,000
Public Utilities, PNM Share Estimated Underpaid Surface Mining Royalties under proposed rate change	46.30%
NMTRD Coal Severance Tax [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest	30,000,000
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Ownership Percentage in Nuclear Reactor	10.20%
Public Utilities, Maximum Potential Assessment Per Incident	38,900,000
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, Maximum Amount under Nuclear Electric Insurance Limited	5,400,000
Public Service Company of New Mexico [Member] | Nuclear Plant [Member] | Maximum [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage	13,600,000,000
Public Utilities, Liability Insurance Coverage Sublimit		2,250,000,000
Public Service Company of New Mexico [Member] | NMTRD Coal Severance Tax [Member] | Four Corners [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, PNM Share Assessed Coal Severance Surtax Penalty and Interest to pass through FFPAC	9.40%
Public Service Company of New Mexico [Member] | Navajo Nation Allottee Matters [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Number of landowners claiming to be Navajo allottees						43
Number of allotment parcels' appraisal requested for review					58
Number of allotments where landowners are revoking rights of way renewal consents			10	6
Public Service Company of New Mexico [Member] | Commercial Providers [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage	375,000,000
Public Service Company of New Mexico [Member] | Industry Wide Retrospective Assessment Program [Member] | Nuclear Plant [Member] | Palo Verde Nuclear Generating Station [Member]
Public Utilities, Commitments And Contingencies [Line Items]
Public Utilities, Liability Insurance Coverage	$13,200,000,000

Regulatory_and_Rate_Matters_El

Regulatory and Rate Matters - Electric Rate Case (Details) (2014 Electric Rate Case [Member], Public Service Company of New Mexico [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
2014 Electric Rate Case [Member] | Public Service Company of New Mexico [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$107.40
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%
Proposed period of delay	60 days

Regulatory_and_Rate_Matters_Re

Regulatory and Rate Matters - Renewable Portfolio Standard and Energy Rider (Details) (Public Service Company of New Mexico [Member], USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
	MWh		MWh
Renewable Portfolio Standard [Member] | Required Percentage by 2011 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	10.00%
Renewable Portfolio Standard [Member] | Required Percentage by 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	15.00%
Renewable Portfolio Standard [Member] | Required Percentage by 2020 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales	20.00%
2014 Wind generated Renewable Energy Credits [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watt Hours of Wind Generation	50,000
Renewable Portfolio Standard 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Final Cost of Solar Photovoltaic Capacity		$46,500,000
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity	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
2015 Wind generated Renewable Energy Credits [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watt Hours of Wind Generation	120,000
Renewable Portfolio Standard 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity	40
Public Utilities, Estimated Cost of Mega Watts of Solar Photovoltaic Capacity	79,300,000
Public Utilities, Approved Revised cost per MWh for additional necessary procurements to comply with RPS			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
Renewable Energy Rider [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revenue from Renewable energy rider			34,300,000
Minimum [Member] | Wind Energy [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	30.00%
Minimum [Member] | Solar Energy [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	20.00%
Minimum [Member] | Renewable Technologies [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	5.00%
Minimum [Member] | Distributed Generation [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Required Percentage of Diversification	3.00%
Maximum [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Reasonable Cost Threshold	3.00%
Maximum [Member] | Renewable Energy Rider [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013	10.50%	10.50%
Public Utilities, Annual Revenue To be Collected Under 2015 Rider Rate	44,700,000
Public Utilities, Revised Annual Revenue To be Collected Under 2015 Rider Rate	43,000,000

Regulatory_and_Rate_Matters_En

Regulatory and Rate Matters - Energy Efficiency and Load Management (Details) (Public Service Company of New Mexico [Member], USD $)	0 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Oct. 06, 2014	Mar. 31, 2015	Dec. 31, 2014
Maximum [Member] | Renewable Portfolio Standard [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Reasonable Cost Threshold		3.00%
Disincentives / Incentives Adder [Member] | Energy Efficiency and Load Management [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Program Costs Related To Energy Efficiency	$25.80
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program, Percentage of Program Costs		7.60%
Public Utilities, Approved Profit Incentive Adder Revenues Related To Energy Efficiency Program		1.7
Public Utilities, Proposed Profit Incentive Adder Revenues Related To 2015 Energy Efficiency Program	2.1
Disincentives / Incentives Adder [Member] | 2014 Energy Efficiency and Load Management Program [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Anticipated future profit incentive 2015			1.7
Public Utilities, Anticipated future profit incentive 2016			$1.80

Regulatory_and_Rate_Matters_In

Regulatory and Rate Matters - Integrated Resource Plan and Four Corners Right of First Refusal (Details) (Public Service Company of New Mexico [Member])	1 Months Ended	3 Months Ended	4 Months Ended
	Jul. 31, 2011	Mar. 31, 2015	Jun. 17, 2015	Feb. 17, 2015
Integrated Resource Plan, 2011 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Frequency of IRP filings		3 years
Public Utilities, Planning Period Covered of IRP	20 years
Four Corners [Member]
Public Utilities, General Disclosures [Line Items]
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities				7.00%
Subsequent Event [Member] | Four Corners [Member]
Public Utilities, General Disclosures [Line Items]
Period of time to file a waiver of rights of first refusal			120 days

Regulatory_and_Rate_Matters_Fo

Regulatory and Rate Matters - Formula Transmission Rate Case (Details) (Formula Transmission Rate Case [Member], Public Service Company of New Mexico [Member], USD $)	0 Months Ended		3 Months Ended
In Millions, unless otherwise specified	2-May-14	Jun. 03, 2013	Mar. 31, 2015	Mar. 20, 2015
				party
Formula Transmission Rate Case [Member] | Public Service Company of New Mexico [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Regulatory Costs Not yet Approved			$3.20
Public Utilities, Return on Equity			10.81%	10.00%
Percentage ownership of EIP transmission line			60.00%
Public Utilities, Requested Rate Increase (Decrease), Amount	0.5	1.3
Number of other parties to settlement				5
Public Utilities, Approved Rate Increase (Decrease), Amount			$1.30

Regulatory_and_Rate_Matters_Fi

Regulatory and Rate Matters - Firm-Requirements Wholesale Customers (Details) (Public Service Company of New Mexico [Member], USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
		MW
Firm Requirements Wholesale Power Rate Case, Navopache [Member] [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$5.30
Public Utilities, Average monthly usage in megawatts		55
Public Utilities, Revenue For Power Sold Under Specific Contract		28.4
Firm Requirements Wholesale Power Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Contract Extension	10 years
City of Gallup, New Mexico Contract [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revenue For Power Sold Under Specific Contract	$6.10

Regulatory_and_Rate_Matters_TN

Regulatory and Rate Matters - TNMP Narrative (Details) (Texas-New Mexico Power Company [Member], USD $)	1 Months Ended
	Jul. 30, 2011	Mar. 31, 2015	Apr. 24, 2015
		customer	customer
Advanced Meter System Deployment and Surcharge Request [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Deployment Costs	$113,400,000
Public Utilities, Collection of Deployment Costs Through Surcharge Period	12 years
Public Utilities, Completion Period of Advanced Meter Deployment	5 years
Public Utilities, Non-standard metering service cost total to be borne by opt-out customers		200,000
Public Utilities, Non-standard metering ongoing expenses total to be borne by opt-out customers		500,000
Public Utilities, Approved Non-standard metering ongoing expenses monthly charge		36.78
Presumed number of customers that will elect non-standard meter service		1,081
Energy Efficiency [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved 2014 Program Implementation Costs		5,600,000
Public Utilities, Unapproved 2015 Program Implementation Costs, Bonus		700,000
Public Utilities, Unapproved 2015 Program Implementation Costs		5,700,000
Public Utilities, Approved 2014 Incentive Portion of Program Implementation Costs		1,500,000
Public Utilities, Approved 2015 Program Implementation Costs		5,700,000
Minimum [Member] | Advanced Meter System Deployment and Surcharge Request [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Non-standard metering service cost initial fee range		63.97
Maximum [Member] | Advanced Meter System Deployment and Surcharge Request [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Non-standard metering service cost initial fee range		$168.61
Subsequent Event [Member] | Advanced Meter System Deployment and Surcharge Request [Member]
Public Utilities, General Disclosures [Line Items]
Current number of customers that have elected non-standard meter service			91

Regulatory_and_Rate_Matters_Tr

Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) (Transmission Cost of Service Rates [Member], Texas-New Mexico Power Company [Member], USD $)	6 Months Ended
In Millions, unless otherwise specified	Mar. 15, 2015	Sep. 07, 2014	Mar. 12, 2014	Sep. 15, 2015
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base	$25.20	$18.20	$18.10
Annual Increase in Revenue	4.2	2.9	2.8
Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base				27.1
Annual Increase in Revenue				$4.40

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Tax Contingency [Line Items]
New Mexico Corporate tax rate, current	7.60%
New Mexico Corporate tax rate, 2014	5.90%
Decrease in regulatory liabilities due to change in state corporate tax rate	$2	$4.60
Decrease in deferred tax asset due to change in state corporate tax rate		0.2
State Net Operating Loss Carryforward, Impairment	1
Public Service Company of New Mexico [Member]
Income Tax Contingency [Line Items]
Increase in deferred tax asset not related to regulatory activity, as a result of tax rate change	0.7
Decrease in income tax expense due to tax rate change	0.5
State Net Operating Loss Carryforward, Impairment	0.7
Corporate and Other [Member]
Income Tax Contingency [Line Items]
Decrease in income tax expense due to tax rate change	0.2
State Net Operating Loss Carryforward, Impairment	$0.30

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$22,727	$21,066
Service billings [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	7,078	7,261
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	92	109
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	10	0
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	6	53
Interest charges [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	79	96
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	29	26
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	0
Income tax sharing payments [Member] | PNMR to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$0	$0