TXNM Energy (TXNM) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 21, 2014	Jun. 28, 2013
Document Information [Line Items]	'	'	'
Entity Registrant Name	'PNM RESOURCES INC	'	'
Entity Central Index Key	'0001108426	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	79,653,624	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$1,767,513,917
Public Service Company of New Mexico [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'PUBLIC SERVICE CO OF NEW MEXICO	'	'
Entity Central Index Key	'0000081023	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	39,117,799	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Texas-New Mexico Power Company [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'TEXAS NEW MEXICO POWER CO	'	'
Entity Central Index Key	'0000022767	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	6,358	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'Yes	'	'
Entity Current Reporting Status	'No	'	'

Consolidated_Statements_of_Ear

Consolidated Statements of Earnings (Loss) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Electric Operating Revenues	'	'	'
Electric Domestic Regulated Revenue	'	'	$1,700,619
Revenue from Related Parties	'	'	0
Electric Operating Revenues	1,387,923	1,342,403	1,700,619
Operating Expenses:	'	'	'
Cost of energy	432,316	399,850	692,922
Administrative and general	179,210	187,740	257,774
Energy production costs	175,819	185,417	180,850
Regulatory disallowances	12,235	0	21,402
Depreciation and amortization	166,881	164,173	157,047
Transmission and distribution costs	70,124	71,125	69,693
Taxes other than income taxes	64,496	60,377	63,632
Total operating expenses	1,101,081	1,068,682	1,443,320
Operating income	286,842	273,721	257,299
Other Income and Deductions:	'	'	'
Interest income	10,043	13,072	15,515
Gains on available-for-sale securities	10,612	12,965	8,985
Other income	10,572	12,746	5,309
Gain on sale of First Choice	0	1,012	174,925
Other (deductions)	-21,552	-17,636	-24,715
Net other income and deductions	9,675	22,159	180,019
Interest Charges	121,448	120,845	124,849
Earnings before Income Taxes	175,069	175,035	312,469
Income Taxes	59,513	54,910	121,535
Net Earnings	115,556	120,125	190,934
(Earnings) Attributable to Valencia Non-controlling Interest	-14,521	-14,050	-14,047
Preferred Stock Dividend Requirements of Subsidiary	-528	-528	-528
Net Earnings (Loss) Attributable to Company	100,507	105,547	176,359
Net Earnings Attributable to PNMR per Common Share:	'	'	'
Basic	$1.26	$1.32	$1.98
Diluted	$1.25	$1.31	$1.96
Public Service Company of New Mexico [Member]	'	'	'
Electric Operating Revenues	'	'	'
Electric Operating Revenues	1,116,312	1,092,264	1,057,289
Operating Expenses:	'	'	'
Cost of energy	374,710	353,649	362,237
Administrative and general	157,144	169,285	157,217
Energy production costs	175,819	185,403	180,802
Regulatory disallowances	12,235	0	17,479
Depreciation and amortization	103,826	97,291	94,787
Transmission and distribution costs	45,936	46,039	45,768
Taxes other than income taxes	37,457	34,715	37,556
Total operating expenses	907,127	886,382	895,846
Operating income	209,185	205,882	161,443
Other Income and Deductions:	'	'	'
Interest income	10,182	13,243	15,562
Gains on available-for-sale securities	10,612	12,965	8,985
Other income	7,650	8,126	2,220
Other (deductions)	-6,974	-7,801	-6,896
Net other income and deductions	21,470	26,533	19,871
Interest Charges	79,175	76,101	75,349
Earnings before Income Taxes	151,480	156,314	105,965
Income Taxes	48,804	50,713	37,427
Net Earnings	102,676	105,601	68,538
(Earnings) Attributable to Valencia Non-controlling Interest	-14,521	-14,050	-14,047
Net Earnings (Loss) Attributable to Company	88,155	91,551	54,491
Preferred Stock Dividends Requirements	-528	-528	-528
Net Earnings (Loss) Available for Company Common Stock	87,627	91,023	53,963
Texas-New Mexico Power Company [Member]	'	'	'
Electric Operating Revenues	'	'	'
Electric Domestic Regulated Revenue	271,611	250,140	204,045
Revenue from Related Parties	0	0	33,813
Electric Operating Revenues	271,611	250,140	237,858
Operating Expenses:	'	'	'
Cost of energy	57,606	46,201	41,166
Administrative and general	44,635	40,775	39,485
Regulatory disallowances	0	0	3,923
Depreciation and amortization	50,219	49,340	44,616
Transmission and distribution costs	24,188	25,086	23,915
Taxes other than income taxes	22,778	21,218	20,911
Total operating expenses	199,426	182,620	174,016
Operating income	72,185	67,520	63,842
Other Income and Deductions:	'	'	'
Interest income	0	1	2
Other income	2,377	4,698	1,753
Other (deductions)	-458	-1,959	-173
Net other income and deductions	1,919	2,740	1,582
Interest Charges	27,393	28,161	29,286
Earnings before Income Taxes	46,711	42,099	36,138
Income Taxes	17,621	15,352	13,881
Net Earnings (Loss) Attributable to Company	$29,090	$26,747	$22,257

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Earnings	$100,507	$105,547	$176,359
Net Earnings	115,556	120,125	190,934
Unrealized Gain on Available-for-Sale Securities:	'	'	'
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	16,564	23,286	20,718
Reclassification adjustment for (gains) included in net earnings (loss), net of income tax expense	-7,222	-22,514	-21,295
Pension Liability Adjustment:	'	'	'
Experience gain (loss), net of income tax (expense) benefit	10,355	-18,174	-1,771
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax (expense) benefit	3,840	2,786	2,593
Fair Value Adjustment for Designated Cash Flow Hedges:	'	'	'
Change in fair market value, net of income tax (expense) benefit	-181	-275	-653
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense	134	117	2,218
Total Other Comprehensive Income (Loss)	23,490	-14,774	1,810
Comprehensive Income	139,046	105,351	192,744
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-14,521	-14,050	-14,047
Preferred Stock Dividend Requirements of Subsidiary	-528	-528	-528
Comprehensive Income Attributable to PNMR	123,997	90,773	178,169
Public Service Company of New Mexico [Member]	'	'	'
Net Earnings	88,155	91,551	54,491
Net Earnings	102,676	105,601	68,538
Unrealized Gain on Available-for-Sale Securities:	'	'	'
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	16,564	23,286	20,718
Reclassification adjustment for (gains) included in net earnings (loss), net of income tax expense	-7,222	-22,514	-21,295
Pension Liability Adjustment:	'	'	'
Experience gain (loss), net of income tax (expense) benefit	10,355	-18,174	-2,035
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax (expense) benefit	3,840	2,786	2,584
Fair Value Adjustment for Designated Cash Flow Hedges:	'	'	'
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense	0	0	16
Total Other Comprehensive Income (Loss)	23,537	-14,616	-12
Comprehensive Income	126,213	90,985	68,526
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	-14,521	-14,050	-14,047
Comprehensive Income Attributable to PNMR	111,692	76,935	54,479
Texas-New Mexico Power Company [Member]	'	'	'
Net Earnings	29,090	26,747	22,257
Pension Liability Adjustment:	'	'	'
Experience gain (loss), net of income tax (expense) benefit	0	0	267
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax (expense) benefit	0	0	8
Fair Value Adjustment for Designated Cash Flow Hedges:	'	'	'
Change in fair market value, net of income tax (expense) benefit	-181	-275	-777
Reclassification adjustment for (gains) losses included in net earnings (loss), net of income tax expense	134	117	1,929
Total Other Comprehensive Income (Loss)	-47	-158	1,427
Comprehensive Income Attributable to PNMR	$29,043	$26,589	$23,684

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrealized holding gains (losses) arising during the period, income tax (expense)	($10,855)	($15,262)	($13,577)
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	4,734	14,755	13,956
Experience gain (loss), income tax (expense) benefit	-6,781	11,910	1,187
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, income tax (expense) benefit	-2,524	-1,825	-1,699
Change in fair market value, income tax (expense)	98	153	349
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	-73	-65	-1,230
Public Service Company of New Mexico [Member]	'	'	'
Unrealized holding gains (losses) arising during the period, income tax (expense)	-10,855	-15,262	-13,577
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	4,734	14,755	13,956
Experience gain (loss), income tax (expense) benefit	-6,781	11,910	1,334
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, income tax (expense) benefit	-2,524	-1,825	-1,694
Change in fair market value, income tax (expense)	0	0	0
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	0	0	-11
Texas-New Mexico Power Company [Member]	'	'	'
Experience gain (loss), income tax (expense) benefit	0	0	-147
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, income tax (expense) benefit	0	0	-5
Change in fair market value, income tax (expense)	98	153	430
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	($73)	($65)	($1,068)

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows From Operating Activities:	'	'	'
Net Earnings	$115,556	$120,125	$190,934
Net Earnings	100,507	105,547	176,359
Adjustments to reconcile net earnings to net cash flows from operating activities:	'	'	'
Depreciation and amortization	208,173	206,499	195,366
Bad debt expense	2,849	3,367	24,116
Deferred income tax expense	60,430	56,243	124,424
(Gain) on sale of First Choice	0	-1,012	-174,925
Net unrealized (gains) on derivatives	-1,866	-1,598	-8,713
Realized (gains) on available-for-sale securities	-10,612	-12,965	-8,985
Loss on reacquired debt	3,253	0	9,209
Abandonment of leased premises	0	7,411	0
Stock based compensation expense	5,320	3,585	6,556
Regulatory disallowances	12,235	0	21,402
Other, net	-4,496	-4,165	-3,497
Changes in certain assets and liabilities:	'	'	'
Accounts receivable and unbilled revenues	-7,562	-2,547	-70,734
Materials, supplies, and fuel stock	-7,580	-5,412	-2,200
Other current assets	8,577	-2,598	-21,979
Other assets	-12,801	-30,778	-15,835
Accounts payable	4,484	14,020	20,969
Accrued interest and taxes	91,537	255	7,304
Other current liabilities	-19,648	-19,905	3,460
Proceeds from governmental grants	0	21,567	2,103
Other liabilities	-61,262	-70,743	-6,735
Net cash flows from operating activities	386,587	281,349	292,240
Cash Flows From Investing Activities:	'	'	'
Utility plant additions	-348,039	-308,909	-326,931
Proceeds from sales of available-for-sale securities	271,140	167,330	145,286
Purchases of available-for-sale securities	-282,000	-176,748	-149,185
Proceeds from sale of First Choice	0	-1,012	-174,925
Return of principal on PVNGS lessor notes	23,357	23,455	32,274
Other, net	4,096	4,943	-17
Net cash flows from investing activities	-331,446	-285,895	19,778
Cash Flows From Financing Activities:	'	'	'
Short-term loan	0	100,000	0
Revolving credit facilities borrowings (repayments), net	-9,500	-24,000	-139,300
Long-term borrowings	75,000	20,000	210,000
Repayment of long-term debt	-29,468	-22,387	-110,752
Debt Instrument, Cash for Bond Exchange Conversion	-13,048	0	0
Purchase of preferred stock	0	0	-73,475
Purchase of common stock	0	0	-125,683
Proceeds from stock option exercise	4,618	11,684	5,622
Purchases to satisfy awards of common stock	-13,807	-25,168	-10,104
Dividends paid	-51,508	-45,137	-45,656
Valencia’s transactions with its owner	-18,335	-15,630	-16,801
Other, net	-5,545	-922	-6,182
Net cash flows from financing activities	-61,593	-1,560	-312,331
Change in Cash and Cash Equivalents	-6,452	-6,106	-313
Cash and Cash Equivalents at Beginning of Year	8,985	15,091	15,404
Cash and Cash Equivalents at End of Year	2,533	8,985	15,091
Supplemental Cash Flow Disclosures:	'	'	'
Interest paid, net of amounts capitalized	99,382	113,265	116,391
Income taxes paid (refunded), net	-95,327	5,302	-5,527
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	6,006	-17,983	24,768
Other Significant Noncash Transaction, Value of Consideration Given	36,297	'	'
Public Service Company of New Mexico [Member]	'	'	'
Cash Flows From Operating Activities:	'	'	'
Net Earnings	102,676	105,601	68,538
Net Earnings	88,155	91,551	54,491
Adjustments to reconcile net earnings to net cash flows from operating activities:	'	'	'
Depreciation and amortization	136,732	129,514	123,216
Deferred income tax expense	50,043	65,479	90,567
Net unrealized (gains) on derivatives	-1,866	-1,598	-3,822
Realized (gains) on available-for-sale securities	-10,612	-12,965	-8,985
Regulatory disallowances	12,235	0	17,479
Other, net	-1,614	-170	1,658
Changes in certain assets and liabilities:	'	'	'
Accounts receivable and unbilled revenues	-3,021	-4,756	-23,487
Materials, supplies, and fuel stock	-7,730	-5,268	-2,067
Other current assets	8,556	-3,014	-14,916
Other assets	-13,363	-27,338	-795
Accounts payable	2,807	11,028	12,524
Accrued interest and taxes	72,740	47,666	-45,579
Other current liabilities	-27,376	-2,539	15,216
Proceeds from governmental grants	0	21,567	2,103
Other liabilities	-59,753	-54,787	-18,612
Net cash flows from operating activities	260,454	268,420	213,038
Cash Flows From Investing Activities:	'	'	'
Utility plant additions	-239,906	-196,800	-251,345
Proceeds from sales of available-for-sale securities	271,140	167,330	145,286
Purchases of available-for-sale securities	-282,000	-176,748	-149,185
Return of principal on PVNGS lessor notes	23,357	23,455	32,274
Other, net	3,843	2,406	1,782
Net cash flows from investing activities	-223,566	-180,357	-221,188
Cash Flows From Financing Activities:	'	'	'
Revolving credit facilities borrowings (repayments), net	28,100	-44,900	-124,000
Proceeds from (Repayments of) Related Party Debt	32,500	0	0
Long-term borrowings	75,000	20,000	160,000
Repayment of long-term debt	0	-20,000	0
Equity contribution from parent	0	0	43,000
Dividends paid	-155,556	-34,961	-47,862
Valencia’s transactions with its owner	-18,335	-15,630	-16,801
Other, net	-2,534	-921	-4,216
Net cash flows from financing activities	-40,825	-96,412	10,121
Change in Cash and Cash Equivalents	-3,937	-8,349	1,971
Cash and Cash Equivalents at Beginning of Year	3,958	12,307	10,336
Cash and Cash Equivalents at End of Year	21	3,958	12,307
Supplemental Cash Flow Disclosures:	'	'	'
Interest paid, net of amounts capitalized	71,306	73,036	69,995
Income taxes paid (refunded), net	-77,434	-63,113	-1,541
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	7,921	-19,732	18,164
Texas-New Mexico Power Company [Member]	'	'	'
Cash Flows From Operating Activities:	'	'	'
Net Earnings	29,090	26,747	22,257
Adjustments to reconcile net earnings to net cash flows from operating activities:	'	'	'
Depreciation and amortization	54,395	54,396	48,572
Deferred income tax expense	20,662	4,378	15,478
Regulatory disallowances	0	0	3,923
Other, net	-30	-889	-532
Changes in certain assets and liabilities:	'	'	'
Accounts receivable and unbilled revenues	-4,542	2,208	-9,130
Materials, supplies, and fuel stock	150	-143	77
Other current assets	-1,137	-3,515	4,777
Other assets	941	-3,145	-3,247
Accounts payable	3,709	-666	2,225
Accrued interest and taxes	-6,713	9,825	-2,520
Other current liabilities	-3,197	-2,106	513
Other liabilities	460	4,311	-611
Net cash flows from operating activities	93,788	91,401	81,782
Cash Flows From Investing Activities:	'	'	'
Utility plant additions	-89,117	-92,973	-67,407
Net cash flows from investing activities	-89,117	-92,973	-67,407
Cash Flows From Financing Activities:	'	'	'
Short-term borrowings (repayments) – affiliate, net	1,100	27,600	-500
Long-term borrowings	0	0	50,000
Repayment of long-term debt	0	0	-50,000
Debt Instrument, Cash for Bond Exchange Conversion	-13,048	0	0
Equity contribution from parent	13,800	0	0
Dividends paid	-3,726	-26,028	-13,714
Other, net	-2,797	0	-161
Net cash flows from financing activities	-4,671	1,572	-14,375
Change in Cash and Cash Equivalents	0	0	0
Cash and Cash Equivalents at Beginning of Year	1	1	1
Cash and Cash Equivalents at End of Year	1	1	1
Supplemental Cash Flow Disclosures:	'	'	'
Interest paid, net of amounts capitalized	14,049	25,360	27,236
Income taxes paid (refunded), net	4,484	1,848	1,466
Noncash or Part Noncash Acquisition, Fixed Assets Acquired	141	-2,749	4,501
Other Significant Noncash Transaction, Value of Consideration Given	36,297	'	'
First Choice [Member]	'	'	'
Adjustments to reconcile net earnings to net cash flows from operating activities:	'	'	'
(Gain) on sale of First Choice	0	4,034	329,281
Cash Flows From Investing Activities:	'	'	'
Proceeds from sale of First Choice	0	4,034	329,281
Transaction costs for sale of First Choice	$0	$0	($10,930)

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$2,533	$8,985
Accounts receivable, net of allowance for uncollectible accounts of $1,423 and $1,751 for PNMR and PNM	90,251	87,093
Unbilled revenues	58,806	57,266
Other receivables	53,909	53,332
Materials, supplies, and fuel stock	67,223	59,643
Regulatory assets	24,416	39,120
Commodity derivative instruments	4,064	3,785
Income taxes receivable	7,066	101,477
Current portion of accumulated deferred income taxes	58,681	0
Other, net	34,590	31,490
Total current assets	401,539	442,191
Other Property and Investments:	'	'
Investment in PVNGS lessor notes	32,200	54,325
Investments held by NDT	226,855	192,511
Other investments	1,835	5,599
Non-utility property, net of accumulated depreciation of $61 and $131	4,353	4,487
Total other property and investments	265,243	256,922
Utility Plant:	'	'
Plant in service and plant held for future use	5,563,061	5,313,796
Less accumulated depreciation and amortization	1,838,832	1,774,223
Net plant in service and plant held for future use	3,724,229	3,539,573
Construction work in progress	132,080	125,287
Nuclear fuel, net of accumulated amortization of $47,347 and $42,644 for PNMR and PNM	77,602	81,627
Net utility plant	3,933,911	3,746,487
Deferred Charges and Other Assets:	'	'
Regulatory assets	523,955	555,577
Goodwill	278,297	278,297
Commodity derivative instruments	3,002	352
Other deferred charges	94,263	92,757
Total deferred charges and other assets	899,517	926,983
Total Assets	5,500,210	5,372,583
Current Liabilities:	'	'
Short-term debt	149,200	158,700
Current installments of long-term debt	75,000	2,530
Accounts payable	109,666	99,177
Customer deposits	13,456	18,176
Accrued interest and taxes	49,600	52,003
Regulatory liabilities	1,081	15,173
Commodity derivative instruments	2,699	1,000
Dividends declared	14,864	11,679
Current portion of accumulated deferred income taxes	0	258
Other current liabilities	77,105	75,407
Total current liabilities	492,671	434,103
Long-term Debt	1,670,420	1,669,760
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	801,408	701,545
Accumulated deferred investment tax credits	25,855	14,242
Regulatory liabilities	460,649	423,460
Asset retirement obligations	96,135	85,893
Accrued pension liability and postretirement benefit cost	80,046	224,565
Commodity derivative instruments	1,094	1,933
Other deferred credits	109,805	116,523
Total deferred credits and other liabilities	1,574,992	1,568,161
Total liabilities	3,738,083	3,672,024
Commitments and Contingencies (See Note 16)	'	'
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529	11,529
Company common stockholders’ equity:	'	'
Common stock outstanding	1,178,369	1,182,819
Accumulated other comprehensive income (loss), net of income taxes	-58,140	-81,630
Retained earnings	553,340	506,998
Total PNMR common stockholders' equity	1,673,569	1,608,187
Non-controlling interest in Valencia	77,029	80,843
Total equity	1,750,598	1,689,030
Total liabilities and stockholders' equity	5,500,210	5,372,583
Public Service Company of New Mexico [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	21	3,958
Accounts receivable, net of allowance for uncollectible accounts of $1,423 and $1,751 for PNMR and PNM	70,126	69,876
Unbilled revenues	48,992	49,085
Other receivables	52,964	50,975
Affiliate receivables	10,054	9,050
Materials, supplies, and fuel stock	64,520	56,790
Regulatory assets	19,394	36,490
Commodity derivative instruments	4,064	3,785
Income taxes receivable	4,030	80,223
Current portion of accumulated deferred income taxes	43,827	0
Other, net	30,510	27,457
Total current assets	348,502	387,689
Other Property and Investments:	'	'
Investment in PVNGS lessor notes	32,200	54,325
Investments held by NDT	226,855	192,511
Other investments	445	494
Non-utility property, net of accumulated depreciation of $61 and $131	976	976
Total other property and investments	260,476	248,306
Utility Plant:	'	'
Plant in service and plant held for future use	4,314,016	4,133,532
Less accumulated depreciation and amortization	1,402,531	1,355,240
Net plant in service and plant held for future use	2,911,485	2,778,292
Construction work in progress	107,344	102,329
Nuclear fuel, net of accumulated amortization of $47,347 and $42,644 for PNMR and PNM	77,602	81,627
Net utility plant	3,096,431	2,962,248
Deferred Charges and Other Assets:	'	'
Regulatory assets	384,217	431,956
Goodwill	51,632	51,632
Commodity derivative instruments	3,002	352
Other deferred charges	83,356	81,724
Total deferred charges and other assets	522,207	565,664
Total Assets	4,227,616	4,163,907
Current Liabilities:	'	'
Short-term debt	49,200	21,100
Notes Payable, Related Parties, Current	32,500	0
Current installments of long-term debt	75,000	0
Accounts payable	84,643	73,914
Customer deposits	13,456	18,176
Affiliate payables	20,498	25,340
Accrued interest and taxes	27,665	30,320
Regulatory liabilities	1,081	15,172
Commodity derivative instruments	2,699	1,000
Dividends declared	132	132
Current portion of accumulated deferred income taxes	0	3,447
Other current liabilities	50,392	54,150
Total current liabilities	357,266	242,751
Long-term Debt	1,215,618	1,215,579
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	651,239	573,881
Accumulated deferred investment tax credits	25,855	14,242
Regulatory liabilities	414,611	379,841
Asset retirement obligations	95,225	85,042
Accrued pension liability and postretirement benefit cost	76,611	208,618
Commodity derivative instruments	1,094	1,933
Other deferred credits	91,340	95,585
Total deferred credits and other liabilities	1,355,975	1,359,142
Total liabilities	2,928,859	2,817,472
Commitments and Contingencies (See Note 16)	'	'
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529	11,529
Company common stockholders’ equity:	'	'
Common stock outstanding	1,061,776	1,061,776
Accumulated other comprehensive income (loss), net of income taxes	-57,877	-81,414
Retained earnings	206,300	273,701
Total PNMR common stockholders' equity	1,210,199	1,254,063
Non-controlling interest in Valencia	77,029	80,843
Total equity	1,287,228	1,334,906
Total liabilities and stockholders' equity	4,227,616	4,163,907
Texas-New Mexico Power Company [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	1	1
Accounts receivable, net of allowance for uncollectible accounts of $1,423 and $1,751 for PNMR and PNM	20,125	17,217
Unbilled revenues	9,814	8,181
Other receivables	1,246	2,359
Materials, supplies, and fuel stock	2,703	2,853
Regulatory assets	5,022	2,630
Current portion of accumulated deferred income taxes	6,501	1,131
Other, net	980	1,107
Total current assets	46,392	35,479
Other Property and Investments:	'	'
Other investments	245	281
Non-utility property, net of accumulated depreciation of $61 and $131	2,240	2,240
Total other property and investments	2,485	2,521
Utility Plant:	'	'
Plant in service and plant held for future use	1,074,193	1,009,108
Less accumulated depreciation and amortization	352,105	339,315
Net plant in service and plant held for future use	722,088	669,793
Construction work in progress	16,790	19,801
Net utility plant	738,878	689,594
Deferred Charges and Other Assets:	'	'
Regulatory assets	139,738	123,621
Goodwill	226,665	226,665
Other deferred charges	8,273	8,349
Total deferred charges and other assets	374,676	358,635
Total Assets	1,162,431	1,086,229
Current Liabilities:	'	'
Short-term debt – affiliate	29,400	28,300
Notes Payable, Related Parties, Current	29,400	28,300
Current installments of long-term debt	0	0
Accounts payable	12,543	8,848
Affiliate payables	3,181	4,381
Accrued interest and taxes	23,778	30,491
Other current liabilities	8,999	8,854
Total current liabilities	77,901	80,874
Long-term Debt	336,036	311,589
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	190,197	163,710
Regulatory liabilities	46,038	43,619
Asset retirement obligations	782	732
Accrued pension liability and postretirement benefit cost	3,435	15,947
Other deferred credits	5,111	5,944
Total deferred credits and other liabilities	245,563	229,952
Total liabilities	659,500	622,415
Commitments and Contingencies (See Note 16)	'	'
Company common stockholders’ equity:	'	'
Common stock outstanding	64	64
Paid-in-capital	404,166	390,366
Accumulated other comprehensive income (loss), net of income taxes	-263	-216
Retained earnings	98,964	73,600
Total PNMR common stockholders' equity	502,931	463,814
Total liabilities and stockholders' equity	$1,162,431	$1,086,229

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Allowance for uncollectible accounts	$1,423	$1,751
Accumulated depreciation, non-utility property	61	131
Accumulated depreciation, nuclear fuel	47,347	42,644
Cumulative preferred stock of subsidiary, stated value	$100	$100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding	115,293	115,293
Common stock, par value	$0	$0
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	79,653,624	79,653,624
Common stock, shares outstanding	79,653,624	79,653,624
Public Service Company of New Mexico [Member]	'	'
Allowance for uncollectible accounts	1,423	1,751
Accumulated depreciation, nuclear fuel	$47,347	$42,644
Cumulative preferred stock of subsidiary, stated value	$100	$100
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	10,000,000
Common stock, par value	$0	$0
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	39,117,799	39,117,799
Common stock, shares outstanding	39,117,799	39,117,799
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding	115,293	115,293
Texas-New Mexico Power Company [Member]	'	'
Cumulative preferred stock of subsidiary, shares authorized	1,000,000	'
Common stock, shares authorized	12,000,000	12,000,000
Common stock, shares issued	6,358	6,358
Common stock, shares outstanding	6,358	6,358
Common stock, par value	$10	$10

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)

Total

Preferred Stock, Series A [Member]

Common Stock [Member]

AOCI [Member]

Retained Earnings [Member]

Total PNMR Common Stockholders' Equity [Member]

Non-controlling Interest in Valencia [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

In Thousands, unless otherwise specified

Common Stock [Member]

AOCI [Member]

Retained Earnings [Member]

Total PNMR Common Stockholders' Equity [Member]

Non-controlling Interest in Valencia [Member]

Common Stock [Member]

Additional Paid-in Capital [Member]

AOCI [Member]

Retained Earnings [Member]

Balance at Dec. 31, 2010

$1,721,919

$100,000

$1,290,465

($68,666)

$314,943

$1,536,742

$85,177

$1,208,526

$1,018,776

($66,786)

$171,359

$1,123,349

$85,177

'

'

'

'

'

Balance TNMP at Dec. 31, 2010

'

'

'

'

'

'

'

'

'

'

'

'

'

453,283

64

430,108

-1,485

24,596

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from stock option exercises

5,622

0

5,622

0

0

5,622

0

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

176,359

'

'

'

'

'

'

54,491

'

'

'

'

'

22,257

0

0

0

22,257

Purchases to satisfy awards of common stock

-10,104

0

-10,104

0

0

-10,104

0

'

'

'

'

'

'

'

'

'

'

'

Stock based compensation expense

6,556

0

6,556

0

0

6,556

0

'

'

'

'

'

'

'

'

'

'

'

Valencia’s transactions with its owner

-16,801

0

0

0

0

0

-16,801

-16,801

0

0

0

0

-16,801

'

'

'

'

'

Purchase of preferred stock

-73,510

-100,000

26,490

0

0

26,490

0

'

'

'

'

'

'

'

'

'

'

'

Purchase of common stock

-125,838

0

-125,838

0

0

-125,838

0

'

'

'

'

'

'

'

'

'

'

'

Net earnings

190,934

0

0

0

176,887

176,887

14,047

68,538

0

0

54,491

54,491

14,047

'

'

'

'

'

Subsidiary preferred stock dividends

-528

0

0

0

-528

-528

0

'

'

'

'

'

'

'

'

'

'

'

Total other comprehensive income

1,810

0

0

1,810

0

1,810

0

-12

0

-12

0

-12

0

1,427

0

0

1,427

0

Equity contributions from parent

'

'

'

'

'

'

'

43,000

43,000

0

0

43,000

0

'

'

'

'

'

Dividends declared on preferred stock

'

'

'

'

'

'

'

-528

0

0

-528

-528

0

'

'

'

'

'

Dividends declared on common stock

-43,652

0

0

0

-43,652

-43,652

0

-8,211

0

0

-8,211

-8,211

0

-13,714

0

-13,714

0

0

Balance TNMP at Dec. 31, 2011

'

'

'

'

'

'

'

'

'

'

'

'

'

463,253

64

416,394

-58

46,853

Balance at Dec. 31, 2011

1,656,408

0

1,193,191

-66,856

447,650

1,573,985

82,423

1,294,512

1,061,776

-66,798

217,111

1,212,089

82,423

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

17,080

'

'

'

'

'

'

17,812

'

'

'

'

'

3,011

'

'

'

'

Net earnings

20,477

'

'

'

'

'

'

21,077

'

'

'

'

'

'

'

'

'

'

Balance TNMP at Mar. 31, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at Dec. 31, 2011

1,656,408

0

1,193,191

-66,856

447,650

1,573,985

82,423

1,294,512

1,061,776

-66,798

217,111

1,212,089

82,423

'

'

'

'

'

Balance TNMP at Dec. 31, 2011

'

'

'

'

'

'

'

'

'

'

'

'

'

463,253

64

416,394

-58

46,853

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from stock option exercises

11,684

0

11,684

0

0

11,684

0

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

105,547

'

'

'

'

'

'

91,551

'

'

'

'

'

26,747

0

0

0

26,747

Purchases to satisfy awards of common stock

-25,168

0

-25,168

0

0

-25,168

0

'

'

'

'

'

'

'

'

'

'

'

Excess tax (shortfall) from stock-based payment arrangements

-473

0

-473

0

0

-473

0

'

'

'

'

'

'

'

'

'

'

'

Stock based compensation expense

3,585

0

3,585

0

0

3,585

0

'

'

'

'

'

'

'

'

'

'

'

Valencia’s transactions with its owner

-15,630

0

0

0

0

0

-15,630

-15,630

0

0

0

0

-15,630

'

'

'

'

'

Net earnings

120,125

0

0

0

106,075

106,075

14,050

105,601

0

0

91,551

91,551

14,050

'

'

'

'

'

Subsidiary preferred stock dividends

-528

0

0

0

-528

-528

0

'

'

'

'

'

'

'

'

'

'

'

Total other comprehensive income

-14,774

0

0

-14,774

0

-14,774

0

-14,616

0

-14,616

0

-14,616

0

-158

0

0

-158

0

Dividends declared on preferred stock

'

'

'

'

'

'

'

-528

0

0

-528

-528

0

'

'

'

'

'

Dividends declared on common stock

-46,199

0

0

0

-46,199

-46,199

0

-34,433

0

0

-34,433

-34,433

0

-26,028

0

-26,028

0

0

Balance TNMP at Dec. 31, 2012

1,608,187

'

'

'

'

'

'

1,254,063

'

'

'

'

'

463,814

64

390,366

-216

73,600

Balance at Dec. 31, 2012

1,689,030

0

1,182,819

-81,630

506,998

1,608,187

80,843

1,334,906

1,061,776

-81,414

273,701

1,254,063

80,843

'

'

'

'

'

Balance at Sep. 30, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

9,091

'

'

'

'

'

'

5,943

'

'

'

'

'

6,634

'

'

'

'

Net earnings

12,573

'

'

'

'

'

'

9,293

'

'

'

'

'

'

'

'

'

'

Balance TNMP at Dec. 31, 2012

1,608,187

'

'

'

'

'

'

1,254,063

'

'

'

'

'

463,814

'

'

'

'

Balance at Dec. 31, 2012

1,689,030

'

'

'

'

'

'

1,334,906

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

10,626

'

'

'

'

'

'

11,569

'

'

'

'

'

3,726

'

'

'

'

Net earnings

13,962

'

'

'

'

'

'

14,773

'

'

'

'

'

'

'

'

'

'

Balance TNMP at Mar. 31, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at Dec. 31, 2012

1,689,030

0

1,182,819

-81,630

506,998

1,608,187

80,843

1,334,906

1,061,776

-81,414

273,701

1,254,063

80,843

'

'

'

'

'

Balance TNMP at Dec. 31, 2012

1,608,187

'

'

'

'

'

'

1,254,063

'

'

'

'

'

463,814

64

390,366

-216

73,600

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from stock option exercises

4,618

0

4,618

0

0

4,618

0

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

100,507

'

'

'

'

'

'

88,155

'

'

'

'

'

29,090

0

0

0

29,090

Purchases to satisfy awards of common stock

-13,807

0

-13,807

0

0

-13,807

0

'

'

'

'

'

'

'

'

'

'

'

Excess tax (shortfall) from stock-based payment arrangements

-581

0

-581

0

0

-581

0

'

'

'

'

'

'

'

'

'

'

'

Stock based compensation expense

5,320

0

5,320

0

0

5,320

0

'

'

'

'

'

'

'

'

'

'

'

Valencia’s transactions with its owner

-18,335

0

0

0

0

0

-18,335

-18,335

0

0

0

0

-18,335

'

'

'

'

'

Net earnings

115,556

0

0

0

101,035

101,035

14,521

102,676

0

0

88,155

88,155

14,521

'

'

'

'

'

Subsidiary preferred stock dividends

-528

0

0

0

-528

-528

0

'

'

'

'

'

'

'

'

'

'

'

Total other comprehensive income

23,490

0

0

23,490

0

23,490

0

23,537

0

23,537

0

23,537

0

-47

0

0

-47

0

Equity contributions from parent

'

'

'

'

'

'

'

'

'

'

'

'

'

13,800

0

13,800

0

0

Dividends declared on preferred stock

'

'

'

'

'

'

'

-528

0

0

-528

-528

0

'

'

'

'

'

Dividends declared on common stock

-54,165

0

0

0

-54,165

-54,165

0

-155,028

0

0

-155,028

-155,028

0

-3,726

0

0

0

-3,726

Balance TNMP at Dec. 31, 2013

1,673,569

'

'

'

'

'

'

1,210,199

'

'

'

'

'

502,931

64

404,166

-263

98,964

Balance at Dec. 31, 2013

1,750,598

0

1,178,369

-58,140

553,340

1,673,569

77,029

1,287,228

1,061,776

-57,877

206,300

1,210,199

77,029

'

'

'

'

'

Balance at Sep. 30, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net earnings (loss)

7,648

'

'

'

'

'

'

2,639

'

'

'

'

'

6,919

'

'

'

'

Net earnings

11,397

'

'

'

'

'

'

6,256

'

'

'

'

'

'

'

'

'

'

Balance TNMP at Dec. 31, 2013

1,673,569

'

'

'

'

'

'

1,210,199

'

'

'

'

'

502,931

'

'

'

'

Balance at Dec. 31, 2013

$1,750,598

'

'

'

'

'

'

$1,287,228

'

'

'

'

'

'

'

'

'

'

Summary_of_the_Business_and_Si

Summary of the Business and Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

'

Summary of the Business and Significant Accounting Policies

'

Summary of the Business and Significant Accounting Policies

Nature of Business

PNMR is an investor-owned holding company of energy and energy-related businesses. PNMR’s primary subsidiaries are PNM and TNMP. PNM is a public utility with regulated operations primarily engaged in the generation, transmission, and distribution of electricity. TNMP is a wholly owned subsidiary of TNP, which is a holding company that is wholly owned by PNMR. TNMP provides regulated transmission and distribution services in Texas. PNMR completed the sale of First Choice (Note 3), which was also a subsidiary of TNP, on November 1, 2011. First Choice was a competitive REP operating in Texas. Until September 23, 2011, PNMR owned 50% of Optim Energy (Note 20), which was focused on unregulated electric operations, principally within the areas of Texas covered by ERCOT. PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM.

Financial Statement Preparation and Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.

The Notes to Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. For discussion purposes, this report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such.

Certain amounts in the 2012 and 2011 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2013 financial statement presentation.

GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.

Principles of Consolidation

The Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia (Note 9). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.

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

Accounting for the Effects of Certain Types of Regulation

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

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

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

Cash and Cash Equivalents

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

Utility Plant

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

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

Allowance for Funds Used During Construction

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

For the years ended December 31, 2013, 2012, and 2011, PNM recorded $3.3 million, $3.5 million, and $1.5 million of allowance for borrowed funds used during construction and $4.4 million, $3.8 million, and zero of allowance for equity funds used during construction. TNMP recorded $0.4 million, $0.7 million, and $0.6 million of allowance for borrowed funds used during construction and zero, $0.6 million, and $0.6 million of allowance for equity funds used during construction.

Capitalized Interest

PNMR capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC. Interest was capitalized at the overall weighted average borrowing rate of 6.9%, 6.6%, and 6.6% for 2013, 2012, and 2011. In 2013, 2012, and 2011, PNMR’s capitalized interest was $1.5 million, $1.2 million, and $0.5 million; PNM’s was $1.1 million, $0.8 million, and $0.2 million; and TNMP had no capitalized interest.

Competition Transition Charge

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

Materials, Supplies, and Fuel Stock

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

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

Inventories consisted of the following at December 31:

PNMR

PNM

TNMP

2013

2012

2013

2012

2013

2012

(In thousands)

Coal

$

24,872

$

19,231

$

24,872

$

19,231

$

—

$

—

Materials and supplies

42,351

40,412

39,648

37,559

2,703

2,853

$

67,223

$

59,643

$

64,520

$

56,790

$

2,703

$

2,853

Investments

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

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). All of these investments are classified as available-for-sale. PNM evaluates the securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2013, 2012, and 2011, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $3.5 million, $4.8 million, and $12.5 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI. The available-for-sale securities are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in PNM’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions.

Investment in Optim Energy

Through September 23, 2011, PNMR accounted for its investment in Optim Energy using the equity method of accounting because PNMR’s ownership interest resulted in significant influence, but not control, over Optim Energy and its operations. On September 23, 2011, PNMR’s ownership interest in Optim Energy was reduced to 1% and PNMR began using the cost method of accounting. On January 4, 2012, ECJV acquired PNMR’s remaining 1% ownership interest at fair market value, which was determined to be zero. PNMR’s investment in Optim Energy was reduced to zero at December 31, 2010 due to the determination that the investment was fully impaired. See Note 20.

Goodwill and Other Intangible Assets

Under GAAP, the Company does not amortize goodwill. In 2011, certain intangible assets were amortized over their estimated useful lives. Goodwill and non-amortizable other intangible assets are evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill and intangible assets might be impaired. Amortizable other intangible assets are amortized over the shorter of their economic or legal lives and are evaluated for impairment when events and circumstances indicate that the assets might be impaired. See Note 21.

Asset Impairment

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

Revenue Recognition

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

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

Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold. The Company has no trading transactions.

Accounts Receivable and Allowance for Uncollectible Accounts

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

Depreciation and Amortization

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

Year ended December 31

2013

2012

2011

PNM

Electric plant

2.27

%

2.25

%

2.24

%

Common, intangible, and general plant

4.87

%

5.35

%

6.03

%

TNMP

3.66

%

3.56

%

3.41

%

Amortization of Debt Acquisition Costs

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

Derivatives

The Company records derivative instruments, other than those designated as normal purchases or normal sales, in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or normal sale criteria are met. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.

The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity.

GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the economic hedge.

Decommissioning Costs

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

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

Environmental Costs

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

The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Amounts recorded for environmental expense in the years ended December 31, 2013, 2012, and 2011, as well as the amounts of environmental liabilities at December 31, 2013 and 2012 were insignificant.

Pension and Other Postretirement Benefits

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

Stock-Based Compensation

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

Income Taxes

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

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

Excise Taxes

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

New Accounting Pronouncements

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

Accounting Standards Update 2013-11 - Income Taxes: Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

The FASB released guidance that requires entities to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for net operating losses in certain circumstances. The guidance is to be applied prospectively and is effective for annual and interim reporting periods beginning after December 15, 2013, with early adoption permitted. The Company will implement the update in 2014. Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss deferred tax assets of $19.9 million for PNMR, $11.1 million for PNM, and $6.8 million for TNMP, along with the elimination of corresponding assets and liabilities associated with unrecognized tax benefits (Note 11). No impact to earnings is anticipated.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information
	The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.
	PNM
	PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale and transmission rates.
	TNMP
	TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT.
	First Choice
	First Choice, which was sold by PNMR on November 1, 2011 (Note 3), operated as a certified REP in Texas. First Choice provided electricity to residential, small commercial, and governmental customers. Although First Choice was regulated in certain respects by the PUCT, it was not subject to traditional rate regulation.
	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
	2013	PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Electric operating revenues	$	1,116,312		$	271,611		$	—		$	1,387,923
	Cost of energy	374,710			57,606			—			432,316
	Margin	741,602			214,005			—			955,607
	Other operating expenses	428,591			91,601			(18,308		)	501,884
	Depreciation and amortization	103,826			50,219			12,836			166,881
	Operating income	209,185			72,185			5,472			286,842
	Interest income	10,182			—			(139		)	10,043
	Other income (deductions)	11,288			1,919			(13,575		)	(368		)
	Net interest charges	(79,175		)	(27,393		)	(14,880		)	(121,448		)
	Segment earnings (loss) before income taxes	151,480			46,711			(23,122		)	175,069
	Income taxes (benefit)	48,804			17,621			(6,912		)	59,513
	Segment earnings (loss)	102,676			29,090			(16,210		)	115,556
	Valencia non-controlling interest	(14,521		)	—			—			(14,521		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	87,627		$	29,090		$	(16,210	)	$	100,507
	Gross property additions	$	239,906		$	89,117		$	19,016		$	348,039
	At December 31, 2013:
	Total Assets	$	4,227,616		$	1,162,431		$	110,163		$	5,500,210
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2012	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,092,264		$	250,140		$	(1	)	$	1,342,403
	Cost of energy	353,649			46,201			—			399,850
	Margin	738,615			203,939			(1		)	942,553
	Other operating expenses	435,442			87,079			(17,862		)	504,659
	Depreciation and amortization	97,291			49,340			17,542			164,173
	Operating income	205,882			67,520			319			273,721
	Interest income	13,243			1			(172		)	13,072
	Gain on sale of First Choice	—			—			1,012			1,012
	Other income (deductions)	13,290			2,739			(7,954		)	8,075
	Net interest charges	(76,101		)	(28,161		)	(16,583		)	(120,845		)
	Segment earnings (loss) before income taxes	156,314			42,099			(23,378		)	175,035
	Income taxes (benefit)	50,713			15,352			(11,155		)	54,910
	Segment earnings (loss)	105,601			26,747			(12,223		)	120,125
	Valencia non-controlling interest	(14,050		)	—			—			(14,050		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	91,023		$	26,747		$	(12,223	)	$	105,547
	Gross property additions	$	196,800		$	92,973		$	19,136		$	308,909
	At December 31, 2012:
	Total Assets	$	4,163,907		$	1,086,229		$	122,447		$	5,372,583
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2011	PNM			TNMP			First			Corporate			Consolidated
								Choice			and Other
								(In thousands)
	Electric operating revenues:
	Non-affiliates	$	1,057,289		$	204,045		$	439,450		$	(165	)	$	1,700,619
	Affiliate	—			33,813			—			(33,813		)	—
	Total electric operating revenues	1,057,289			237,858			439,450			(33,978		)	1,700,619
Cost of energy	362,237			41,166			323,331			(33,812		)	692,922
Margin	695,052			196,692			116,119			(166		)	1,007,697
Other operating expenses	438,822			88,234			75,966			(9,671		)	593,351
Depreciation and amortization	94,787			44,616			1,098			16,546			157,047
Operating income (loss)	161,443			63,842			39,055			(7,041		)	257,299
Interest income	15,562			2			64			(113		)	15,515
Gain on sale of First Choice	—			—			—			174,925			174,925
Other income (deductions)	4,309			1,580			(650		)	(15,660		)	(10,421		)
Net interest charges	(75,349		)	(29,286		)	(581		)	(19,633		)	(124,849		)
Segment earnings before income taxes	105,965			36,138			37,888			132,478			312,469
Income taxes	37,427			13,881			13,772			56,455			121,535
Segment earnings	68,538			22,257			24,116			76,023			190,934
Valencia non-controlling interest	(14,047		)	—			—			—			(14,047		)
Subsidiary preferred stock dividends	(528		)	—			—			—			(528		)
Segment earnings attributable to PNMR	$	53,963		$	22,257		$	24,116		$	76,023		$	176,359
Gross property additions	$	251,345		$	67,407		$	2,089		$	6,090		$	326,931
At December 31, 2011:
Total Assets	$	4,095,287		$	1,037,445		$	—		$	71,881		$	5,204,613
Goodwill	$	51,632		$	226,665		$	—		$	—		$	278,297
Major Customers
No individual customer accounted for more than 10% of the electric operating revenues of PNMR or PNM. The acquiror of First Choice, including the former First Choice operations, accounted for 17% and 19% of TNMP’s electric operating revenues in 2013 and 2012. Two other unaffiliated customers of TNMP accounted for revenues of 16% in 2013, 17% in 2012, and 19% in 2011 and 10% in 2013, 10% in 2012, and 12% in 2011. First Choice accounted for 17% of TNMP’s revenues in 2011.

Sale_of_First_Choice

Sale of First Choice	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Sale of First Choice	'
	Sale of First Choice
	On September 23, 2011, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the actual amounts of certain components of working capital at closing. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which included an estimate of the components of working capital. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. PNMR recognized a pre-tax gain of $174.9 million on the sale in 2011. The amount received was subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. The parties could not agree on the working capital amount and, in accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012. The decision resulted in PNMR being awarded $6.4 million of the $8.2 million in dispute. PNMR recorded an additional pre-tax gain of $1.0 million in 2012. PNMR used the net proceeds from the sale of First Choice to repurchase certain of PNMR’s outstanding debt and equity securities (Note 6) and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility. PNMR Services Company continued to provide certain services at cost to First Choice for a transitional period through August 1, 2012. Because PNMR continues to have direct cash flows resulting from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations. After October 31, 2011, TNMP’s revenues from First Choice are not intercompany and are not eliminated in consolidation by PNMR.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory Assets and Liabilities	'
	Regulatory Assets and Liabilities
	The operations of PNM and TNMP are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to its regulated operations. Regulatory assets represent probable future recovery of previously incurred costs that will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below.
	PNM
		December 31,
		2013			2012
	Assets:	(In thousands)
	Current:
	FPPAC	$	19,394		$	36,266
	Other	—			224
		19,394			36,490
	Non-Current:
	Coal mine reclamation costs	40,144			46,065
	Deferred income taxes	61,850			54,781
	Loss on reacquired debt	27,490			29,702
	Pension and OPEB	206,691			254,351
	FPPAC	25,386			18,619
	Renewable energy costs	13,311			18,768
	Other	9,345			9,670
		384,217			431,956
	Total regulatory assets	$	403,611		$	468,446
	Liabilities:
	Current:
	Other	$	(1,081	)	$	(15,172	)
	Non-Current:
	Cost of removal	$	(266,075	)	$	(257,396	)
	Deferred income taxes	(80,495		)	(49,723		)
	AROs	(37,567		)	(39,280		)
	Renewable energy tax benefits	(26,011		)	(26,988		)
	Other	(4,463		)	(6,454		)
		(414,611		)	(379,841		)
	Total regulatory liabilities	$	(415,692	)	$	(395,013	)
	TNMP
		December 31,
		2013			2012
	Assets:	(In thousands)
	Current:
	Transmission cost recovery factor	$	4,250		$	2,287
	Other	772			343
		5,022			2,630
	Non-Current:
	CTC, including carrying charges	63,606			71,240
	Deferred income taxes	10,868			11,179
	Pension	19,938			28,307
	Loss on reacquired debt	38,616			1,711
	Hurricane recovery costs	—			4,572
	AMS retirement costs	5,083			3,538
	Other	1,627			3,074
		139,738			123,621
	Total regulatory assets	$	144,760		$	126,251
	Liabilities:
	Non-Current:
	Cost of removal	$	(30,863	)	$	(31,115	)
	Deferred income taxes	(4,563		)	(5,203		)
	AMS surcharge	(7,251		)	(6,386		)
	OPEB	(3,361		)	(915		)
	Total regulatory liabilities	$	(46,038	)	$	(43,619	)
	The Company’s regulatory assets and regulatory liabilities are reflected in rates charged to customers or have been addressed in a regulatory proceeding. The Company does not receive or pay a rate of return on the following regulatory assets and regulatory liabilities (and their remaining amortization periods): coal mine reclamation costs (through 2020); deferred income taxes (over the remaining life of the taxable item, up to the remaining life of utility plant); pension and OPEB costs (through 2033); FPPAC deferrals greater than $49.1 million (based on future FPPAC activity and regulatory proceedings); and AROs (to be determined in a future regulatory proceeding). In addition, TNMP does not receive a return on substantially all of its loss on reacquired debt (through 2043).
	The Company is permitted, under rate regulation, to accrue and record a regulatory liability for the estimated cost of removal and salvage associated with certain of its assets through depreciation expense. Under GAAP, actuarial losses and prior service costs for pension plans are required to be recorded in AOCI; however, to the extent authorized for recovery through the regulatory process these amounts are recorded as regulatory assets or liabilities. Based on prior regulatory approvals, the amortization of these amounts will be included in the Company’s rates.
	Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that future recovery of its regulatory assets are probable.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Stockholders' Equity	'
	Stockholders’ Equity
	Common Stock and Equity Contributions
	PNMR, PNM and TNMP did not issue any common stock during the three year period ended December 31, 2013. See Note 6 for additional information related to PNMR’s common stock. PNMR made a cash equity contribution to PNM of $43.0 million in 2011. PNMR funded a cash equity contribution of $13.8 million to TNMP in 2013.
	Dividends on Common Stock
	The declaration of common dividends by PNMR is dependent upon a number of factors including the ability of PNMR’s subsidiaries to pay dividends. PNMR’s primary sources of dividends are its operating subsidiaries.
	PNM declared and paid cash dividends to PNMR of $155.0 million, $34.4 million, and $8.2 million in 2013, 2012, and 2011. In addition, PNM declared a dividend of $39.1 million in December 2010 that was paid in January 2011. TNMP paid cash dividends to PNMR of $3.7 million, $26.0 million, and $13.7 million in 2013, 2012, and 2011. TNMP dividends paid in 2012 and 2011 were recorded as reductions of paid-in-capital.
	The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including the restriction that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC provisions allow PNM to pay dividends from equity contributions previously made by PNMR and current earnings, determined on a rolling four quarter basis, without prior NMPRC approval. The Federal Power Act also imposes certain restrictions on dividends by public utilities. Each of the PNMR Revolving Credit Facility, PNMR Term Loan Agreement, PNM Revolving Credit Facility, PNM Term Loan Agreement, PNM New Mexico Credit Facility, TNMP Revolving Credit Facility, and TNMP 2011 Term Loan Agreement contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%, which could limit amounts of dividends that could be paid. For PNMR and PNM these ratios reflect the present value of payments under the PVNGS and EIP leases as debt. PNM also has other financial covenants that limit the transfer of assets, through dividends or other means, including a requirement to obtain approval of certain financial counterparties to transfer more than five percent of PNM’s assets. As of December 31, 2013, none of the numerical tests would restrict the payment of dividends from the retained earnings of PNMR, PNM, or TNMP, except that PNM would not be able to distribute amounts in excess of approximately $206 million and TNMP would not be able to distribute amounts in excess of approximately $199 million without approval of regulators or financial counterparties.
	In addition, the ability of PNMR to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, financial circumstances and performance, current and future regulatory decisions, Congressional and legislative acts, and economic conditions. Conditions imposed by the NMPRC or PUCT, future growth plans and related capital requirements, and business considerations may also affect PNMR’s ability to pay dividends.
	Preferred Stock
	PNMR had 477,800 shares of Series A convertible preferred stock outstanding through September 23, 2011 when it entered into an agreement to purchase all of the outstanding shares from Cascade. See Note 6. The Series A convertible preferred stock was convertible into PNMR common stock in a ratio of 10 shares of common stock for each share of preferred stock and received dividends equivalent to dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The Series A convertible preferred stock was entitled to vote on all matters voted upon by common stockholders, except for the election of the Board, and would have received distributions substantially equivalent to common stock in the event of liquidation of PNMR. The terms of the Series A convertible preferred stock resulted in it being substantially equivalent to common stock. Therefore, for earnings per share purposes, the number of common shares into which the Series A convertible preferred stock was convertible was included in the weighted average number of common shares outstanding for periods the Series A convertible preferred stock was outstanding. Similarly, dividends on the Series A convertible preferred stock were considered to be common dividends in the accompanying Consolidated Financial Statements.
	PNM’s cumulative preferred shares outstanding bear dividends at 4.58% per annum. PNM preferred stock does not have a mandatory redemption requirement but may be redeemed, at PNM’s option, at 102% of the stated value plus accrued dividends. The holders of the PNM preferred stock are entitled to payment before the holders of common stock in the event of any liquidation or dissolution or distribution of assets of PNM. In addition, PNM’s preferred stock is not entitled to a sinking fund and cannot be converted into any other class of stock of PNM.
	TNMP has no preferred stock outstanding. The number of authorized shares of TNMP cumulative preferred stock is 1 million shares.

Financing

Financing	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Financing	'
	Financing
	Financing Activities
	PNMR
	On September 23, 2011, PNMR entered into an agreement to purchase all of its outstanding Series A convertible preferred stock from Cascade. Cascade owned all of the 477,800 outstanding shares of the preferred stock, which were convertible into 4,778,000 shares of PNMR common stock. Upon signing, the agreement obligated PNMR to purchase the preferred stock at a 2% discount from the arithmetic mean of the daily volume weighted average price per share of PNMR’s common stock on each trading day in the period beginning September 19, 2011 and ending on September 30, 2011 times the number of shares of PNMR common stock into which the preferred stock was convertible. The purchase of the preferred stock closed on October 5, 2011 with PNMR paying Cascade an aggregate purchase price of $73.5 million. The difference between the purchase price and the $100.0 million carrying value of the preferred stock is reflected as an addition to common stock in the Consolidated Financial Statements. PNMR utilized a borrowing under its revolving credit facility to fund the purchase of the preferred stock. Such borrowing was repaid on November 1, 2011 with a portion of the proceeds from the sale of First Choice. See Note 3.
	On October 24, 2011, PNMR commenced a cash tender offer to purchase up to $50.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015. PNMR offered to pay a premium of up to 17%, depending on when the notes were tendered. The tender offer expired on November 21, 2011 and was oversubscribed. On November 22, 2011, PNMR purchased $50.0 million of the notes for $58.5 million, plus accrued and unpaid interest. PNMR used a portion of the proceeds from the sale of First Choice to fund the purchase. PNMR recognized a loss of $9.2 million on the purchase, including transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which is included in other deductions on the Consolidated Statements of Earnings.
	In the year ended December 31, 2013, PNMR purchased $23.8 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in several small open-market purchases, for $26.9 million plus accrued and unpaid interest. PNMR recognized losses of $3.3 million on these purchases, including transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which are included in other deductions on the Consolidated Statements of Earnings.
	On November 4, 2011, PNMR entered into an agreement to purchase up to 7,019,550 shares of common stock from Cascade. Upon signing, the agreement obligated PNMR to purchase the common stock at a 2% discount from the arithmetic mean of the volume weighted average price on each trading day in the period beginning October 27, 2011 and ending November 9, 2011. The purchase of the common stock closed on November 10, 2011 with PNMR purchasing all 7,019,550 shares of common stock owned by Cascade for an aggregate purchase price of $125.7 million. The shares of common stock repurchased have become authorized but unissued shares, as determined by the Board. PNMR used a portion of the proceeds from the sale of First Choice to fund the purchase.
	On December 14, 2012, PNMR entered into a $100.0 million Term Loan Agreement (the “PNMR Term Loan Agreement”) among PNMR, the lenders identified therein, and JPMorgan Chase Bank, N.A., as Administrative Agent. Funding of the PNMR Term Loan Agreement occurred on December 27, 2012. PNMR borrowed $100.0 million under the agreement and used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility. PNMR pays interest on its borrowing under the agreement, which matured on December 27, 2013.  The PNMR Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio, and customary events of default. The PNMR Term Loan Agreement has a cross default provision and a change of control provision. On December 27, 2013, PNMR entered into an agreement that amends and restates the PNMR Term Loan Agreement extending the maturity date to December 26, 2014.
	PNMR offers shares of PNMR common stock through the PNMR Direct Plan. PNMR utilizes shares of its common stock purchased on the open market, by an independent agent, rather than issuing additional shares to satisfy subscriptions under the PNMR Direct Plan. The shares of PNMR common stock utilized in the PNMR Direct Plan are offered under a SEC shelf registration statement that expires in August 2015.
	For offerings of equity and debt securities registered with the SEC, PNMR has a shelf registration statement expiring in March 2014. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations.
	PNM
	On October 6, 2011, PNM priced a public offering of $160.0 million aggregate principal amount of its 5.35% Senior Unsecured Notes due 2021. The bonds were offered at 99.857% of face amount and the offering closed on October 12, 2011. Proceeds from the offering were used to repay outstanding short-term debt.
	In April 2012, PNM filed an application with the NMPRC requesting approval to participate in the refunding of $20.0 million of PCRBs, which was approved in May 2012. PNM also received NMPRC authority to exercise the two one-year extension options under the PNM Revolving Credit Facility. In September 2012, PNM participated in the issuance of $20.0 million of new PCRBs by the City of Farmington, New Mexico, which bear interest at 2.54% and mature September 1, 2042 with a mandatory tender on June 1, 2017. The new PCRBs refunded a $20.0 million series of PCRBs, which bore interest at 5.15% and matured in 2037, that were redeemed at par and retired.
	On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the “PNM Term Loan Agreement”) among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. The PNM Term Loan Agreement bears interest at a variable rate and must be repaid on or before October 21, 2014. The PNM Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Term Loan Agreement has a cross default provision and a change of control provision.
	PNM has a shelf registration statement for the issuance of up to $440.0 million of senior unsecured notes that will expire in May 2014.
	TNMP
	On September 30, 2011, TNMP entered into the TNMP 2011 Term Loan Agreement with JPMorgan Chase Bank, N.A and borrowed $50.0 million under it. The TNMP 2011 Term Loan Agreement replaces a previous term loan agreement. Borrowings under the TNMP 2011 Term Loan Agreement must be repaid by June 30, 2014 and are secured by $50.0 million aggregate principal amount of first mortgage bonds of TNMP (the “Series 2011A Bonds”). TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing of 1.475% through March 30, 2014 and 1.985% thereafter, which is an effective rate of 3.566% over the life of the debt considering the amounts paid to exit the prior arrangements and enter into the new arrangements. The hedging obligations entered into in connection with the TNMP 2011 Term Loan Agreement are also secured by the Series 2011A Bonds. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.2 million and $0.3 million at December 31, 2013 and 2012, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.
	On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP’s $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in a premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. The premium amounted to $23.2 million, after reduction for the cash paid in the exchange. A regulatory asset was recorded offsetting the premium, including the cash consideration paid in the exchange.
	On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provides that TNMP will issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”). The terms of the TNMP 2013 Bond Purchase Agreement provide that, subject to satisfaction of certain conditions, TNMP will issue the Series 2014A Bonds on or about June 27, 2014. TNMP anticipates using $50.0 million of the proceeds from the issuance to repay the TNMP 2011 Term Loan Agreement at its maturity and using the remaining proceeds to reduce short-term debt under the TNMP Revolving Credit Facility and/or TNMP’s intercompany borrowings from PNMR. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement, which are due on June 30, 2014, are reflected as being long-term in the Consolidated Balance Sheet at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrates TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis.
	Borrowing Arrangements Between PNMR and its Subsidiaries
	PNMR has one-year intercompany loan agreements with its subsidiaries. Individual subsidiary loan agreements vary in amount up to $100.0 million and have either reciprocal or non-reciprocal terms. Interest charged to the subsidiaries is equivalent to interest paid by PNMR on its short-term borrowings. As of December 31, 2013 and 2012, PNM had outstanding borrowings of $32.5 million and zero and TNMP had outstanding borrowings of $29.4 million and $28.3 million from PNMR. At February 21, 2014, PNM and TNMP had borrowings of $17.3 million and $35.8 million from PNMR.
	Short-term Debt
	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. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from December 16, 2015 to September 18, 2018.
	On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. These facilities replaced existing facilities and provided for two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. In October 2012 and October 2013, these extension options were exercised and both facilities now expire on October 31, 2018. Each of these facilities contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%.  These ratios reflect the present value of payments under the PVNGS and EIP leases as debt.
	On January 8, 2014, PNM entered into a new $50.0 million unsecured revolving credit facility (the “PNM New Mexico Credit Facility”) by and among PNM, the lenders identified therein, U.S. Bank National Association, as Administrative Agent, and BOKF, NA dba Bank of Albuquerque, as Syndication Agent. The nine participating lenders are all banks that have a significant presence in New Mexico and PNM’s service territory or are headquartered in New Mexico. The PNM New Mexico Credit Facility expires on January 8, 2018 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility.
	As discussed above, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement in December 2012 and extended the maturity of that arrangement in December 2013. PNMR used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility.
	At December 31, 2013, the weighted average interest rate was 1.02% for the PNMR Term Loan Agreement, 1.42% for the PNM Revolving Credit Facility, and 1.42% for the PNM Term Loan Agreement. The PNMR Revolving Credit Facility and the TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2013. Short-term debt outstanding consists of:
			December 31,
	Short-term Debt		2013				2012
			(In thousands)
	PNM Revolving Credit Facility		$	49,200			$	21,100
	TNMP Revolving Credit Facility		—				—
	PNMR
	Revolving Credit Facility		—				37,600
	PNMR Term Loan Agreement		100,000				100,000
			$	149,200			$	158,700
	In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $8.6 million, $3.2 million, and $0.3 million at December 31, 2013 that reduce the available capacity under their respective revolving credit facilities.
	At February 21, 2014, PNMR, PNM, and TNMP had $291.4 million, $327.4 million, and $74.7 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $25.0 million of availability under the PNM New Mexico Credit Facility. Total availability at February 21, 2014, on a consolidated basis, was $718.5 million for PNMR. At February 21, 2014, PNMR had invested cash of $1.9 million. PNM and TNMP had no invested cash at February 21, 2014.
	Long-Term Debt
	Information concerning long-term debt outstanding is as follows:
			December 31,
	Long-term Debt		2013				2012
			(In thousands)
	PNM Debt
	Senior Unsecured Notes, Pollution Control Revenue Bonds:
	4.875% due 2033		$	146,000			$	146,000
	6.25% due 2038		36,000				36,000
	4.75% due 2040, mandatory tender at June 1, 2017		37,000				37,000
	5.20% due 2040, mandatory tender at June 1, 2020		40,045				40,045
	5.90% due 2040		255,000				255,000
	6.25% due 2040		11,500				11,500
	2.54% due 2042, mandatory tender at June 1, 2017		20,000				20,000
	4.00% due 2043, mandatory tender at June 1, 2015		39,300				39,300
	5.20% due 2043, mandatory tender at June 1, 2020		21,000				21,000
	Senior Unsecured Notes:
	7.95% due 2018		350,000				350,000
	7.50% due 2018		100,025				100,025
	5.35% due 2021		160,000				160,000
	PNM Term Loan Agreement due 2014		75,000				—
	Unamortized premiums (discounts)		(252		)		(291		)
			1,290,618				1,215,579
	Less current maturities		75,000				—
			1,215,618				1,215,579
TNMP Debt
First Mortgage Bonds:
2011 Term Loan Agreement, due 2014		50,000				50,000
9.50% due 2019, Series 2009A		172,302				265,500
6.95% due 2043, Series 2013A		93,198				—
Unamortized premiums (discounts)		20,536				(3,911		)
		336,036				311,589
Less current maturities		—				—
		336,036				311,589
PNMR Debt
Senior unsecured notes, 9.25% due 2015		118,766				142,592
Other		—				2,530
		118,766				145,122
Less current maturities		—				2,530
		118,766				142,592
Total Consolidated PNMR Debt		1,745,420				1,672,290
Less current maturities		75,000				2,530
		$	1,670,420			$	1,669,760
Reflecting mandatory tender dates, long-term debt matures as follows:
	PNMR				PNM				TNMP		PNMR Consolidated
	(In thousands)
2014	$	—			$	75,000			$	—	$	75,000
2015	118,766				39,300				—		158,066
2016	—				—				—		—
2017	—				57,000				—		57,000
2018	—				450,025				—		450,025
Thereafter	—				669,545				315,500		985,045
Total	$	118,766			$	1,290,870			$	315,500	$	1,725,136
The TNMP 2011 Term Loan Agreement, which is due on June 30, 2014, is not reflected as maturing in 2014 in the above tables since TNMP has entered into the TNMP 2013 Bond Purchase Agreement to re-finance that debt on a long-term basis as discussed in Financing Activities above.

Lease_Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Leases Commitments	'
	Lease Commitments
	The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and an interest in the EIP transmission line. Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation, and has no significant rights-of-way that will expire before 2020. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. The Navajo Nation rights-of-way agreement is accounted for as an operating lease.
	The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Each of the leases provide PNM with an option to purchase the leased assets at fair market value at the end of the leases, but PNM does not have a fixed price purchase option. In addition, the leases provide PNM with options to renew the leases at fixed rates set forth in each of the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years (the “Maximum Option Period”) if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. The rental payments during the fixed renewal option periods would be 50% of the amounts during the original terms of the leases. Gross annual lease payments, before considering the impacts of amounts returned to PNM through ownership of the lessor notes, aggregate $33.0 million for the Unit 1 leases and $23.7 million for the Unit 2 leases. If the leases are extended, the leases provide PNM with the option to purchase the leased assets at fair market value at the end of the extended lease terms.
	Each lease provides that no later than three years prior to the expiration of the lease, PNM must give notice to the lessor if it wishes to “retain” the leased assets (but without specifying whether it would purchase the leased assets or extend the lease) or “return” the leased assets to the lessor. Furthermore, each lease provides that, if PNM gives notice to “retain” the leased assets, PNM must give notice as to which of the purchase or renewal options it will exercise no later than two years prior to the expiration of the lease. The elections PNM makes under each of the leases is independent of the elections made under the other leases.
	In accordance with the notice provisions, PNM notified each of the lessors that PNM will “retain” the assets leased upon the expiration of the basic lease term on January 6, 2012 for the Unit 1 leases and on January 9, 2013 for the Unit 2 leases. On January 9, 2013, PNM notified each of the lessors of the Unit 1 leases that it will extend each Unit 1 Lease for the Maximum Option Period. On December 11, 2013, PNM and each of the Unit 1 lessors entered into amendments to each of the Unit 1 leases setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period of January 15, 2023 and provide for certain casualty values during the extended terms. On December 30, 2013, PNM notified the lessor of the one Unit 2 lease containing the Maximum Option Period provision that it will extend that lease for the Maximum Option Period. PNM anticipates entering into an amendment to that Unit 2 lease that would extend the term of the lease through a Maximum Option Period of January 15, 2024. The annual payments during the renewal periods aggregate $16.5 million for the PVNGS Unit 1 leases and $1.6 million for the Unit 2 lease. The table of future lease payments as of December 31, 2013 shown below includes payments during the renewal periods for those leases that will be extended at the end of their original terms.
	On January 13, 2014, PNM provided notices to each of the lessors under the three other Unit 2 leases, which are not subject to the Maximum Option Period provision, that PNM will exercise its option under the terms of each of those leases to purchase the assets underlying the leases at fair market value at the expiration of the leases on January 15, 2016. As provided in the leases, the fair market value of the leased assets under each of the leases will be determined by negotiation between the parties, or, if the parties are unable to agree on the fair market value, then the fair market value will be determined under the appraisal procedure specified in each of the leases. The appraisal process outlined in the leases anticipates the process to be completed within approximately six months. On February 25, 2014, PNM and the lessor under one of the Unit 2 leases entered into a letter agreement that establishes that the purchase price, representing the fair market value, to be paid by PNM for the assets underlying that lease will be $78.1 million on January 15, 2016. This lease is for 31.2494 MW of the entitlement from PVNGS Unit 2. The lease remains in existence and PNM will record the purchase at the termination of the lease on January 15, 2016.
	Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the equity participants, and take title to the leased interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2013, PNM could have been required to pay the equity participants up to approximately $154.1 million. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Exercise of renewal options under the leases requires that amounts payable to equity participants under the circumstances described above would increase to the fair market value as of the renewal date.
	PNM owns 60% of the EIP and leases the other 40%, under a lease that expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease. On November 1, 2012, PNM and the lessor entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity.
	PNMR leases a building that was used as part of its corporate headquarters, as well as housing certain support functions for the utility operations of PNM and TNMP. The lease expires on November 30, 2015 and provides for annual rents of $1.9 million, which are included in the tables below. PNMR is also obligated to pay taxes, insurance, and utilities applicable to the building. In November 2011, PNMR notified the lessor of its intent to vacate the building by the end of 2012 and made a settlement offer to terminate the lease. A termination agreement was not reached with the lessor. As of December 31, 2012, PNMR completed the abandonment of this building, as well as the partial abandonment of another leased building. In accordance with GAAP, PNMR recorded an abandonment expense of $7.4 million at December 31, 2012. PNM was allocated $6.2 million and TNMP was allocated $1.2 million of the abandonment expense for the period ended December 31, 2012, which is reflected as administrative and general expense.
	PNM has a PPA for the entire output of Delta, a gas-fired generating plant in Albuquerque, New Mexico, which is classified as an operating lease with imputed annual lease payments of $6.0 million. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.
	Operating lease expense, including the PVNGS and EIP leases, was:
		PNMR		PNM		TNMP
		(In thousands)
	2013	$	82,882	$	78,306	$	2,663
	2012	$	84,794	$	78,483	$	2,871
	2011	$	86,323	$	78,422	$	3,606
	As discussed under Investments in Note 1, the PVNGS Capital Trust, which is consolidated by PNM, acquired the lessor notes that were issued by the PVNGS lessors and PNM acquired the remaining lessor note issued by the remaining EIP lessor. Future minimum operating lease payments at December 31, 2013 shown below have been reduced by payments on the PVNGS lessor notes of $25.4 million in 2014, $24.0 million in 2015, and $9.0 million in 2016 that will be returned in cash to PNM:
		PNMR		PNM		TNMP
		(In thousands)
	2014	$	53,594	$	49,580	$	815
	2015	40,952		38,290		676
	2016	33,788		33,363		237
	2017	30,942		30,749		—
	2018	30,948		30,749		—
	Later years	167,225		166,830		—
		357,449		349,561		1,728
	Future payments under non-cancelable subleases	93		—		—
	Net minimum lease payments	$	357,356	$	349,561	$	1,728

Fair_Value_of_Derivative_and_O

Fair Value of Derivative and Other Financial Instruments	12 Months Ended
	Dec. 31, 2013
Fair Value of Derivative and Other Financial Instruments [Abstract]	'
Fair Value of Derivative and Other Financial Instruments	'
		Fair Value of Derivative and Other Financial Instruments
	Energy Related Derivative Contracts
	Overview
	The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. 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.
	On November 1, 2011, PNMR completed the sale of First Choice. See Note 3. Accordingly, PNMR information reflects activity for First Choice through October 31, 2011. The difference between the PNMR and PNM amounts represents First Choice.
	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.
	First Choice was responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers were negotiated with each customer. First Choice purchased power at wholesale and sold power at retail to customers in the competitive ERCOT retail markets. First Choice’s strategy was to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. However, First Choice had a residual exposure to wholesale power price risk for the mismatch between the forecast and actual load.
	Accounting for Derivatives
	Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal purchases and normal sales exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle.
	For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. The Company assesses the effectiveness of hedge relationships at least quarterly using statistical data. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. As of December 31, 2013 and 2012, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges.
	The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the 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, recorded at fair value are summarized as follows:
		Economic Hedges
		December 31,
		2013				2012
		(In thousands)
	PNM and PNMR
	Current assets	$	4,064			$	3,785
	Deferred charges	3,002				352
		7,066				4,137
	Current liabilities	(2,699		)		(1,000		)
	Long-term liabilities	(1,094		)		(1,933		)
		(3,793		)		(2,933		)
	Net	$	3,273			$	1,204
	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 was immaterial at December 31, 2013 and 2012.
	At December 31, 2013 and 2012, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at December 31, 2013 and 2012, amounts posted as cash collateral under margin arrangements were $2.8 million and $1.9 million for both PNMR and PNM. At December 31, 2013 and 2012, PNMR and PNM had obligations to return cash collateral of approximately $0.2 million and zero. Cash collateral amounts are included in other current assets and other current liabilities on the Consolidated Balance Sheets.
	PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.4 million of current assets and $0.1 million of current liabilities at December 31, 2013, and less than $0.1 million of current assets and current liabilities at December 31, 2012 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Consolidated Balance Sheets.
	The following table presents the effect of mark-to-market commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, including de-designated hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.
		Economic										Qualified Cash
		Hedges										Flow Hedges
		Year Ended										Year Ended
		December 31,										December 31,
		2013				2012			2011			2013		2012			2011
		(In thousands)
	PNMR
	Electric operating revenues	$	1,727			$	6,168		$	5,682		$	—	$	—		$	—
	Cost of energy	1,109				(460		)	(2,201		)	—		—			(422		)
	Total gain (loss)	$	2,836			$	5,708		$	3,481		$	—	$	—		$	(422	)
	Recognized in OCI											$	—	$	—		$	422
	PNM
	Electric operating revenues	$	1,727			$	6,168		$	5,682		$	—	$	—		$	—
	Cost of energy	1,109				(460		)	(1,058		)	—		—			—
	Total gain (loss)	$	2,836			$	5,708		$	4,624		$	—	$	—		$	—
	Recognized in OCI											$	—	$	—		$	—
	Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
		Economic Hedges
		MMBTU			MWh
	December 31, 2013
	PNMR and PNM	905,000			(3,343,783	)
	December 31, 2012
	PNMR and PNM	1,127,500			(2,477,520	)
	In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral.
	The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.
	Contingent Feature –		Contractual				Existing Cash			Net Exposure
	Credit Rating Downgrade		Liability				Collateral
			(In thousands)
	December 31, 2013
	PNMR and PNM		$	2,398			$	—		$	2,152
	December 31, 2012
	PNMR and PNM		$	2,933			$	—		$	2,777
Sale of Power from PVNGS Unit 3
Because PNM’s 134 MW share of Unit 3 at PVNGS is excluded from retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of December 31, 2013, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium.  PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015.
Non-Derivative Financial Instruments
The carrying amounts reflected on the Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). PNMR and PNM do not have any unrealized losses on available-for-sale securities. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2013 and 2012, the fair value of available-for-sale securities included $222.5 million and $189.0 million for the NDT and $4.4 million and $3.5 million for the mine reclamation trust.
	December 31, 2013							December 31, 2012
	Unrealized				Fair Value			Unrealized			Fair Value
	Gains							Gains
PNMR and PNM					(In thousands)
Cash and cash equivalents	$	—			$	3,356		$	—		$	4,628
Equity securities:
Domestic value	14,523				39,460			5,223			30,044
Domestic growth	25,656				76,292			15,212			51,650
International and other	1,040				16,633			247			14,868
Fixed income securities:
U.S. Government	158				21,941			1,305			32,592
Municipals	1,018				58,568			4,069			43,861
Corporate and other	207				10,605			1,100			14,868
	$	42,602			$	226,855		$	27,156		$	192,511
The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold.
	Year Ended December 31,
	2013				2012			2011
	(In thousands)
Proceeds from sales	$	271,140			$	167,330		$	145,286
Gross realized gains	$	14,308			$	15,907		$	17,493
Gross realized (losses)	$	(4,298	)		$	(8,170	)	$	(6,223	)
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments.
The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.
At December 31, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities:
	Fair Value
	Available-for-Sale				Held-to-Maturity
	PNMR and PNM				PNMR			PNM
	(In thousands)
Within 1 year	$	3,025			$	1,149		$	1,149
After 1 year through 5 years	24,068				57,497			56,130
After 5 years through 10 years	10,128				—			—
After 10 years through 15 years	6,136				—			—
After 15 years through 20 years	10,331				—			—
After 20 years	37,426				—			—
	$	91,114			$	58,646		$	57,279
Fair Value Disclosures
The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.
For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services.
The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the years ended December 31, 2013 and 2012.
Derivatives and Investments
Items recorded at fair value on the Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at December 31, 2013 and 2012 for items recorded at fair value.
					GAAP Fair Value Hierarchy
	Total				Quoted Prices			Significant
					in Active			Other
					Market for			Observable
					Identical Assets			Inputs
					(Level 1)			(Level 2)
December 31, 2013					(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356			$	3,356		$	—
Equity securities:
Domestic value	39,460				39,460			—
Domestic growth	76,292				76,292			—
International and other	16,633				16,633			—
Fixed income securities:
U.S. Government	21,941				20,194			1,747
Municipals	58,568				—			58,568
Corporate and other	10,605				2,245			8,360
	$	226,855			$	158,180		$	68,675
Commodity derivative assets	$	7,066			$	—		$	7,066
Commodity derivative liabilities	(3,793		)		—			(3,793		)
Net	$	3,273			$	—		$	3,273
					GAAP Fair Value Hierarchy
	Total				Quoted Prices			Significant
					in Active			Other
					Market for			Observable
					Identical Assets			Inputs
					(Level 1)			(Level 2)
December 31, 2012					(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	4,628			$	4,628		$	—
Equity securities:
Domestic value	30,044				30,044			—
Domestic growth	51,650				51,650			—
International and other	14,868				14,868			—
Fixed income securities:
U.S. Government	32,592				27,737			4,855
Municipals	43,861				—			43,861
Corporate and other	14,868				—			14,868
	$	192,511			$	128,927		$	63,584
Commodity derivative assets	$	4,137			$	—		$	4,137
Commodity derivative liabilities	(2,933		)		—			(2,933		)
Net	$	1,204			$	—		$	1,204
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 Consolidated Balance Sheets are presented below:
								GAAP Fair Value Hierarchy
	Carrying				Fair Value			Level 1			Level 2		Level 3
	Amount
December 31, 2013	(In thousands)
PNMR
Long-term debt	$	1,745,420			$	1,905,230		$	—		$	1,905,230	$	—
Investment in PVNGS lessor notes	$	52,958			$	57,279		$	—		$	—	$	57,279
Other investments	$	1,835			$	3,196		$	690		$	—	$	2,506
PNM
Long-term debt	$	1,290,618			$	1,382,938		$	—		$	1,382,938	$	—
Investment in PVNGS lessor notes	$	52,958			$	57,279		$	—		$	—	$	57,279
Other investments	$	445			$	445		$	445		$	—	$	—
TNMP
Long-term debt	$	336,036			$	390,814		$	—		$	390,814	$	—
Other investments	$	245			$	245		$	245		$	—	$	—
December 31, 2012
PNMR
Long-term debt	$	1,672,290			$	1,969,362		$	—		$	1,966,725	$	2,637
Investment in PVNGS lessor notes	$	77,682			$	84,198		$	—		$	—	$	84,198
Other investments	$	5,599			$	6,965		$	774		$	—	$	6,191
PNM
Long-term debt	$	1,215,579			$	1,385,433		$	—		$	1,385,433	$	—
Investment in PVNGS lessor notes	$	77,682			$	84,198		$	—		$	—	$	84,198
Other investments	$	494			$	494		$	494		$	—	$	—
TNMP
Long-term debt	$	311,589			$	418,166		$	—		$	418,166	$	—
Other investments	$	281			$	281		$	281		$	—	$	—
Investments Held by Employee Benefit Plans
As discussed in Note 12, PNM and TNMP have trusts that hold investment assets for their pension and other postretirement benefit plans. The fair value of the assets held by the trusts impacts the determination of the funded status of each plan, but the assets are not reflected on the Company’s Consolidated Balance Sheets. Both the PNM Pension Plan and the TNMP Pension Plan hold units of participation in the PNM Resources, Inc. Master Trust (the “PNMR Master Trust”), which was established for the investment of assets of the pension plans. Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For level 2 fair values, the pricing provider predominately uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. Level 2 investments in mutual funds are measured at net asset value as year-end. Level 3 investments are comprised of alternative investments, which are measured at net asset value at year-end and include private equity funds, hedge funds, and real estate funds. The private equity funds are not voluntarily redeemable. These investments are realized through periodic distributions occurring over a 10 to 15-year term after the initial investment. The real estate funds and hedge funds may be voluntarily redeemed but are subject to redemption provisions that may result in the funds not being able to be redeemed in the near term. Audited financial statements are received for each fund and are reviewed by the Company annually.
The valuation of alternative investments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates and cash flows. The fair values of investments held by the employee benefit plans are as follows:
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active Market for Identical Assets			Significant			Significant
					(Level 1)			Other			Unobservable
								Observable			Inputs
								Inputs			(Level 3)
								(Level 2)
December 31, 2013					(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	557,258			$	145,364		$	330,903		$	80,991
TNMP Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	66,285			$	18,657		$	32,620		$	15,008
PNM OPEB Plan
Cash and cash equivalents	$	1,152			$	1,152		$	—		$	—
Equity securities:
International funds	3,057				—			3,057			—
Domestic value	6,388				6,388			—			—
Domestic growth	54,851				20,769			34,082			—
Other funds	5,564				—			5,564			—
Fixed income securities:
Mutual funds	3,121				3,121			—			—
	$	74,133			$	31,430		$	42,703		$	—
TNMP OPEB Plan
Cash and cash equivalents	$	302			$	302		$	—		$	—
Equity securities:
International funds	1,334				—			1,334			—
Domestic value	381				381			—			—
Domestic growth	1,848				1,848			—			—
Other funds	4,167				—			4,167			—
Fixed income securities:
Mutual funds	1,702				1,702			—			—
	$	9,734			$	4,233		$	5,501		$	—
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in Active			Significant			Significant
					Market for Identical Assets			Other			Unobservable
					(Level 1)			Observable			Inputs
								Inputs			(Level 3)
								(Level 2)
December 31, 2012	(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust	$	517,238			$	205,491		$	232,730		$	79,017
TNMP Pension Plan
Participation in PNMR Master Trust	$	66,450			$	26,462		$	25,817		$	14,171
PNM OPEB Plan
Cash and cash equivalents	$	4,976			$	4,976		$	—		$	—
Equity securities:
International funds	2,651				—			2,651			—
Domestic growth	46,145				19,511			26,634			—
Other funds	7,588				—			7,588			—
Fixed income securities:
Mutual funds	4,176				4,176			—			—
	$	65,536			$	28,663		$	36,873		$	—
TNMP OPEB Plan
Cash and cash equivalents	$	42			$	42		$	—		$	—
Equity securities:
International funds	1,444				—			1,444			—
Domestic growth	1,289				1,289			—			—
Other funds	3,660				—			3,660			—
Fixed income securities:
Mutual funds	2,325				2,325			—			—
	$	8,760			$	3,656		$	5,104		$	—
The fair values of investments in the PNMR Master Trust are as follows:
					GAAP Fair Value Hierarchy
	Total				Quoted Prices in			Significant			Significant
					Active Market for			Other			Unobservable
					Identical Assets			Observable			Inputs
					(Level 1)			Inputs			(Level 3)
								(Level 2)
December 31, 2013	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	16,281			$	16,281		$	—		$	—
Equity securities:
International	24,471				24,471			—			—
Domestic value	41,451				41,451			—			—
Domestic growth	36,805				36,805			—			—
Other funds	22,522				—			22,522			—
Fixed income securities:
Corporate	202,897				363			202,358			176
U.S. Government	99,748				44,541			55,207			—
Municipals	17,259				—			17,259			—
Other funds	66,286				109			66,177			—
Alternative investments:
Private equity funds	39,122				—			—			39,122
Hedge funds	34,912				—			—			34,912
Real estate funds	21,789				—			—			21,789
	$	623,543			$	164,021		$	363,523		$	95,999
December 31, 2012
PNMR Master Trust
Cash and cash equivalents	$	10,404			$	10,404		$	—		$	—
Equity securities:
International	39,867				39,867			—			—
Domestic value	39,492				39,492			—			—
Domestic growth	63,888				63,888			—			—
Other funds	17,035				—			17,035			—
Fixed income securities:
Corporate	101,936				—			101,936			—
U.S. Government	148,341				78,302			70,039			—
Municipals	3,639				—			3,639			—
Other funds	65,898				—			65,898			—
Alternative investments:
Private equity funds	38,212				—			—			38,212
Hedge funds	31,277				—			—			31,277
Real estate funds	23,699				—			—			23,699
	$	583,688			$	231,953		$	258,547		$	93,188
A reconciliation of the changes in Level 3 fair value measurements is as follows:
	Year Ended December 31,
Level 3 Fair Value Assets and Liabilities	2013				2012
	(In thousands)
PNM Pension	Master				Master
	Trust				Trust
Balance at beginning of period	$	79,017			$	84,133
Actual return on assets sold during the period	3,303				2,627
Actual return on assets still held at period end	3,361				2,386
Purchases	15,110				5,498
Sales	(19,800		)		(15,627		)
Balance at end of period	$	80,991			$	79,017
TNMP Pension
Balance at beginning of period	$	14,171			$	14,555
Actual return on assets sold during the period	1,400				197
Actual return on assets still held at period end	1,425				179
Purchases	6,408				413
Sales	(8,396		)		(1,173		)
Balance at end of period	$	15,008			$	14,171
Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
Level 3 Fair Value Assets and Liabilities
PNMR Master Trust	Private				Hedge			Real			Fixed income - corporate		Total
	equity				funds			estate
	funds							funds
					(In thousands)
Balance at December 31, 2011	$	37,100			$	36,904		$	24,684		$	—	$	98,688
Actual return on assets sold during the period	2,966				(80		)	(62		)	—		2,824
Actual return on assets still held at period end	40				2,453			72			—		2,565
Purchases	3,906				—			2,005			—		5,911
Sales	(5,800		)		(8,000		)	(3,000		)	—		(16,800		)
Balance at December 31, 2012	38,212				31,277			23,699			—		93,188
Actual return on assets sold during the period	4,677				135			(109		)	—		4,703
Actual return on assets still held at period end	1,162				3,500			123			1		4,786
Purchases	3,117				16,151			2,076			175		21,519
Sales	(8,046		)		(16,151		)	(4,000		)	—		(28,197		)
Balance at December 31, 2013	$	39,122			$	34,912		$	21,789		$	176	$	95,999

Variable_Interest_Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2013
Variable Interest Entities	'
Variable Interest Entities	'
	Variable Interest Entities
	GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.
	Valencia
	PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the years ended December 31, 2013, 2012, and 2011, PNM paid $18.9 million, $18.8 million, and $18.3 million for fixed charges and $1.2 million, $0.9 million, and $1.4 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.
	PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.
	Summarized financial information for Valencia is as follows:
	Results of Operations
		Year ended December 31,
		2013			2012			2011
		(In thousands)
	Operating revenues	$	20,166		$	19,585		$	19,720
	Operating expenses	(5,645		)	(5,535		)	(5,673		)
	Earnings attributable to non-controlling interest	$	14,521		$	14,050		$	14,047
	Financial Position
		December 31,
		2013			2012
		(In thousands)
	Current assets	$	2,658		$	3,655
	Net property, plant and equipment	75,137			77,953
	Total assets	77,795			81,608
	Current liabilities	766			765
	Owners’ equity – non-controlling interest	$	77,029		$	80,843
	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 has been initiated since the parties failed to reach agreement on fair market value within 60 days. After the purchase price has been determined through the appraisal process, PNM may in its sole discretion determine whether or not it desires to exercise its option to purchase the 50% interest. In that regard, PNM will evaluate all its alternatives with respect to Valencia with the goal of achieving a fair and economical benefit for its customers. Also, PNM is in the process of developing its 2014 IRP (Note 17). Through this process, PNM will evaluate all of its resource options, including Valencia, to determine the optimal way to serve its customers. If PNM decides to exercise its option, the approval of the NMPRC and FERC would be required, which process could take up to 15 months. Since the purchase price is yet to be established, PNM cannot determine whether or not it will exercise its option or if required regulatory approvals would be received.
	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. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases, but PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provide PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. See Note 7 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $52.5 million over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM has elected to renew. 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 December 31, 2013, PNM could have been required to pay the beneficial owners up to approximately $154.1 million, which would result in PNM taking ownership of the leased assets and termination of the leases. During the terms of the leases: PNM has no other financial obligations or commitments to the trusts or the beneficial owners; creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments; and PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Consolidated Balance Sheets related to the trusts other than accrued lease payments of $26.0 million at December 31, 2013 and 2012, which are included in other current liabilities on the Consolidated Balance Sheets.
	PNM has evaluated the PVNGS lease arrangements, including the notices provided through January 2014 to the lessors (Note 7), and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts during the original and extended lease terms and, therefore, is not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since the operating licenses for the plants have been extended for twenty years through 2045 for Unit 1 and 2046 for Unit 2; PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease terms, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so does not significantly influence the day-to-day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from potential carbon legislation or regulation.
	Delta
	PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. PNM makes fixed and variable payments to Delta under the PPA. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. For the years ended December 31, 2013, 2012, and 2011, PNM incurred fixed capacity charges of $6.4 million, $6.2 million, and $6.0 million and variable energy charges of $1.8 million, $0.8 million, and $1.5 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of December 31, 2013, aggregated $39.2 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation.
	This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.
	In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owns Delta. At closing PNM would make a cash payment of $23.0 million, which would be adjusted for actual working capital compared to a targeted working capital and certain prepayments of debt. Delta had project financing debt of $19.2 million at December 31, 2012, including $3.0 million due in 2013, which PNM would retire at closing of the purchase. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing is subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM and Delta are working with the City of Albuquerque and EPA in order to remedy certain environmental issues. Closing of the purchase will occur once those issues are resolved.
	Delta informed PNM that at December 31, 2013 and December 31, 2012, it had total assets of $23.7 million and $26.6 million, including net property, plant, and equipment of $20.3 million and $23.1 million, and total liabilities of $18.2 million and $21.1 million. Delta’s project financing debt amounted to $16.2 million at December 31, 2013, of which $3.3 million is due in 2014. Delta also indicated its 2013 and 2012 revenues were $9.5 million and $7.4 million and its net earnings were $1.2 million and $0.9 million. Consolidation of Delta would be immaterial to the Consolidated Balance Sheets for PNMR and PNM. Since all of Delta’s revenues and expenses are attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Consolidated Statements of Earnings for PNMR and PNM would be to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

Earnings_and_Dividends_Per_Sha

Earnings and Dividends Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings and Dividends Per Share	'
	Earnings and Dividends Per Share
	In accordance with GAAP, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share and dividends per share is as follows:
		Year Ended December 31,
		2013		2012		2011
		(In thousands, except per share amounts)
	Earnings Attributable to PNMR	$	100,507	$	105,547	$	176,359
	Average Number of Common Shares:
	Outstanding during year	79,654		79,654		85,558
	Equivalents from convertible preferred stock (Note 5)	—		—		3,469
	Vested awards of restricted stock	191		145		174
	Average Shares - Basic	79,845		79,799		89,201
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	586		618		556
	Average Shares – Diluted	80,431		80,417		89,757
	Net Earnings Per Share of Common Stock:
	Basic	$	1.26	$	1.32	$	1.98
	Diluted	$	1.25	$	1.31	$	1.96
	Dividends Declared per Common Share	$	0.68	$	0.58	0.5
	(1)	Excludes out-of-the-money options for 509,916 shares of common stock at December 31, 2013. See Note 13.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	PNMR
	PNMR’s income taxes consist of the following components:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current federal income tax	$	—		$	(1,296	)	$	1,319
	Current state income tax	(917		)	(37		)	(4,208		)
	Deferred federal income tax	50,044			51,559			119,280
	Deferred state income tax	12,578			6,921			7,462
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Total income taxes	$	59,513		$	54,910		$	121,535
	PNMR’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Federal income tax at statutory rates	$	61,274		$	61,262		$	109,364
	First Choice goodwill	—			—			15,055
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Flow-through of depreciation items	1,132			1,284			3,659
	Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
	State income tax, net of federal benefit	3,818			4,646			3,395
	Impairment of state production tax credits, net of federal benefit	3,880			718			—
	Other	(3,317		)	(5,845		)	(2,703		)
	Total income taxes	$	59,513		$	54,910		$	121,535
	Effective tax rate	33.99		%	31.37		%	38.9		%
	The components of PNMR’s net accumulated deferred income tax liability were:
		December 31,
		2013			2012
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	134,418		$	110,989
	Pension	—			26,452
	Regulatory liabilities related to income taxes	83,838			53,439
	Other	144,126			129,801
	Total deferred tax assets	362,382			320,681
	Deferred tax liabilities:
	Depreciation and plant related	(814,671		)	(759,587		)
	Investment tax credit	(25,855		)	(14,242		)
	Regulatory assets related to income taxes	(66,352		)	(59,471		)
	CTC	(22,262		)	(24,934		)
	Pension	(58,780		)	—
	Other	(143,044		)	(178,492		)
	Total deferred tax liabilities	(1,130,964		)	(1,036,726		)
	Net accumulated deferred income tax liabilities	(768,582		)	(716,045		)
	Current accumulated deferred income tax (asset) liability	(58,681		)	258
	Non-current accumulated deferred income tax liability	$	(827,263	)	$	(715,787	)
	The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2013
		(In thousands)
	Net change in deferred income tax liability per above table	$	52,537
	Change in tax effects of income tax related regulatory assets and liabilities	23,592
	Tax effect of mark-to-market adjustments	(6,096		)
	Tax effect of excess pension liability	(9,305		)
	Adjustment for uncertain income tax positions	691
	Other	(989		)
	Deferred income taxes	$	60,430
	PNM
	PNM’s income taxes consist of the following components:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
Current federal income tax	$	(479	)	$	(12,951	)	$	(46,364	)
Current state income tax	(760		)	(1,815		)	(6,776		)
Deferred federal income tax	42,806			56,194			78,673
Deferred state income tax	9,429			11,522			14,212
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Total income taxes	$	48,804		$	50,713		$	37,427
PNM’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Federal income tax at statutory rates	$	53,018		$	54,710		$	37,088
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Flow-through of depreciation items	1,115			1,268			3,656
Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
State income tax, net of federal benefit	6,202			6,500			4,797
Other	(4,257		)	(4,610		)	(879		)
Total income taxes	$	48,804		$	50,713		$	37,427
Effective tax rate	32.22		%	32.44		%	35.32		%
The components of PNM’s net accumulated deferred income tax liability were:
	December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Net operating loss	$	99,247		$	93,980
Pension	—			32,532
Regulatory liabilities related to income taxes	78,849			48,027
Other	67,179			55,629
Total deferred tax assets	245,275			230,168
Deferred tax liabilities:
Depreciation and plant related	(661,239		)	(624,724		)
Investment tax credit	(25,855		)	(14,242		)
Regulatory assets related to income taxes	(55,844		)	(48,726		)
Pension	(52,104		)	—
Other	(83,500		)	(134,046		)
Total deferred tax liabilities	(878,542		)	(821,738		)
Net accumulated deferred income tax liabilities	(633,267		)	(591,570		)
Current accumulated deferred income tax (asset) liability	(43,827		)	3,447
Non-current accumulated deferred income tax liability	$	(677,094	)	$	(588,123	)
The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
	Year Ended
	December 31, 2013
	(In thousands)
Net change in deferred income tax liability per above table	$	41,697
Change in tax effects of income tax related regulatory assets and liabilities	23,704
Tax effect of mark-to-market adjustments	(6,121		)
Tax effect of excess pension liability	(9,305		)
Adjustment for uncertain income tax positions	691
Other	(623		)
Deferred income taxes	$	50,043
TNMP
TNMP’s income taxes consist of the following components:
	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Current federal income tax	$	(4,957	)	$	9,152		$	(3,578	)
Current state income tax	1,916			1,822			1,981
Deferred federal income tax	20,688			4,406			15,507
Deferred state income tax	(26		)	(28		)	(29		)
Total income taxes	$	17,621		$	15,352		$	13,881
TNMP’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the periods shown. The differences are attributable to the following factors:
	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Federal income tax at statutory rates	$	16,349		$	14,735		$	12,648
State income tax, net of federal benefit	1,247			1,185			1,288
Other	25			(568		)	(55		)
Total income taxes	$	17,621		$	15,352		$	13,881
Effective tax rate	37.72		%	36.47		%	38.41		%
The components of TNMP’s net accumulated deferred income tax liability at December 31, were:
	December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	4,988		$	5,412
Other	23,479			16,702
Total deferred tax assets	28,467			22,114
Deferred tax liabilities:
Depreciation and plant related	(151,581		)	(133,686		)
CTC	(22,262		)	(24,934		)
Regulatory assets related to income taxes	(10,509		)	(10,745		)
Loss on reacquired debt	(13,516		)	(599		)
Other	(14,295		)	(14,729		)
Total deferred tax liabilities	(212,163		)	(184,693		)
Net accumulated deferred income tax liabilities	(183,696		)	(162,579		)
Current accumulated deferred income tax (asset)	(6,501		)	(1,131		)
Non-current accumulated deferred income tax liability	$	(190,197	)	$	(163,710	)
The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
	Year Ended
	December 31, 2013
	(In thousands)
Net change in deferred income tax liability per above table	$	21,117
Change in tax effects of income tax related regulatory assets and liabilities	(112		)
Other	(343		)
Deferred income taxes	$	20,662
Other Disclosures
GAAP requires that the Company recognize only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the taxing authority. A reconciliation of unrecognized tax benefits (expenses) is as follows:
	PNMR			PNM			TNMP
	(In thousands)
Balance at December 31, 2010	$	36,105		$	11,918		$	7,788
Additions based on tax positions related to 2011	(790		)	(717		)	(74		)
Reductions for tax positions of prior years	(15,735		)	(449		)	(13		)
Settlements	—			—			—
Balance at December 31, 2011	19,580			10,752			7,701
Additions based on tax positions related to 2012	2,046			1,152			—
Reductions for tax positions of prior years	(2,428		)	(1,522		)	(905		)
Settlements	—			—			—
Balance at December 31, 2012	19,198			10,382			6,796
Reductions based on tax positions related to 2013	(54		)	(54		)	—
Additions for tax positions of prior years	745			745			—
Settlements	—			—			—
Balance at December 31, 2013	$	19,889		$	11,073		$	6,796
Included in the balance at December 31, 2013 are $5.6 million and $1.4 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate for PNMR and PNM. None of TNMP’s unrecognized tax benefits at December 31, 2013 would affect the effective tax rate if recognized. The Company believes that it is reasonably possible that approximately $5.5 million of PNMR’s unrecognized tax expenses, $0.4 million of PNM’s unrecognized tax benefits, and $6.8 million of TNMP’s unrecognized tax expenses will be reduced or settled in 2014 as a result of the conclusion of income tax examinations. As discussed in Note 1, the Company has elected not to early adopt Accounting Standards Update 2013-11.
Estimated interest income related to refunds the Company expects to receive is included in Other Income and estimated interest expense and penalties related to potential cash settlements are included in interest expense in the Consolidated Statements of Earnings (Loss). Interest income (expense) related to income taxes is as follows:
	PNMR			PNM			TNMP
	(In thousands)
2013	$	242		$	251		$	(2	)
2012	$	243		$	244		$	(3	)
2011	$	467		$	401		$	2
Accumulated accrued interest receivable (payable) related to income taxes is as follows:
	PNMR			PNM			TNMP
	(In thousands)
December 31, 2013:
Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)
December 31, 2012:
Accumulated accrued interest receivable	$	3,796		$	3,796		$	—
Accumulated accrued interest payable	$	(1,108	)	$	(23	)	$	(116	)
The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2003 are closed to examination by either federal or state taxing authorities. Tax year 2003 is open for examination only for certain items. Tax year 2004 is closed to examination by federal and state taxing authorities. Other tax years are open to examination by federal and state taxing authorities. At December 31, 2013, the Company has $301.2 million of federal net operating loss carryforwards that expire beginning in 2030 and $40.6 million of federal tax credit carryforwards that expire beginning in 2023. State net operating losses expire beginning in 2015 and vary from federal due to differences between state and federal tax law.
PNMR has New Mexico wind energy production tax credit carry forwards with statutory expiration dates beginning in 2013. In 2012, PNMR impaired $0.7 million, after federal tax benefit, of the New Mexico wind energy production tax credit carry forwards that were not expected to be utilized prior to their expiration due to the Company’s net operating loss position. The impairment is reflected in PNMR’s Corporate and Other segment.
On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law.  Due to provisions in the act, taxes payable to the state of New Mexico for 2013 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR recorded this impairment, which after federal income tax benefit, amounted to $1.5 million as additional income tax expense during the year ended December 31, 2013. The impairment is reflected in PNMR’s Corporate and Other segment.
On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse. The portion of the adjustment related to PNM's regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. The portion of the adjustment that is not related to PNM's regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the year ended December 31, 2013. This additional income tax expense is reflected in PNMR's Corporate and Other segment.
The future reduction in taxes payable to the State of New Mexico resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income resulted in a further impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $2.4 million as additional income tax expense during the year ended December 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment.
The impairments of the New Mexico wind energy production tax credits discussed above are reflected as a valuation allowance against deferred tax assets. At December 31, 2013, PNMR had a total allowance of $7.2 million, all of which is attributable to these credits. During the year ended December 31, 2013, the valuation allowance increased by $3.9 million. PNM and TNMP have no such valuation allowances.
In April 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property.  Adoption of the safe harbor method is elective for years ending on or after December 31, 2012.  On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material.
In September 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material.
In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM.

Pension_and_Other_Postretireme

Pension and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Pension and Other Postretirement Benefits	'
	Pension and Other Postretirement Benefits
	PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (“PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. PNM receives a regulated return on the amount it has funded for its pension plan in excess of the periodic cost or income to the extent included in retail rates.
	Participants in the PNM Plans include eligible employees and retirees of PNMR and other subsidiaries of PNMR. Participants in the TNMP Plans include eligible employees and retirees of TNMP. The PNM pension plan was frozen at the end of 1997 with regard to new participants, salary levels, and benefits. Through December 31, 2007, additional credited service could be accrued under the PNM pension plan up to a limit determined by age and service. The TNMP pension plan was frozen at December 31, 2005 with regard to new participants, salary levels, and benefits.
	GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur.
	GAAP requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs will ultimately be included as pension and postretirement benefit periodic cost or income in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP record the costs as a regulatory asset or regulatory liability.
	For the PNM Plans and TNMP Plans, the Company has in place a policy that defines the investment objectives, establishes performance goals of the asset managers, and provides procedures for the manner in which investments are to be reviewed. The plans implement investment strategies to achieve the following objectives:
	•	Maximize the return on assets, commensurate with the risk that the Corporate Investment Committee deems appropriate to meet the obligations of the pension plans and OPEB plans, minimize the volatility of expense, and account for contingencies
	•	Transition asset mix over time to a higher proportion of high quality fixed income investments as the plans’ funded statuses improve
	Management is responsible for the determination of the asset target mix and the expected rate of return. The target asset allocations are determined based on consultations with external investment advisors. The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility. For the PNM Plans and TNMP Plans, the market-related value of assets is equal to the prior year’s market related value of assets adjusted for contributions, benefit payments and investment gains and losses that are within a corridor of plus or minus 4.0% around the expected return on market value. Gains and losses that are outside the corridor are amortized over five years.
	Pension Plans
	For defined benefit pension plans, including the executive retirement plans, the PBO represents the actuarial present value of all benefits attributed by the pension benefit formula to employee service rendered prior to that date using assumptions regarding future compensation levels. The ABO represents the PBO without considering future compensation levels. Since the plans are frozen, the PBO and ABO are equal. The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2013				2012				2013			2012
		(In thousands)
	PBO at beginning of year	$	675,549			$	588,874			$	76,640		$	67,234
	Service cost	—				—				—			—
	Interest cost	28,142				32,232				3,087			3,635
	Plan amendment	(6,346		)		—				—			—
	Actuarial (gain) loss	(56,533		)		94,361				(7,820		)	11,434
	Benefits paid	(41,275		)		(39,918		)		(5,748		)	(5,663		)
	PBO at end of year	599,537				675,549				66,159			76,640
	Fair value of plan assets at beginning of year	518,095				427,386				66,540			59,952
	Actual return on plan assets	19,533				52,927				4,326			6,951
	Employer contributions	60,000				77,700				1,000			5,300
	Benefits paid	(41,275		)		(39,918		)		(5,748		)	(5,663		)
	Fair value of plan assets at end of year	556,353				518,095				66,118			66,540
	Funded status – asset (liability) for pension benefits	$	(43,184	)		$	(157,454	)		$	(41	)	$	(10,100	)
	Effective January 1, 2014, the PNM Pension Plan was amended to allow for all participants, terminating after the effective date, to elect a lump sum payment of benefits. This change is reflected in the above table as of December 31, 2013.
	The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2013.
		PNM Plan								TNMP Plan
		December 31, 2013								December 31, 2013
		Prior service				Net actuarial				Net actuarial
		cost				(gain) loss				(gain) loss
		(In thousands)
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$	32			$	159,826			$	—
	Experience loss (gain)	—				(34,136		)		(7,297		)
	Regulatory asset (liability) adjustment	—				19,799				7,297
	Plan amendment	(2,665		)		—				—
	Amortization recognized in net periodic benefit cost (income)	(32		)		(6,233		)		—
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,665	)		$	139,256			$	—
	Amortization expected to be recognized in 2014	$	(405	)		$	5,469			$	—
	The following table presents the components of net periodic benefit cost (income):
		Year Ended December 31,
		2013				2012				2011
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	28,142				32,232				32,804
	Expected return on plan assets	(41,930		)		(41,301		)		(37,075		)
	Amortization of net (gain) loss	14,840				10,516				9,209
	Amortization of prior service cost	76				317				317
	Net periodic benefit cost	$	1,128			$	1,764			$	5,255
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	3,087				3,635				3,800
	Expected return on plan assets	(4,849		)		(5,324		)		(5,470		)
	Amortization of net (gain) loss	1,049				462				346
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost (income)	$	(713	)		$	(1,227	)		$	(1,324	)
	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.
		Year Ended December 31,
	PNM Plan	2013			2012			2011
Discount rate for determining December 31 PBO	5.27	%		4.3	%		5.67	%
Discount rate for determining net periodic benefit cost (income)	4.3	%		5.67	%		5.72	%
Expected return on plan assets	7.65	%		8.25	%		8.5	%
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.06	%		4.19	%		5.69	%
Discount rate for determining net periodic benefit cost (income)	4.19	%		5.69	%		5.5	%
Expected return on plan assets	7.65	%		8.25	%		8.5	%
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in discount rates resulted in a decrease in the PNM PBO of $60.9 million at December 31, 2013 and an increase of $86.4 million at December 31, 2012. Changes in discount rates resulted in a decrease in the TNMP PBO of $6.4 million at December 31, 2013 and an increase of $10.7 million at December 31, 2012. Changes in demographic experiences also resulted in actuarial losses in the PNM PBO of $4.4 million and $8.0 million at December 31, 2013 and 2012. Changes in demographic experiences resulted in an actuarial gain in the TNMP PBO of $1.4 million at December 31, 2013 and an actuarial loss of $0.8 million at December 31, 2012. The impacts of other changes in assumptions and experience were not significant. These changes are reflected as actuarial (gain) loss above. In 2011, TNMP had an actuarial loss due to changes in demographics associated with the early retirement of First Choice employees. The loss was not significant and is not included in the net periodic benefit (income) cost above.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the PBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates) and current and target asset allocations between asset categories. The expected long-term rate of return assumption for the PNM and TNMP pension plans compares to the actual return of 3.5% and 6.7% for the year ended December 31, 2013. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2014 net periodic cost to increase $5.3 million and $0.7 million (analogous changes would result from a 1% increase).
The Company’s long-term pension investment strategy is to invest in assets whose interest rate sensitivity is correlated with the pension liability. The Company has chosen to implement this strategy known as Liability Driven Investing (“LDI”) by increasing the liability matching investments as the funded status of the pension plans improves. These liability matching investments are currently fixed income securities. The pension plans current targeted asset allocation is 21% equities, 65% fixed income, and 14% alternative investments. Equity investments are primarily in domestic securities that include large, mid, and small capitalization companies. The pension plans have a 6% targeted allocation to equities of companies domiciled primarily in developed countries outside of the United States. This category includes actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries, and government securities. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. The hedge funds and private equity funds are structured as multi-manager multi-strategy fund of funds to achieve a diversified position in these asset classes. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, buy-outs, and venture capital. The real estate investment is structured as an open-ended, commingled private real estate portfolio that invests in a diversified portfolio of assets including commercial property and multi-family housing. See Note 8 for fair value information concerning assets held by the pension plans.
The following pension benefit payments are expected to be paid:
	PNM				TNMP
	Plan				Plan
	(In thousands)
2014	$	54,356			$	6,111
2015	52,532				6,181
2016	52,204				5,831
2017	50,954				5,631
2018	49,325				5,696
2019 – 2023	222,241				23,804
Due to declines in the general price levels of marketable equity securities held by the pension plans, PNM and TNMP have been making contributions to the pension plans since 2010. The Company does not anticipate making any contributions to the pension plans in 2014 due to the current funded status of the PNM and TNMP pension plans. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the pension plan trust for 2015-2018 are estimated to total $61.5 million for PNM and none for TNMP. These anticipated contributions were developed using current funding assumptions with discount rates of 5.2% to 5.5%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate.
Other Postretirement Benefit Plans
For postretirement benefit plans, the APBO is the actuarial present value of all future benefits attributed under the terms of the postretirement benefit plan to employee service rendered to date.
The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:
	PNM Plan								TNMP Plan
	Year Ended December 31,								Year Ended December 31,
	2013				2012				2013			2012
	(In thousands)
APBO at beginning of year	$	99,613			$	96,221			$	13,678		$	11,344
Service cost	260				217				299			244
Interest cost	4,113				5,293				566			624
Participant contributions	2,537				2,266				373			404
Actuarial (gain) loss	(4,566		)		5,008				(1,080		)	2,727
Benefits paid	(9,792		)		(9,392		)		(1,570		)	(1,665		)
APBO at end of year	92,165				99,613				12,266			13,678
Fair value of plan assets at beginning of year	64,464				58,776				8,643			8,303
Actual return on plan assets	12,780				9,285				1,813			1,259
Employer contributions	3,576				3,529				342			342
Participant contributions	2,537				2,266				373			404
Benefits paid	(9,792		)		(9,392		)		(1,570		)	(1,665		)
Fair value of plan assets at end of year	73,565				64,464				9,601			8,643
Funded status – asset (liability)	$	(18,600	)		$	(35,149	)		$	(2,665	)	$	(5,035	)
In the year ended December 31, 2013, actuarial gains of $12.3 million and $2.4 million were recorded as regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2013.
The following table presents the components of net periodic benefit cost:
	Year Ended December 31,
	2013				2012				2011
	(In thousands)
PNM Plan
Service cost	$	260			$	217			$	259
Interest cost	4,113				5,293				5,378
Expected return on plan assets	(5,043		)		(4,901		)		(5,388		)
Amortization of net (gain) loss	4,242				3,888				3,205
Amortization of prior service credit	(1,343		)		(1,343		)		(2,648		)
Net periodic benefit cost	$	2,229			$	3,154			$	806
TNMP Plan
Service cost	$	299			$	244			$	306
Interest cost	566				624				654
Expected return on plan assets	(503		)		(516		)		(533		)
Amortization of net (gain) loss	—				(209		)		(193		)
Amortization of prior service cost	57				57				60
Net periodic benefit cost	$	419			$	200			$	294
The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.
	Year Ended December 31,
PNM Plan	2013			2012			2011
Discount rate for determining December 31 APBO	5.21	%		4.26	%		5.7	%
Discount rate for determining net periodic benefit cost	4.26	%		5.7	%		5.59	%
Expected return on plan assets	8.5	%		8.5	%		8.5	%
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 APBO	5.21	%		4.26	%		5.7	%
Discount rate for determining net periodic benefit cost	4.26	%		5.7	%		5.59	%
Expected return on plan assets	6.5	%		6.5	%		6.3	%
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the APBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in the discount rates resulted in a decrease in the PNM APBO of $8.8 million at December 31, 2013 and an increase of $13.1 million at December 31, 2012. Changes in discount rates resulted in a decrease in the TNMP APBO of $1.3 million at December 31, 2013 and an increase of $2.0 million at December 31, 2012. Changes in claims, contributions, medical trends and demographic experience also resulted in actuarial losses in the PNM plan of $4.2 million at December 31, 2013 and actuarial gains of $8.1 million at December 31, 2012. Changes in claims, contributions, and demographic experience resulted in an actuarial losses in the TNMP plan of $0.2 million at December 31, 2013 and $0.8 million at December 31, 2012. The impacts of other changes in assumptions and experience were not significant. These changes are reflected as actuarial (gain) loss above.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the APBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates), and current and target asset allocations between asset categories. The expected long-term rate of return assumption for the PNM and TNMP postretirement benefit plans compares to the actual return of 20.4% and 22.1% for the year ended December 31, 2013. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2014 postretirement benefit cost to increase $0.7 million and $0.1 million (analogous changes would result from a 1% increase).
TNMP’s exposure to cost increases in the postretirement benefit plan is minimized by a provision that limits TNMP’s share of costs under the plan. Costs of the plan in excess of the limit are wholly borne by the participants. TNMP reached the cost limit at the end of 2001. As a result, a one-percentage-point change in assumed health care cost trend rates would have no effect on either the net periodic expense or the year-end APBO.
The following table shows the assumed health care cost trend rates:
	PNM Plan
	December 31,
	2013			2012
Health care cost trend rate assumed for next year	7.5	%		7	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5	%		5	%
Year that the rate reaches the ultimate trend rate	2019			2017
The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:
	PNM Plan
	1-Percentage-				1-Percentage-
	Point  Increase				Point  Decrease
	(In thousands)
Effect on total of service and interest cost	$	322			$	(274	)
Effect on APBO	$	5,859			$	(4,826	)
The Company’s other postretirement benefit plans invest in a portfolio that is diversified by asset class and style strategies. The other postretirement benefit plans generally use the same pension fixed income and equity investment managers and utilize the same overall investment strategy as described above for the pension plans, except there is no allocation to alternative investments. The other postretirement benefit plans have a target asset allocation of 70% equities and 30% fixed income. See Note 8 for fair value information concerning assets held by the other postretirement benefit plans.
The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:
	PNM				TNMP
	Plan				Plan
	(In thousands)
2014	$	6,586			$	787
2015	6,720				795
2016	6,943				815
2017	7,080				833
2018	7,306				852
2019 - 2023	36,569				4,558
PNM expects to make contributions to the PNM postretirement benefit plan totaling $3.5 million in 2014 and $14.0 million for 2015-2018. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.3 million in 2014 and $1.4 million for 2015-2018 .
Executive Retirement Programs
For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:
	PNM Plan								TNMP Plan
	Year Ended								Year Ended
	December 31,								December 31,
	2013				2012				2013			2012
	(In thousands)
PBO at beginning of year	$	17,467			$	16,191			$	902		$	844
Service cost	—				—				—			—
Interest cost	720				876				36			45
Actuarial (gain) loss	(330		)		1,895				(21		)	107
Benefits paid	(1,494		)		(1,495		)		(94		)	(94		)
PBO at end of year – funded status	16,363				17,467				823			902
Less current liability	1,536				1,452				94			90
Non-current liability	$	14,827			$	16,015			$	729		$	812
The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2013.
	December 31, 2013
	PNM Plan				TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,069			$	—
Experience loss (gain)	(330		)		(22		)
Regulatory asset (liability) adjustment	192				22
Amortization recognized in net periodic benefit cost (income)	(98		)		—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	1,833			$	—
Amortization expected to be recognized in 2014	$	88			$	—
The following table presents the components of net periodic benefit:
	Year Ended December 31,
	2013				2012				2011
	(In thousands)
PNM Plan
Service cost	$	—			$	—			$	—
Interest cost	720				876				930
Amortization of net (gain) loss	232				83				93
Amortization of prior service cost	—				—				—
Net periodic benefit cost	$	952			$	959			$	1,023
TNMP Plan
Service cost	$	—			$	—			$	—
Interest cost	36				45				46
Amortization of net (gain) loss	—				—				—
Amortization of prior service cost	—				—				—
Net periodic benefit cost	$	36			$	45			$	46
The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.
	Year Ended December 31,
PNM Plan	2013			2012			2011
Discount rate for determining December 31 PBO	5.27	%		4.3	%		5.67	%
Discount rate for determining net periodic benefit cost	4.3	%		5.67	%		5.72	%
Long-term rate of return on plan assets	N/A			N/A			N/A
Rate of compensation increase	N/A			N/A			N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.06	%		4.19	%		5.69	%
Discount rate for determining net periodic benefit cost	4.19	%		5.69	%		5.5	%
Long-term rate of return on plan assets	N/A			N/A			N/A
Rate of compensation increase	N/A			N/A			N/A
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The impacts of changes in assumptions or experience were not significant.
The following executive retirement plan payments, which reflect expected future service, are expected:
	PNM				TNMP
	Plan				Plan
	(In thousands)
2014	$	1,535			$	93
2015	1,516				92
2016	1,494				90
2017	1,468				88
2018	1,438				85
2019 – 2023	6,580				365
Other Retirement Plans
PNMR sponsors a 401(k) defined contribution plan for eligible employees, including those of its subsidiaries. PNMR’s contributions to the 401(k) plan consist of a discretionary matching contribution equal to 75% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. PNMR also makes a non-matching contribution ranging from 3% to 10% of eligible compensation based on the eligible employee’s age.
PNMR also provides executive deferred compensation benefits through an unfunded, non-qualified plan. The purpose of this plan is to permit certain key employees of PNMR who participate in the 401(k) defined contribution plan to defer compensation and receive credits without reference to the certain limitations on contributions. Eligible employees are allowed to save on an after-tax basis. This plan has been amended and the after-tax provision will be eliminated on June 30, 2015.
A summary of expenses for these other retirement plans is as follows:
	Year Ended December 31,
	2013				2012				2011
	(In thousands)
PNMR
401(k) plan	$	16,785			$	16,185			$	17,000
Non-qualified plan	$	2,204			$	1,491			$	1,931
PNM
401(k) plan	$	12,952			$	12,427			$	12,541
Non-qualified plan	$	1,691			$	1,143			$	1,407
TNMP
401(k) plan	$	3,953			$	3,739			$	3,723
Non-qualified plan	$	513			$	327			$	431

StockBased_Compensation_Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation Plans	'
	Stock-Based Compensation Plans
	PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options were granted in 2011, 2012, or 2013 and awards of restricted stock increased. Certain restricted stock awards are subject to achieving performance or market targets and some also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements.
	Performance Equity Plan
	The PEP provides for the granting of non-qualified stock options, restricted stock rights, performance shares, performance units, and stock appreciation rights to officers, key employees, and non-employee board members. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions not 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 and plan provisions provide that upon retirement, participants become 100% vested in stock awards. The total number of shares of PNMR common stock subject to all awards under the PEP may not exceed 12.34 million shares, subject to adjustment under certain circumstances defined in the PEP. The number of shares of PNMR common stock subject to the grant of restricted stock rights, performance shares and units and stock appreciation rights is limited to 3.24 million shares. Re-pricing of stock options is prohibited unless specific shareholder approval is obtained.
	Source of Shares
	The source of shares for exercised stock options and vested restricted stock is shares acquired on the open market by an independent agent, rather than newly issued shares.
	Accounting for Stock Awards
	The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for stock options and restricted stock 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 remain with the Company during the period.
	Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2013, 2012, and 2011 was $5.3 million, $3.6 million, and $6.2 million. Stock compensation expense of $3.8 million, $2.7 million, and $4.3 million was charged to PNM and $1.5 million, $1.0 million, and $1.4 million was charged to TNMP.
	PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date.
	At December 31, 2013, PNMR had no unrecognized compensation expense related to stock options. Unrecognized compensation expense of $3.4 million related to restricted stock and performance-based shares and $1.2 million related to market-based shares is expected to be recognized over an average of 1.7 years.
	The Company uses the Black Scholes option pricing model to estimate the fair value of stock option awards based on multiple factors, including historical exercise patterns of employees in relatively homogenous groups with respect to exercise and post-vesting employment termination behaviors, expected exercising patterns for these same homogenous groups, and both the implied and historical volatility of PNMR’s stock price. The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.
	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
			Year Ended December 31,
	Restricted Shares and Performance-Based Shares		2013				2012				2011
	Expected quarterly dividends per share		$	0.165			$	0.145			$	0.125
	Risk-free interest rate		0.34		%		1.22		%		1.35		%
	Market-Based Shares
	Dividend yield		2.86		%		3.45		%		N/A
	Expected volatility		25.11		%		43.98		%		N/A
	Risk-free interest rate		0.36		%		1.04		%		N/A
	The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares:
		Stock Options							Restricted Stock
		Shares			Weighted				Shares			Weighted-Average Grant Date Fair Value
					Average
					Exercise
					Price
	Outstanding at December 31, 2012	1,992,700			$	20.72			353,722			$	14.03
	Granted	—			$	—			249,113			$	20.03
	Exercised	(319,239	)		$	14.47			(275,988	)		$	15.92
	Forfeited	—			$	—			(11,542	)		$	18.39
	Expired	(329,795	)		$	27.17			—			—
	Outstanding at December 31, 2013	1,343,666			$	20.63			315,305			17.87
	Included as restricted stock granted and exercised above are 100,593 shares that were based upon achieving performance or market targets for the 2011 through 2012 performance period. The Board approved these shares in February 2013, including shares with market targets at near maximum levels.
	As of December 31, 2013, PNMR’s stock-based compensation program provides for performance and market targets through 2015. Excluded from the above table are 112,864 shares approved by the Board in February 2014 (based upon achieving market targets, weighted at 60%, at maximum levels and performance targets, weighted at 40%, at below threshold levels for the 2011 through 2013 performance period), as well as maximums of 198,369 and 179,811 shares for the three-year performance periods ending in 2014 and 2015 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 the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any restricted stock shares under the retention award agreement.
	At December 31, 2013, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $7.3 million with a weighted-average remaining contract life of 3.43 years. At December 31, 2013, the exercise price of 509,916 outstanding stock options is greater than the closing price of PNMR common stock on that date so those options have no intrinsic value.
	The following table provides additional information concerning stock options, and restricted stock activity including performance-based and market-based shares:
			Year Ended December 31,
	Stock Options		2013				2012				2011
	Weighted-average grant date fair value of options granted		$	—			$	—			$	—
	Total fair value of options that vested (in thousands)		$	625			$	1,054			$	1,189
	Total intrinsic value of options exercised (in thousands)		$	2,721			$	6,356			$	2,616
	Restricted Stock
	Weighted-average grant date fair value		$	20.03			$	16.75			$	13.79
	Total fair value of restricted shares that vested (in thousands)		$	4,395			$	5,099			$	1,240

Construction_Program_and_Joint

Construction Program and Jointly-Owned Electric Generating Plants	12 Months Ended
	Dec. 31, 2013
Construction Program and Jointly-Owned Electric Generating Plants [Abstract]	'
Construction Program and Jointly-Owned Electric Generating Plants	'
	Construction Program and Jointly-Owned Electric Generating Plants
	PNM’s expenditures for additions to utility plant were $239.9 million in 2013, including expenditures on jointly-owned projects. TNMP does not participate in the ownership or operation of any generating plants, but incurred expenditures for additions to utility plant of $89.1 million during 2013. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $348.0 million in 2013.
	Joint Projects
	Under the agreements for the jointly-owned projects, PNM has an undivided interest in each asset and liability of the project and records its pro-rata share of each item in the corresponding asset and liability account on PNM’s Consolidated Balance Sheets. Likewise, PNM records its pro-rata share of each item of operating and maintenance expenses for its jointly-owned plants within the corresponding operating expense account in its Consolidated Statements of Earnings. PNM is responsible for financing its share of the capital and operating costs of the joint projects.
	At December 31, 2013, PNM’s interests and investments in jointly-owned generating facilities are:
	Station (Fuel Type)	Plant in		Accumulated			Construction		Composite
		Service		Depreciation			Work in		Interest
							Progress
		(In thousands)
	SJGS (Coal)	$	1,004,138	$	(414,054	)	$	13,860	46.3	%
	PVNGS (Nuclear) (1)	$	508,426	$	(141,347	)	$	43,627	10.2	%
	Four Corners Units 4 and 5 (Coal)	$	159,016	$	(100,462	)	$	3,236	13	%
	Luna (Gas)	$	62,873	$	(17,743	)	$	169	33.33	%
	(1)	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.
	San Juan Generating Station
	PNM operates and jointly owns SJGS. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri-State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by M-S-R Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the potential restructuring of SJGS ownership.
	Palo Verde Nuclear Generating Station
	PNM is a participant in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA, and The Department of Water and Power of the City of Los Angeles. PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. See Note 7 for additional information concerning the PVNGS leases, including PNM’s notices that it will exercise its option to purchase the assets underlying certain of the leases at the expiration of the leases on January 15, 2016.
	Operation of each of the three PVNGS units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power operating licenses were originally for a period of 40 years and authorize APS, as operating agent for PVNGS, to operate the three PVNGS units. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through June 2045 for Unit 1, April 2046 for Unit 2, and November 2047 for Unit 3. In April 2010, APS entered into a Municipal Effluent Purchase and Sale Agreement that provides effluent water rights necessary for cooling purposes at PVNGS through 2050.
	Four Corners Power Plant
	PNM is a participant in two units of Four Corners with APS (the operating agent), EPE, SRP, and Tucson. PNM has a 13.0% undivided interest in Units 4 and 5 of Four Corners. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a PSD permit from EPA to install SCR technology at Four Corners. PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to PNM and the other Four Corners owners. See Note 16 for additional information about Four Corners.
	Luna Energy Facility
	Luna is a combined-cycle power plant near Deming, New Mexico. Luna is owned equally by PNM, Tucson, and Freeport McMoRan. The operation and maintenance of the facility has been contracted to North American Energy Services.
	Construction Program
	The Company anticipates making substantial capital expenditures for the construction and acquisition of utility plant and other property and equipment. An unaudited summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, and nuclear fuel, is as follows:
		2014		2015			2016		2017		2018		Total
							(In millions)
	PNM	$	360.8	$	433.7		$	387.3	$	335.4	$	181.7	$	1,698.90
	TNMP	129.9		76			87.8		93.9		106.4		494
	Corporate and Other	18.3		14.3			14.2		13.8		13.7		74.3
	Total PNMR	$	509	$	524		$	489.3	$	443.1	$	301.8	$	2,267.20
	The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $80.0 million related to environmental upgrades at SJGS to address regional haze and $276.3 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners estimated to be $80.3 million, the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, and the anticipated purchase of Delta.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	AROs are recorded based on the determination of underlying assumptions, such as discount rates, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Any changes in these assumptions underlying the required calculations may require revisions to the estimated AROs when identified. A reconciliation of the ARO liability is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Liability at December 31, 2010	$	76,637		$	75,888		$	648
	Liabilities incurred	60			60			—
	Liabilities settled	(4		)	—			(4		)
	Accretion expense	6,114			6,051			55
	Revisions to estimated cash flows (1)	(3,574		)	(3,574		)	—
	Liability at December 31, 2011	79,233			78,425			699
	Liabilities incurred	—			—			—
	Liabilities settled	(25		)	—			(25		)
	Accretion expense	6,685			6,617			58
	Liability at December 31, 2012	85,893			85,042			732
	Liabilities incurred	—			—			—
	Liabilities settled	(79		)	(67		)	(12		)
	Accretion expense	7,245			7,174			62
	Revisions to estimated cash flows(1)	3,076			3,076			—
	Liability at December 31, 2013	$	96,135		$	95,225		$	782
	(1)	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2011 and 2013, new decommissioning studies for PVNGS were implemented reflecting updated cash flow estimates, including the extended operating licenses. The new studies resulted in a $4.2 million decrease to the ARO in 2011 and an increase of $0.5 million to the ARO in 2013. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Overview
	There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 17) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.
	With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. The Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.
	Commitments and Contingencies Related to the Environment
	PVNGS Decommissioning Funding
	PNM has a program for funding its share of decommissioning costs for PVNGS, including portions held under leases. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. PNM funded $4.9 million, $2.6 million, and $2.6 million for the years ended December 31, 2013, 2012, and 2011 into the qualified and non-qualified trust funds. The estimated market value of the trusts at December 31, 2013 and 2012 was $222.5 million and $189.0 million.
	Nuclear Spent Fuel and Waste Disposal
	Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. As part of the 2010 Electric Rate Case, the NMPRC ordered PNM to refund $1.3 million of the DOE settlement to customers, which was recorded as a regulatory disallowance in 2011.  See Note 17. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. PNM is unable to predict the outcome of this matter.
	PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At December 31, 2013 and 2012, PNM had a liability for interim storage costs of $11.9 million and $13.9 million included in other deferred credits.
	On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision. The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. In September 2013, the NRC issued its draft environmental impact statement to support an updated Waste Confidence Decision. In late 2013, the NRC held a series of nationwide public meetings to receive stakeholder input on the draft environmental impact statement. NRC Commissioners have instructed the staff to issue the final generic environmental impact statement and rule by no later than September 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, PVNGS does not have any licensing actions pending with the NRC. The petitioners had also sought a writ requiring the NRC to comply with the law and resume processing DOE’s pending license application for a nuclear waste site at Yucca Mountain in Nevada. In August 2013, the D.C. Circuit ordered the NRC to resume reviewing the license application. PNM is unable to predict the impact of these decisions.
	In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. This fee is recovered by PNM in its retail rates. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of the intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of the intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. PNM anticipates challenges to this action and is unable to predict its ultimate outcome, but is continuing to accrue the one-mill fee.
	The Clean Air Act
	Regional Haze
	In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.
	SJGS
	BART Determination Process - SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016.
	PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA’s rule in the Tenth Circuit, seeking to shorten the rule’s compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court’s order, the parties have filed supplemental information.
	In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico’s regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.
	Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. At that time, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be refined through an “open book” subcontractor bidding process. The costs for the project to install SCRs would also encompass installation of technology to comply with the NAAQS requirements described below.
	Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs.
	Based upon its current SJGS ownership interest, PNM’s share under either SCRs or SNCRs would be about 46.3%.
	During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by EIB and EPA. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. Certain aspects of this alternative are subject to approval by the NMPRC. At December 31, 2013, PNM’s net book value of its ownership share of SJGS Units 2 and 3 was approximately $287 million.
	Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the terms agreed to do not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the revised SIP.
	This revised plan primarily focuses on how SJGS would meet the regional haze rule and also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized.  PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability.
	In connection with the implementation of the revised plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners or other changes in the contractual cost sharing arrangements, as may be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may seek approvals of their utility commissions or governing boards.
	The parties file periodic status reports with the Tenth Circuit.  To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties’ submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement.  PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.
	Due to the long lead times on certain equipment purchases, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract.
	On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order required PNM to make monthly presentations to the NMPRC on this matter. The NMPRC closed this docket on January 22, 2014.
	In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA deemed the SIP application complete on December 17, 2013. It is anticipated that EPA will publish its proposed action on the revised SIP within 135 days of determining it was complete. Final EPA action on the revised SIP is expected within 150 days of publishing the proposed action, which would be about the end of September 2014.
	On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requests:
	•	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, currently estimated to be approximately $205 million, along with a regulated return on those costs
	•	A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018
	•	An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million
	•	A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM. The expected net impact of this transaction and the retirement of Units 2 and 3 will be a reduction of 340 MW in PNM’s ownership of SJGS.
	In its filing, PNM requested the NMPRC to issue its final ruling on the application no later than December 2014. On January 22, 2014, the NMPRC directed PNM to file supplemental testimony in support of its application, determined that the application was incomplete, and that the statutory time clock for a decision on the CCNs has not started. PNM filed the supplemental testimony on February 5, 2014. On February 11, 2014, the Hearing Examiner issued an order finding that PNM’s application is now complete. The order also stated that there was not a statutory time clock for the request to retire SJGS Units 2 and 3 and the statutory time clock on the CCN requests has not yet begun. The Hearing Examiner indicated the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014. The Hearing Examiner indicated that he will schedule a public hearing to begin on August 19, 2014.
	The above estimate of PNM’s share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 includes gross receipts taxes, AFUDC, and other PNM costs. This amount and the above estimate of net book value of SJGS Units 2 and 3 at December 31, 2017 reflect the requested exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4 resulting in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 52%. The December 20, 2013 filing identifies a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar 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. Specific approvals to acquire these facilities and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $276.3 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of either SCRs or SNCRs. See Note 17 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.
	PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished within the required timeframes or at all. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would need to rely on EPA’s pledge to work with PNM and the State of New Mexico to develop a reasonable FIP compliance plan or otherwise negotiate a solution with EPA or seek relief from the Tenth Circuit in order to continue to be able to operate the plant, including during the installation process for any alternate solution. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM’s needs or, if available, what costs would be incurred.
	PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS. PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.
	SJGS Ownership Restructuring Matters - 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. Accordingly, they have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS. Therefore, the California participants have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant has also expressed a similar intent to exit ownership in the plant. PNM is unable to predict the actions of the SJGS participants. Likewise, PNM cannot predict the impact of those actions on the ownership of SJGS or the operations of SJGS and PNM.
	The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. The negotiations have included potential shifts in ownership among participants and between units in order to facilitate the shutdown of SJGS Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could result in certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4. In this regard, PNM’s December 20, 2013 filing requested NMPRC approval to exchange 78 MW of its capacity in SJGS Unit 3 for an equal amount of capacity in SJGS Unit 4. In addition to shifts in ownership, the discussions among the SJGS participants regarding restructuring have included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. These discussions could result in PNM acquiring more than 78 MW of SJGS Unit 4. The SJGS participants have engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners. Although discussions are continuing, no agreements have been reached. PNM is unable to predict the outcome of the negotiations.
	The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or common property. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements, to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM, in its capacity as operating agent of SJGS, is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and will take reasonable and prudent actions as it deems necessary. PNM cannot predict the outcome of this matter, its impact on SJGS’ compliance with the CAA, or the impact on PNM’s financial position and results of operations.
	Four Corners
	On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to close permanently Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but has no ownership interest in Units 1, 2, and 3, which were shutdown by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.
	SCE, a participant in Four Corners, indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. A principal condition to closing was the execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below.
	On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners, was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.
	The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.
	PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to approximately $80.3 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.
	Four Corners BART FIP Challenge
	On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP.  In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA.  APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS’ motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. Oral argument was presented before the Tenth Circuit on January 23, 2014. A decision is expected before the end of 2014. PNM cannot currently predict the outcome of this matter or the range of its potential impact.
	Regional Haze Challenges
	On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO2 and particulate matter emissions elements of EPA’s approval of New Mexico’s Regional Haze SIP.  On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA’s final approval of the remaining elements of New Mexico’s Regional Haze SIP, as well as EPA’s approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. This matter is now proceeding in the Tenth Circuit. All briefing has been completed and filed with the court. Oral argument is scheduled before the Tenth Circuit on March 20, 2014. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.
	SJGS Operating Permit Challenge
	On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS’s operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG.  EPA’s order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has exceded any emission limits.
	In August 2012, NMED issued a response to the EPA order stating that SJGS’s operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO2 and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide (“CO”) emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved.
	National Ambient Air Quality Standards (“NAAQS”)
	The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO2, ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO2 NAAQS.  On May 21, 2013, EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO2 sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO2 NAAQS. Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO2 standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO2 standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above.
	EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.
	In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and has stated it intends to propose a new standard.  Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014. Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation.
	Citizen Suit Under the Clean Air Act
	The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.
	In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS.  The special master issued a report indicating he was unable to make a determination on either of these issues.  In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. The parties filed a joint status update on January 23, 2014, advising the court that the parties had reached an agreement, subject to final approval by each party’s respective managing body. If approved, the parties would file a stipulated order with the court. PNM cannot predict if the agreement will be approved, the court will approve a stipulated order, or the ultimate outcome of this matter.
	Section 114 Request
In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA’s request. PNM is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.
Four Corners Clean Air Act Lawsuit
In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.
WEG v. OSM NEPA Lawsuit
In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012.  In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM.  Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine.  WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008.  WEG alleges various National Environmental Policy Act violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents.  WEG’s petition seeks various forms of relief, including voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC’s claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. PNM cannot currently predict the outcome of this matter or the range of its potential impact.
Navajo Nation Environmental Issues
Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.
Endangered Species Act
In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners.  The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats.  The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA.  Neither PNM nor APS was a party to the lawsuit. The court dismissed the lawsuit without prejudice and this matter is concluded.
Cooling Water Intake Structures
EPA issued its proposed cooling water intake structures rule in April 2011, which would provide national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required.
The proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date was extended to January 14, 2014. On January 10, 2014, EPA announced it would not meet that deadline. On February 10, 2014, EPA indicated it would issue the final rule by April 17, 2014 and did not intend to seek any more extensions. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.
Effluent Limitation Guidelines
On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for 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. EPA is currently subject to a consent decree deadline to finalize the revised guidelines by May 2014, although it is in negotiations to obtain an extension of time. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.
Santa Fe Generating Station
PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of the former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.
The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.
Coal Combustion Byproducts Waste Disposal
Regulation
CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production.  Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.
In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule.
On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA’s regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary and that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. On January 29, 2014, EPA entered into a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.
PNM advocates for the non-hazardous regulation of CCBs. If CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA’s or OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows.
Sierra Club Allegations
In April 2010, the Sierra Club filed suit against PNMR, PNM, SJCC, and BHP in the United States District Court for the District of New Mexico. In the complaint, as amended, Sierra Club alleged that activities at SJGS and SJCC’s San Juan mine were causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan mine constituted “open dumping” in violation of RCRA.  The suit also includes claims against SJCC and BHP under the Surface Mine Control and Reclamation Act. The complaint requested judgment for injunctive relief, payment of civil penalties, and an award of plaintiffs’ attorney’s fees and costs.
On March 28, 2012, the parties filed an executed consent decree with the court, which was approved by the court on April 12, 2012, settling the litigation. Under the terms of the consent decree, the SJGS owners and SJCC will construct and operate a slurry wall and recovery trench, fund other environmental projects, and pay Sierra Club’s attorneys’ and experts’ fees. The total estimated cost of the settlement is $10.2 million, of which about $4.5 million is PNM’s share. Substantially all of the income statement impact related to this settlement was recorded in 2011. The consent decree also includes a release of claims and a covenant not to sue by Sierra Club. PNM is complying with the requirements of the consent decree.
Hazardous Air Pollutants (“HAPs”) Rulemaking
In December 2011, the EPA issued its final Mercury and Air Toxics Standards (“MATS”) to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM’s assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.
Other Commitments and Contingencies
Coal Supply
The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At December 31, 2013 and 2012, prepayments for coal, which are included in other current assets, amounted to $12.3 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.
APS purchases all of Four Corners’ coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. As discussed under The Clean Air Act - Regional Haze - Four Corners above, on December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until July 2016. Coal costs are anticipated to increase approximately 26% beginning in July 2016 under the terms of the new contract. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.
In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $55.7 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of December 31, 2013. At December 31, 2013 and 2012, liabilities, in current dollars, of $23.8 million and $26.8 million for surface mine reclamation and $7.8 million and $4.2 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 $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 (See Note 4) and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act - Regional Haze - SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. It has not been decided how costs would be divided among the owners of SJGS. Regulatory determinations made by the NMPRC may also affect the impact on PNM. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.
San Juan Underground Mine Fire Incident
On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC has completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembed it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time.
The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between $17.4 million and $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and has informed PNM that it has settled with its insurance carrier. PNM believes the settlement proceeds obtained by SJCC through its insurance carrier are reimbursable (in whole or in part) to the owners of SJGS through the coal sales agreement. PNM’s portion of the insurance recovery is estimated to be $18.7 million. PNM has credited its FPPAC balancing account for the amount of its estimated insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 17.
Continuous Highwall Mining Royalty Rate
In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”).  Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule.
SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS.  In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM.  In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal.  The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed.  PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.
SJCC Arbitration
The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues have been submitted to a panel for binding arbitration. In October 2013, the arbitration panel ruled on one issue and set other issues for hearing. The panel ruled that the SJGS participants owe SJCC $1.5 million for disputed mining costs.  PNM’s share of this amount is $0.7 million of which $0.5 million was passed through PNM’s FPPAC. The remaining issues are: 1) whether the SJGS participants owe SJCC unbilled mining costs of $5.2 million or whether SJCC owes the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $13.9 million as mining costs that SJCC should have considered to be capital costs, which are not billable under the mining contract.  PNM’s share of any amounts resulting from the arbitration would be approximately 46.3%. Of PNM’s share of the costs, approximately 33% of the first remaining issue as well as approximately 25% of the second remaining issue would be passed through PNM’s FPPAC and the rest would impact earnings. A hearing before the arbitration panel on the remaining issues is scheduled to be held in May 2014. PNM is unable to predict the outcome of the arbitration hearing.
Four Corners Severance Tax Assessment
On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.
PVNGS Liability and Insurance Matters
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential assessment per incident for all three units is $38.9 million, with an annual payment limitation of $5.7 million.
The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective assessments of $4.3 million for each retrospective assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.
Natural Gas Supply
PNM procures gas supplies for its power plants from third-party sources and contracts with third party transportation providers.
Water Supply
Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a Federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.
PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a long-term supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.
In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.
PVNGS Water Supply Litigation
In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.
San Juan River Adjudication
In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding, and on November 1, 2013 issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM is in the process of entering 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.
Conflicts at San Juan Mine Involving Oil and Gas Leaseholders
SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has prevailed in court in defeating the claims of other claimants. Several other claims and potential claimants remain. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders or the range of potential outcomes.
Rights-of-Way Matter
On January 28, 2014, the 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. If the challenge to the ordinance is unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.
Complaint Against Southwestern Public Service Company
In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ. FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated.  PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.
Navajo Nation Allottee Matters
A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both.  In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court.  In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice.  The allottees have not refiled their appeals. PNM continues to participate in this matter in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.
In a separate matter, in September 2012, forty-three landowners claiming to be Navajo allottees, filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. 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. Although this matter is currently stayed, PNM continues to participate in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

Regulatory_and_Rate_Matters

Regulatory and Rate Matters	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory and Rate Matters	'
	Regulatory and Rate Matters
	The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 16.
	PNM
	Renewable Portfolio Standard
	The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, the NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. This weighting applies to future procurement approved and brought into service after December 18, 2013. The NMPRC has granted motions for rehearing of amendments in order to address the merits of the motions.
	The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC established a RCT for 2011 of 2% of all customers’ aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers’ annual electric charges beginning in 2013 and continuing thereafter.
	In August 2010, the NMPRC partially approved PNM’s revised 2010 procurement plan, including PNM’s investment in 22 MW of solar PV facilities at various PNM sites and the construction of a solar-storage demonstration project. Construction of these facilities was completed in 2011 at a total cost of approximately $95 million.
	In July 2010, PNM filed its renewable energy procurement plan for 2011. The NMPRC rejected PNM’s proposed REC-only purchase and ordered PNM to acquire actual renewable energy and the associated RECs. An appeal of the order was dismissed by the New Mexico Supreme Court. PNM made the required renewable energy procurement and is recovering those costs through the renewable rider discussed below.
	In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM’s 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of the new 10 MW Lightning Dock Geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM’s voluntary renewable energy tariff. The plan would enable PNM to comply with the statutory RPS in 2013, but required a variance from the NMPRC’s diversity requirements in 2013 while the proposed geothermal facilities were being constructed. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. In 2013, PNM made renewable procurements consistent with the 2013 plan approved by the NMPRC. Construction of the solar PV facilities was completed in 2013 at a cost of $48.9 million. The geothermal facility began providing power to PNM in January 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. PNM does not believe this delay will affect its ability to comply with its 2014 non-wind/non-solar diversity requirements, as amended in December 2012.
	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 proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind facility 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 is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.
	Renewable Energy Rider
	On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The approved rates were $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held prior to inclusion of the costs in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider were capped at $18.0 million in 2012 and $24.6 million in 2013, which amounts were not exceeded. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeded 10.5%, which did not occur, PNM would have been required to refund the amount over 10.5% to customers during May through December 2014.
	In compliance with the NMPRC’s rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills.  On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.0030468 per KWh on May 28, 2013.
	In its 2014 renewable energy procurement plan described above, PNM proposed to increase the rider rate to $0.0044391 effective January 1, 2014. This increase was approved by the NMPRC on December 18, 2013.
	Energy Efficiency and Load Management
	Program Costs
	Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue.
	In September 2010, PNM filed an energy efficiency program application for programs to be offered beginning July 1, 2011. The NMPRC issued an order in June 2011 that approved a rider recovery amount of $17.1 million in program costs. The new rider rate was effective with bills rendered July 27, 2011.
	In April 2011, PNM filed a reconciliation of energy efficiency program costs and collections as of December 31, 2010. Included in this filing was an adjustment of the adder amount to reflect the measured and verified savings for 2010 program participation. After a hearing, the NMPRC issued an order in November 2011 that authorized recovery of substantially all of the $2.6 million in under-collected program costs.
	In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million. PNM subsequently revised its proposed profit incentive to $2.9 million. The NMPRC approved PNM’s program application and an annual profit incentive of $1.7 million on November 6, 2013.
	Disincentives/Incentives
	The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010 PNM began implementing a NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In July 2011, the New Mexico Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011.
	In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific incentives for savings due to programs implemented in 2011. PNM collected approximately $1.3 million, on an annual basis, in incentive revenues through November 2013 consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the PNM-specific incentives and to refund such revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM was not required to refund any incentive revenues and is authorized to continue collecting the incentives. However, in an order on rehearing, which it subsequently rescinded, the NMPRC reduced the amount of the PNM-specific incentives. In March 2012, the Supreme Court granted PNM’s motion to vacate the rehearing order and dismissed PNM’s appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG sought to overturn the NMPRC order allowing PNM to continue to collect incentives in light of the 2011 Supreme Court decision. On May 21, 2012, the Supreme Court dismissed the writ proceeding. On September 20, 2013, the Supreme Court affirmed the NMPRC’s decision authorizing the PNM-specific incentives and remanded the case to the NMPRC. On October 2, 2013, the NMPRC closed the docket.
	On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013.
	Energy Efficiency Rulemaking
	On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.
	On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the product (expressed in dollars) of the utility’s WACC (expressed as a percent) and its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013.
	2010 Electric Rate Case
	PNM filed its 2010 Electric Rate Case application with the NMPRC in June 2010 for rate increases totaling $165.2 million for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for customers served by TNMP prior to its acquisition by PNMR (“PNM South”) and other customers of PNM (“PNM North”). PNM also proposed to implement a FPPAC for PNM South. The filed revenue requirements were based on a future test period ending December 31, 2011.
	On August 21, 2011, PNM implemented a $72.1 million annual increase in rates as authorized by an order of the NMPRC, which modified a stipulation agreed to by PNM and several other parties. The amended stipulation limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $48.6 million of FPPAC costs being deferred for future collection at June 30, 2014. This amount reflects the pending settlement in the FPPAC Continuation Application case discussed below. The portion of the costs and insurance recovery attributable to customers covered by the FPPAC resulting from the mine fire incident discussed in Note 16 are included in the FPPAC amounts.
	As a result of the modified stipulation, PNM recorded pre-tax losses for the $10.0 million of fuel costs that will not be recovered through the FPPAC and $7.5 million for other costs that will not be recovered in rates. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM’s Consolidated Statement of Earnings.
	FPPAC Continuation Application
	Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed that would resolve this case. The settlement would allow PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, would resolve all costs related to the San Juan Coal mine fire discussed in Note 16, resolve the ratemaking treatment for the coal pre-treatment at SJGS until the next rate case, require PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and require PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the $10.5 million write-off as a regulatory disallowance in 2013. A public hearing on the stipulation was held on February 25, 2014. The hearing examiner stated at the hearing’s conclusion that he would recommend approval of the settlement in its entirety to the NMPRC. PNM is unable to predict the outcome of this proceeding.
	Integrated Resource Plan
	NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. On September 18, 2013, the NMPRC issued an order that closed the docket on the 2011 IRP.
	PNM has initiated the process to prepare its 2014 IRP. Public participation meetings have been held. The 2014 IRP is scheduled to be filed at the NMPRC by June 30, 2014.
	Emergency FPPAC
	In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM’s base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM’s motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC’s order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed.
	Applications for Approvals to Purchase Delta
	As discussed in Note 9, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. Closing on the purchase will occur once certain environmental issues are resolved.
	Application for Approval of La Luz Generating Station
	On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requested a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. Both contracts allow PNM to cancel if NMPRC approval is not obtained. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a rate base value of up to $56 million for the facility. PNM is unable to predict the outcome of this matter.
	San Juan Generating Station Units 2 and 3 Retirement
	As discussed in Note 16, on December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2016. In that application, PNM also seeks approval to recover the net book value of SJGS Units 2 and 3 at the date of retirement, for a CCN to include PNM’s share of PVNGS Unit 3 as a resource to serve New Mexico consumers, authority to install SNCRs on SJGS Units 1 and 4, and a CCN to exchange 78 MW in SJGS for the same amount of capacity in SJGS Unit 4. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM requested the NMPRC issue its final ruling on the application no later than December 2014. A public hearing on the application has been scheduled to commence on August 19, 2014. PNM is unable to predict the outcome of this matter.
	Transmission Rate Case
	In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  In December 2010, FERC issued an order accepting PNM’s filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM’s wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM’s transmission system to transmit power at the wholesale level.  The rate increase did not impact PNM’s retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC’s approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter.
	Formula Transmission Rate Case
	On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. The rates resulting from PNM’s application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013.
	On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its return-on-equity (“ROE”) using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003 ; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM’s wholesale electric transmission service customers. The new rates will not apply to PNM’s retail customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.
	Firm-Requirements Wholesale Customers
	Navopache Electric Cooperative, Inc. Rate Case
	In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement provided for an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter.
	City of Gallup, New Mexico Contract
	PNM provides both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will have increased by $3.1 million during the term of the amended agreement.
	On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On January 13, 2014, PNM was notified that its proposal was not the highest ranked. Gallup has stated that a contract is being negotiated with the top-ranked bidder.  If those negotiations do not result in the execution of a contract, Gallup could enter into negotiations with PNM or others.  If a contract is executed with the top-ranked bidder, PNM’s contract with Gallup would expire on June 30, 2014.  PNM’s 2013 revenues for power sold under the Gallup contract were $11.7 million.  PNM is unable to predict the outcome of this matter.
	TNMP
	Interest Rate Compliance Tariff
	Following a revision of the interest rate on TNMP’s CTC, TNMP filed a compliance tariff to implement the new lower 8.31% rate. Intervenors asserted objections and, after regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. Ultimately, the Texas 3rd Court of Appeals reaffirmed the PUCT’s decision. Due to the new retroactive ratemaking theory contained in the Texas 3rd Court of Appeals opinion, TNMP recorded a pre-tax regulatory disallowance of $3.9 million in 2011 to reflect the impact of applying the 8.31% rate retroactively. In June 2012, the Texas Supreme Court denied TNMP’s petition for review. TNMP filed a motion for rehearing, which was denied in August 2012 concluding this matter.
	2010 Rate Case
	In August 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues. In January 2011, the PUCT approved a settlement that provided for a revenue increase of $10.25 million, a return on equity of 10.125%, and a target 55%/45% debt-equity capital structure. The PUCT approved the settlement in January 2011. TNMP implemented the new rates on February 1, 2011.
	2010 Rate Case Expense Proceeding
	The determination of the amount of reasonable rate case expenses incurred by TNMP and other parties in TNMP’s 2010 Rate Case was severed into a separate proceeding. The parties agreed to a settlement of the case, which was approved by the PUCT in May 2011. TNMP began collecting $2.8 million over three years on July 1, 2011.
Advanced Meter System Deployment
In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.
In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.
On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service will be borne by opt-out customers through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT are required to initiate proceedings to establish these charges.
On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP’s filing seeks recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48. An additional $0.5 million in ongoing expenses would be recovered via a proposed monthly charge of $38.99. A hearing on this matter is scheduled for April 8, 2014. TNMP cannot predict the outcome of this proceeding although TNMP does not expect it to have a material impact on its financial position, results of operations, or cash flows.
Remand of ERCOT Transmission Rates for 1999 and 2000
Following a variety of appeals, the ERCOT transmission rates approved in 1999 and 2000 were remanded back to the PUCT. These dockets concern the recalculation of rates for the fourth quarter of 1999 and all of 2000. In October 2011, TNMP joined in a non-unanimous settlement of the issues relating to resettlement of the last four months of 1999. In January 2012, the PUCT approved the non-unanimous settlement. TNMP received $1.6 million under the settlement. In June 2012, TNMP filed its transmission cost recovery factor filing (“TCRF”) seeking $3.2 million in additional transmission costs. The PUCT staff requested a hearing asserting the settlement proceeds from the 1999 remand settlement need to be credited against the costs TNMP requested in its TCRF. TNMP maintains that the settlement proceeds should not be passed on to customers since TNMP was unable to recover those costs in 1999. Subsequently, the PUCT staff agreed to interim rate relief permitting TNMP to add $1.6 million in uncontested costs to its existing TCRF and add $1.6 million in costs in a subsequent TCRF if TNMP is successful in the contested case. The ALJ approved the interim relief on July 16, 2012. TNMP implemented the interim rates on September 1, 2012. On September 26, 2012, the contested portion of the case was remanded to the PUCT pursuant to an agreed resolution that permits the $1.6 million in interim rates to become final and authorizes TNMP to institute a surcharge in March 2013 to collect the additional $1.6 million in initially disputed costs plus interest at the PUCT under-billing rate. The PUCT approved the joint resolution on November 19, 2012.
Energy Efficiency
TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. The PUCT approved TNMP’s collection of its 2010 energy efficiency program costs of $2.6 million over 11 months beginning February 1, 2010. Recovery of the 2011 program costs of $2.7 million were approved for collection beginning January 1, 2011. In September 2011, the PUCT approved a settlement that allows TNMP to collect the estimated 2012 energy efficiency program costs of $3.4 million and a $0.3 million bonus for 2010. TNMP’s new rates were effective January 1, 2012. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP’s new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to permit TNMP to collect the substantially all of the requested $5.6 million beginning March 1, 2014. The settlement was approved by the PUCT on October 25, 2013.
Transmission Cost of Service Rates
TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.
On August 23, 2012, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The application reflected an increase in total rate base of $26.4 million and requested an increase in revenues of $2.5 million annually. The PUCT approved the interim adjustment and TNMP implemented it on September 27, 2012.
On January 31, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $21.9 million, which will increase revenues $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 20, 2013.
On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.
On January 21, 2014, TNMP filed an application to further update its transmission rates resulting from changes in its invested capital. The requested increase in total rate base is $18.2 million, which would increase revenues by $2.9 million annually. TNMP has requested approval by March 23, 2014.
Periodic Distribution Rate Adjustment
In September 2011, the PUCT approved a new rule permitting interim rate adjustments to reflect changes in investments in distribution assets. The rule permits distribution utilities to file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data.
Consolidated Tax Savings Adjustment
On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment (“CTSA”) from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	PNMR, PNM, and TNMP are considered related parties as defined under GAAP. TNMP provides transmission and distribution services to First Choice. On November 1, 2011, PNMR sold First Choice (Note 3). TNMP revenues from First Choice through October 31, 2011 are considered related party revenues and included in the table below. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. Optim Energy was a related party prior to September 23, 2011 (Note 20). PNMR Services Company provided corporate services to Optim Energy under a services agreement. There was also a services agreement for Optim Energy to provide services to PNMR.
	PNMR files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PNMR and each of its affiliated companies. These agreements provide that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PNMR. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PNMR to the extent that PNMR is able to utilize those benefits.
	See Note 6 for information on intercompany borrowing arrangements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:
		Year Ended December 31,
		2013		2012		2011
				(In thousands)
	Electricity, transmission and distribution related services billings:
	TNMP to PNMR	$	—	$	—	$	33,813
	Services billings:
	PNMR to PNM	92,597		99,986		98,914
	PNMR to TNMP	28,937		29,110		29,353
	PNM to TNMP	562		595		550
	TNMP to PNMR	7		15		164
	PNMR to Optim Energy	—		—		4,083
	Optim Energy to PNMR	—		—		23
	Income tax sharing payments:
	PNMR to TNMP	—		1,951		—
	PNMR to PNM	77,433		63,114		—
	TNMP to PNMR	3,643		—		—
	Interest payments:
	PNM to PNMR	4		1		54
	TNMP to PNMR	481		137		40

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Accumulated Other Comprehensive Income (Loss)	'
	Accumulated Other Comprehensive Income (Loss)
	AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNMR
	Balance at December 31, 2010	$	16,211		$	(83,254	)	$	(1,623	)	$	(68,666	)
	Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,292			3,448			(27,511		)
	Income tax impact of amounts reclassified	13,956			(1,699		)	(1,230		)	11,027
	Other OCI changes (pre-tax)	34,295			(2,958		)	(1,002		)	30,335
	Income tax impact of other OCI changes	(13,577		)	1,187			349			(12,041		)
	Net change after income taxes	(577		)	822			1,565			1,810
	Balance at December 31, 2011	15,634			(82,432		)	(58		)	(66,856		)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			182			(32,476		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	(65		)	12,865
	Other OCI changes (pre-tax)	38,548			(30,084		)	(428		)	8,036
	Income tax impact of other OCI changes	(15,262		)	11,910			153			(3,199		)
	Net change after income taxes	772			(15,388		)	(158		)	(14,774		)
	Balance at December 31, 2012	16,406			(97,820		)	(216		)	(81,630		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			207			(5,385		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	(73		)	2,137
	Other OCI changes (pre-tax)	27,419			17,136			(279		)	44,276
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	98			(17,538		)
	Net change after income taxes	9,342			14,195			(47		)	23,490
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNM
	Balance at December 31, 2010	$	16,211		$	(82,981	)	$	(16	)	$	(66,786	)
	Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,278			27			(30,946		)
	Income tax impact of amounts reclassified	13,956			(1,694		)	(11		)	12,251
	Other OCI changes (pre-tax)	34,295			(3,369		)	—			30,926
	Income tax impact of other OCI changes	(13,577		)	1,334			—			(12,243		)
	Net change after income taxes	(577		)	549			16			(12		)
	Balance at December 31, 2011	15,634			(82,432		)	—			(66,798		)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			—			(32,658		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	—			12,930
	Other OCI changes (pre-tax)	38,548			(30,084		)	—			8,464
	Income tax impact of other OCI changes	(15,262		)	11,910			—			(3,352		)
	Net change after income taxes	772			(15,388		)	—			(14,616		)
	Balance at December 31, 2012	16,406			(97,820		)	—			(81,414		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			—			(5,592		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	—			2,210
	Other OCI changes (pre-tax)	27,419			17,136			—			44,555
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	—			(17,636		)
	Net change after income taxes	9,342			14,195			—			23,537
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—		$	(57,877	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	TNMP
	Balance at December 31, 2010	$	—		$	(275	)	$	(1,210	)	$	(1,485	)
	Amounts reclassified from AOCI (pre-tax)	—			13			2,997			3,010
	Income tax impact of amounts reclassified	—			(5		)	(1,068		)	(1,073		)
	Other OCI changes (pre-tax)	—			414			(1,207		)	(793		)
	Income tax impact of other OCI changes	—			(147		)	430			283
Net change after income taxes	—			275			1,152			1,427
Balance at December 31, 2011	—			—			(58		)	(58		)
Amounts reclassified from AOCI (pre-tax)	—			—			182			182
Income tax impact of amounts reclassified	—			—			(65		)	(65		)
Other OCI changes (pre-tax)	—			—			(428		)	(428		)
Income tax impact of other OCI changes	—			—			153			153
Net change after income taxes	—			—			(158		)	(158		)
Balance at December 31, 2012	—			—			(216		)	(216		)
Amounts reclassified from AOCI (pre-tax)	—			—			207			207
Income tax impact of amounts reclassified	—			—			(73		)	(73		)
Other OCI changes (pre-tax)	—			—			(279		)	(279		)
Income tax impact of other OCI changes	—			—			98			98
Net change after income taxes	—			—			(47		)	(47		)
Balance at December 31, 2013	$	—		$	—		$	(263	)	$	(263	)
Pre-tax amounts reclassified from AOCI related to Unrealized Gain on Available-for-Sale Securities are included in Gains on available-for-sale securities in the Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to Pension Liability Adjustment are reclassified to Operating Expenses - Administrative and general in the Consolidated Statements of Earnings. For the year ended December 31, 2013, approximately 18.7% of the amount reclassified was capitalized into construction work in process and approximately 3.0%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 Consolidated Statements of Earnings. An insignificant amount is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in Income Taxes in the Consolidated Statements of Earnings.

Optim_Energy

Optim Energy	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Optim Energy	'
	Optim Energy
	In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding energy markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company. Optim Energy had a bank financing arrangement that provided for a revolving line of credit, the issuance of bank letters of credit support certain contractual arrangements, and a maturity of May 31, 2012. Cascade and ECJV guaranteed Optim Energy’s obligations on this facility. Optim Energy’s debt was non-recourse to PNMR.
	Beginning in 2009, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. Under GAAP, there were indicators of impairment that required PNMR to perform an impairment analyses of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010. In accordance with GAAP, PNMR did not record income or losses associated with its investment in Optim Energy in 2011 as PNMR had no contractual requirement or agreement to provide Optim Energy with additional financial resources.
	As a result of the adverse market conditions described above, PNMR (in collaboration with Optim Energy and ECJV) assessed various strategic alternatives relating to Optim Energy. On September 23, 2011, PNMR, ECJV, and Cascade agreed to restructure Optim Energy and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR’s ownership in Optim Energy being reduced from 50% to 1%. As part of this transaction, PNMR did not make any equity contribution to Optim Energy nor was it required to make any future contribution. PNMR Services Company provided certain corporate services to Optim Energy through December 31, 2011 and thereafter with respect to certain open tax matters. On January 4, 2012, ECJV exercised its option to acquire PNMR’s remaining 1% ownership interest in Optim Energy at fair market value, which was determined to be zero.
	As discussed above, PNMR fully impaired its investment in Optim Energy at December 31, 2010 and did not recognize losses of Optim Energy from January 1, 2011 through September 23, 2011 when PNMR ceased to account for its investment using the equity method of accounting. Accordingly, Optim Energy has no impact on PNMR’s 2011 statement of earnings and statement of cash flows. For the nine months ended September 30, 2011, Optim Energy reported operating revenues of $256.8 million, margin of $84.7 million, and a net loss of $21.4 million.

Goodwill_and_Other_Intangible_

Goodwill and Other Intangible Assets; Impairments	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Goodwill and Other Intangible Assets; Impairments	'
	Goodwill and Other Intangible Assets; Impairments
	The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its June  6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. Additionally, the trade name “First Choice” and the First Choice customer list were acquired in the TNP acquisition. The trade name was considered to have an indefinite useful life; therefore, no amortization was recorded. The useful life of the customer list was estimated to be approximately eight years. As discussed in Note 3, PNMR completed the sale of First Choice on November 1, 2011. As a result, the goodwill and other intangible assets of First Choice are no longer included in PNMR’s Consolidated Balance Sheet and PNMR no longer has any other intangible assets.
	GAAP requires the Company to evaluate its goodwill and non-amortizing intangible assets for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill or intangible assets may be impaired. The Company evaluates goodwill impairment as of April 1st of each year. PNMR’s current reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.
	GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment, an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.
	In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. Prior to 2012, the Company also compared the fair value of non-amortizing intangibles other than goodwill to the recorded value.
	An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. Prior to 2013, the Company performed qualitative analyses for all reporting units having goodwill. For the annual evaluation performed as of April 1, 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit.
	The 2013 qualitative analysis for the TNMP reporting unit, which has goodwill of $226.7 million, included the consideration of various reporting unit specific factors as well as industry and macroeconomic factors to determine whether these factors were reasonably likely to have a material impact on the fair value of the reporting unit. Factors considered included the results of the April 1, 2012 quantitative analysis, which indicated that fair value exceeded carrying value of the reporting unit by approximately 26%, current and long-term forecasted financial results, regulatory environment, credit rating, interest rate environment, absolute and relative price of PNMR’s common stock, and operating strategy. TNMP believes it is operating within a generally favorable regulatory environment, its historical and forecasted financial results are positive, and its credit is perceived positively. Based on the analysis of the relevant factors, PNMR concluded that it is more likely than not that the fair value of the TNMP reporting unit exceeds its carrying value.
	For the PNM reporting unit, a discounted cash flow methodology was primarily used as the quantitative analysis to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2013 and 2012 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 27% and 15%. An increase of 0.5% in the expected return on equity capital utilized in discounting the forecasted cash flows, would have reduced the excess of PNM’s fair value over carrying value to approximately 20% at April 1, 2013.
	The annual evaluations performed as of April 1, 2013 and 2012 did not indicate impairments of the goodwill of any of PNMR's reporting units. Since the April 1, 2013 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values.
	Prior annual evaluations have not indicated impairments of any of PNMR’s reporting units, except in 2008. During 2008, the market capitalization of PNMR’s common stock was significantly below book value. In addition, changes in the ERCOT market significantly impacted the results of operations of First Choice. The financial challenges facing First Choice were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in significant increases in the levels of uncollectible accounts. As a result, the Company recorded goodwill impairments of $51.1 million for PNM, $34.5 million for TNMP, and $88.8 million for First Choice in 2008. Pre-tax impairment losses of $42.6 million for the First Choice trade name and $4.8 million for the First Choice customer list were also recorded in 2008. Since 2008, the price of PNMR’s common stock has increased, improving the relationship between PNMR’s market capitalization and book value. In addition, improved regulatory treatment has been experienced by PNM in New Mexico and by TNMP in Texas. Furthermore, First Choice’s business became more stable, primarily due to more predictable power and fuel price patterns in the ERCOT market. These factors resulted in more predictable earnings and increased fair values of the reporting units. Since 2008, the annual evaluations have not indicated that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

Quarterly_Operating_Results_Un

Quarterly Operating Results (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Quarterly Operating Results (Unaudited)	'
	Quarterly Operating Results (Unaudited)
	Unaudited operating results by quarters for 2013 and 2012 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included.
		Quarter Ended
		March 31		June 30		September 30		December 31
		(In thousands, except per share amounts)
	PNMR
	2013
	Operating revenues	$	317,665	$	347,599	$	399,730	$	322,929
	Operating income	50,704		77,867		117,739		40,532
	Net earnings	13,962		31,383		58,814		11,397
	Net earnings attributable to PNMR	10,626		27,678		54,555		7,648
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.13		0.35		0.68		0.1
	Diluted	0.13		0.34		0.68		0.1
	2012
	Operating revenues	$	305,374	$	323,860	$	390,411	$	322,758
	Operating income	53,729		65,106		118,150		36,736
	Net earnings	20,477		25,099		61,976		12,573
	Net earnings attributable to PNMR	17,080		21,512		57,864		9,091
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.21		0.27		0.73		0.11
	Diluted	0.21		0.27		0.72		0.11
	PNM
	2013
	Operating revenues	$	257,894	$	279,690	$	326,026	$	252,702
	Operating income	37,239		58,302		95,217		18,427
	Net earnings	14,773		29,697		51,950		6,256
	Net earnings attributable to PNM	11,569		26,124		47,823		2,639
	2012
	Operating revenues	$	250,416	$	260,094	$	321,731	$	260,023
	Operating income	42,105		46,669		96,973		20,135
	Net earnings	21,077		20,340		54,891		9,293
	Net earnings attributable to PNM	17,812		16,885		50,911		5,943
	TNMP
	2013
	Operating revenues	$	59,771	$	67,909	$	73,704	$	70,227
	Operating income	13,054		19,667		22,254		17,210
	Net earnings	3,726		8,339		10,106		6,919
	2012
	Operating revenues	$	54,958	$	63,766	$	68,680	$	62,736
	Operating income	11,791		18,897		20,970		15,862
	Net earnings	3,011		8,018		9,084		6,634

Schedule_I_Condensed_Financial

Schedule I - Condensed Financial Information of Parent Company	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule I - Condensed Financial Information of Parent Company	'
	SCHEDULE I
	PNM RESOURCES, INC.
	CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
	STATEMENTS OF EARNINGS
		Year ended December 31,
		2013			2012			2011
		(In thousands)
	Operating Revenues	$	—		$	—		$	—
	Operating Expenses	941			3,287			20,547
	Operating income (loss)	(941		)	(3,287		)	(20,547		)
	Other Income and Deductions:
	Equity in earnings of subsidiaries	116,634			117,900			205,215
	Other income	769			670			59
	Other deductions	(22,825		)	(20,904		)	(34,124		)
	Net other income (deductions)	94,578			97,666			171,150
	Earnings Before Income Taxes	93,637			94,379			150,603
	Income Tax Expense (Benefit)	(6,870		)	(11,168		)	(25,756		)
	Net Earnings	$	100,507		$	105,547		$	176,359
	SCHEDULE I
	PNM RESOURCES, INC.
	CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
	STATEMENTS OF CASH FLOWS
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Cash Flows From Operating Activities:
	Net earnings	$	100,507		$	105,547		$	176,359
	Adjustments to reconcile net earnings to net cash flows from operating activities:
	Depreciation and amortization	4,192			5,000			7,654
	Deferred income tax expense	(51,820		)	(46,632		)	(34,396		)
	Equity in (earnings) of subsidiaries	(116,634		)	(117,900		)	(205,215		)
	Loss on reacquired debt	3,253			—			9,209
	Stock based compensation expense	5,320			3,585			6,556
	Changes in certain assets and liabilities:
	Other current assets	28,460			(43,638		)	42,687
	Other assets	46,558			34,096			59,975
	Accounts payable	620			8			(1		)
	Accrued interest and taxes	(9,266		)	(28,855		)	27,348
	Other current liabilities	(146		)	3,876			4,765
	Other liabilities	(27,756		)	(29,601		)	(12,854		)
	Net cash flows from operating activities	(16,712		)	(114,514		)	82,087
	Cash Flows From Investing Activities:
	Utility plant additions	(960		)	(7,524		)	—
	Investments in subsidiaries	(13,800		)	—			(43,000		)
	Cash dividends from subsidiaries	158,772			61,406			285,757
	Net cash flows from investing activities	144,012			53,882			242,757
	Cash Flows From Financing Activities:
	Short-term borrowings (repayments), net	(37,600		)	120,900			(15,300		)
	Short-term borrowings (repayments) – affiliate, net	—			—			300
	Repayment of long-term debt	(29,468		)	(2,387		)	(60,391		)
	Purchase of preferred stock	—			—			(73,475		)
	Purchase of common stock	—			—			(125,683		)
	Proceeds from stock option exercise	4,618			11,684			5,622
	Purchases to satisfy awards of common stock	(13,807		)	(25,168		)	(10,104		)
	Dividends paid	(50,980		)	(44,609		)	(45,128		)
	Other, net	—			—			(747		)
	Net cash flows from financing activities	(127,237		)	60,420			(324,906		)
	Change in Cash and Cash Equivalents	63			(212		)	(62		)
	Cash and Cash Equivalents at Beginning of Period	29			241			303
	Cash and Cash Equivalents at End of Period	$	92		$	29		$	241
	Supplemental Cash Flow Disclosures:
	Interest paid	$	14,510		$	15,007		$	19,215
	Income taxes paid (refunded), net	$	22,378		$	1,501		$	5,454
SCHEDULE I
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
BALANCE SHEETS
	December 31,
	2013			2012
	(In thousands)
Assets
Cash and cash equivalents	$	92		$	29
Intercompany receivables	136,387			108,875
Income taxes receivable	14,989			41,434
Other, net	8,544			2,204
Total current assets	160,012			152,542
Property, plant and equipment, net of accumulated depreciation of $9,167 and $8,262	26,601			25,642
Long-term investments	—			3,651
Investment in subsidiaries	1,683,321			1,688,168
Other long-term assets	53,892			49,302
Total long-term assets	1,763,814			1,766,763
	$	1,923,826		$	1,919,305
Liabilities and Stockholders’ Equity
Short-term debt	$	100,000		$	137,600
Short-term debt-affiliate	8,819			8,819
Current maturities of long-term debt	—			2,530
Accrued interest and taxes	2,797			3,127
Other current liabilities	16,876			13,218
Total current liabilities	128,492			165,294
Long-term debt	118,766			142,592
Other long-term liabilities	2,999			3,232
Total liabilities	250,257			311,118
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369			1,182,819
Accumulated other comprehensive income (loss), net of tax	(58,140		)	(81,630		)
Retained earnings	553,340			506,998
Total common stockholders’ equity	1,673,569			1,608,187
	$	1,923,826		$	1,919,305
See Notes 6, 7, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
Schedule II - Valuation and Qualifying Accounts	'
	SCHEDULE II
	PNM RESOURCES, INC. AND SUBSIDIARIES
	VALUATION AND QUALIFYING ACCOUNTS
							Additions						Deductions
		Description		Balance at			Charged to			Charged to			Write-offs and other			Balance at
				beginning of			costs and			other						end of year
				year			expenses			accounts
							(In thousands)
		Allowance for doubtful accounts, year ended December 31:
		2011		$	11,178		$	24,116		$	—		$	33,516	(1)	$	1,778
		2012		$	1,778		$	3,367		$	—		$	3,394		$	1,751
		2013		$	1,751		$	2,849		$	—		$	3,177		$	1,423
	(1)  Includes reduction of $11,818 due to the sale of First Choice on November 1, 2011.
	SCHEDULE II
	PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY
	A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
	VALUATION AND QUALIFYING ACCOUNTS
							Additions						Deductions
		Description		Balance at			Charged to			Charged to			Write-offs			Balance at
				beginning of			costs and			other						end of year
				year			expenses			accounts
							(In thousands)
		Allowance for doubtful accounts, year ended December 31:
		2011		$	1,483		$	3,736		$	—		$	3,441		$	1,778
		2012		$	1,778		$	3,384		$	—		$	3,411		$	1,751
		2013		$	1,751		$	2,864		$	—		$	3,192		$	1,423
	SCHEDULE II
	TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
	A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
	VALUATION AND QUALIFYING ACCOUNTS
						Additions						Deductions
	Description		Balance at			Charged to			Charged to			Write-offs			Balance at
			beginning of			costs and			other						end of year
			year			expenses			accounts
						(In thousands)
	Allowance for doubtful accounts, year ended December 31:
	2011		$	—		$	33		$	—		$	33		$	—
	2012		$	—		$	(17	)	$	—		$	(17	)	$	—
	2013		$	—		$	(15	)	$	—		$	(15	)	$	—

Summary_of_the_Business_and_Si1

Summary of the Business and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Principles of Consolidation	'
	The Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia (Note 9). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.
	PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and equity transactions. All intercompany transactions and balances have been eliminated.
Accounting for the Effects of Certain Types of Regulation	'
	The Company maintains its accounting records in accordance with the uniform system of accounts prescribed by FERC and adopted by the NMPRC and PUCT.
	Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to the regulated operations. Regulators may assign costs to accounting periods that differ from accounting methods applied by non-regulated utilities.  When it is probable that regulators will permit recovery of costs through future rates, costs that otherwise would be expensed are deferred as regulatory assets.  Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred.  Regulatory assets and liabilities are amortized into earnings over the authorized recovery period. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of FERC, the NMPRC, and the PUCT. Information on regulatory assets and regulatory liabilities is contained in Note 4.
	In some circumstances, regulators allow a requested increase in rates to be implemented, subject to refund, before the regulatory process has been completed and a decision rendered by the regulator. When this occurs, the Company assesses the possible outcomes of the rate proceeding. The Company records a provision for refund to the extent the amounts being collected, subject to refund, exceed the amount the Company determines is probable of ultimately being allowed by the regulator.
Cash and Cash Equivalents	'
	Investments in highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.
Utility Plant	'
	Utility plant is stated at cost, which includes capitalized payroll-related costs such as taxes, pension, and other fringe benefits, administrative costs, and AFUDC where authorized by rate regulation.
	Repairs, including major maintenance activities, and minor replacements of property are expensed when incurred, except as required by regulators for ratemaking purposes. Major replacements are charged to utility plant. Gains or losses resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to accumulated depreciation.
Allowance for Funds Used During Construction	'
	As provided by the FERC uniform systems of accounts, AFUDC is charged to regulated utility plant for construction projects. This allowance is a non-cash item designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). The allowance for borrowed funds used during construction is recorded in interest charges and the allowance for equity funds used during construction is recorded in other income on the Consolidated Statements of Earnings.
Capitalized Interest	'
	PNMR capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC.
Carrying Charges on Stranded Costs	'
	In connection with the adoption of Senate Bill 7 by the Texas Legislature in 1999 that deregulated electric utilities operating within ERCOT, TNMP was allowed to recover its stranded costs through the CTC and to also recover a carrying charge on the CTC. The amounts yet to be collect are recorded as regulatory assets by TNMP. TNMP’s calculation of allowable carrying charges on stranded costs recoverable from its transmission and distribution customers is based on a Texas Supreme Court ruling and the PUCT’s application of that ruling.
Materials, Supplies, and Fuel Stock	'
	Materials and supplies relate to transmission, distribution, and generating assets. Materials and supplies are charged to inventory when purchased and are expensed or capitalized as appropriate when issued. Materials and supplies are valued using an average costing method.
	Coal is valued using a rolling weighted average costing method that is updated based on the current period cost per ton. Periodic aerial surveys are performed on the coal piles and adjustments are made.
Investments	'
	PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). All of these investments are classified as available-for-sale. PNM evaluates the securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2013, 2012, and 2011, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $3.5 million, $4.8 million, and $12.5 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI.
Equity Method Investments	'
	Through September 23, 2011, PNMR accounted for its investment in Optim Energy using the equity method of accounting because PNMR’s ownership interest resulted in significant influence, but not control, over Optim Energy and its operations.
Cost Method Investments	'
	On September 23, 2011, PNMR’s ownership interest in Optim Energy was reduced to 1% and PNMR began using the cost method of accounting.
Goodwill and Other Intangible Assets	'
	Under GAAP, the Company does not amortize goodwill. In 2011, certain intangible assets were amortized over their estimated useful lives. Goodwill and non-amortizable other intangible assets are evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill and intangible assets might be impaired. Amortizable other intangible assets are amortized over the shorter of their economic or legal lives and are evaluated for impairment when events and circumstances indicate that the assets might be impaired.
Asset Impairment	'
	Tangible long-lived assets are evaluated in relation to the future undiscounted cash flows to assess recoverability when events and circumstances indicate that the assets might be impaired.
Revenue Recognition	'
	Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience.
	PNM’s wholesale electricity sales are recorded as electric operating revenues and the wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are net settled or “booked-out” are recorded net in earnings. A book-out is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.
	Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold. The Company has no trading transactions.
Accounts Receivable and Allowance for Uncollectible Accounts	'
	Accounts receivable consists primarily of trade receivables from customers. In the normal course of business, credit is extended to customers on a short-term basis. The Company calculates the allowance for uncollectible accounts based on historical experience and estimated default rates. The accounts receivable balances are reviewed monthly and adjustments to the allowance for uncollectible accounts and bad debt expense are made as necessary. Amounts that are deemed uncollectible are written off.
Depreciation and Amortization	'
	PNM’s provision for depreciation and amortization of utility plant, other than nuclear fuel, is based upon composite straight-line rates approved by the NMPRC. Amortization of nuclear fuel is based on units-of-production. TNMP’s provision for depreciation and amortization of utility plant is based upon straight-line rates approved by the PUCT. Depreciation of non-utility property is computed based on the straight-line method. The provision for depreciation of certain equipment is allocated between operating expenses and construction projects based on the use of the equipment.
Amortization of Debt Acquisition Costs	'
	Discount, premium, and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. Gains and losses incurred upon the early retirement of long-term debt are recognized in other income or other deductions, except for amounts attributable to NMPRC, FERC, or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues.
Derivatives	'
	The Company records derivative instruments, other than those designated as normal purchases or normal sales, in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or normal sale criteria are met. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.
	The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity.
	GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the economic hedge.
	Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal purchases and normal sales exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle.
	For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. The Company assesses the effectiveness of hedge relationships at least quarterly using statistical data. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. As of December 31, 2013 and 2012, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges.
	The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.
	Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.
Decommissioning Costs	'
	PNM owns and leases nuclear and fossil-fuel generating facilities. In accordance with GAAP, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Nuclear decommissioning costs and related accruals are based on site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions. PNM’s accruals for PVNGS Units 1, 2, and 3, including portions held under leases, have been made based on such estimates, the guidelines of the NRC, and the extended PVNGS license period. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 is currently excluded. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fueled generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. See Note 15 and Note 16.
	In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation as well as the costs for final reclamation of the coal mines. The reclamation costs are based on site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for a discussion of the final reclamation costs.
Environmental Costs	'
	The normal operations of the Company involve activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred.
	The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process.
Income Taxes	'
	Income taxes are recognized using the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current NMPRC, FERC, and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC, FERC, and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets.
Excise Taxes	'
	The Company pays certain fees or taxes which are either considered to be an excise tax or similar to an excise tax. Substantially all of these taxes are recorded on a net basis in the Consolidated Statements of Earnings.
Segment Information	'
	The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.
Fair Value Derivatives	'
	The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.
	For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services.
Variable Interest Entities	'
	GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.
Pension and Other Postretirement Benefits	'
	GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur.
	GAAP requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs will ultimately be included as pension and postretirement benefit periodic cost or income in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP record the costs as a regulatory asset or regulatory liability.
	The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility.
Commitments and Contingencies	'
	There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 17) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.
	With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. The Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Summary_of_the_Business_and_Si2

Summary of the Business and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Schedule of Inventory, Current [Table Text Block]	'
	Inventories consisted of the following at December 31:
		PNMR							PNM				TNMP
		2013			2012				2013		2012		2013		2012
		(In thousands)
	Coal	$	24,872		$	19,231			$	24,872	$	19,231	$	—	$	—
	Materials and supplies	42,351			40,412				39,648		37,559		2,703		2,853
		$	67,223		$	59,643			$	64,520	$	56,790	$	2,703	$	2,853
Schedule of Average Rates Used Allocated Between Depreciation Expense and Construction Expense Projects Based on Use of Equipment [Table Text Block]	'
	Average straight-line rates used were as follows:
		Year ended December 31
		2013		2012			2011
	PNM
	Electric plant	2.27	%	2.25	%		2.24	%
	Common, intangible, and general plant	4.87	%	5.35	%		6.03	%
	TNMP	3.66	%	3.56	%		3.41	%

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment [Table Text Block]	'
	PNMR SEGMENT INFORMATION
	2013	PNM			TNMP			Corporate			Consolidated
								and Other
		(In thousands)
	Electric operating revenues	$	1,116,312		$	271,611		$	—		$	1,387,923
	Cost of energy	374,710			57,606			—			432,316
	Margin	741,602			214,005			—			955,607
	Other operating expenses	428,591			91,601			(18,308		)	501,884
	Depreciation and amortization	103,826			50,219			12,836			166,881
	Operating income	209,185			72,185			5,472			286,842
	Interest income	10,182			—			(139		)	10,043
	Other income (deductions)	11,288			1,919			(13,575		)	(368		)
	Net interest charges	(79,175		)	(27,393		)	(14,880		)	(121,448		)
	Segment earnings (loss) before income taxes	151,480			46,711			(23,122		)	175,069
	Income taxes (benefit)	48,804			17,621			(6,912		)	59,513
	Segment earnings (loss)	102,676			29,090			(16,210		)	115,556
	Valencia non-controlling interest	(14,521		)	—			—			(14,521		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	87,627		$	29,090		$	(16,210	)	$	100,507
	Gross property additions	$	239,906		$	89,117		$	19,016		$	348,039
	At December 31, 2013:
	Total Assets	$	4,227,616		$	1,162,431		$	110,163		$	5,500,210
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2012	PNM			TNMP			Corporate			Consolidated
								and Other
	Electric operating revenues	$	1,092,264		$	250,140		$	(1	)	$	1,342,403
	Cost of energy	353,649			46,201			—			399,850
	Margin	738,615			203,939			(1		)	942,553
	Other operating expenses	435,442			87,079			(17,862		)	504,659
	Depreciation and amortization	97,291			49,340			17,542			164,173
	Operating income	205,882			67,520			319			273,721
	Interest income	13,243			1			(172		)	13,072
	Gain on sale of First Choice	—			—			1,012			1,012
	Other income (deductions)	13,290			2,739			(7,954		)	8,075
	Net interest charges	(76,101		)	(28,161		)	(16,583		)	(120,845		)
	Segment earnings (loss) before income taxes	156,314			42,099			(23,378		)	175,035
	Income taxes (benefit)	50,713			15,352			(11,155		)	54,910
	Segment earnings (loss)	105,601			26,747			(12,223		)	120,125
	Valencia non-controlling interest	(14,050		)	—			—			(14,050		)
	Subsidiary preferred stock dividends	(528		)	—			—			(528		)
	Segment earnings (loss) attributable to PNMR	$	91,023		$	26,747		$	(12,223	)	$	105,547
	Gross property additions	$	196,800		$	92,973		$	19,136		$	308,909
	At December 31, 2012:
	Total Assets	$	4,163,907		$	1,086,229		$	122,447		$	5,372,583
	Goodwill	$	51,632		$	226,665		$	—		$	278,297
	2011	PNM			TNMP			First			Corporate			Consolidated
								Choice			and Other
								(In thousands)
	Electric operating revenues:
	Non-affiliates	$	1,057,289		$	204,045		$	439,450		$	(165	)	$	1,700,619
	Affiliate	—			33,813			—			(33,813		)	—
	Total electric operating revenues	1,057,289			237,858			439,450			(33,978		)	1,700,619
	Cost of energy	362,237			41,166			323,331			(33,812		)	692,922
	Margin	695,052			196,692			116,119			(166		)	1,007,697
	Other operating expenses	438,822			88,234			75,966			(9,671		)	593,351
	Depreciation and amortization	94,787			44,616			1,098			16,546			157,047
	Operating income (loss)	161,443			63,842			39,055			(7,041		)	257,299
	Interest income	15,562			2			64			(113		)	15,515
	Gain on sale of First Choice	—			—			—			174,925			174,925
	Other income (deductions)	4,309			1,580			(650		)	(15,660		)	(10,421		)
	Net interest charges	(75,349		)	(29,286		)	(581		)	(19,633		)	(124,849		)
	Segment earnings before income taxes	105,965			36,138			37,888			132,478			312,469
	Income taxes	37,427			13,881			13,772			56,455			121,535
Segment earnings	68,538			22,257			24,116			76,023			190,934
Valencia non-controlling interest	(14,047		)	—			—			—			(14,047		)
Subsidiary preferred stock dividends	(528		)	—			—			—			(528		)
Segment earnings attributable to PNMR	$	53,963		$	22,257		$	24,116		$	76,023		$	176,359
Gross property additions	$	251,345		$	67,407		$	2,089		$	6,090		$	326,931
At December 31, 2011:
Total Assets	$	4,095,287		$	1,037,445		$	—		$	71,881		$	5,204,613
Goodwill	$	51,632		$	226,665		$	—		$	—		$	278,297

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Public Service Company of New Mexico [Member]	'
Regulatory Assets [Line Items]	'
Regulatory Assets and Liabilities [Table Text Block]	'
	Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below.
	PNM
		December 31,
		2013			2012
	Assets:	(In thousands)
	Current:
	FPPAC	$	19,394		$	36,266
	Other	—			224
		19,394			36,490
	Non-Current:
	Coal mine reclamation costs	40,144			46,065
	Deferred income taxes	61,850			54,781
	Loss on reacquired debt	27,490			29,702
	Pension and OPEB	206,691			254,351
	FPPAC	25,386			18,619
	Renewable energy costs	13,311			18,768
	Other	9,345			9,670
		384,217			431,956
	Total regulatory assets	$	403,611		$	468,446
	Liabilities:
	Current:
	Other	$	(1,081	)	$	(15,172	)
	Non-Current:
	Cost of removal	$	(266,075	)	$	(257,396	)
	Deferred income taxes	(80,495		)	(49,723		)
	AROs	(37,567		)	(39,280		)
	Renewable energy tax benefits	(26,011		)	(26,988		)
	Other	(4,463		)	(6,454		)
		(414,611		)	(379,841		)
	Total regulatory liabilities	$	(415,692	)	$	(395,013	)
Texas-New Mexico Power Company [Member]	'
Regulatory Assets [Line Items]	'
Regulatory Assets and Liabilities [Table Text Block]	'
	TNMP
		December 31,
		2013			2012
	Assets:	(In thousands)
	Current:
	Transmission cost recovery factor	$	4,250		$	2,287
	Other	772			343
		5,022			2,630
	Non-Current:
	CTC, including carrying charges	63,606			71,240
	Deferred income taxes	10,868			11,179
	Pension	19,938			28,307
	Loss on reacquired debt	38,616			1,711
	Hurricane recovery costs	—			4,572
	AMS retirement costs	5,083			3,538
	Other	1,627			3,074
		139,738			123,621
	Total regulatory assets	$	144,760		$	126,251
	Liabilities:
	Non-Current:
	Cost of removal	$	(30,863	)	$	(31,115	)
	Deferred income taxes	(4,563		)	(5,203		)
	AMS surcharge	(7,251		)	(6,386		)
	OPEB	(3,361		)	(915		)
	Total regulatory liabilities	$	(46,038	)	$	(43,619	)

Financing_Tables

Financing (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Short-term Debt [Table Text Block]	'
	Short-term debt outstanding consists of:
			December 31,
	Short-term Debt		2013				2012
			(In thousands)
	PNM Revolving Credit Facility		$	49,200			$	21,100
	TNMP Revolving Credit Facility		—				—
	PNMR
	Revolving Credit Facility		—				37,600
	PNMR Term Loan Agreement		100,000				100,000
			$	149,200			$	158,700
Schedule of Long-term Debt Instruments [Table Text Block]	'
	Information concerning long-term debt outstanding is as follows:
			December 31,
	Long-term Debt		2013				2012
			(In thousands)
	PNM Debt
	Senior Unsecured Notes, Pollution Control Revenue Bonds:
	4.875% due 2033		$	146,000			$	146,000
	6.25% due 2038		36,000				36,000
	4.75% due 2040, mandatory tender at June 1, 2017		37,000				37,000
	5.20% due 2040, mandatory tender at June 1, 2020		40,045				40,045
	5.90% due 2040		255,000				255,000
	6.25% due 2040		11,500				11,500
	2.54% due 2042, mandatory tender at June 1, 2017		20,000				20,000
	4.00% due 2043, mandatory tender at June 1, 2015		39,300				39,300
	5.20% due 2043, mandatory tender at June 1, 2020		21,000				21,000
	Senior Unsecured Notes:
	7.95% due 2018		350,000				350,000
	7.50% due 2018		100,025				100,025
	5.35% due 2021		160,000				160,000
	PNM Term Loan Agreement due 2014		75,000				—
	Unamortized premiums (discounts)		(252		)		(291		)
			1,290,618				1,215,579
	Less current maturities		75,000				—
			1,215,618				1,215,579
	TNMP Debt
	First Mortgage Bonds:
	2011 Term Loan Agreement, due 2014		50,000				50,000
	9.50% due 2019, Series 2009A		172,302				265,500
	6.95% due 2043, Series 2013A		93,198				—
	Unamortized premiums (discounts)		20,536				(3,911		)
			336,036				311,589
	Less current maturities		—				—
			336,036				311,589
	PNMR Debt
	Senior unsecured notes, 9.25% due 2015		118,766				142,592
	Other		—				2,530
			118,766				145,122
	Less current maturities		—				2,530
			118,766				142,592
	Total Consolidated PNMR Debt		1,745,420				1,672,290
	Less current maturities		75,000				2,530
			$	1,670,420			$	1,669,760
Schedule of Maturities of Long-term Debt [Table Text Block]	'
	Reflecting mandatory tender dates, long-term debt matures as follows:
		PNMR				PNM				TNMP		PNMR Consolidated
		(In thousands)
	2014	$	—			$	75,000			$	—	$	75,000
	2015	118,766				39,300				—		158,066
	2016	—				—				—		—
	2017	—				57,000				—		57,000
	2018	—				450,025				—		450,025
	Thereafter	—				669,545				315,500		985,045
	Total	$	118,766			$	1,290,870			$	315,500	$	1,725,136
	The TNMP 2011 Term Loan Agreement, which is due on June 30, 2014, is not reflected as maturing in 2014 in the above tables since TNMP has entered into the TNMP 2013 Bond Purchase Agreement to re-finance that debt on a long-term basis as discussed in Financing Activities above.

Lease_Commitments_Lease_Commit

Lease Commitments Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Schedule of Rent Expense [Table Text Block]	'
	Operating lease expense, including the PVNGS and EIP leases, was:
		PNMR		PNM		TNMP
		(In thousands)
	2013	$	82,882	$	78,306	$	2,663
	2012	$	84,794	$	78,483	$	2,871
	2011	$	86,323	$	78,422	$	3,606
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	'
	Future minimum operating lease payments at December 31, 2013 shown below have been reduced by payments on the PVNGS lessor notes of $25.4 million in 2014, $24.0 million in 2015, and $9.0 million in 2016 that will be returned in cash to PNM:
		PNMR		PNM		TNMP
		(In thousands)
	2014	$	53,594	$	49,580	$	815
	2015	40,952		38,290		676
	2016	33,788		33,363		237
	2017	30,942		30,749		—
	2018	30,948		30,749		—
	Later years	167,225		166,830		—
		357,449		349,561		1,728
	Future payments under non-cancelable subleases	93		—		—
	Net minimum lease payments	$	357,356	$	349,561	$	1,728

Fair_Value_of_Derivative_and_O1

Fair Value of Derivative and Other Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value of Derivative and Other Financial Instruments [Abstract]	'
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	'
	Commodity derivative instruments, recorded at fair value are summarized as follows:
		Economic Hedges
		December 31,
		2013				2012
		(In thousands)
	PNM and PNMR
	Current assets	$	4,064			$	3,785
	Deferred charges	3,002				352
		7,066				4,137
	Current liabilities	(2,699		)		(1,000		)
	Long-term liabilities	(1,094		)		(1,933		)
		(3,793		)		(2,933		)
	Net	$	3,273			$	1,204
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	'
	The following table presents the effect of mark-to-market commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, including de-designated hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.
		Economic										Qualified Cash
		Hedges										Flow Hedges
		Year Ended										Year Ended
		December 31,										December 31,
		2013				2012			2011			2013		2012			2011
		(In thousands)
	PNMR
	Electric operating revenues	$	1,727			$	6,168		$	5,682		$	—	$	—		$	—
	Cost of energy	1,109				(460		)	(2,201		)	—		—			(422		)
	Total gain (loss)	$	2,836			$	5,708		$	3,481		$	—	$	—		$	(422	)
	Recognized in OCI											$	—	$	—		$	422
	PNM
	Electric operating revenues	$	1,727			$	6,168		$	5,682		$	—	$	—		$	—
	Cost of energy	1,109				(460		)	(1,058		)	—		—			—
	Total gain (loss)	$	2,836			$	5,708		$	4,624		$	—	$	—		$	—
	Recognized in OCI											$	—	$	—		$	—
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	'
	Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
		Economic Hedges
		MMBTU			MWh
	December 31, 2013
	PNMR and PNM	905,000			(3,343,783	)
	December 31, 2012
	PNMR and PNM	1,127,500			(2,477,520	)
Schedule of Collateral Related to Derivative [Table Text Block]	'
	Contingent Feature –		Contractual				Existing Cash			Net Exposure
	Credit Rating Downgrade		Liability				Collateral
			(In thousands)
	December 31, 2013
	PNMR and PNM		$	2,398			$	—		$	2,152
	December 31, 2012
	PNMR and PNM		$	2,933			$	—		$	2,777
Available-for-sale Securities [Table Text Block]	'
	The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2013 and 2012, the fair value of available-for-sale securities included $222.5 million and $189.0 million for the NDT and $4.4 million and $3.5 million for the mine reclamation trust.
		December 31, 2013							December 31, 2012
		Unrealized				Fair Value			Unrealized			Fair Value
		Gains							Gains
	PNMR and PNM					(In thousands)
	Cash and cash equivalents	$	—			$	3,356		$	—		$	4,628
	Equity securities:
	Domestic value	14,523				39,460			5,223			30,044
	Domestic growth	25,656				76,292			15,212			51,650
	International and other	1,040				16,633			247			14,868
	Fixed income securities:
	U.S. Government	158				21,941			1,305			32,592
	Municipals	1,018				58,568			4,069			43,861
	Corporate and other	207				10,605			1,100			14,868
		$	42,602			$	226,855		$	27,156		$	192,511
Schedule of Realized Gain (Loss) [Table Text Block]	'
	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.
		Year Ended December 31,
		2013				2012			2011
		(In thousands)
	Proceeds from sales	$	271,140			$	167,330		$	145,286
	Gross realized gains	$	14,308			$	15,907		$	17,493
	Gross realized (losses)	$	(4,298	)		$	(8,170	)	$	(6,223	)
Investments Classified by Contractual Maturity Date [Table Text Block]	'
	At December 31, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities:
		Fair Value
		Available-for-Sale				Held-to-Maturity
		PNMR and PNM				PNMR			PNM
		(In thousands)
	Within 1 year	$	3,025			$	1,149		$	1,149
	After 1 year through 5 years	24,068				57,497			56,130
	After 5 years through 10 years	10,128				—			—
	After 10 years through 15 years	6,136				—			—
	After 15 years through 20 years	10,331				—			—
	After 20 years	37,426				—			—
		$	91,114			$	58,646		$	57,279
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block]	'
	Items recorded at fair value on the Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at December 31, 2013 and 2012 for items recorded at fair value.
						GAAP Fair Value Hierarchy
		Total				Quoted Prices			Significant
						in Active			Other
						Market for			Observable
						Identical Assets			Inputs
						(Level 1)			(Level 2)
	December 31, 2013					(In thousands)
	PNMR and PNM
	Available-for-sale securities
	Cash and cash equivalents	$	3,356			$	3,356		$	—
	Equity securities:
	Domestic value	39,460				39,460			—
	Domestic growth	76,292				76,292			—
	International and other	16,633				16,633			—
	Fixed income securities:
	U.S. Government	21,941				20,194			1,747
	Municipals	58,568				—			58,568
	Corporate and other	10,605				2,245			8,360
		$	226,855			$	158,180		$	68,675
	Commodity derivative assets	$	7,066			$	—		$	7,066
	Commodity derivative liabilities	(3,793		)		—			(3,793		)
	Net	$	3,273			$	—		$	3,273
						GAAP Fair Value Hierarchy
		Total				Quoted Prices			Significant
						in Active			Other
						Market for			Observable
						Identical Assets			Inputs
						(Level 1)			(Level 2)
	December 31, 2012					(In thousands)
	PNMR and PNM
	Available-for-sale securities
	Cash and cash equivalents	$	4,628			$	4,628		$	—
	Equity securities:
	Domestic value	30,044				30,044			—
	Domestic growth	51,650				51,650			—
	International and other	14,868				14,868			—
	Fixed income securities:
	U.S. Government	32,592				27,737			4,855
	Municipals	43,861				—			43,861
	Corporate and other	14,868				—			14,868
		$	192,511			$	128,927		$	63,584
	Commodity derivative assets	$	4,137			$	—		$	4,137
	Commodity derivative liabilities	(2,933		)		—			(2,933		)
	Net	$	1,204			$	—		$	1,204
Fair Value, by Balance Sheet Grouping [Table Text Block]	'
	The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Consolidated Balance Sheets are presented below:
									GAAP Fair Value Hierarchy
		Carrying				Fair Value			Level 1			Level 2		Level 3
		Amount
	December 31, 2013	(In thousands)
	PNMR
	Long-term debt	$	1,745,420			$	1,905,230		$	—		$	1,905,230	$	—
	Investment in PVNGS lessor notes	$	52,958			$	57,279		$	—		$	—	$	57,279
	Other investments	$	1,835			$	3,196		$	690		$	—	$	2,506
	PNM
	Long-term debt	$	1,290,618			$	1,382,938		$	—		$	1,382,938	$	—
	Investment in PVNGS lessor notes	$	52,958			$	57,279		$	—		$	—	$	57,279
	Other investments	$	445			$	445		$	445		$	—	$	—
	TNMP
	Long-term debt	$	336,036			$	390,814		$	—		$	390,814	$	—
	Other investments	$	245			$	245		$	245		$	—	$	—
	December 31, 2012
	PNMR
	Long-term debt	$	1,672,290			$	1,969,362		$	—		$	1,966,725	$	2,637
	Investment in PVNGS lessor notes	$	77,682			$	84,198		$	—		$	—	$	84,198
	Other investments	$	5,599			$	6,965		$	774		$	—	$	6,191
	PNM
	Long-term debt	$	1,215,579			$	1,385,433		$	—		$	1,385,433	$	—
	Investment in PVNGS lessor notes	$	77,682			$	84,198		$	—		$	—	$	84,198
	Other investments	$	494			$	494		$	494		$	—	$	—
	TNMP
	Long-term debt	$	311,589			$	418,166		$	—		$	418,166	$	—
	Other investments	$	281			$	281		$	281		$	—	$	—
Fair Value, Assets Measured on Recurring Basis [Table Text Block]	'
	The fair values of investments held by the employee benefit plans are as follows:
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active Market for Identical Assets			Significant			Significant
						(Level 1)			Other			Unobservable
									Observable			Inputs
									Inputs			(Level 3)
									(Level 2)
	December 31, 2013					(In thousands)
	PNM Pension Plan
	Participation in PNMR Master Trust Total Plan Investments	$	557,258			$	145,364		$	330,903		$	80,991
	TNMP Pension Plan
	Participation in PNMR Master Trust Total Plan Investments	$	66,285			$	18,657		$	32,620		$	15,008
	PNM OPEB Plan
	Cash and cash equivalents	$	1,152			$	1,152		$	—		$	—
	Equity securities:
	International funds	3,057				—			3,057			—
	Domestic value	6,388				6,388			—			—
	Domestic growth	54,851				20,769			34,082			—
	Other funds	5,564				—			5,564			—
	Fixed income securities:
	Mutual funds	3,121				3,121			—			—
		$	74,133			$	31,430		$	42,703		$	—
	TNMP OPEB Plan
	Cash and cash equivalents	$	302			$	302		$	—		$	—
	Equity securities:
	International funds	1,334				—			1,334			—
	Domestic value	381				381			—			—
	Domestic growth	1,848				1,848			—			—
	Other funds	4,167				—			4,167			—
	Fixed income securities:
	Mutual funds	1,702				1,702			—			—
		$	9,734			$	4,233		$	5,501		$	—
						GAAP Fair Value Hierarchy
		Total				Quoted Prices in Active			Significant			Significant
						Market for Identical Assets			Other			Unobservable
						(Level 1)			Observable			Inputs
									Inputs			(Level 3)
									(Level 2)
	December 31, 2012	(In thousands)
	PNM Pension Plan
	Participation in PNMR Master Trust	$	517,238			$	205,491		$	232,730		$	79,017
	TNMP Pension Plan
	Participation in PNMR Master Trust	$	66,450			$	26,462		$	25,817		$	14,171
	PNM OPEB Plan
	Cash and cash equivalents	$	4,976			$	4,976		$	—		$	—
	Equity securities:
	International funds	2,651				—			2,651			—
	Domestic growth	46,145				19,511			26,634			—
	Other funds	7,588				—			7,588			—
	Fixed income securities:
	Mutual funds	4,176				4,176			—			—
		$	65,536			$	28,663		$	36,873		$	—
	TNMP OPEB Plan
	Cash and cash equivalents	$	42			$	42		$	—		$	—
	Equity securities:
	International funds	1,444				—			1,444			—
	Domestic growth	1,289				1,289			—			—
	Other funds	3,660				—			3,660			—
	Fixed income securities:
	Mutual funds	2,325				2,325			—			—
		$	8,760			$	3,656		$	5,104		$	—
	The fair values of investments in the PNMR Master Trust are as follows:
						GAAP Fair Value Hierarchy
	Total				Quoted Prices in			Significant			Significant
					Active Market for			Other			Unobservable
					Identical Assets			Observable			Inputs
					(Level 1)			Inputs			(Level 3)
								(Level 2)
December 31, 2013	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	16,281			$	16,281		$	—		$	—
Equity securities:
International	24,471				24,471			—			—
Domestic value	41,451				41,451			—			—
Domestic growth	36,805				36,805			—			—
Other funds	22,522				—			22,522			—
Fixed income securities:
Corporate	202,897				363			202,358			176
U.S. Government	99,748				44,541			55,207			—
Municipals	17,259				—			17,259			—
Other funds	66,286				109			66,177			—
Alternative investments:
Private equity funds	39,122				—			—			39,122
Hedge funds	34,912				—			—			34,912
Real estate funds	21,789				—			—			21,789
	$	623,543			$	164,021		$	363,523		$	95,999
December 31, 2012
PNMR Master Trust
Cash and cash equivalents	$	10,404			$	10,404		$	—		$	—
Equity securities:
International	39,867				39,867			—			—
Domestic value	39,492				39,492			—			—
Domestic growth	63,888				63,888			—			—
Other funds	17,035				—			17,035			—
Fixed income securities:
Corporate	101,936				—			101,936			—
U.S. Government	148,341				78,302			70,039			—
Municipals	3,639				—			3,639			—
Other funds	65,898				—			65,898			—
Alternative investments:
Private equity funds	38,212				—			—			38,212
Hedge funds	31,277				—			—			31,277
Real estate funds	23,699				—			—			23,699
	$	583,688			$	231,953		$	258,547		$	93,188
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	A reconciliation of the changes in Level 3 fair value measurements is as follows:
		Year Ended December 31,
	Level 3 Fair Value Assets and Liabilities	2013				2012
		(In thousands)
	PNM Pension	Master				Master
		Trust				Trust
	Balance at beginning of period	$	79,017			$	84,133
	Actual return on assets sold during the period	3,303				2,627
	Actual return on assets still held at period end	3,361				2,386
	Purchases	15,110				5,498
	Sales	(19,800		)		(15,627		)
	Balance at end of period	$	80,991			$	79,017
	TNMP Pension
	Balance at beginning of period	$	14,171			$	14,555
	Actual return on assets sold during the period	1,400				197
	Actual return on assets still held at period end	1,425				179
	Purchases	6,408				413
	Sales	(8,396		)		(1,173		)
	Balance at end of period	$	15,008			$	14,171
	Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
	Level 3 Fair Value Assets and Liabilities
	PNMR Master Trust	Private				Hedge			Real			Fixed income - corporate		Total
		equity				funds			estate
		funds							funds
						(In thousands)
	Balance at December 31, 2011	$	37,100			$	36,904		$	24,684		$	—	$	98,688
	Actual return on assets sold during the period	2,966				(80		)	(62		)	—		2,824
	Actual return on assets still held at period end	40				2,453			72			—		2,565
	Purchases	3,906				—			2,005			—		5,911
	Sales	(5,800		)		(8,000		)	(3,000		)	—		(16,800		)
	Balance at December 31, 2012	38,212				31,277			23,699			—		93,188
	Actual return on assets sold during the period	4,677				135			(109		)	—		4,703
	Actual return on assets still held at period end	1,162				3,500			123			1		4,786
	Purchases	3,117				16,151			2,076			175		21,519
	Sales	(8,046		)		(16,151		)	(4,000		)	—		(28,197		)
	Balance at December 31, 2013	$	39,122			$	34,912		$	21,789		$	176	$	95,999

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2013
Variable Interest Entities [Abstract]	'
Noncontrolling Interest Summarized Financial Information [Table Text Block]	'
	Summarized financial information for Valencia is as follows:
	Results of Operations
		Year ended December 31,
		2013			2012			2011
		(In thousands)
	Operating revenues	$	20,166		$	19,585		$	19,720
	Operating expenses	(5,645		)	(5,535		)	(5,673		)
	Earnings attributable to non-controlling interest	$	14,521		$	14,050		$	14,047
	Financial Position
		December 31,
		2013			2012
		(In thousands)
	Current assets	$	2,658		$	3,655
	Net property, plant and equipment	75,137			77,953
	Total assets	77,795			81,608
	Current liabilities	766			765
	Owners’ equity – non-controlling interest	$	77,029		$	80,843

Earnings_and_Dividends_Per_Sha1

Earnings and Dividends Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	Information regarding the computation of earnings per share and dividends per share is as follows:
		Year Ended December 31,
		2013		2012		2011
		(In thousands, except per share amounts)
	Earnings Attributable to PNMR	$	100,507	$	105,547	$	176,359
	Average Number of Common Shares:
	Outstanding during year	79,654		79,654		85,558
	Equivalents from convertible preferred stock (Note 5)	—		—		3,469
	Vested awards of restricted stock	191		145		174
	Average Shares - Basic	79,845		79,799		89,201
	Dilutive Effect of Common Stock Equivalents (1):
	Stock options and restricted stock	586		618		556
	Average Shares – Diluted	80,431		80,417		89,757
	Net Earnings Per Share of Common Stock:
	Basic	$	1.26	$	1.32	$	1.98
	Diluted	$	1.25	$	1.31	$	1.96
	Dividends Declared per Common Share	$	0.68	$	0.58	0.5
	(1)	Excludes out-of-the-money options for 509,916 shares of common stock at December 31, 2013. See Note 13.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes [Line Items]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	PNMR’s income taxes consist of the following components:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current federal income tax	$	—		$	(1,296	)	$	1,319
	Current state income tax	(917		)	(37		)	(4,208		)
	Deferred federal income tax	50,044			51,559			119,280
	Deferred state income tax	12,578			6,921			7,462
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Total income taxes	$	59,513		$	54,910		$	121,535
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	PNMR’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Federal income tax at statutory rates	$	61,274		$	61,262		$	109,364
	First Choice goodwill	—			—			15,055
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Flow-through of depreciation items	1,132			1,284			3,659
	Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
	State income tax, net of federal benefit	3,818			4,646			3,395
	Impairment of state production tax credits, net of federal benefit	3,880			718			—
	Other	(3,317		)	(5,845		)	(2,703		)
	Total income taxes	$	59,513		$	54,910		$	121,535
	Effective tax rate	33.99		%	31.37		%	38.9		%
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
	The components of PNMR’s net accumulated deferred income tax liability were:
		December 31,
		2013			2012
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	134,418		$	110,989
	Pension	—			26,452
	Regulatory liabilities related to income taxes	83,838			53,439
	Other	144,126			129,801
	Total deferred tax assets	362,382			320,681
	Deferred tax liabilities:
	Depreciation and plant related	(814,671		)	(759,587		)
	Investment tax credit	(25,855		)	(14,242		)
	Regulatory assets related to income taxes	(66,352		)	(59,471		)
	CTC	(22,262		)	(24,934		)
	Pension	(58,780		)	—
	Other	(143,044		)	(178,492		)
	Total deferred tax liabilities	(1,130,964		)	(1,036,726		)
	Net accumulated deferred income tax liabilities	(768,582		)	(716,045		)
	Current accumulated deferred income tax (asset) liability	(58,681		)	258
	Non-current accumulated deferred income tax liability	$	(827,263	)	$	(715,787	)
Schedule of Deferred Income Tax Components [Table Text Block]	'
	The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2013
		(In thousands)
	Net change in deferred income tax liability per above table	$	52,537
	Change in tax effects of income tax related regulatory assets and liabilities	23,592
	Tax effect of mark-to-market adjustments	(6,096		)
	Tax effect of excess pension liability	(9,305		)
	Adjustment for uncertain income tax positions	691
	Other	(989		)
	Deferred income taxes	$	60,430
Summary of Income Tax Contingencies [Table Text Block]	'
	A reconciliation of unrecognized tax benefits (expenses) is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Balance at December 31, 2010	$	36,105		$	11,918		$	7,788
	Additions based on tax positions related to 2011	(790		)	(717		)	(74		)
	Reductions for tax positions of prior years	(15,735		)	(449		)	(13		)
	Settlements	—			—			—
	Balance at December 31, 2011	19,580			10,752			7,701
	Additions based on tax positions related to 2012	2,046			1,152			—
	Reductions for tax positions of prior years	(2,428		)	(1,522		)	(905		)
	Settlements	—			—			—
	Balance at December 31, 2012	19,198			10,382			6,796
	Reductions based on tax positions related to 2013	(54		)	(54		)	—
	Additions for tax positions of prior years	745			745			—
	Settlements	—			—			—
	Balance at December 31, 2013	$	19,889		$	11,073		$	6,796
Interest Income (Expense) Related to Income Taxes [Table Text Block]	'
	Interest income (expense) related to income taxes is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	2013	$	242		$	251		$	(2	)
	2012	$	243		$	244		$	(3	)
	2011	$	467		$	401		$	2
Accumulated Accrued Interest Receivable (Payable) Related to Income Taxes [Table Text Block]	'
	Accumulated accrued interest receivable (payable) related to income taxes is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	December 31, 2013:
	Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
	Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)
	December 31, 2012:
	Accumulated accrued interest receivable	$	3,796		$	3,796		$	—
	Accumulated accrued interest payable	$	(1,108	)	$	(23	)	$	(116	)
Public Service Company of New Mexico [Member]	'
Income Taxes [Line Items]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	PNM’s income taxes consist of the following components:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current federal income tax	$	(479	)	$	(12,951	)	$	(46,364	)
	Current state income tax	(760		)	(1,815		)	(6,776		)
	Deferred federal income tax	42,806			56,194			78,673
	Deferred state income tax	9,429			11,522			14,212
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Total income taxes	$	48,804		$	50,713		$	37,427
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	The differences are attributable to the following factors:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Federal income tax at statutory rates	$	53,018		$	54,710		$	37,088
	Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
	Flow-through of depreciation items	1,115			1,268			3,656
	Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
	State income tax, net of federal benefit	6,202			6,500			4,797
	Other	(4,257		)	(4,610		)	(879		)
	Total income taxes	$	48,804		$	50,713		$	37,427
	Effective tax rate	32.22		%	32.44		%	35.32		%
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
	The components of PNM’s net accumulated deferred income tax liability were:
		December 31,
		2013			2012
		(In thousands)
	Deferred tax assets:
	Net operating loss	$	99,247		$	93,980
	Pension	—			32,532
	Regulatory liabilities related to income taxes	78,849			48,027
	Other	67,179			55,629
	Total deferred tax assets	245,275			230,168
	Deferred tax liabilities:
	Depreciation and plant related	(661,239		)	(624,724		)
	Investment tax credit	(25,855		)	(14,242		)
	Regulatory assets related to income taxes	(55,844		)	(48,726		)
	Pension	(52,104		)	—
	Other	(83,500		)	(134,046		)
	Total deferred tax liabilities	(878,542		)	(821,738		)
	Net accumulated deferred income tax liabilities	(633,267		)	(591,570		)
	Current accumulated deferred income tax (asset) liability	(43,827		)	3,447
	Non-current accumulated deferred income tax liability	$	(677,094	)	$	(588,123	)
Schedule of Deferred Income Tax Components [Table Text Block]	'
	The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2013
		(In thousands)
	Net change in deferred income tax liability per above table	$	41,697
	Change in tax effects of income tax related regulatory assets and liabilities	23,704
	Tax effect of mark-to-market adjustments	(6,121		)
	Tax effect of excess pension liability	(9,305		)
	Adjustment for uncertain income tax positions	691
	Other	(623		)
	Deferred income taxes	$	50,043
Texas-New Mexico Power Company [Member]	'
Income Taxes [Line Items]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	TNMP’s income taxes consist of the following components:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current federal income tax	$	(4,957	)	$	9,152		$	(3,578	)
	Current state income tax	1,916			1,822			1,981
	Deferred federal income tax	20,688			4,406			15,507
	Deferred state income tax	(26		)	(28		)	(29		)
	Total income taxes	$	17,621		$	15,352		$	13,881
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	The differences are attributable to the following factors:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Federal income tax at statutory rates	$	16,349		$	14,735		$	12,648
	State income tax, net of federal benefit	1,247			1,185			1,288
	Other	25			(568		)	(55		)
	Total income taxes	$	17,621		$	15,352		$	13,881
	Effective tax rate	37.72		%	36.47		%	38.41		%
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
	The components of TNMP’s net accumulated deferred income tax liability at December 31, were:
		December 31,
		2013			2012
		(In thousands)
	Deferred tax assets:
	Regulatory liabilities related to income taxes	$	4,988		$	5,412
	Other	23,479			16,702
	Total deferred tax assets	28,467			22,114
	Deferred tax liabilities:
	Depreciation and plant related	(151,581		)	(133,686		)
	CTC	(22,262		)	(24,934		)
	Regulatory assets related to income taxes	(10,509		)	(10,745		)
	Loss on reacquired debt	(13,516		)	(599		)
	Other	(14,295		)	(14,729		)
	Total deferred tax liabilities	(212,163		)	(184,693		)
	Net accumulated deferred income tax liabilities	(183,696		)	(162,579		)
	Current accumulated deferred income tax (asset)	(6,501		)	(1,131		)
	Non-current accumulated deferred income tax liability	$	(190,197	)	$	(163,710	)
Schedule of Deferred Income Tax Components [Table Text Block]	'
	The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
		Year Ended
		December 31, 2013
		(In thousands)
	Net change in deferred income tax liability per above table	$	21,117
	Change in tax effects of income tax related regulatory assets and liabilities	(112		)
	Other	(343		)
	Deferred income taxes	$	20,662

Pension_and_Other_Postretireme1

Pension and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	A reconciliation of the changes in Level 3 fair value measurements is as follows:
		Year Ended December 31,
	Level 3 Fair Value Assets and Liabilities	2013				2012
		(In thousands)
	PNM Pension	Master				Master
		Trust				Trust
	Balance at beginning of period	$	79,017			$	84,133
	Actual return on assets sold during the period	3,303				2,627
	Actual return on assets still held at period end	3,361				2,386
	Purchases	15,110				5,498
	Sales	(19,800		)		(15,627		)
	Balance at end of period	$	80,991			$	79,017
	TNMP Pension
	Balance at beginning of period	$	14,171			$	14,555
	Actual return on assets sold during the period	1,400				197
	Actual return on assets still held at period end	1,425				179
	Purchases	6,408				413
	Sales	(8,396		)		(1,173		)
	Balance at end of period	$	15,008			$	14,171
	Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
	Level 3 Fair Value Assets and Liabilities
	PNMR Master Trust	Private				Hedge				Real			Fixed income - corporate			Total
		equity				funds				estate
		funds								funds
						(In thousands)
	Balance at December 31, 2011	$	37,100			$	36,904			$	24,684		$	—		$	98,688
	Actual return on assets sold during the period	2,966				(80		)		(62		)	—			2,824
	Actual return on assets still held at period end	40				2,453				72			—			2,565
	Purchases	3,906				—				2,005			—			5,911
	Sales	(5,800		)		(8,000		)		(3,000		)	—			(16,800		)
	Balance at December 31, 2012	38,212				31,277				23,699			—			93,188
	Actual return on assets sold during the period	4,677				135				(109		)	—			4,703
	Actual return on assets still held at period end	1,162				3,500				123			1			4,786
	Purchases	3,117				16,151				2,076			175			21,519
	Sales	(8,046		)		(16,151		)		(4,000		)	—			(28,197		)
	Balance at December 31, 2013	$	39,122			$	34,912			$	21,789		$	176		$	95,999
Schedule of Defined Contribution Plan Expenses [Table Text Block]	'
	A summary of expenses for these other retirement plans is as follows:
		Year Ended December 31,
		2013				2012				2011
		(In thousands)
	PNMR
	401(k) plan	$	16,785			$	16,185			$	17,000
	Non-qualified plan	$	2,204			$	1,491			$	1,931
	PNM
	401(k) plan	$	12,952			$	12,427			$	12,541
	Non-qualified plan	$	1,691			$	1,143			$	1,407
	TNMP
	401(k) plan	$	3,953			$	3,739			$	3,723
	Non-qualified plan	$	513			$	327			$	431
Pension Plan [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2013				2012				2013			2012
		(In thousands)
	PBO at beginning of year	$	675,549			$	588,874			$	76,640		$	67,234
	Service cost	—				—				—			—
	Interest cost	28,142				32,232				3,087			3,635
	Plan amendment	(6,346		)		—				—			—
	Actuarial (gain) loss	(56,533		)		94,361				(7,820		)	11,434
	Benefits paid	(41,275		)		(39,918		)		(5,748		)	(5,663		)
	PBO at end of year	599,537				675,549				66,159			76,640
	Fair value of plan assets at beginning of year	518,095				427,386				66,540			59,952
	Actual return on plan assets	19,533				52,927				4,326			6,951
	Employer contributions	60,000				77,700				1,000			5,300
	Benefits paid	(41,275		)		(39,918		)		(5,748		)	(5,663		)
	Fair value of plan assets at end of year	556,353				518,095				66,118			66,540
	Funded status – asset (liability) for pension benefits	$	(43,184	)		$	(157,454	)		$	(41	)	$	(10,100	)
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	'
	The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2013.
		PNM Plan								TNMP Plan
		December 31, 2013								December 31, 2013
		Prior service				Net actuarial				Net actuarial
		cost				(gain) loss				(gain) loss
		(In thousands)
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$	32			$	159,826			$	—
	Experience loss (gain)	—				(34,136		)		(7,297		)
	Regulatory asset (liability) adjustment	—				19,799				7,297
	Plan amendment	(2,665		)		—				—
	Amortization recognized in net periodic benefit cost (income)	(32		)		(6,233		)		—
	Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,665	)		$	139,256			$	—
	Amortization expected to be recognized in 2014	$	(405	)		$	5,469			$	—
Schedule of Net Benefit Costs [Table Text Block]	'
	The following table presents the components of net periodic benefit cost (income):
		Year Ended December 31,
		2013				2012				2011
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	28,142				32,232				32,804
	Expected return on plan assets	(41,930		)		(41,301		)		(37,075		)
	Amortization of net (gain) loss	14,840				10,516				9,209
	Amortization of prior service cost	76				317				317
	Net periodic benefit cost	$	1,128			$	1,764			$	5,255
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	3,087				3,635				3,800
	Expected return on plan assets	(4,849		)		(5,324		)		(5,470		)
	Amortization of net (gain) loss	1,049				462				346
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost (income)	$	(713	)		$	(1,227	)		$	(1,324	)
Schedule of Assumptions Used [Table Text Block]	'
	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.
		Year Ended December 31,
	PNM Plan	2013			2012			2011
	Discount rate for determining December 31 PBO	5.27	%		4.3	%		5.67	%
	Discount rate for determining net periodic benefit cost (income)	4.3	%		5.67	%		5.72	%
	Expected return on plan assets	7.65	%		8.25	%		8.5	%
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 PBO	5.06	%		4.19	%		5.69	%
	Discount rate for determining net periodic benefit cost (income)	4.19	%		5.69	%		5.5	%
	Expected return on plan assets	7.65	%		8.25	%		8.5	%
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments [Table Text Block]	'
	The following pension benefit payments are expected to be paid:
		PNM				TNMP
		Plan				Plan
		(In thousands)
	2014	$	54,356			$	6,111
	2015	52,532				6,181
	2016	52,204				5,831
	2017	50,954				5,631
	2018	49,325				5,696
	2019 – 2023	222,241				23,804
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	'
	The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended December 31,								Year Ended December 31,
		2013				2012				2013			2012
		(In thousands)
	APBO at beginning of year	$	99,613			$	96,221			$	13,678		$	11,344
	Service cost	260				217				299			244
	Interest cost	4,113				5,293				566			624
	Participant contributions	2,537				2,266				373			404
	Actuarial (gain) loss	(4,566		)		5,008				(1,080		)	2,727
	Benefits paid	(9,792		)		(9,392		)		(1,570		)	(1,665		)
	APBO at end of year	92,165				99,613				12,266			13,678
	Fair value of plan assets at beginning of year	64,464				58,776				8,643			8,303
	Actual return on plan assets	12,780				9,285				1,813			1,259
	Employer contributions	3,576				3,529				342			342
	Participant contributions	2,537				2,266				373			404
	Benefits paid	(9,792		)		(9,392		)		(1,570		)	(1,665		)
	Fair value of plan assets at end of year	73,565				64,464				9,601			8,643
	Funded status – asset (liability)	$	(18,600	)		$	(35,149	)		$	(2,665	)	$	(5,035	)
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	'
	In the year ended December 31, 2013, actuarial gains of $12.3 million and $2.4 million were recorded as regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2013.
Schedule of Net Benefit Costs [Table Text Block]	'
	The following table presents the components of net periodic benefit cost:
		Year Ended December 31,
		2013				2012				2011
		(In thousands)
	PNM Plan
	Service cost	$	260			$	217			$	259
	Interest cost	4,113				5,293				5,378
	Expected return on plan assets	(5,043		)		(4,901		)		(5,388		)
	Amortization of net (gain) loss	4,242				3,888				3,205
	Amortization of prior service credit	(1,343		)		(1,343		)		(2,648		)
	Net periodic benefit cost	$	2,229			$	3,154			$	806
	TNMP Plan
	Service cost	$	299			$	244			$	306
	Interest cost	566				624				654
	Expected return on plan assets	(503		)		(516		)		(533		)
	Amortization of net (gain) loss	—				(209		)		(193		)
	Amortization of prior service cost	57				57				60
	Net periodic benefit cost	$	419			$	200			$	294
Schedule of Assumptions Used [Table Text Block]	'
	The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.
		Year Ended December 31,
	PNM Plan	2013			2012			2011
	Discount rate for determining December 31 APBO	5.21	%		4.26	%		5.7	%
	Discount rate for determining net periodic benefit cost	4.26	%		5.7	%		5.59	%
	Expected return on plan assets	8.5	%		8.5	%		8.5	%
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 APBO	5.21	%		4.26	%		5.7	%
	Discount rate for determining net periodic benefit cost	4.26	%		5.7	%		5.59	%
	Expected return on plan assets	6.5	%		6.5	%		6.3	%
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments [Table Text Block]	'
	The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:
		PNM				TNMP
		Plan				Plan
		(In thousands)
	2014	$	6,586			$	787
	2015	6,720				795
	2016	6,943				815
	2017	7,080				833
	2018	7,306				852
	2019 - 2023	36,569				4,558
Schedule of Health Care Cost Trend Rates [Table Text Block]	'
	The following table shows the assumed health care cost trend rates:
		PNM Plan
		December 31,
		2013			2012
	Health care cost trend rate assumed for next year	7.5	%		7	%
	Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5	%		5	%
	Year that the rate reaches the ultimate trend rate	2019			2017
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	'
	The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:
		PNM Plan
		1-Percentage-				1-Percentage-
		Point  Increase				Point  Decrease
		(In thousands)
	Effect on total of service and interest cost	$	322			$	(274	)
	Effect on APBO	$	5,859			$	(4,826	)
Executive Retirement Program [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	'
	The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2013.
		December 31, 2013
		PNM Plan				TNMP Plan
		(In thousands)
	Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,069			$	—
	Experience loss (gain)	(330		)		(22		)
	Regulatory asset (liability) adjustment	192				22
	Amortization recognized in net periodic benefit cost (income)	(98		)		—
	Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	1,833			$	—
	Amortization expected to be recognized in 2014	$	88			$	—
Schedule of Net Benefit Costs [Table Text Block]	'
	The following table presents the components of net periodic benefit:
		Year Ended December 31,
		2013				2012				2011
		(In thousands)
	PNM Plan
	Service cost	$	—			$	—			$	—
	Interest cost	720				876				930
	Amortization of net (gain) loss	232				83				93
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost	$	952			$	959			$	1,023
	TNMP Plan
	Service cost	$	—			$	—			$	—
	Interest cost	36				45				46
	Amortization of net (gain) loss	—				—				—
	Amortization of prior service cost	—				—				—
	Net periodic benefit cost	$	36			$	45			$	46
Schedule of Assumptions Used [Table Text Block]	'
	The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.
		Year Ended December 31,
	PNM Plan	2013			2012			2011
	Discount rate for determining December 31 PBO	5.27	%		4.3	%		5.67	%
	Discount rate for determining net periodic benefit cost	4.3	%		5.67	%		5.72	%
	Long-term rate of return on plan assets	N/A			N/A			N/A
	Rate of compensation increase	N/A			N/A			N/A
	TNMP Plan
	Discount rate for determining December 31 PBO	5.06	%		4.19	%		5.69	%
	Discount rate for determining net periodic benefit cost	4.19	%		5.69	%		5.5	%
	Long-term rate of return on plan assets	N/A			N/A			N/A
	Rate of compensation increase	N/A			N/A			N/A
Schedule of Expected Benefit Payments [Table Text Block]	'
	The following executive retirement plan payments, which reflect expected future service, are expected:
		PNM				TNMP
		Plan				Plan
		(In thousands)
	2014	$	1,535			$	93
	2015	1,516				92
	2016	1,494				90
	2017	1,468				88
	2018	1,438				85
	2019 – 2023	6,580				365
Schedule of Net Funded Status [Table Text Block]	'
	For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:
		PNM Plan								TNMP Plan
		Year Ended								Year Ended
		December 31,								December 31,
		2013				2012				2013			2012
		(In thousands)
	PBO at beginning of year	$	17,467			$	16,191			$	902		$	844
	Service cost	—				—				—			—
	Interest cost	720				876				36			45
	Actuarial (gain) loss	(330		)		1,895				(21		)	107
	Benefits paid	(1,494		)		(1,495		)		(94		)	(94		)
	PBO at end of year – funded status	16,363				17,467				823			902
	Less current liability	1,536				1,452				94			90
	Non-current liability	$	14,827			$	16,015			$	729		$	812

StockBased_Compensation_Plans_

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	'
	The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares:
		Stock Options							Restricted Stock
		Shares			Weighted				Shares			Weighted-Average Grant Date Fair Value
					Average
					Exercise
					Price
	Outstanding at December 31, 2012	1,992,700			$	20.72			353,722			$	14.03
	Granted	—			$	—			249,113			$	20.03
	Exercised	(319,239	)		$	14.47			(275,988	)		$	15.92
	Forfeited	—			$	—			(11,542	)		$	18.39
	Expired	(329,795	)		$	27.17			—			—
	Outstanding at December 31, 2013	1,343,666			$	20.63			315,305			17.87
	The following table provides additional information concerning stock options, and restricted stock activity including performance-based and market-based shares:
			Year Ended December 31,
	Stock Options		2013				2012				2011
	Weighted-average grant date fair value of options granted		$	—			$	—			$	—
	Total fair value of options that vested (in thousands)		$	625			$	1,054			$	1,189
	Total intrinsic value of options exercised (in thousands)		$	2,721			$	6,356			$	2,616
	Restricted Stock
	Weighted-average grant date fair value		$	20.03			$	16.75			$	13.79
	Total fair value of restricted shares that vested (in thousands)		$	4,395			$	5,099			$	1,240
	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:
			Year Ended December 31,
	Restricted Shares and Performance-Based Shares		2013				2012				2011
	Expected quarterly dividends per share		$	0.165			$	0.145			$	0.125
	Risk-free interest rate		0.34		%		1.22		%		1.35		%
	Market-Based Shares
	Dividend yield		2.86		%		3.45		%		N/A
	Expected volatility		25.11		%		43.98		%		N/A
	Risk-free interest rate		0.36		%		1.04		%		N/A

Construction_Program_and_Joint1

Construction Program and Jointly-Owned Electric Generating Plants Schedule of Jointly Owned Utility Plants (Tables)	12 Months Ended
	Dec. 31, 2013
Construction Program and Jointly-Owned Electric Generating Plants [Abstract]	'
Schedule of Jointly Owned Utility Plants [Table Text Block]	'
	At December 31, 2013, PNM’s interests and investments in jointly-owned generating facilities are:
	Station (Fuel Type)	Plant in		Accumulated			Construction		Composite
		Service		Depreciation			Work in		Interest
							Progress
		(In thousands)
	SJGS (Coal)	$	1,004,138	$	(414,054	)	$	13,860	46.3	%
	PVNGS (Nuclear) (1)	$	508,426	$	(141,347	)	$	43,627	10.2	%
	Four Corners Units 4 and 5 (Coal)	$	159,016	$	(100,462	)	$	3,236	13	%
	Luna (Gas)	$	62,873	$	(17,743	)	$	169	33.33	%
	(1)	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.
Summary of budgeted construction expenditures [Table Text Block]	'
	An unaudited summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, and nuclear fuel, is as follows:
		2014		2015			2016		2017		2018		Total
							(In millions)
	PNM	$	360.8	$	433.7		$	387.3	$	335.4	$	181.7	$	1,698.90
	TNMP	129.9		76			87.8		93.9		106.4		494
	Corporate and Other	18.3		14.3			14.2		13.8		13.7		74.3
	Total PNMR	$	509	$	524		$	489.3	$	443.1	$	301.8	$	2,267.20

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Asset Retirement Obligations [Table Text Block]	'
	A reconciliation of the ARO liability is as follows:
		PNMR			PNM			TNMP
		(In thousands)
	Liability at December 31, 2010	$	76,637		$	75,888		$	648
	Liabilities incurred	60			60			—
	Liabilities settled	(4		)	—			(4		)
	Accretion expense	6,114			6,051			55
	Revisions to estimated cash flows (1)	(3,574		)	(3,574		)	—
	Liability at December 31, 2011	79,233			78,425			699
	Liabilities incurred	—			—			—
	Liabilities settled	(25		)	—			(25		)
	Accretion expense	6,685			6,617			58
	Liability at December 31, 2012	85,893			85,042			732
	Liabilities incurred	—			—			—
	Liabilities settled	(79		)	(67		)	(12		)
	Accretion expense	7,245			7,174			62
	Revisions to estimated cash flows(1)	3,076			3,076			—
	Liability at December 31, 2013	$	96,135		$	95,225		$	782
	(1)	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2011 and 2013, new decommissioning studies for PVNGS were implemented reflecting updated cash flow estimates, including the extended operating licenses. The new studies resulted in a $4.2 million decrease to the ARO in 2011 and an increase of $0.5 million to the ARO in 2013. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions [Table Text Block]	'
	The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:
		Year Ended December 31,
		2013		2012		2011
				(In thousands)
	Electricity, transmission and distribution related services billings:
	TNMP to PNMR	$	—	$	—	$	33,813
	Services billings:
	PNMR to PNM	92,597		99,986		98,914
	PNMR to TNMP	28,937		29,110		29,353
	PNM to TNMP	562		595		550
	TNMP to PNMR	7		15		164
	PNMR to Optim Energy	—		—		4,083
	Optim Energy to PNMR	—		—		23
	Income tax sharing payments:
	PNMR to TNMP	—		1,951		—
	PNMR to PNM	77,433		63,114		—
	TNMP to PNMR	3,643		—		—
	Interest payments:
	PNM to PNMR	4		1		54
	TNMP to PNMR	481		137		40

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNMR
	Balance at December 31, 2010	$	16,211		$	(83,254	)	$	(1,623	)	$	(68,666	)
	Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,292			3,448			(27,511		)
	Income tax impact of amounts reclassified	13,956			(1,699		)	(1,230		)	11,027
	Other OCI changes (pre-tax)	34,295			(2,958		)	(1,002		)	30,335
	Income tax impact of other OCI changes	(13,577		)	1,187			349			(12,041		)
	Net change after income taxes	(577		)	822			1,565			1,810
	Balance at December 31, 2011	15,634			(82,432		)	(58		)	(66,856		)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			182			(32,476		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	(65		)	12,865
	Other OCI changes (pre-tax)	38,548			(30,084		)	(428		)	8,036
	Income tax impact of other OCI changes	(15,262		)	11,910			153			(3,199		)
	Net change after income taxes	772			(15,388		)	(158		)	(14,774		)
	Balance at December 31, 2012	16,406			(97,820		)	(216		)	(81,630		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			207			(5,385		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	(73		)	2,137
	Other OCI changes (pre-tax)	27,419			17,136			(279		)	44,276
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	98			(17,538		)
	Net change after income taxes	9,342			14,195			(47		)	23,490
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	PNM
	Balance at December 31, 2010	$	16,211		$	(82,981	)	$	(16	)	$	(66,786	)
	Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,278			27			(30,946		)
	Income tax impact of amounts reclassified	13,956			(1,694		)	(11		)	12,251
	Other OCI changes (pre-tax)	34,295			(3,369		)	—			30,926
	Income tax impact of other OCI changes	(13,577		)	1,334			—			(12,243		)
	Net change after income taxes	(577		)	549			16			(12		)
	Balance at December 31, 2011	15,634			(82,432		)	—			(66,798		)
	Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			—			(32,658		)
	Income tax impact of amounts reclassified	14,755			(1,825		)	—			12,930
	Other OCI changes (pre-tax)	38,548			(30,084		)	—			8,464
	Income tax impact of other OCI changes	(15,262		)	11,910			—			(3,352		)
	Net change after income taxes	772			(15,388		)	—			(14,616		)
	Balance at December 31, 2012	16,406			(97,820		)	—			(81,414		)
	Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			—			(5,592		)
	Income tax impact of amounts reclassified	4,734			(2,524		)	—			2,210
	Other OCI changes (pre-tax)	27,419			17,136			—			44,555
	Income tax impact of other OCI changes	(10,855		)	(6,781		)	—			(17,636		)
	Net change after income taxes	9,342			14,195			—			23,537
	Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—		$	(57,877	)
		Accumulated Other Comprehensive Income (Loss)
		Unrealized Gain on Available-for-Sale Securities			Pension			Fair Value Adjustment for Cash Flow Hedges			Total
					Liability
					Adjustment
					(In thousands)
	TNMP
	Balance at December 31, 2010	$	—		$	(275	)	$	(1,210	)	$	(1,485	)
	Amounts reclassified from AOCI (pre-tax)	—			13			2,997			3,010
	Income tax impact of amounts reclassified	—			(5		)	(1,068		)	(1,073		)
	Other OCI changes (pre-tax)	—			414			(1,207		)	(793		)
	Income tax impact of other OCI changes	—			(147		)	430			283
	Net change after income taxes	—			275			1,152			1,427
Balance at December 31, 2011	—			—			(58		)	(58		)
Amounts reclassified from AOCI (pre-tax)	—			—			182			182
Income tax impact of amounts reclassified	—			—			(65		)	(65		)
Other OCI changes (pre-tax)	—			—			(428		)	(428		)
Income tax impact of other OCI changes	—			—			153			153
Net change after income taxes	—			—			(158		)	(158		)
Balance at December 31, 2012	—			—			(216		)	(216		)
Amounts reclassified from AOCI (pre-tax)	—			—			207			207
Income tax impact of amounts reclassified	—			—			(73		)	(73		)
Other OCI changes (pre-tax)	—			—			(279		)	(279		)
Income tax impact of other OCI changes	—			—			98			98
Net change after income taxes	—			—			(47		)	(47		)
Balance at December 31, 2013	$	—		$	—		$	(263	)	$	(263	)

Quarterly_Operating_Results_Un1

Quarterly Operating Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Schedule of Quarterly Financial Information [Table Text Block]	'
	Unaudited operating results by quarters for 2013 and 2012 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included.
		Quarter Ended
		March 31		June 30		September 30		December 31
		(In thousands, except per share amounts)
	PNMR
	2013
	Operating revenues	$	317,665	$	347,599	$	399,730	$	322,929
	Operating income	50,704		77,867		117,739		40,532
	Net earnings	13,962		31,383		58,814		11,397
	Net earnings attributable to PNMR	10,626		27,678		54,555		7,648
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.13		0.35		0.68		0.1
	Diluted	0.13		0.34		0.68		0.1
	2012
	Operating revenues	$	305,374	$	323,860	$	390,411	$	322,758
	Operating income	53,729		65,106		118,150		36,736
	Net earnings	20,477		25,099		61,976		12,573
	Net earnings attributable to PNMR	17,080		21,512		57,864		9,091
	Net Earnings Attributable to PNMR per Common Share:
	Basic	0.21		0.27		0.73		0.11
	Diluted	0.21		0.27		0.72		0.11
	PNM
	2013
	Operating revenues	$	257,894	$	279,690	$	326,026	$	252,702
	Operating income	37,239		58,302		95,217		18,427
	Net earnings	14,773		29,697		51,950		6,256
	Net earnings attributable to PNM	11,569		26,124		47,823		2,639
	2012
	Operating revenues	$	250,416	$	260,094	$	321,731	$	260,023
	Operating income	42,105		46,669		96,973		20,135
	Net earnings	21,077		20,340		54,891		9,293
	Net earnings attributable to PNM	17,812		16,885		50,911		5,943
	TNMP
	2013
	Operating revenues	$	59,771	$	67,909	$	73,704	$	70,227
	Operating income	13,054		19,667		22,254		17,210
	Net earnings	3,726		8,339		10,106		6,919
	2012
	Operating revenues	$	54,958	$	63,766	$	68,680	$	62,736
	Operating income	11,791		18,897		20,970		15,862
	Net earnings	3,011		8,018		9,084		6,634

Schedule_I_Condensed_Financial1

Schedule I - Condensed Financial Information of Parent Company (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Income Statement [Table Text Block]	'
		Year ended December 31,
		2013			2012			2011
		(In thousands)
	Operating Revenues	$	—		$	—		$	—
	Operating Expenses	941			3,287			20,547
	Operating income (loss)	(941		)	(3,287		)	(20,547		)
	Other Income and Deductions:
	Equity in earnings of subsidiaries	116,634			117,900			205,215
	Other income	769			670			59
	Other deductions	(22,825		)	(20,904		)	(34,124		)
	Net other income (deductions)	94,578			97,666			171,150
	Earnings Before Income Taxes	93,637			94,379			150,603
	Income Tax Expense (Benefit)	(6,870		)	(11,168		)	(25,756		)
	Net Earnings	$	100,507		$	105,547		$	176,359
Condensed Cash Flow Statement [Table Text Block]	'
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Cash Flows From Operating Activities:
	Net earnings	$	100,507		$	105,547		$	176,359
	Adjustments to reconcile net earnings to net cash flows from operating activities:
	Depreciation and amortization	4,192			5,000			7,654
	Deferred income tax expense	(51,820		)	(46,632		)	(34,396		)
	Equity in (earnings) of subsidiaries	(116,634		)	(117,900		)	(205,215		)
	Loss on reacquired debt	3,253			—			9,209
	Stock based compensation expense	5,320			3,585			6,556
	Changes in certain assets and liabilities:
	Other current assets	28,460			(43,638		)	42,687
	Other assets	46,558			34,096			59,975
	Accounts payable	620			8			(1		)
	Accrued interest and taxes	(9,266		)	(28,855		)	27,348
	Other current liabilities	(146		)	3,876			4,765
	Other liabilities	(27,756		)	(29,601		)	(12,854		)
	Net cash flows from operating activities	(16,712		)	(114,514		)	82,087
	Cash Flows From Investing Activities:
	Utility plant additions	(960		)	(7,524		)	—
	Investments in subsidiaries	(13,800		)	—			(43,000		)
	Cash dividends from subsidiaries	158,772			61,406			285,757
	Net cash flows from investing activities	144,012			53,882			242,757
	Cash Flows From Financing Activities:
	Short-term borrowings (repayments), net	(37,600		)	120,900			(15,300		)
	Short-term borrowings (repayments) – affiliate, net	—			—			300
	Repayment of long-term debt	(29,468		)	(2,387		)	(60,391		)
	Purchase of preferred stock	—			—			(73,475		)
	Purchase of common stock	—			—			(125,683		)
	Proceeds from stock option exercise	4,618			11,684			5,622
	Purchases to satisfy awards of common stock	(13,807		)	(25,168		)	(10,104		)
	Dividends paid	(50,980		)	(44,609		)	(45,128		)
	Other, net	—			—			(747		)
	Net cash flows from financing activities	(127,237		)	60,420			(324,906		)
	Change in Cash and Cash Equivalents	63			(212		)	(62		)
	Cash and Cash Equivalents at Beginning of Period	29			241			303
	Cash and Cash Equivalents at End of Period	$	92		$	29		$	241
	Supplemental Cash Flow Disclosures:
	Interest paid	$	14,510		$	15,007		$	19,215
	Income taxes paid (refunded), net	$	22,378		$	1,501		$	5,454
Condensed Balance Sheet [Table Text Block]	'
		December 31,
		2013			2012
		(In thousands)
	Assets
	Cash and cash equivalents	$	92		$	29
	Intercompany receivables	136,387			108,875
	Income taxes receivable	14,989			41,434
	Other, net	8,544			2,204
	Total current assets	160,012			152,542
	Property, plant and equipment, net of accumulated depreciation of $9,167 and $8,262	26,601			25,642
	Long-term investments	—			3,651
	Investment in subsidiaries	1,683,321			1,688,168
	Other long-term assets	53,892			49,302
	Total long-term assets	1,763,814			1,766,763
		$	1,923,826		$	1,919,305
	Liabilities and Stockholders’ Equity
	Short-term debt	$	100,000		$	137,600
	Short-term debt-affiliate	8,819			8,819
	Current maturities of long-term debt	—			2,530
	Accrued interest and taxes	2,797			3,127
	Other current liabilities	16,876			13,218
	Total current liabilities	128,492			165,294
	Long-term debt	118,766			142,592
	Other long-term liabilities	2,999			3,232
	Total liabilities	250,257			311,118
	Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369			1,182,819
	Accumulated other comprehensive income (loss), net of tax	(58,140		)	(81,630		)
	Retained earnings	553,340			506,998
	Total common stockholders’ equity	1,673,569			1,608,187
		$	1,923,826		$	1,919,305
	See Notes 6, 7, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

Summary_of_the_Business_and_Si3

Summary of the Business and Significant Accounting Policies (Details) (USD $)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 04, 2012

Dec. 31, 2012

Sep. 23, 2011

Sep. 22, 2011

Dec. 31, 2013

Dec. 31, 1986

Dec. 31, 2004

Dec. 31, 2003

Dec. 31, 1985

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

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]

Optim Energy [Member]

Optim Energy [Member]

Optim Energy [Member]

Optim Energy [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

EIP Transmission Line [Member]

EIP Transmission Line [Member]

EIP Transmission Line [Member]

10.3% Lessor Notes [Member]

10.15% Lessor Notes [Member]

10.25% EIP Lessor Note Maturing in 2012 [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

EIP Transmission Line [Member]

Operating_Leases

Operating_Leases

Operating_Leases

Public Service Company of New Mexico [Member]

Accounting Policies Disclosures [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New Accounting Pronouncements Not Yet Adopted, Effect on Deferred Tax Asset

$19,900,000

'

'

$11,100,000

'

'

$6,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity method investment,ownership percentage (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

Allowance for funds used during construction, capitalized interest

'

'

'

3,300,000

3,500,000

1,500,000

400,000

700,000

600,000

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity

'

'

'

4,400,000

3,800,000

0

0

600,000

600,000

'

'

'

'

'

'

'

'

'

'

'

'

Debt, weighted average interest rate (as a percent)

6.90%

6.60%

6.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest costs incurred, capitalized

1,500,000

1,200,000

500,000

1,100,000

800,000

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of operating leases (in ones)

'

'

'

'

'

'

'

'

'

'

'

'

'

8

11

'

'

2

'

'

'

Notes receivable, stated percentage rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.30%

10.15%

10.25%

Ownership percentage acquired (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40.00%

60.00%

'

'

'

'

Other investments

1,835,000

5,599,000

'

445,000

494,000

'

245,000

281,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment losses on securities held in the NDT

'

'

'

3,500,000

4,800,000

12,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost method investment, ownership percentage (as a percent)

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

Ownership percentage, sold (as a percent)

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

Cost Method Investments

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investments

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

'

'

'

'

'

'

Summary_of_the_Business_and_Si4

Summary of the Business and Significant Accounting Policies (Inventories/Depreciation and Amortization) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	67,223	59,643	'
Coal [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	24,872	19,231	'
Materials and supplies [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	42,351	40,412	'
Public Service Company of New Mexico [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	64,520	56,790	'
Public Service Company of New Mexico [Member] | Coal [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	24,872	19,231	'
Public Service Company of New Mexico [Member] | Materials and supplies [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	39,648	37,559	'
Public Service Company of New Mexico [Member] | Electric plant [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Depreciation average rates used (as a percent)	2.27%	2.25%	2.24%
Public Service Company of New Mexico [Member] | Common, intangible, and general plant [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Depreciation average rates used (as a percent)	4.87%	5.35%	6.03%
Texas-New Mexico Power Company [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	2,703	2,853	'
Depreciation average rates used (as a percent)	3.66%	3.56%	3.41%
Texas-New Mexico Power Company [Member] | Coal [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	0	0	'
Texas-New Mexico Power Company [Member] | Materials and supplies [Member]	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Inventory, Net	2,703	2,853	'

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information, Profit (Loss) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	$1,700,619
Revenue from Related Parties	'	'	'	'	'	'	'	'	'	'	0
Electric Operating Revenues	322,929	399,730	347,599	317,665	322,758	390,411	323,860	305,374	1,387,923	1,342,403	1,700,619
Cost of energy	'	'	'	'	'	'	'	'	432,316	399,850	692,922
Gross margin	'	'	'	'	'	'	'	'	955,607	942,553	1,007,697
Other operating expenses	'	'	'	'	'	'	'	'	501,884	504,659	593,351
Depreciation and amortization	'	'	'	'	'	'	'	'	166,881	164,173	157,047
Operating income	40,532	117,739	77,867	50,704	36,736	118,150	65,106	53,729	286,842	273,721	257,299
Interest income	'	'	'	'	'	'	'	'	10,043	13,072	15,515
Gain on sale of First Choice	'	'	'	'	'	'	'	'	0	1,012	174,925
Other income (deductions)	'	'	'	'	'	'	'	'	-368	8,075	-10,421
Net interest charges	'	'	'	'	'	'	'	'	-121,448	-120,845	-124,849
Earnings before Income Taxes	'	'	'	'	'	'	'	'	175,069	175,035	312,469
Income Taxes	'	'	'	'	'	'	'	'	59,513	54,910	121,535
Net earnings	11,397	58,814	31,383	13,962	12,573	61,976	25,099	20,477	115,556	120,125	190,934
Earnings (loss) from continuing operations	'	'	'	'	'	'	'	'	'	'	190,934
Valencia non-controlling interest	'	'	'	'	'	'	'	'	-14,521	-14,050	-14,047
Preferred Stock Dividend Requirements of Subsidiary	'	'	'	'	'	'	'	'	-528	-528	-528
Segment earnings (loss) from continuing operations attributable to PNMR (excluding discontinued operations amounts related to sale of PNM Gas)	'	'	'	'	'	'	'	'	'	'	176,359
Earnings Attributable to PNMR	7,648	54,555	27,678	10,626	9,091	57,864	21,512	17,080	100,507	105,547	176,359
Gross property additions	'	'	'	'	'	'	'	'	348,039	308,909	326,931
Gross property additions	'	'	'	'	'	'	'	'	'	'	326,931
Total Assets	5,500,210	'	'	'	5,372,583	'	'	'	5,500,210	5,372,583	5,204,613
Goodwill	278,297	'	'	'	278,297	'	'	'	278,297	278,297	278,297
PNM [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	1,057,289
Revenue from Related Parties	'	'	'	'	'	'	'	'	'	'	0
Electric Operating Revenues	'	'	'	'	'	'	'	'	1,116,312	1,092,264	1,057,289
Cost of energy	'	'	'	'	'	'	'	'	374,710	353,649	362,237
Gross margin	'	'	'	'	'	'	'	'	741,602	738,615	695,052
Other operating expenses	'	'	'	'	'	'	'	'	428,591	435,442	438,822
Depreciation and amortization	'	'	'	'	'	'	'	'	103,826	97,291	94,787
Operating income	'	'	'	'	'	'	'	'	209,185	205,882	161,443
Interest income	'	'	'	'	'	'	'	'	10,182	13,243	15,562
Gain on sale of First Choice	'	'	'	'	'	'	'	'	'	0	0
Other income (deductions)	'	'	'	'	'	'	'	'	11,288	13,290	4,309
Net interest charges	'	'	'	'	'	'	'	'	-79,175	-76,101	-75,349
Earnings before Income Taxes	'	'	'	'	'	'	'	'	151,480	156,314	105,965
Income Taxes	'	'	'	'	'	'	'	'	48,804	50,713	37,427
Net earnings	'	'	'	'	'	'	'	'	102,676	105,601	'
Earnings (loss) from continuing operations	'	'	'	'	'	'	'	'	'	'	68,538
Valencia non-controlling interest	'	'	'	'	'	'	'	'	-14,521	-14,050	-14,047
Preferred Stock Dividend Requirements of Subsidiary	'	'	'	'	'	'	'	'	-528	-528	-528
Segment earnings (loss) from continuing operations attributable to PNMR (excluding discontinued operations amounts related to sale of PNM Gas)	'	'	'	'	'	'	'	'	'	'	53,963
Earnings Attributable to PNMR	'	'	'	'	'	'	'	'	87,627	91,023	'
Gross property additions	'	'	'	'	'	'	'	'	239,906	196,800	'
Gross property additions	'	'	'	'	'	'	'	'	'	'	251,345
Total Assets	4,227,616	'	'	'	4,163,907	'	'	'	4,227,616	4,163,907	4,095,287
Goodwill	51,632	'	'	'	51,632	'	'	'	51,632	51,632	51,632
TNMP [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	204,045
Revenue from Related Parties	'	'	'	'	'	'	'	'	'	'	33,813
Electric Operating Revenues	'	'	'	'	'	'	'	'	271,611	250,140	237,858
Cost of energy	'	'	'	'	'	'	'	'	57,606	46,201	41,166
Gross margin	'	'	'	'	'	'	'	'	214,005	203,939	196,692
Other operating expenses	'	'	'	'	'	'	'	'	91,601	87,079	88,234
Depreciation and amortization	'	'	'	'	'	'	'	'	50,219	49,340	44,616
Operating income	'	'	'	'	'	'	'	'	72,185	67,520	63,842
Interest income	'	'	'	'	'	'	'	'	0	1	2
Gain on sale of First Choice	'	'	'	'	'	'	'	'	'	0	0
Other income (deductions)	'	'	'	'	'	'	'	'	1,919	2,739	1,580
Net interest charges	'	'	'	'	'	'	'	'	-27,393	-28,161	-29,286
Earnings before Income Taxes	'	'	'	'	'	'	'	'	46,711	42,099	36,138
Income Taxes	'	'	'	'	'	'	'	'	17,621	15,352	13,881
Valencia non-controlling interest	'	'	'	'	'	'	'	'	0	0	0
Preferred Stock Dividend Requirements of Subsidiary	'	'	'	'	'	'	'	'	0	0	0
Earnings Attributable to PNMR	'	'	'	'	'	'	'	'	29,090	26,747	22,257
Gross property additions	'	'	'	'	'	'	'	'	89,117	92,973	'
Gross property additions	'	'	'	'	'	'	'	'	'	'	67,407
Total Assets	1,162,431	'	'	'	1,086,229	'	'	'	1,162,431	1,086,229	1,037,445
Goodwill	226,665	'	'	'	226,665	'	'	'	226,665	226,665	226,665
First Choice [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	439,450
Revenue from Related Parties	'	'	'	'	'	'	'	'	'	'	0
Electric Operating Revenues	'	'	'	'	'	'	'	'	'	'	439,450
Cost of energy	'	'	'	'	'	'	'	'	'	'	323,331
Gross margin	'	'	'	'	'	'	'	'	'	'	116,119
Other operating expenses	'	'	'	'	'	'	'	'	'	'	75,966
Depreciation and amortization	'	'	'	'	'	'	'	'	'	'	1,098
Operating income	'	'	'	'	'	'	'	'	'	'	39,055
Interest income	'	'	'	'	'	'	'	'	'	'	64
Gain on sale of First Choice	'	'	'	'	'	'	'	'	'	'	0
Other income (deductions)	'	'	'	'	'	'	'	'	'	'	-650
Net interest charges	'	'	'	'	'	'	'	'	'	'	-581
Earnings before Income Taxes	'	'	'	'	'	'	'	'	'	'	37,888
Income Taxes	'	'	'	'	'	'	'	'	'	'	13,772
Valencia non-controlling interest	'	'	'	'	'	'	'	'	'	'	0
Preferred Stock Dividend Requirements of Subsidiary	'	'	'	'	'	'	'	'	'	'	0
Earnings Attributable to PNMR	'	'	'	'	'	'	'	'	'	'	24,116
Gross property additions	'	'	'	'	'	'	'	'	'	'	2,089
Total Assets	'	'	'	'	'	'	'	'	'	'	0
Goodwill	'	'	'	'	'	'	'	'	'	'	0
Significant Reconciling Items [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	-165
Revenue from Related Parties	'	'	'	'	'	'	'	'	'	'	-33,813
Electric Operating Revenues	'	'	'	'	'	'	'	'	0	-1	-33,978
Cost of energy	'	'	'	'	'	'	'	'	0	0	-33,812
Gross margin	'	'	'	'	'	'	'	'	0	-1	-166
Other operating expenses	'	'	'	'	'	'	'	'	-18,308	-17,862	-9,671
Depreciation and amortization	'	'	'	'	'	'	'	'	12,836	17,542	16,546
Operating income	'	'	'	'	'	'	'	'	5,472	319	-7,041
Interest income	'	'	'	'	'	'	'	'	-139	-172	-113
Gain on sale of First Choice	'	'	'	'	'	'	'	'	'	1,012	174,925
Other income (deductions)	'	'	'	'	'	'	'	'	-13,575	-7,954	-15,660
Net interest charges	'	'	'	'	'	'	'	'	-14,880	-16,583	-19,633
Earnings before Income Taxes	'	'	'	'	'	'	'	'	-23,122	-23,378	132,478
Income Taxes	'	'	'	'	'	'	'	'	-6,912	-11,155	56,455
Valencia non-controlling interest	'	'	'	'	'	'	'	'	0	0	0
Preferred Stock Dividend Requirements of Subsidiary	'	'	'	'	'	'	'	'	0	0	0
Earnings Attributable to PNMR	'	'	'	'	'	'	'	'	-16,210	-12,223	76,023
Gross property additions	'	'	'	'	'	'	'	'	19,016	19,136	'
Gross property additions	'	'	'	'	'	'	'	'	'	'	6,090
Total Assets	110,163	'	'	'	122,447	'	'	'	110,163	122,447	71,881
Goodwill	$0	'	'	'	$0	'	'	'	$0	$0	$0

Segment_Information_Narrative_

Segment Information (Narrative and Major Customers) (Details) (Sales [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
First Choice [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Operating revenues from continuing operations (as a percent)	17.00%	19.00%	17.00%
Unaffiliated Customer of Texas-New Mexico Power Company One [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Operating revenues from continuing operations (as a percent)	16.00%	17.00%	19.00%
Unaffiliated Customer of Texas-New Mexico Power Company Two [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Operating revenues from continuing operations (as a percent)	10.00%	10.00%	12.00%
PNMR and PNM [Member] | Maximum [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Operating revenues from continuing operations (as a percent)	10.00%	'	'

Sale_of_First_Choice_Details

Sale of First Choice (Details) (USD $)	12 Months Ended			0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 23, 2011	Dec. 31, 2013	Dec. 31, 2013
				First Choice [Member]	First Choice [Member]	First Choice [Member]
						Other Income [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'
Sale of Business Segment subject to adjustments of certain componets of working capital	'	'	'	$270,000,000	'	'
Sale of Business Segment, Amount received including estimate of components of working capital	'	'	'	329,300,000	'	'
Gain on sale of First Choice	0	1,012,000	174,925,000	'	174,900,000	1,000,000
Sale of Business Segment Working Capital That Parent Disputed, Portion of Disputed Total Awarded	'	'	'	'	6,400,000	'
Sale of Business Segment Working Capital That Parent Disputed, Disputed Amount	'	'	'	'	$8,200,000	'

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets	'	'
Regulatory Assets, Current	$24,416	$39,120
Regulatory Assets, Noncurrent	523,955	555,577
Regulatory Liabilities	'	'
Regulatory Liability, Current	-1,081	-15,173
Regulatory liabilities, Noncurrent	-460,649	-423,460
Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	19,394	36,490
Regulatory Assets, Noncurrent	384,217	431,956
Regulatory Assets	403,611	468,446
Regulatory Liabilities	'	'
Regulatory Liability, Current	-1,081	-15,172
Regulatory liabilities, Noncurrent	-414,611	-379,841
Regulatory Liabilities	-415,692	-395,013
Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	5,022	2,630
Regulatory Assets, Noncurrent	139,738	123,621
Regulatory Assets	144,760	126,251
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-46,038	-43,619
Deferred income taxes Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-80,495	-49,723
Deferred income taxes Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-4,563	-5,203
Advanced Metering Infrastructure Costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	7,251	6,386
Other [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory Liability, Current	-1,081	-15,172
Removal Costs [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-266,075	-257,396
Removal Costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-30,863	-31,115
Asset retirement obligations [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-37,567	-39,280
Renewable energy costs [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-26,011	-26,988
Other [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-4,463	-6,454
Other [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Liabilities	'	'
Regulatory liabilities, Noncurrent	-3,361	-915
Regulatory Assets, Transmission Cost Recovery | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	4,250	2,287
Regulatory Assets, Other Current [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	0	224
Stranded costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	63,606	71,240
Environmental Restoration Costs [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	40,144	46,065
Deferred income taxes Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	61,850	54,781
Deferred income taxes Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	10,868	11,179
Pension and Other Postretirement Plans Costs [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	206,691	254,351
Pension and Other Postretirement Plans Costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	19,938	28,307
Loss on reacquired debt [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	27,490	29,702
Loss on reacquired debt [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	38,616	1,711
Fuel and purchased power adjustment clause [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	49,100	'
Fuel and purchased power adjustment clause [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	19,394	36,266
Regulatory Assets, Noncurrent	25,386	18,619
Renewable energy costs [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	13,311	18,768
Hurricane recovery costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	0	4,572
Advanced Metering Infrastructure Costs [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	5,083	3,538
Other [Member] | Public Service Company of New Mexico [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Noncurrent	9,345	9,670
Other [Member] | Texas-New Mexico Power Company [Member]	'	'
Regulatory Assets	'	'
Regulatory Assets, Current	772	343
Regulatory Assets, Noncurrent	$1,627	$3,074

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Oct. 31, 2011

Sep. 23, 2011

Sep. 23, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Series A convertible preferred stock [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]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Affiliated Entity [Member]

Line of Credit [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]

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity contribution from parent

'

'

'

$0

$0

$43,000,000

$13,800,000

$0

$0

'

'

'

'

'

'

'

'

Cash dividends paid to parent company by consolidated subsidiaries

'

'

'

'

'

'

'

'

'

39,100,000

155,000,000

34,400,000

8,200,000

3,700,000

26,000,000

13,700,000

'

Ratio of debt to capital, maximum (as a percent)

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

Amount available for dividend distribution without prior approval from regulators or financial counterparties

'

'

'

$206,000,000

'

'

$199,000,000

'

'

'

'

'

'

'

'

'

'

Agreement to purchase all outstanding shares related to Series A convertible preferred stock (in shares)

'

'

477,800

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Convertible Preferred Stock, Shares Issued upon Conversion (in shares)

'

4,778,000

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, dividend rate (as a percent)

'

'

'

4.58%

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, redemption percent (as a percent)

'

'

'

102.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, cumulative shares authorized (in shares)

'

'

'

10,000,000

10,000,000

'

1,000,000

'

'

'

'

'

'

'

'

'

'

Financing_Details

Financing (Details) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

Nov. 22, 2011

Nov. 04, 2011

Oct. 05, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 24, 2011

Sep. 23, 2011

Dec. 31, 2013

Oct. 24, 2011

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2012

Dec. 31, 2013

Oct. 12, 2011

Oct. 06, 2011

Dec. 31, 2013

Mar. 06, 2013

Dec. 31, 2012

Apr. 03, 2013

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 14, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 22, 2013

Dec. 31, 2013

Apr. 03, 2013

Mar. 06, 2013

Dec. 31, 2012

Dec. 31, 2013

Apr. 03, 2013

Mar. 06, 2013

Dec. 31, 2012

Dec. 09, 2013

Feb. 21, 2014

Feb. 21, 2014

Feb. 21, 2014

Feb. 21, 2014

Unsecured Debt [Member]

Unsecured Debt [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]

Notes Payable to Banks [Member]

Notes Payable to Banks [Member]

Notes Payable to Banks [Member]

New Mexico Public Regulation Commission [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

PNMR Term Loan Agreement [Member]

PNMR Term Loan Agreement [Member]

PNMR Term Loan Agreement [Member]

PNMR Term Loan Agreement [Member]

2.54% Maturing of September First, 2042 with a Mandatory Tender on June First, 2017 [Member]

5.15% Percent Maturing in 2037 [Member]

PNM Term Loan Agreement [Member]

PNM Term Loan Agreement [Member]

PNM Term Loan Agreement [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds Due 2024, Series 2014A, at 4 point 03 percent [Member] [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

First Mortgage Bonds [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Public Service Company of New Mexico [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Notes Payable to Banks [Member]

Notes Payable to Banks [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Notes Payable to Banks [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

New Mexico Revolving Credit Facility [Member]

Extensions

Pollution Control Revenue Bonds [Member]

Pollution Control Revenue Bonds [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

Pollution Control Revenue Bonds [Member]

Public Service Company of New Mexico [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Remaining Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$291,400,000

$327,400,000

$74,700,000

$25,000,000

Preferred Stock, Shares Outstanding

'

'

'

'

'

'

'

477,800

'

'

115,293

115,293

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Convertible Preferred Stock, Shares Issued upon Conversion

'

'

'

'

'

'

'

4,778,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock Purchase Discount

'

'

'

'

'

'

'

0.02

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments for Repurchase of Convertible Preferred Stock

'

'

73,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Value, Outstanding

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unsecured Long-term Debt, Noncurrent

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

118,766,000

142,592,000

'

'

'

'

'

'

75,000,000

0

'

172,302,000

'

'

265,500,000

93,198,000

'

'

0

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

9.25%

9.25%

'

'

'

'

'

5.35%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.54%

5.15%

'

'

'

9.50%

9.50%

9.50%

9.50%

6.95%

6.95%

6.95%

6.95%

4.03%

'

'

'

'

Debt Instrument, Repurchase Premium

'

'

'

'

'

'

0.17

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

160,000,000

'

1,000

'

'

'

'

'

'

23,800,000

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

265,500,000

'

'

93,200,000

'

'

80,000,000

'

'

'

'

Repayments of Unsecured Debt

58,500,000

'

'

26,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on reacquired debt

'

'

'

3,253,000

0

9,209,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares outstanding

'

7,019,550

'

79,653,624

79,653,624

'

'

'

'

'

39,117,799

39,117,799

'

'

'

'

6,358

'

6,358

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock Repurchase Discount

'

0.02

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments for Repurchase of Common Stock

'

125,700,000

'

0

0

125,683,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term debt

'

'

'

149,200,000

158,700,000

'

'

'

'

'

49,200,000

21,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

100,000,000

'

100,000,000

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Short-term Debt

'

'

'

0

100,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Issuance, Face Amount Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.99857

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Requested Approval to Refinance Debt

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Number of Extension Options Received Authority To Exercise

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Extension Option Granted Authority To Exercise, Years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Refunded Amount Redeemed at Par and Retired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Lines of Credit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Shelf Registration Statement for Unsecured Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

440,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Bank Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Amount Secured by Collateral

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.48%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.99%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Effective Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.57%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Flow Hedge Derivative Instrument Liabilities at Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000

300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Cash Offered for Debt Exchanged

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

140

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Cash Paid for Debt Exchanged

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Premium

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$23,200,000

'

'

'

'

'

'

'

Financing_Shortterm_Debt_Detai

Financing Short-term Debt (Details) (USD $)

0 Months Ended

12 Months Ended

Oct. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2009

Dec. 31, 2013

Dec. 31, 2012

Oct. 31, 2011

Dec. 31, 2013

Jan. 08, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Feb. 22, 2013

Feb. 21, 2014

Feb. 21, 2014

Feb. 21, 2014

Feb. 21, 2014

Feb. 21, 2014

Extensions

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Maximum [Member]

New Mexico Revolving Credit Facility [Member]

PNMR Term Loan Agreement [Member]

PNMR Term Loan Agreement [Member]

Revolving Credit Facility [Member]

PNM Term Loan Agreement [Member]

Borrowings from PNMR [Member]

Available Borrowing Capacity [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [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]

Public Service Company of New Mexico [Member]

New Mexico Revolving Credit Facility [Member]

Public Service Company of New Mexico [Member]

Short-term Debt [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notes Payable, Related Parties, Current

'

'

'

$29,400,000

$28,300,000

'

$32,500,000

$0

'

$100,000,000

'

'

'

'

'

$35,800,000

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

300,000,000

'

'

'

'

75,000,000

'

'

400,000,000

'

50,000,000

'

'

'

'

'

'

'

'

'

'

Securities Received as Collateral

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Number of Extension Options

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Extension Option, Years

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ratio of debt to capital, maximum (as a percent)

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term Debt, Weighted Average Interest Rate

'

'

'

'

'

'

'

'

'

'

'

1.02%

'

1.42%

1.42%

'

'

'

'

'

'

Line of Credit Facility, Amount Outstanding

'

0

37,600,000

0

0

'

49,200,000

21,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term debt

'

149,200,000

158,700,000

'

'

'

49,200,000

21,100,000

'

'

'

100,000,000

100,000,000

'

'

'

'

'

'

'

'

Letters of Credit Outstanding, Amount

'

8,600,000

'

300,000

'

'

3,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Remaining Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

718,500,000

291,400,000

74,700,000

327,400,000

25,000,000

Invested Cash and Cash Equivalents

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,900,000

'

'

'

Financing_Schedule_of_Longterm

Financing Schedule of Long-term Debt (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Oct. 24, 2011

Dec. 31, 2013

Oct. 24, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Oct. 06, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Apr. 03, 2013

Mar. 06, 2013

Dec. 31, 2012

Dec. 31, 2013

Apr. 03, 2013

Mar. 06, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

In Thousands, unless otherwise specified

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Other [Member]

Other [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Senior Unsecured Notes, Pollution Control Revenue Bonds [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Other [Member]

Other [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

First Mortgage Bonds [Member]

Other [Member]

Other [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

4.875% due 2033 [Member]

4.875% due 2033 [Member]

6.25% due 2038 [Member]

6.25% due 2038 [Member]

4.75% due 2040, mandatory tender at June 1, 2017 [Member]

4.75% due 2040, mandatory tender at June 1, 2017 [Member]

5.20% due 2040, mandatory tender at June 1, 2020 [Member]

5.20% due 2040, mandatory tender at June 1, 2020 [Member]

5.90% due 2040 [Member]

5.90% due 2040 [Member]

6.25% due 2040 [Member]

6.25% due 2040 [Member]

2.54% due 2042, mandatory tender at June 1, 2017 [Member]

2.54% due 2042, mandatory tender at June 1, 2017 [Member]

4.00% due 2043, mandatory tender at June 1, 2015 [Member]

4.00% due 2043, mandatory tender at June 1, 2015 [Member]

5.20% due 2043, mandatory tender at June 1, 2020 [Member]

5.20% due 2043, mandatory tender at June 1, 2020 [Member]

7.95% due 2018 [Member]

7.95% due 2018 [Member]

7.50% due 2018 [Member]

7.50% due 2018 [Member]

5.35% due 2021 [Member]

5.35% due 2021 [Member]

PNM Term Loan Agreement [Member]

PNM Term Loan Agreement [Member]

2011 Term Loan Agreement, due 2014 [Member]

2011 Term Loan Agreement, due 2014 [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds Due 2014, Series 2009A, at 9 point 50 percent [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

First Mortgage Bonds 6 Point 95 Percent, due 2043, Series 2013A [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Senior unsecured notes, 9.25% due 2015 [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

9.25%

9.25%

'

'

'

'

'

'

4.88%

4.88%

6.25%

6.25%

4.75%

4.75%

5.20%

5.20%

5.90%

5.90%

6.25%

6.25%

2.54%

2.54%

4.00%

4.00%

5.20%

5.20%

5.35%

7.95%

7.95%

7.50%

7.50%

5.35%

5.35%

'

'

'

'

'

'

'

'

9.50%

9.50%

9.50%

9.50%

6.95%

6.95%

6.95%

6.95%

'

'

'

'

9.25%

9.25%

Unsecured Long-term Debt, Noncurrent

'

'

$50,000

'

'

$118,766

$142,592

$0

$2,530

'

'

$146,000

$146,000

$36,000

$36,000

$37,000

$37,000

$40,045

$40,045

$255,000

$255,000

$11,500

$11,500

$20,000

$20,000

$39,300

$39,300

$21,000

$21,000

'

$350,000

$350,000

$100,025

$100,025

$160,000

$160,000

$75,000

$0

'

'

'

'

$50,000

$50,000

$172,302

'

'

$265,500

$93,198

'

'

$0

'

'

'

'

'

'

Unamortized premiums (discounts)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-252

-291

'

'

'

'

'

'

'

'

'

'

'

'

20,536

-3,911

'

'

'

'

Long-term Debt

1,745,420

1,672,290

'

'

'

'

'

'

'

1,290,618

1,215,579

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

336,036

311,589

'

'

'

'

'

'

'

'

'

'

'

'

118,766

145,122

'

'

Less current maturities

75,000

2,530

'

'

'

'

'

'

'

75,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

0

2,530

'

'

Long-term Debt, Excluding Current Maturities

$1,670,420

$1,669,760

'

'

'

'

'

'

'

$1,215,618

$1,215,579

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$336,036

$311,589

'

'

'

'

'

'

'

'

'

'

'

'

$118,766

$142,592

'

'

Financing_Schedule_of_Longterm1

Financing Schedule of Long-term Debt Maturities (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Long-term Debt, by Maturity [Abstract]	'
2014	$75,000
2015	158,066
2016	0
2017	57,000
2018	450,025
Therafter	985,045
Total	1,725,136
PNMR [Member]	'
Long-term Debt, by Maturity [Abstract]	'
2014	0
2015	118,766
2016	0
2017	0
2018	0
Therafter	0
Total	118,766
Public Service Company of New Mexico [Member]	'
Long-term Debt, by Maturity [Abstract]	'
2014	75,000
2015	39,300
2016	0
2017	57,000
2018	450,025
Therafter	669,545
Total	1,290,870
Texas-New Mexico Power Company [Member]	'
Long-term Debt, by Maturity [Abstract]	'
2014	0
2015	0
2016	0
2017	0
2018	0
Therafter	315,500
Total	$315,500

Lease_Commitments_Narratives_D

Lease Commitments Narratives (Details) (USD $)

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 15, 2016

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Corporate Headquarters [Member]

Administrative and General Expense [Member]

Administrative and General Expense [Member]

Administrative and General Expense [Member]

Approximate Annual Total for Operating Lease Payments [Member]

Approximate Annual Total for Operating Lease Payments [Member]

Approximate Annual Total for Operating Lease Payments [Member]

TGP Granada, LLC and its affiliate Complaint [Member]

TGP Granada, LLC and its affiliate Complaint [Member]

Subsequent Event [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station, Unit 1 Leases [Member]

Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]

Navajo Nation [Member]

Delta [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Public Service Company of New Mexico [Member]

Tortoise Capital Resources Corporation [Member]

Public Service Company of New Mexico [Member]

Palo Verde Nuclear Generating Station, Unit 2 Leases [Member]

MW

Lease commitments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual lease payments

'

'

'

'

'

$33,000,000

$23,700,000

$6,000,000

$6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Lease, Extended Term

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Renewal Options After Original Lease Term

'6 years

'2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rental Payments, Fixed renewal option period during original terms of leases

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Lease, Extended Term, Notice Period to Retain Leased Assets

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Lease, Extended Term, Notice Period to Purchase or Renewal Options

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual Lease Payments During Renewal Period

'

'

'

'

'

16,500,000

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Purchase Price of Leased Asset

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

78,100,000

Leased Capacity to be Purchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

Lease Covenant, Restriction on Conveying, Transferring, Leasing, & Dividends

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Range of Possible Loss, Portion Not Accrued

'

'

'

'

154,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Lease ownership percentage in EIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

40.00%

'

Operating Lease, Notice Period to Purchase Leased Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

Public Utilities, Option to Purchase Leased Capacity At Fair Value

'

7,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Rent Expense, Net

'

78,306,000

78,483,000

78,422,000

'

'

'

'

'

2,663,000

2,871,000

3,606,000

1,900,000

'

'

'

'

'

'

'

'

'

Abandonment expense

'

'

'

'

'

'

'

'

'

'

'

'

'

-7,400,000

-6,200,000

-1,200,000

'

'

'

'

'

'

Operating Leases Rent Expense Return on Lessor notes Rental Payments to be Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$9,000,000

$24,000,000

$25,400,000

'

'

'

Lease_Commitments_Schedule_of_

Lease Commitments Schedule of Rent Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
PNMR [Member]	'	'	'
Operating lease expense [Line Items]	'	'	'
Operating Leases, Rent Expense, Net	$82,882	$84,794	$86,323
Public Service Company of New Mexico [Member]	'	'	'
Operating lease expense [Line Items]	'	'	'
Operating Leases, Rent Expense, Net	78,306	78,483	78,422
Texas-New Mexico Power Company [Member]	'	'	'
Operating lease expense [Line Items]	'	'	'
Operating Leases, Rent Expense, Net	$2,663	$2,871	$3,606

Lease_Commitments_Schedule_of_1

Lease Commitments Schedule of Future Minimum Rental Payments for Operating Leases (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
PNMR [Member]	'
Lease commitments	'
2014	$53,594
2015	40,952
2016	33,788
2017	30,942
2018	30,948
Later years	167,225
Operating Leases, Future Minimum Payments Due	357,449
Future payments under non-cancelable subleases	93
Operating Leases, Future Minimum Payments Due, Net	357,356
Public Service Company of New Mexico [Member]	'
Lease commitments	'
2014	49,580
2015	38,290
2016	33,363
2017	30,749
2018	30,749
Later years	166,830
Operating Leases, Future Minimum Payments Due	349,561
Future payments under non-cancelable subleases	0
Operating Leases, Future Minimum Payments Due, Net	349,561
Texas-New Mexico Power Company [Member]	'
Lease commitments	'
2014	815
2015	676
2016	237
2017	0
2018	0
Later years	0
Operating Leases, Future Minimum Payments Due	1,728
Future payments under non-cancelable subleases	0
Operating Leases, Future Minimum Payments Due, Net	$1,728

Fair_Value_of_Derivative_and_O2

Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Commodity derivative instruments, Current assets	$4,064,000	$3,785,000
Commodity derivative instruments, Deferred charges	3,002,000	352,000
Commodity derivative instruments, Current liabilities	-2,699,000	-1,000,000
Commodity derivative instruments, Long-term liabilities	-1,094,000	-1,933,000
PNMR and PNM [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Margin Deposit Assets	2,800,000	1,900,000
Derivative, Collateral, Obligation to Return Cash	200,000	0
Public Service Company of New Mexico [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Commodity derivative instruments, Current assets	4,064,000	3,785,000
Commodity derivative instruments, Deferred charges	3,002,000	352,000
Commodity derivative instruments, Current liabilities	-2,699,000	-1,000,000
Commodity derivative instruments, Long-term liabilities	-1,094,000	-1,933,000
Commodity Contract [Member] | Economic hedges [Member] | PNMR and PNM [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Commodity derivative instruments, Current assets	4,064,000	3,785,000
Commodity derivative instruments, Deferred charges	3,002,000	352,000
Commodity derivative instruments, Assets	7,066,000	4,137,000
Commodity derivative instruments, Current liabilities	-2,699,000	-1,000,000
Commodity derivative instruments, Long-term liabilities	-1,094,000	-1,933,000
Commodity derivative instruments, Liabilities	-3,793,000	-2,933,000
Commodity derivative instruments, Net	3,273,000	1,204,000
Commodity Contract [Member] | Fuel and purchased power adjustment clause [Member] | Economic hedges [Member] | Public Service Company of New Mexico [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Commodity derivative instruments, Current assets	400,000	100,000
Commodity derivative instruments, Current liabilities	($100,000)	'

Fair_Value_of_Derivative_and_O3

Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (Commodity Contract [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	$2,836	$5,708	$3,481
Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	0	0	-422
Recognized in OCI	0	0	422
Electric operating revenues [Member] | Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	1,727	6,168	5,682
Electric operating revenues [Member] | Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	0	0	0
Cost of energy [Member] | Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	1,109	-460	-2,201
Cost of energy [Member] | Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	0	0	-422
Public Service Company of New Mexico [Member] | Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	2,836	5,708	4,624
Public Service Company of New Mexico [Member] | Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	0	0	0
Recognized in OCI	0	0	0
Public Service Company of New Mexico [Member] | Electric operating revenues [Member] | Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	1,727	6,168	5,682
Public Service Company of New Mexico [Member] | Electric operating revenues [Member] | Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	0	0	0
Public Service Company of New Mexico [Member] | Cost of energy [Member] | Economic hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	1,109	-460	-1,058
Public Service Company of New Mexico [Member] | Cost of energy [Member] | Cash flow hedges [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss)	$0	$0	$0

Fair_Value_of_Derivative_and_O4

Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (PNMR and PNM [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Contractual Liability	$2,398	$2,933
Existing Cash Collateral	0	0
Net Exposure	$2,152	$2,777
Commodity Contract [Member] | Economic hedges [Member] | Derivative Long Position [Member]	'	'
Derivative [Line Items]	'	'
Volume positions (MMBTU/ MWh)	-3,343,783,000	1,127,500,000

Fair_Value_of_Derivative_and_O5

Fair Value of Derivative and Other Financial Instruments, Sale of Power (Details) (Palo Verde Nuclear Generating Station Unit 3 [Member], PNMR and PNM [Member])	Dec. 31, 2013
	MW
Sale of Power [Line Items]	'
Public Utilities, Number of Megawatts Nuclear Generation	134
Percentage of Electric Power Plant Output Sold for 2014 and 2015	100.00%
Commodity Contract [Member]	'
Sale of Power [Line Items]	'
Derivative, Average Forward Price	37

Fair_Value_of_Derivative_and_O6

Fair Value of Derivative and Other Financial Instruments, Avaialbe for Sale Securities (Details) (PNMR and PNM [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	$226,855	$192,511	'
Available-for-sale securities, Unrealized gains	42,602	27,156	'
Proceeds from sales	271,140	167,330	145,286
Gross realized gains	14,308	15,907	17,493
Gross realized (losses)	-4,298	-8,170	-6,223
Domestic value [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	39,460	30,044	'
Available-for-sale securities, Unrealized gains	14,523	5,223	'
Domestic growth [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	76,292	51,650	'
Available-for-sale securities, Unrealized gains	25,656	15,212	'
International and other [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	16,633	14,868	'
Available-for-sale securities, Unrealized gains	1,040	247	'
U.S. Government [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	21,941	32,592	'
Available-for-sale securities, Unrealized gains	158	1,305	'
Municipals [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	58,568	43,861	'
Available-for-sale securities, Unrealized gains	1,018	4,069	'
Corporate and other [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	10,605	14,868	'
Available-for-sale securities, Unrealized gains	207	1,100	'
Cash and equivalents [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	3,356	4,628	'
Available-for-sale securities, Unrealized gains	0	0	'
Measured on a recurring basis [Member] | Nuclear Decommissioning Trust [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	222,500	189,000	'
Measured on a recurring basis [Member] | Mine Reclamation Trust [Member]	'	'	'
Schedule of Available-for-sale Securities [Line Items]	'	'	'
Available-for-sale securities, Fair value	$4,400	$3,500	'

Fair_Value_of_Derivative_and_O7

Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
PNMR and PNM [Member]	'
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]	'
Available-for-sale debt securities, Within 1 year	$3,025
Available-for-sale debt securities, After 1 year through 5 years	24,068
Available-for-sale debt securities, After 5 years through 10 years	10,128
Available-for-sale debt securities, After 10 years through 15 years	6,136
Available-for-sale debt securities, After 15 years through 20 years	10,331
Available-for-sale debt securities, After 20 years	37,426
Available-for-sale debt securities	91,114
PNM Resources [Member]	'
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]	'
Held-to-maturity debt securities, Due within 1 year	1,149
Held-to-maturity debt securities, After 1 year through 5 years	57,497
Held-to-maturity debt securities, After 5 years through 10 years	0
Held to Maturity Securities, Debt Maturities, after Ten Years Through Fifteen Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Fifteen Years Through Twenty Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Twenty Years, Fair Value	0
Held-to-maturity debt securities	58,646
Public Service Company of New Mexico [Member]	'
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]	'
Held-to-maturity debt securities, Due within 1 year	1,149
Held-to-maturity debt securities, After 1 year through 5 years	56,130
Held-to-maturity debt securities, After 5 years through 10 years	0
Held to Maturity Securities, Debt Maturities, after Ten Years Through Fifteen Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Fifteen Years Through Twenty Years, Fair Value	0
Held to Maturity Securities, Debt Maturities, after Twenty Years, Fair Value	0
Held-to-maturity debt securities	$57,279

Fair_Value_of_Derivative_and_O8

Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (PNMR and PNM [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	$226,855	$192,511
Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	226,855	192,511
Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	158,180	128,927
Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	68,675	63,584
Cash and equivalents [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	3,356	4,628
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	3,356	4,628
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	3,356	4,628
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	0	0
Domestic value [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	39,460	30,044
Domestic value [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	39,460	30,044
Domestic value [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	39,460	30,044
Domestic value [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	0	0
Domestic growth [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	76,292	51,650
Domestic growth [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	76,292	51,650
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	76,292	51,650
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	0	0
International and other [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	16,633	14,868
International and other [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	16,633	14,868
International and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	16,633	14,868
International and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	0	0
U.S. Government [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	21,941	32,592
U.S. Government [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	21,941	32,592
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	20,194	27,737
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	1,747	4,855
Municipals [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	58,568	43,861
Municipals [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	58,568	43,861
Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	0	0
Municipals [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	58,568	43,861
Corporate and other [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	10,605	14,868
Corporate and other [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	10,605	14,868
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	2,245	0
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Available-for-sale securities, Fair value	8,360	14,868
Commodity Contract [Member] | Measured on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity derivative instruments, Assets	7,066	4,137
Commodity derivative instruments, Liabilities	-3,793	-2,933
Commodity derivative instruments, Net	-3,273	-1,204
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity derivative instruments, Assets	0	0
Commodity derivative instruments, Liabilities	0	0
Commodity derivative instruments, Net	0	0
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity derivative instruments, Assets	7,066	4,137
Commodity derivative instruments, Liabilities	-3,793	-2,933
Commodity derivative instruments, Net	$3,273	($1,204)

Fair_Value_of_Derivative_and_O9

Fair Value of Derivative and Other Financial Instruments, Defined Benefit Plans Disclosure (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

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In Thousands, unless otherwise specified

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Pension Plan [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Carrying (Reported) Amount, Fair Value Disclosure [Member]

PNMR [Member]

PNMR [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Other Funds [Member]

Fixed Income Securities, Other Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Hedge Funds [Member]

Hedge Funds [Member]

Real Estate [Member]

Real Estate [Member]

PNMR [Member]

PNMR [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Other Funds [Member]

Fixed Income Securities, Other Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Hedge Funds [Member]

Hedge Funds [Member]

Real Estate [Member]

Real Estate [Member]

PNMR [Member]

PNMR [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Other Funds [Member]

Fixed Income Securities, Other Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Hedge Funds [Member]

Hedge Funds [Member]

Real Estate [Member]

Real Estate [Member]

PNMR [Member]

PNMR [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]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, Corporate [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, U.S. Government [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Municipals [Member]

Fixed Income Securities, Other Funds [Member]

Fixed Income Securities, Other Funds [Member]

Private Equity Funds [Member]

Private Equity Funds [Member]

Hedge Funds [Member]

Hedge Funds [Member]

Real Estate [Member]

Real Estate [Member]

Private Equity, Hedge and Real Estate Funds [Member]

Private Equity, Hedge and Real Estate Funds [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]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [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]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Estimate of Fair Value, Fair Value Disclosure [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 1 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 2 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

PNMR [Member]

PNMR [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]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [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]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

PNMR Master Trust [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [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]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Cash and Cash Equivalents [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, International Funds [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Value [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Domestic Growth [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Equity Securities, Other Funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [Member]

Fixed income securities, Mutual funds [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]

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]

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]

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]

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]

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]

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]

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]

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]

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]

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]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [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]

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]

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]

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]

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]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [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]

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]

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]

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]

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]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [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]

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]

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]

Defined Benefit Plan Disclosure [Line Items]

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'

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Long-term debt

$1,905,230

$1,969,362

$1,382,938

$1,385,433

$390,814

$418,166

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0

$0

$0

$0

$0

$0

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

$1,905,230

$1,966,725

$1,382,938

$1,385,433

$390,814

$418,166

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0

$2,637

$0

$0

$0

$0

'

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'

'

'

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'

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'

'

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'

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'

'

'

'

'

'

'

$1,745,420

$1,672,290

$1,290,618

$1,215,579

$336,036

$311,589

Investment in PVNGS lessor notes

57,279

84,198

57,279

84,198

'

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'

'

'

'

'

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'

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0

0

0

0

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

0

0

0

0

'

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'

'

'

'

'

'

'

'

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'

'

57,279

84,198

57,279

84,198

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

52,958

77,682

52,958

77,682

'

'

Other investments

3,196

6,965

445

494

245

281

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

690

774

445

494

245

281

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

0

0

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,506

6,191

0

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,835

5,599

445

494

245

281

Defined Benefit Plan, Fair Value of Plan Total Assets Owned At the End of Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

74,133

65,536

9,734

8,760

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of plan assets at beginning of year

623,543

583,688

'

'

'

'

16,281

10,404

24,471

39,867

41,451

39,492

36,805

63,888

22,522

17,035

202,897

101,936

99,748

148,341

17,259

3,639

66,286

65,898

39,122

38,212

34,912

31,277

21,789

23,699

164,021

231,953

'

'

'

'

16,281

10,404

24,471

39,867

41,451

39,492

36,805

63,888

0

0

363

0

44,541

78,302

0

0

109

0

0

0

0

0

0

0

363,523

258,547

'

'

'

'

0

0

0

0

0

0

0

0

22,522

17,035

202,358

101,936

55,207

70,039

17,259

3,639

66,177

65,898

0

0

0

0

0

0

95,999

93,188

'

'

'

'

79,017

84,133

14,171

14,555

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

38,212

37,100

31,277

36,904

23,699

24,684

93,188

98,688

556,353

518,095

427,386

66,118

66,540

59,952

557,258

517,238

66,285

66,450

145,364

205,491

18,657

26,462

330,903

232,730

32,620

25,817

80,991

79,017

15,008

14,171

73,565

64,464

58,776

9,601

8,643

8,303

6,388

381

'

'

'

'

1,152

4,976

302

42

3,057

2,651

1,334

1,444

54,851

46,145

1,848

1,289

5,564

7,588

4,167

3,660

3,121

4,176

1,702

2,325

31,430

28,663

4,233

3,656

1,152

4,976

302

42

0

0

0

0

6,388

381

20,769

19,511

1,848

1,289

0

0

0

0

3,121

4,176

1,702

2,325

42,703

36,873

5,501

5,104

0

0

0

0

3,057

2,651

1,334

1,444

0

0

34,082

26,634

0

0

5,564

7,588

4,167

3,660

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

'

'

'

'

'

'

Actual return on assets sold during the period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,303

2,627

1,400

197

'

'

'

'

'

'

'

'

'

'

0

0

'

'

'

'

'

'

4,677

2,966

135

-80

-109

-62

4,703

2,824

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Actual return on assets still held at period end

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,361

2,386

1,425

179

'

'

'

'

'

'

'

'

'

'

1

0

'

'

'

'

'

'

1,162

40

3,500

2,453

123

72

4,786

2,565

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchases

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,110

5,498

6,408

413

'

'

'

'

'

'

'

'

'

'

175

0

'

'

'

'

'

'

3,117

3,906

16,151

0

2,076

2,005

21,519

5,911

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Sales

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-19,800

15,627

-8,396

1,173

'

'

'

'

'

'

'

'

'

'

0

0

'

'

'

'

'

'

-8,046

-5,800

-16,151

-8,000

-4,000

-3,000

-28,197

-16,800

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of plan assets at end of year

$623,543

$583,688

'

'

'

'

$16,281

$10,404

$24,471

$39,867

$41,451

$39,492

$36,805

$63,888

$22,522

$17,035

$202,897

$101,936

$99,748

$148,341

$17,259

$3,639

$66,286

$65,898

$39,122

$38,212

$34,912

$31,277

$21,789

$23,699

$164,021

$231,953

'

'

'

'

$16,281

$10,404

$24,471

$39,867

$41,451

$39,492

$36,805

$63,888

$0

$0

$363

$0

$44,541

$78,302

$0

$0

$109

$0

$0

$0

$0

$0

$0

$0

$363,523

$258,547

'

'

'

'

$0

$0

$0

$0

$0

$0

$0

$0

$22,522

$17,035

$202,358

$101,936

$55,207

$70,039

$17,259

$3,639

$66,177

$65,898

$0

$0

$0

$0

$0

$0

$95,999

$93,188

'

'

'

'

$80,991

$79,017

$15,008

$14,171

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$176

$0

$0

$0

$0

$0

$0

$0

$39,122

$38,212

$34,912

$31,277

$21,789

$23,699

$95,999

$93,188

$556,353

$518,095

$427,386

$66,118

$66,540

$59,952

$557,258

$517,238

$66,285

$66,450

$145,364

$205,491

$18,657

$26,462

$330,903

$232,730

$32,620

$25,817

$80,991

$79,017

$15,008

$14,171

$73,565

$64,464

$58,776

$9,601

$8,643

$8,303

$6,388

$381

'

'

'

'

$1,152

$4,976

$302

$42

$3,057

$2,651

$1,334

$1,444

$54,851

$46,145

$1,848

$1,289

$5,564

$7,588

$4,167

$3,660

$3,121

$4,176

$1,702

$2,325

$31,430

$28,663

$4,233

$3,656

$1,152

$4,976

$302

$42

$0

$0

$0

$0

$6,388

$381

$20,769

$19,511

$1,848

$1,289

$0

$0

$0

$0

$3,121

$4,176

$1,702

$2,325

$42,703

$36,873

$5,501

$5,104

$0

$0

$0

$0

$3,057

$2,651

$1,334

$1,444

$0

$0

$34,082

$26,634

$0

$0

$5,564

$7,588

$4,167

$3,660

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

$0

'

'

'

'

'

'

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

30-May-08

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Valencia [Member]

Valencia [Member]

Valencia [Member]

Valencia [Member]

Valencia [Member]

Valencia [Member]

PVNGS [Member]

Delta [Member]

Delta [Member]

Delta [Member]

Delta [Member]

Delta [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

LeaseAgreements

LeaseAgreements

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Maximum [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

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]

PVNGS [Member]

PVNGS [Member]

InstitutionalInvestors

InstitutionalInvestors

MW

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Variable Interest Entity [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of mega watts purchased (in megawatts)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

158

'

'

'

'

'

'

'

'

'

Power plant total construction costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$90,000,000

'

'

'

'

'

'

'

'

'

Long term contract for purchase of electric power fixed costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,900,000

18,800,000

18,300,000

'

'

'

6,400,000

6,200,000

6,000,000

'

'

'

'

Long term contract for purchase of electric power variable charges

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

900,000

1,400,000

'

'

'

1,800,000

800,000

1,500,000

'

'

'

'

Variable Interest Entity, Statement Of Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Electric Revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,166,000

19,585,000

19,720,000

'

'

'

'

'

'

'

'

'

'

Operating expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-5,645,000

-5,535,000

-5,673,000

'

'

'

'

'

'

'

'

'

'

Earnings Attributable to non-controlling interest

'

'

'

'

'

'

'

'

14,521,000

14,050,000

14,047,000

'

'

'

'

'

'

'

'

14,521,000

14,050,000

14,047,000

'

-14,521,000

-14,050,000

-14,047,000

'

'

'

'

'

'

'

'

'

'

Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current assets

401,539,000

'

'

'

442,191,000

'

'

'

401,539,000

442,191,000

'

348,502,000

'

'

'

387,689,000

'

'

'

348,502,000

387,689,000

'

'

2,658,000

3,655,000

'

'

'

'

'

'

'

'

'

'

'

Net property, plant and equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,137,000

77,953,000

'

'

'

'

'

'

'

'

'

'

'

Total Assets

5,500,210,000

'

'

'

5,372,583,000

'

'

'

5,500,210,000

5,372,583,000

5,204,613,000

4,227,616,000

'

'

'

4,163,907,000

'

'

'

4,227,616,000

4,163,907,000

'

'

77,795,000

81,608,000

'

'

'

'

'

'

'

'

'

'

'

Current liabilities

492,671,000

'

'

'

434,103,000

'

'

'

492,671,000

434,103,000

'

357,266,000

'

'

'

242,751,000

'

'

'

357,266,000

242,751,000

'

'

766,000

765,000

'

'

'

'

'

'

'

'

'

'

'

Owners' equity - non-controlling interest

-77,029,000

'

'

'

-80,843,000

'

'

'

-77,029,000

-80,843,000

'

-77,029,000

'

'

'

-80,843,000

'

'

'

-77,029,000

-80,843,000

'

'

77,029,000

80,843,000

'

'

'

'

'

'

'

'

'

'

'

Jointly owned utility plant, option to purchase proportionate ownership share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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, approximate approval period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 months

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Currently active with trusts

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, trust lessors

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Different institutional investors of trust lessors

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, renewal options after original lease term

'

'

'

'

'

'

'

'

'6 years

'

'

'

'

'

'

'

'

'

'

'2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Extended lease term option

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating leases, future minimum payments due

'

'

'

'

'

'

'

'

'

'

'

349,561,000

'

'

'

'

'

'

'

349,561,000

'

'

'

'

'

'

'

'

52,500,000

'

'

'

'

'

'

'

Operating leases, future minimum payments due, renewal term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

145,200,000

'

'

'

'

'

'

'

Loss contingency, range of possible loss, portion not accrued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

154,100,000

'

'

'

'

'

'

'

Operating Leases, Future Minimum Payments Due, Current

'

'

'

'

'

'

'

'

'

'

'

49,580,000

'

'

'

'

'

'

'

49,580,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26,000,000

26,000,000

Long Term Contract For Purchase of Power Term of Contract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

39,200,000

'

'

'

'

'

'

Payments to Acquire Businesses, Gross

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16,200,000

19,200,000

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,300,000

3,000,000

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,700,000

26,600,000

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,300,000

23,100,000

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,200,000

21,100,000

'

'

Intersegment revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,500,000

7,400,000

'

'

Earnings Attributable to PNMR

$7,648,000

$54,555,000

$27,678,000

$10,626,000

$9,091,000

$57,864,000

$21,512,000

$17,080,000

$100,507,000

$105,547,000

$176,359,000

$2,639,000

$47,823,000

$26,124,000

$11,569,000

$5,943,000

$50,911,000

$16,885,000

$17,812,000

$88,155,000

$91,551,000

$54,491,000

'

'

'

'

'

'

'

'

'

'

$1,200,000

$900,000

'

'

Earnings_and_Dividends_Per_Sha2

Earnings and Dividends Per Share (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Earnings Per Share [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Earnings Attributable to PNMR

$7,648

$54,555

$27,678

$10,626

$9,091

$57,864

$21,512

$17,080

$100,507

$105,547

$176,359

Average Number of Common Shares:

'

'

'

'

'

'

'

'

'

'

'

Outstanding during year

'

'

'

'

'

'

'

'

79,654,000

79,654,000

85,558,000

Equivalents from convertible preferred stock (Note 5)

'

'

'

'

'

'

'

'

0

0

3,469,000

Vested awards of restricted stock

'

'

'

'

'

'

'

'

191,000

145,000

174,000

Average Shares - Basic

'

'

'

'

'

'

'

'

79,845,000

79,799,000

89,201,000

Dilutive Effect of Common Stock Equivalents:

'

'

'

'

'

'

'

'

'

'

'

Stock options and restricted stock

'

'

'

'

'

'

'

'

586,000

[1]

618,000

[1]

556,000

[1]

Average Shares – Diluted

'

'

'

'

'

'

'

'

80,431,000

[1]

80,417,000

[1]

89,757,000

[1]

Net Earnings Per Share of Common Stock:

'

'

'

'

'

'

'

'

'

'

'

Basic (dollars per share)

$0.10

$0.68

$0.35

$0.13

$0.11

$0.73

$0.27

$0.21

$1.26

$1.32

$1.98

Diluted (dollars per share)

$0.10

$0.68

$0.34

$0.13

$0.11

$0.72

$0.27

$0.21

$1.25

$1.31

$1.96

Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price (in shares)

'

'

'

'

'

'

'

'

509,916

'

'

Common Stock, Dividends, Per Share, Declared

'

'

'

'

'

'

'

'

$0.68

$0.58

$0.50

[1]

Excludes out-of-the-money options for 509,916 shares of common stock at December 31, 2013. See Note 13.

Income_Taxes_Schedule_of_Compo

Income Taxes Schedule of Components of Income Tax Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'
Current federal income tax	$0	($1,296)	$1,319
Current state income tax	-917	-37	-4,208
Deferred federal income tax	50,044	51,559	119,280
Deferred state income tax	12,578	6,921	7,462
Amortization of accumulated investment tax credits	-2,192	-2,237	-2,318
Total income taxes (benefit)	59,513	54,910	121,535
Public Service Company of New Mexico [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Current federal income tax	-479	-12,951	-46,364
Current state income tax	-760	-1,815	-6,776
Deferred federal income tax	42,806	56,194	78,673
Deferred state income tax	9,429	11,522	14,212
Amortization of accumulated investment tax credits	-2,192	-2,237	-2,318
Total income taxes (benefit)	48,804	50,713	37,427
Texas-New Mexico Power Company [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Current federal income tax	-4,957	9,152	-3,578
Current state income tax	1,916	1,822	1,981
Deferred federal income tax	20,688	4,406	15,507
Deferred state income tax	-26	-28	-29
Total income taxes (benefit)	$17,621	$15,352	$13,881

Income_Taxes_Schedule_of_Effec

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'
Federal income tax at statutory rates	$61,274	$61,262	$109,364
First Choice goodwill	0	0	15,055
Investment tax credits	-2,192	-2,237	-2,318
Flow-through of depreciation items	1,132	1,284	3,659
Earnings attributable to non-controlling interest in Valencia	-5,082	-4,918	-4,917
State income tax	3,818	4,646	3,395
Effective Income Tax Rate Reconciliation, Impairment of Production Tax Credits, Amount	3,880	718	0
Other	-3,317	-5,845	-2,703
Total income taxes (benefit)	59,513	54,910	121,535
Effective tax rate	33.99%	31.37%	38.90%
Public Service Company of New Mexico [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Federal income tax at statutory rates	53,018	54,710	37,088
Investment tax credits	-2,192	-2,237	-2,318
Flow-through of depreciation items	1,115	1,268	3,656
Earnings attributable to non-controlling interest in Valencia	-5,082	-4,918	-4,917
State income tax	6,202	6,500	4,797
Other	-4,257	-4,610	-879
Total income taxes (benefit)	48,804	50,713	37,427
Effective tax rate	32.22%	32.44%	35.32%
Texas-New Mexico Power Company [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Federal income tax at statutory rates	16,349	14,735	12,648
State income tax	1,247	1,185	1,288
Other	25	-568	-55
Total income taxes (benefit)	$17,621	$15,352	$13,881
Effective tax rate	37.72%	36.47%	38.41%

Income_Taxes_Schedule_of_Defer

Income Taxes Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]	'	'	'
Deferred Tax Assets, Valuation Allowance	'	$7,200,000	'
Valuation Allowance, Deferred Tax Asset, Change in Amount	3,900,000	'	'
Components of Deferred Tax Assets [Abstract]	'	'	'
Net operating loss	'	134,418,000	110,989,000
Pension	'	0	26,452,000
Regulatory liabilities related to income taxes	'	83,838,000	53,439,000
Other	'	144,126,000	129,801,000
Total deferred tax assets	'	362,382,000	320,681,000
Components of Deferred Tax Liabilities [Abstract]	'	'	'
Depreciation and plant related	'	-814,671,000	-759,587,000
Investment tax credit	'	-25,855,000	-14,242,000
Regulatory assets related to income taxes	'	-66,352,000	-59,471,000
Stranded costs	'	-22,262,000	-24,934,000
Deferred Tax Liabilities, Compensation and Benefits, Pensions	'	-58,780,000	0
Other	'	-143,044,000	-178,492,000
Total deferred tax liabilities	'	-1,130,964,000	-1,036,726,000
Deferred Tax Assets (Liabilities), Net [Abstract]	'	'	'
Net accumulated deferred income tax liabilities	'	-768,582,000	-716,045,000
Current accumulated deferred income tax (asset) liability	'	-58,681,000	258,000
Non-current accumulated deferred income tax liability	'	-827,263,000	-715,787,000
Public Service Company of New Mexico [Member]	'	'	'
Components of Deferred Tax Assets [Abstract]	'	'	'
Net operating loss	'	99,247,000	93,980,000
Pension	'	0	32,532,000
Regulatory liabilities related to income taxes	'	78,849,000	48,027,000
Other	'	67,179,000	55,629,000
Total deferred tax assets	'	245,275,000	230,168,000
Components of Deferred Tax Liabilities [Abstract]	'	'	'
Depreciation and plant related	'	-661,239,000	-624,724,000
Investment tax credit	'	-25,855,000	-14,242,000
Regulatory assets related to income taxes	'	-55,844,000	-48,726,000
Deferred Tax Liabilities, Compensation and Benefits, Pensions	'	-52,104,000	0
Other	'	-83,500,000	-134,046,000
Total deferred tax liabilities	'	-878,542,000	-821,738,000
Deferred Tax Assets (Liabilities), Net [Abstract]	'	'	'
Net accumulated deferred income tax liabilities	'	-633,267,000	-591,570,000
Current accumulated deferred income tax (asset) liability	'	-43,827,000	3,447,000
Non-current accumulated deferred income tax liability	'	-677,094,000	-588,123,000
Texas-New Mexico Power Company [Member]	'	'	'
Components of Deferred Tax Assets [Abstract]	'	'	'
Regulatory liabilities related to income taxes	'	4,988,000	5,412,000
Other	'	23,479,000	16,702,000
Total deferred tax assets	'	28,467,000	22,114,000
Components of Deferred Tax Liabilities [Abstract]	'	'	'
Depreciation and plant related	'	-151,581,000	-133,686,000
Regulatory assets related to income taxes	'	-10,509,000	-10,745,000
Deferred Tax Liability, Loss on reacquired debt	'	-13,516,000	-599,000
Stranded costs	'	-22,262,000	-24,934,000
Other	'	-14,295,000	-14,729,000
Total deferred tax liabilities	'	-212,163,000	-184,693,000
Deferred Tax Assets (Liabilities), Net [Abstract]	'	'	'
Net accumulated deferred income tax liabilities	'	-183,696,000	-162,579,000
Current accumulated deferred income tax (asset) liability	'	-6,501,000	-1,131,000
Non-current accumulated deferred income tax liability	'	($190,197,000)	($163,710,000)

Income_Taxes_Schedule_of_Defer1

Income Taxes Schedule of Deferred Income Tax Components (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'
Net change in deferred income tax liability per above table	$52,537	'	'
Change in tax effects of income tax related regulatory assets and liabilities	23,592	'	'
Tax effect of mark-to-market adjustments	-6,096	'	'
Tax effect of excess pension liability	-9,305	'	'
Adjustment for uncertain income tax positions	691	'	'
Other	-989	'	'
Deferred income taxes	60,430	56,243	124,424
Public Service Company of New Mexico [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Net change in deferred income tax liability per above table	41,697	'	'
Change in tax effects of income tax related regulatory assets and liabilities	23,704	'	'
Tax effect of mark-to-market adjustments	-6,121	'	'
Tax effect of excess pension liability	-9,305	'	'
Adjustment for uncertain income tax positions	691	'	'
Other	-623	'	'
Deferred income taxes	50,043	65,479	90,567
Texas-New Mexico Power Company [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Net change in deferred income tax liability per above table	21,117	'	'
Change in tax effects of income tax related regulatory assets and liabilities	-112	'	'
Other	-343	'	'
Deferred income taxes	$20,662	$4,378	$15,478

Income_Taxes_Summary_of_Income

Income Taxes Summary of Income Tax Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	($54,000)	'	'
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	-745,000	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits - Beginning	19,198,000	19,580,000	36,105,000
Additions based on tax positions	'	2,046,000	-790,000
Reductions for tax positions of prior years	'	-2,428,000	-15,735,000
Settlements	0	0	0
Unrecognized Tax Benefits - End	19,889,000	19,198,000	19,580,000
PNMR [Member]	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized tax benefits that would impact effective tax rate	5,600,000	'	'
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	5,500,000	'	'
Public Service Company of New Mexico [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	-54,000	'	'
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	-745,000	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits - Beginning	10,382,000	10,752,000	11,918,000
Additions based on tax positions	'	1,152,000	-717,000
Reductions for tax positions of prior years	'	-1,522,000	-449,000
Settlements	0	0	0
Unrecognized Tax Benefits - End	11,073,000	10,382,000	10,752,000
Unrecognized tax benefits that would impact effective tax rate	1,400,000	'	'
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	400,000	'	'
Texas-New Mexico Power Company [Member]	'	'	'
Income Taxes [Line Items]	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	'	'
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits - Beginning	6,796,000	7,701,000	7,788,000
Additions based on tax positions	'	0	-74,000
Reductions for tax positions of prior years	'	-905,000	-13,000
Settlements	0	0	0
Unrecognized Tax Benefits - End	6,796,000	6,796,000	7,701,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	$6,800,000	'	'

Income_Taxes_Interest_Expense_

Income Taxes Interest Expense (Income) Related to Income Taxes (Details) (USD $)	1 Months Ended	12 Months Ended
	31-May-13	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Line Items]	'	'	'	'
New Mexico Corporate tax rate, current	'	7.60%	'	'
Interest income related to income taxes	'	$242,000	$243,000	$467,000
New Mexico Corporate tax rate, 2014	'	5.90%	'	'
Increase in regulatory liabilities due to change in state corporate tax rate	'	23,900,000	'	'
Increase in income tax expense due to change in state corporate tax rate	'	1,200,000	'	'
Additional Income Tax Expense, Impairment of NM Wind Credits	'	2,400,000	700,000	'
Federal Tax Refund	96,200,000	'	'	'
Public Service Company of New Mexico [Member]	'	'	'	'
Income Taxes [Line Items]	'	'	'	'
Interest income related to income taxes	'	251,000	244,000	401,000
Federal Tax Refund	77,400,000	'	'	'
Texas-New Mexico Power Company [Member]	'	'	'	'
Income Taxes [Line Items]	'	'	'	'
Interest income related to income taxes	'	($2,000)	($3,000)	$2,000

Income_Taxes_Accumulated_Accru

Income Taxes Accumulated Accrued Interest Receivable (Payable) Related to Income Taxes (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]	'	'
Deferred Tax Assets, Valuation Allowance	$7,200,000	'
PNMR [Member]	'	'
Income Taxes [Line Items]	'	'
Accumulated accrued interest receivable	4,048,000	3,796,000
Accumulated accrued interest payable	-1,118,000	-1,108,000
Public Service Company of New Mexico [Member]	'	'
Income Taxes [Line Items]	'	'
Accumulated accrued interest receivable	4,048,000	3,796,000
Accumulated accrued interest payable	-24,000	-23,000
Texas-New Mexico Power Company [Member]	'	'
Income Taxes [Line Items]	'	'
Accumulated accrued interest receivable	0	0
Accumulated accrued interest payable	($118,000)	($116,000)

Income_Taxes_Carryforwards_Det

Income Taxes Carryforwards (Details) (USD $)	Dec. 31, 2013	Mar. 31, 2014
In Millions, unless otherwise specified	Internal Revenue Service (IRS) [Member]	Subsequent Event [Member]
Operating Loss Carryforwards [Line Items]	'	'
Federal Net Operating Loss Carryforwards to Expire in 2030	$301.20	'
Federal Tax Credit Carryforwards that Expire Beginning in 2023	40.6	'
Deferred Tax Assets, Operating Loss Carryforwards, State and Local, Decrease	'	$1.50

Pension_and_Other_Postretireme2

Pension and Other Postretirement Benefits Narrative (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected return on plan assets	'	4.00%	'	'
Defined Benefit Plans, Gains and losses that lie outside the corridor, amortized (in years)	'	'5 years	'	'
Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected long-term return resulting from effect of one-percentage point decrease (as a percent)	'	1.00%	'	'
Expected long-term return resulting from effect of one-percentage point increase (as a percent)	'	1.00%	'	'
Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected long-term return resulting from effect of one-percentage point decrease (as a percent)	'	1.00%	'	'
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected return on plan assets	'	7.65%	8.25%	8.50%
Defined Benefit Plan, Other Changes	'	($60.90)	$86.40	'
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	'	-4.4	-8	'
Actual plan asset allocations (as a percent)	'	3.50%	'	'
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	'	5.3	'	'
Estimated future employer contributions from 2013-2017	'	61.5	'	'
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected return on plan assets	'	8.50%	8.50%	8.50%
Defined Benefit Plan, Other Changes	-8.8	'	13.1	'
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	-4.2	'	8.1	'
Actual plan asset allocations (as a percent)	'	20.40%	'	'
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	'	0.7	'	'
Estimated future employer contributions in next fiscal year	'	3.5	'	'
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected return on plan assets	'	7.65%	8.25%	8.50%
Defined Benefit Plan, Other Changes	'	-6.4	10.7	'
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	'	1.4	-0.8	'
Actual plan asset allocations (as a percent)	'	6.70%	'	'
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	'	0.7	'	'
Estimated future employer contributions from 2013-2017	'	0	'	'
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Expected return on plan assets	'	6.50%	6.50%	6.30%
Defined Benefit Plan, Other Changes	-1.3	'	2	'
Defined Benefit Plan, Actuarial Gain (Loss) resulting from changes in demographics and other trends	-0.2	'	-0.8	'
Actual plan asset allocations (as a percent)	'	22.10%	'	'
Expected Long-term return on assets decrease resulting in increase net periodic costs In next fiscal year	'	0.1	'	'
Estimated future employer contributions in next fiscal year	'	$0.30	'	'
Equity Securities [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	21.00%	'	'
Equity Securities [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	70.00%	'	'
Debt Securities [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	65.00%	'	'
Debt Securities [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	30.00%	'	'
Alternative Investments [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	14.00%	'	'
Minimum [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Weighted average discount rate related to anticipated contributions (as a percent)	'	5.20%	'	'
Maximum [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Weighted average discount rate related to anticipated contributions (as a percent)	'	5.50%	'	'
Developed Countries Outside of United States [Member] | Equity Securities [Member] | Pension Plan [Member]	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Target plan asset allocations (as a percent)	'	6.00%	'	'

Pension_and_Other_Postretireme3

Pension and Other Postretirement Benefits APBO, PBO, Fair Value of Plan Assets, and Funded Status of the Plans (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Non-current liability	$80,046	$224,565	'
Public Service Company of New Mexico [Member]	'	'	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Non-current liability	76,611	208,618	'
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	675,549	588,874	'
Service cost	0	0	0
Interest cost	28,142	32,232	32,804
Actuarial (gain) loss	-56,533	94,361	'
Benefits paid	-41,275	-39,918	'
Plan amendments	6,346	0	'
Benefit Obligation at end of year	599,537	675,549	588,874
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of year	518,095	427,386	'
Actual return on plan assets	19,533	52,927	'
Employer contributions	60,000	77,700	'
Benefits paid	-41,275	-39,918	'
Fair value of plan assets at end of year	556,353	518,095	427,386
Funded status - asset (liability)	-43,184	-157,454	'
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	99,613	96,221	'
Service cost	260	217	259
Interest cost	4,113	5,293	5,378
Participants contributions	2,537	2,266	'
Actuarial (gain) loss	-4,566	5,008	'
Benefits paid	-9,792	-9,392	'
Benefit Obligation at end of year	92,165	99,613	96,221
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of year	64,464	58,776	'
Actual return on plan assets	12,780	9,285	'
Employer contributions	3,576	3,529	'
Participants contributions	2,537	2,266	'
Benefits paid	-9,792	-9,392	'
Fair value of plan assets at end of year	73,565	64,464	58,776
Funded status - asset (liability)	-18,600	-35,149	'
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	17,467	16,191	'
Service cost	0	0	0
Interest cost	720	876	930
Actuarial (gain) loss	-330	1,895	'
Benefits paid	-1,494	-1,495	'
Benefit Obligation at end of year	16,363	17,467	16,191
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Benefits paid	-1,494	-1,495	'
Less current liability	1,536	1,452	'
Non-current liability	14,827	16,015	'
Texas-New Mexico Power Company [Member]	'	'	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Non-current liability	3,435	15,947	'
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	76,640	67,234	'
Service cost	0	0	0
Interest cost	3,087	3,635	3,800
Actuarial (gain) loss	-7,820	11,434	'
Benefits paid	-5,748	-5,663	'
Plan amendments	0	0	'
Benefit Obligation at end of year	66,159	76,640	67,234
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of year	66,540	59,952	'
Actual return on plan assets	4,326	6,951	'
Employer contributions	1,000	5,300	'
Benefits paid	-5,748	-5,663	'
Fair value of plan assets at end of year	66,118	66,540	59,952
Funded status - asset (liability)	-41	-10,100	'
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	13,678	11,344	'
Service cost	299	244	306
Interest cost	566	624	654
Participants contributions	373	404	'
Actuarial (gain) loss	-1,080	2,727	'
Benefits paid	-1,570	-1,665	'
Benefit Obligation at end of year	12,266	13,678	11,344
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of year	8,643	8,303	'
Actual return on plan assets	1,813	1,259	'
Employer contributions	342	342	'
Participants contributions	373	404	'
Benefits paid	-1,570	-1,665	'
Fair value of plan assets at end of year	9,601	8,643	8,303
Funded status - asset (liability)	-2,665	-5,035	'
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Benefit Obligation at beginning of year	902	844	'
Service cost	0	0	0
Interest cost	36	45	46
Actuarial (gain) loss	-21	107	'
Benefits paid	-94	-94	'
Benefit Obligation at end of year	823	902	844
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Benefits paid	-94	-94	'
Less current liability	94	90	'
Non-current liability	$729	$812	'

Pension_and_Other_Postretireme4

Pension and Other Postretirement Benefits Pre-Tax Information about Prior Service Cost and Net Actuarial (Gain) loss in AOCI (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Prior service cost (credit) - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$32
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	159,826
Prior service cost (credit) - Experience loss (gain)	0
Net actuarial (gain) loss - Experience loss (gain)	-34,136
Prior service cost (credit) - Regulatory asset (liability) adjustment	0
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	19,799
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Prior Service Costs, Plan Amendments, before Tax	-2,665
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Actuarial (Gain) Loss, Plan Amendments, before Tax	0
Prior service cost (credit) - Amortization recognized in net periodic benefit cost (income)	-32
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	-6,233
Prior service cost (credit) - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	-2,665
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	139,256
Prior service cost (credit) - Amortization expected to be recognized in in 2013	-405
Net actuarial (gain) loss - Amortization expected to be recognized in in 2013	5,469
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial (gain) loss - Experience loss (gain)	-12,300
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	2,069
Net actuarial (gain) loss - Experience loss (gain)	-330
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	192
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	-98
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	1,833
Net actuarial (gain) loss - Amortization expected to be recognized in in 2013	88
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	0
Net actuarial (gain) loss - Experience loss (gain)	-7,297
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	7,297
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Actuarial (Gain) Loss, Plan Amendments, before Tax	0
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	0
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	0
Net actuarial (gain) loss - Amortization expected to be recognized in in 2013	0
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial (gain) loss - Experience loss (gain)	-2,400
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	0
Net actuarial (gain) loss - Experience loss (gain)	-22
Net actuarial (gain) loss - Regulatory asset (liability) adjustment	22
Net actuarial (gain) loss - Amortization recognized in net periodic benefit cost (income)	0
Net actuarial (gain) loss - Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	0
Net actuarial (gain) loss - Amortization expected to be recognized in in 2013	$0

Pension_and_Other_Postretireme5

Pension and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Income) Recognized (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	$0	$0	$0
Interest cost	28,142	32,232	32,804
Expected return on plan assets	-41,930	-41,301	-37,075
Amortization of net (gain) loss	14,840	10,516	9,209
Amortization of prior service cost (credit)	76	317	317
Net periodic benefit cost	1,128	1,764	5,255
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	0	0	0
Interest cost	720	876	930
Amortization of net (gain) loss	232	83	93
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	952	959	1,023
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	260	217	259
Interest cost	4,113	5,293	5,378
Expected return on plan assets	-5,043	-4,901	-5,388
Amortization of net (gain) loss	4,242	3,888	3,205
Amortization of prior service cost (credit)	-1,343	-1,343	-2,648
Net periodic benefit cost	2,229	3,154	806
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	0	0	0
Interest cost	3,087	3,635	3,800
Expected return on plan assets	-4,849	-5,324	-5,470
Amortization of net (gain) loss	1,049	462	346
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	-713	-1,227	-1,324
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	0	0	0
Interest cost	36	45	46
Amortization of net (gain) loss	0	0	0
Amortization of prior service cost (credit)	0	0	0
Net periodic benefit cost	36	45	46
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]	'	'	'
Service cost	299	244	306
Interest cost	566	624	654
Expected return on plan assets	-503	-516	-533
Amortization of net (gain) loss	0	-209	-193
Amortization of prior service cost (credit)	57	57	60
Net periodic benefit cost	$419	$200	$294

Pension_and_Other_Postretireme6

Pension and Other Postretirement Benefits Assumptions Used (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Expected return on plan assets	4.00%	'	'
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.27%	4.30%	5.67%
Discount rate for determining net periodic benefit cost (income)	4.30%	5.67%	5.72%
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.21%	4.26%	5.70%
Discount rate for determining net periodic benefit cost (income)	4.26%	5.70%	5.59%
Expected return on plan assets	8.50%	8.50%	8.50%
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.27%	4.30%	5.67%
Discount rate for determining net periodic benefit cost (income)	4.30%	5.67%	5.72%
Expected return on plan assets	7.65%	8.25%	8.50%
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.06%	4.19%	5.69%
Discount rate for determining net periodic benefit cost (income)	4.19%	5.69%	5.50%
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.21%	4.26%	5.70%
Discount rate for determining net periodic benefit cost (income)	4.26%	5.70%	5.59%
Expected return on plan assets	6.50%	6.50%	6.30%
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Discount rate for determining December 31	5.06%	4.19%	5.69%
Discount rate for determining net periodic benefit cost (income)	4.19%	5.69%	5.50%
Expected return on plan assets	7.65%	8.25%	8.50%

Pension_and_Other_Postretireme7

Pension and Other Postretirement Benefits Pension Benefit Payments are Expected to be Paid (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	$1,535
2015	1,516
2016	1,494
2017	1,468
2018	1,438
Years 2019 - 2023	6,580
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	6,586
2015	6,720
2016	6,943
2017	7,080
2018	7,306
Years 2019 - 2023	36,569
Public Service Company of New Mexico [Member] | Pension Plan [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	54,356
2015	52,532
2016	52,204
2017	50,954
2018	49,325
Years 2019 - 2023	222,241
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	93
2015	92
2016	90
2017	88
2018	85
Years 2019 - 2023	365
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	787
2015	795
2016	815
2017	833
2018	852
Years 2019 - 2023	4,558
Texas-New Mexico Power Company [Member] | Pension Plan [Member]	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'
2014	6,111
2015	6,181
2016	5,831
2017	5,631
2018	5,696
Years 2019 - 2023	$23,804

Pension_and_Other_Postretireme8

Pension and Other Postretirement Benefits Assumed Health Care Cost Trend Rates and Impact of a One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Details) (Public Service Company of New Mexico [Member], Other Postretirement Benefits [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]	'	'
Health care cost trend rate assumed for next year (as a percent)	7.50%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) (as a percent)	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	'2019	'2017
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]	'	'
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$322	'
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	-274	'
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	5,859	'
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	($4,826)	'

Pension_and_Other_Postretireme9

Pension and Other Postretirement Benefits (Other Postretirement Benefits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Maximum annual contribution per employee (as a percent)	75.00%	'	'
Employer matching contribution (as a percent)	6.00%	'	'
Minimum [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Non-matching contribution of eligible compensation based on eligible employee's age (as a percent)	3.00%	'	'
Maximum [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Non-matching contribution of eligible compensation based on eligible employee's age (as a percent)	10.00%	'	'
401 (k) plan [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Expenses recognized	$16,785	$16,185	$17,000
Public Service Company of New Mexico [Member] | 401 (k) plan [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Expenses recognized	12,952	12,427	12,541
Texas-New Mexico Power Company [Member] | 401 (k) plan [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Expenses recognized	3,953	3,739	3,723
Non-qualified plan [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Compensation expense	2,204	1,491	1,931
Non-qualified plan [Member] | Public Service Company of New Mexico [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Compensation expense	1,691	1,143	1,407
Non-qualified plan [Member] | Texas-New Mexico Power Company [Member]	'	'	'
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'	'
Compensation expense	$513	$327	$431

StockBased_Compensation_Plans_1

Stock-Based Compensation Plans (Performance Equity Plan/ Accounting for Stock Awards and ESPP) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$5.30	$3.60	$6.20
Public Service Company of New Mexico [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	3.8	2.7	4.3
Texas-New Mexico Power Company [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	1.5	1	1.4
Performance Equity Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Vesting Rate	100.00%	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized, Shares	12,340,000	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant, Shares	3,240,000	'	'
Restricted Stock and Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	3.4	'	'
Market-Based Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$1.20	'	'
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition (years)	'1 year 8 months	'	'

StockBased_Compensation_Plans_2

Stock-Based Compensation Plans (Weighted Average Assumptions) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock and Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Risk-free interest rates, percentage	0.34%	1.22%	1.35%
Expected quarterly dividends per share, in dollars per share	$0.17	$0.14	$0.13
Market-Based Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Dividend yield	2.86%	3.45%	'
Expected volatility	25.11%	43.98%	'
Risk-free interest rates, percentage	0.36%	1.04%	'

StockBased_Compensation_Plans_3

Stock-Based Compensation Plans (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Achieves a specified improvement in total shareholder return at the end of 2016 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | Chairman, President, and Chief Executive Officer [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	135,000	'	'
Achieves a specified improvement in total shareholder return at the end of 2014 compared to 2011 and she remains an employee [Member] | Common Stock [Member] | Chairman, President, and Chief Executive Officer [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	35,000	'	'
Stock Options [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'	'
Options, Outstanding at beginning of period, Shares	1,992,700	'	'
Options, Outstanding at beginning of period, Weighted-Average Exercise Price, in dollars per share	$20.72	'	'
Options, Granted, Shares	0	'	'
Options, Granted, Weighted-Average Exercise Price, in dollars per share	$0	'	'
Options, Exercised, Shares	-319,239	'	'
Options, Exercised, Weighted-Average Exercise Price, in dollars per share	$14.47	'	'
Options, Forfeited, Shares	0	'	'
Options, Forfeited, Weighted-Average Exercise Price, in dollars per share	$0	'	'
Options, Expired, Shares	-329,795	'	'
Options, Expired, Weighted-Average Exercise Price, in dollars per share	$27.17	'	'
Options, Outstanding at end of period, Shares	1,343,666	1,992,700	'
Options, Outstanding at end of period, Weighted-Average Exercise Price, in dollars per share	$20.63	$20.72	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]	'	'	'
Options, Outstanding at end of period, Aggregate Intrinsic Value	$7,300,000	'	'
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	'3 years 5 months 5 days	'	'
Options, Outstanding at end of period, No intrinsic value	509,916,000	'	'
Weighted-average grant date fair value options granted, in dollars per share	$0	$0	$0
Total fair value of options that vested	625,000	1,054,000	1,189,000
Total intrinsic value of options exercised	2,721,000	6,356,000	2,616,000
Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]	'	'	'
Restricted Stock, at Beginning of period, Shares	353,722	'	'
Restricted Stock, at Beginning of period, Weighted-Average Grant-Date Fair Value, in dollars per share	$14.03	'	'
Restricted Stock, Granted, Shares	249,113	'	'
Restricted Stock, Vested, Shares	-275,988	'	'
Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value, in dollars per share	$15.92	'	'
Restricted Stock, Forfeited, Shares	-11,542	'	'
Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value, in dollars per share	$18.39	'	'
Restricted Stock, at end of period, Shares	315,305	353,722	'
Restricted Stock, at end of period, Weighted-Average Grant-Date Fair Value, in dollars per share	$17.87	$14.03	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]	'	'	'
Weighted-average grant date fair value	$20.03	$16.75	$13.79
Total fair value of restricted shares that vested (in thousands)	$4,395,000	$5,099,000	$1,240,000
Performance Shares [Member] | Executive [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Excluded from Shares Outstanding, Number	112,864	100,593	'
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in 2013	198,369	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Number of Shares in 2014	179,811	'	'

Construction_Program_and_Joint2

Construction Program and Jointly-Owned Electric Generating Plants Construction Program and Jointly-Owned Electric Generating Plants (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Construction Expenditures	$348,039,000		$308,909,000	$326,931,000
Public Utilities, Property, Plant and Equipment, Plant in Service	5,563,061,000		5,313,796,000	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-1,838,832,000		-1,774,223,000	'
Operating Lease, Extended Term	'2 years		'	'
Public Service Company of New Mexico [Member]	'		'	'
Construction Expenditures	239,906,000		196,800,000	251,345,000
Public Utilities, Property, Plant and Equipment, Plant in Service	4,314,016,000		4,133,532,000	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-1,402,531,000		-1,355,240,000	'
Texas-New Mexico Power Company [Member]	'		'	'
Construction Expenditures	89,117,000		92,973,000	67,407,000
Public Utilities, Property, Plant and Equipment, Plant in Service	1,074,193,000		1,009,108,000	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-352,105,000		-339,315,000	'
Joint Projects [Member] | Public Service Company of New Mexico [Member]	'		'	'
Construction Expenditures	239,900,000		'	'
Joint Projects [Member] | Texas-New Mexico Power Company [Member]	'		'	'
Construction Expenditures	89,100,000		'	'
Joint Projects [Member] | PNMR [Member]	'		'	'
Construction Expenditures	348,000,000		'	'
Four Corners Units 4 and 5 (Coal) [Member] | Public Service Company of New Mexico [Member]	'		'	'
Public Utilities, Property, Plant and Equipment, Plant in Service	159,016,000		'	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-100,462,000		'	'
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	3,236,000		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	13.00%		'	'
Environmental Upgrades Requirement Estimates	80,300,000		'	'
Luna (Gas) [Member] | Other Unrelated Entities 9 [Member]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	33.30%		'	'
Luna (Gas) [Member] | Public Service Company of New Mexico [Member]	'		'	'
Public Utilities, Property, Plant and Equipment, Plant in Service	62,873,000		'	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-17,743,000		'	'
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	169,000		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	33.33%		'	'
SJGS Units 1 and 2 [Member] | Public Service Company of New Mexico [Member]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%		'	'
SJGS (Coal) [Member] | Unit 3 [Member] | Other Unrelated Entities 1 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	41.80%		'	'
SJGS (Coal) [Member] | Unit 3 [Member] | Other Unrelated Entities 2 [Member]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	8.20%		'	'
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 3 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	28.80%		'	'
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 4 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	10.04%		'	'
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 5 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	8.48%		'	'
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 6 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	7.20%		'	'
SJGS (Coal) [Member] | Unit 4 [Member] | Other Unrelated Entities 7 [Member]	'		'	'
Jointly Owned Utility Plant Proportionate Ownership Share, Other Entities	7.03%		'	'
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member]	'		'	'
Public Utilities, Property, Plant and Equipment, Plant in Service	1,004,138,000		'	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-414,054,000		'	'
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	13,860,000		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	46.30%		'	'
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member] | Unit 3 [Member]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%		'	'
SJGS (Coal) [Member] | Public Service Company of New Mexico [Member] | Unit 4 [Member]	'		'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	38.46%		'	'
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member]	'		'	'
Public Utilities, Property, Plant and Equipment, Plant in Service	508,426,000	[1]	'	'
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	-141,347,000	[1]	'	'
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	$43,627,000	[1]	'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	10.20%	[1]	'	'
Operating Lease, Original term	'40 years		'	'
Number of operating units	3		'	'
Operating Lease, Extended Term	'20 years		'	'
[1]	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.

Summary_of_Budgeted_Constructi

Summary of Budgeted Construction Expenditures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Summary of Budgeted Construction Expenditures [Line Items]	'
2014	$509
2015	524
2016	489.3
2017	443.1
2018	301.8
Total	2,267.20
Public Service Company of New Mexico [Member]	'
Summary of Budgeted Construction Expenditures [Line Items]	'
2014	360.8
2015	433.7
2016	387.3
2017	335.4
2018	181.7
Total	1,698.90
Texas-New Mexico Power Company [Member]	'
Summary of Budgeted Construction Expenditures [Line Items]	'
2014	129.9
2015	76
2016	87.8
2017	93.9
2018	106.4
Total	494
Other Subsidiaries [Member]	'
Summary of Budgeted Construction Expenditures [Line Items]	'
2014	18.3
2015	14.3
2016	14.2
2017	13.8
2018	13.7
Total	74.3
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member]	'
Summary of Budgeted Construction Expenditures [Line Items]	'
Environmental Upgrades Requirement Estimates	80
Budgeted Construction Expenditures Related to Replacement Capacity	$276.30

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Liability Beginning Balance	$85,893,000		$79,233,000	$76,637,000
Liabilities incurred	0		0	60,000
Liabilities settled	-79,000		-25,000	-4,000
Accretion expense	7,245,000		6,685,000	6,114,000
Revisions to estimated cash flows	3,076,000	[1]	'	-3,574,000	[1]
Liability Ending Balance	96,135,000		85,893,000	79,233,000
Public Service Company of New Mexico [Member]	'		'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Liability Beginning Balance	85,042,000		78,425,000	75,888,000
Liabilities incurred	0		0	60,000
Liabilities settled	-67,000		0	0
Accretion expense	7,174,000		6,617,000	6,051,000
Revisions to estimated cash flows	3,076,000	[1]	'	-3,574,000	[1]
Liability Ending Balance	95,225,000		85,042,000	78,425,000
Texas-New Mexico Power Company [Member]	'		'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Liability Beginning Balance	732,000		699,000	648,000
Liabilities incurred	0		0	0
Liabilities settled	-12,000		-25,000	-4,000
Accretion expense	62,000		58,000	55,000
Revisions to estimated cash flows	0	[1]	'	0	[1]
Liability Ending Balance	782,000		732,000	699,000
Palo Verde Nuclear Generating Station [Member] | Public Service Company of New Mexico [Member]	'		'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Asset Retirement Obligation, Period Increase (Decrease)	500,000		'	-4,200,000
San Juan Generating Station [Member] | Public Service Company of New Mexico [Member]	'		'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Asset Retirement Obligation, Period Increase (Decrease)	$2,500,000		'	'
[1]	Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2011 and 2013, new decommissioning studies for PVNGS were implemented reflecting updated cash flow estimates, including the extended operating licenses. The new studies resulted in a $4.2 million decrease to the ARO in 2011 and an increase of $0.5 million to the ARO in 2013. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 21, 2011

Dec. 21, 2011

Nov. 08, 2010

Jun. 18, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2010

Jan. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 12, 2012

Apr. 12, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 06, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

mw

San Juan Generating Station [Member]

Four Corners [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Pnm Electric [Member]

PNMR and PNM [Member]

Fuel and purchased power adjustment clause [Member]

Fuel and purchased power adjustment clause [Member]

Sierra Club Allegations [Member]

Sierra Club Allegations [Member]

Clean Air Act related to Regional Haze [Member]

Clean Air Act related to Post-Combustion Controls [Member]

Clean Air Act related to Post-Combustion Controls [Member]

Mercury Control [Member]

Mercury Control [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Loss on Long-term Purchase Commitment [Member]

Loss on Long-term Purchase Commitment [Member]

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]

Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]

Environmental Protection Agency [Member]

Environmental Protection Agency [Member]

San Juan Underground Mine Fire [Member]

NMTRD Coal Severance Tax [Member]

NMTRD Coal Severance Tax [Member]

Navajo Nation Allottee Matters [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

San Juan Generating Station [Member]

San Juan Generating Station Units 2 and 3 [Member]

Four Corners Units 4 and 5 (Coal) [Member]

San Juan Generating Station Units 1 and 4 [Member]

Other Deferred Credits [Member]

Other Deferred Credits [Member]

Minimum [Member]

Maximum [Member]

Coal Supply [Member]

Coal Supply [Member]

Surface [Member]

Surface [Member]

Surface [Member]

Surface [Member]

Underground [Member]

Underground [Member]

Underground [Member]

Nuclear Plant [Member]

Nuclear Plant [Member]

Commercial Providers [Member]

Industry Wide Retrospective Assessment Program [Member]

San Juan Generating Station Units 2 and 3 [Member]

Palo Verde Nuclear Generating Station Unit 3 [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

San Juan Generating Station [Member]

Public Service Company of New Mexico [Member]

state

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

PNMR and PNM [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act, SNCR [Member]

Clean Air Act related to Post-Combustion Controls [Member]

WildEarth Guardians filed an action to challenge EPA's rule in the Tenth Circuit [Member]

Fuel and purchased power adjustment clause [Member]

Four Corners [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Continuous Highwall Mining [Member]

SJCC Arbitration [Member]

SJCC Arbitration [Member]

Nuclear Spent Fuel And Waste Disposal [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

San Juan Generating Station And Four Corners [Member]

San Juan Generating Station And Four Corners [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

Loss on Long-term Purchase Commitment [Member]

Loss on Long-term Purchase Commitment [Member]

San Juan Generating Station [Member]

Loss on Long-term Purchase Commitment [Member]

Loss on Long-term Purchase Commitment [Member]

San Juan Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

Maximum [Member]

Nuclear Plant [Member]

Nuclear Plant [Member]

MW

Minimum [Member]

Maximum [Member]

San Juan Generating Station [Member]

Four Corners [Member]

Four Corners Units 4 and 5 (Coal) [Member]

San Juan Generating Station [Member]

Maximum [Member]

San Juan Generating Station Unit 4 [Member]

San Juan Generating Station [Member]

San Juan Generating Station Units 2 and 3 [Member]

San Juan Generating Station Units 2 and 3 [Member]

San Juan Generating Station Units 2 and 3 [Member]

Palo Verde Nuclear Generating Station Unit 3 [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

San Juan Generating Station [Member]

Public Service Company of New Mexico [Member]

Four Corners [Member]

Public Service Company of New Mexico [Member]

Nuclear Spent Fuel And Waste Disposal [Member]

Nuclear Spent Fuel And Waste Disposal [Member]

opp

opp

Loss on Long-term Purchase Commitment [Member]

Loss on Long-term Purchase Commitment [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

Palo Verde Nuclear Generating Station [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

compliance_alternative

San Juan Generating Station [Member]

MW

MW

MW

MW

Minimum [Member]

Maximum [Member]

Maximum [Member]

Four Corners [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

San Juan Generating Station [Member]

San Juan Generating Station Units 1 and 4 [Member]

Loss Contingencies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Investments to be Held in Decommissioning Trust Fund

'

'

'

'

'

'

'

'

$4,900,000

$2,600,000

$2,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decommissioning Fund Investments, Fair Value

'

'

'

'

'

'

'

'

222,500,000

189,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Litigation Settlement, Gross

'

'

'

'

'

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Estimate of Possible Loss

'

'

'

'

'

'

'

'

'

'

'

58,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

55,700,000

'

'

93,300,000

'

'

'

'

'

'

'

'

'

'

'

80,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Mine Reclamation and Closing Liability, Noncurrent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,900,000

13,900,000

'

'

'

'

'

23,800,000

26,800,000

'

7,800,000

4,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of States To Address Regional Haze

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Proposed Seeking Shorter Compliance Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

Public Utilities, Number of years after issuance of final determination to achieve compliance with requirements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

Estimated Total Capital Cost If Requirement Occured

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

824,000,000

910,000,000

'

'

'

'

'

'

'

'

'

'

Estimated Installation Capital Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

85,000,000

90,000,000

82,000,000

'

'

'

'

'

'

'

'

'

Estimated Portion of Total Capital Costs if Requirement Occured

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

105,000,000

110,000,000

'

'

'

'

'

'

'

'

'

'

Jointly Owned Utility Plant, Proportionate Ownership Share

'

'

'

'

'

'

'

'

10.20%

[1]

'

'

'

46.30%

'

13.00%

52.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net book value

'

'

'

'

'

'

'

'

'

'

'

'

'

287,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Time Period from completed application to EPA Proposed Action

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'135 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Time Period from EPA Proposed Action to Final Action

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'150 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Time Period to Recover Retired Units NBV

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Expected NBV of Units at Retirement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

205,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Megawatts Nuclear Generation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

134

'

'

'

'

'

'

'

'

'

'

'

'

'

'

134

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Additional Ownership To Be Obtained, in Megawatts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

78

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Overall Reduction Of Ownership, in Megawatts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

340

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

177

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

276,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Compliance alternatives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Ownership Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.06

0.07

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.015

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilitites, Plant Requirment to Meet Opacity Limit, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

48.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current Annual Mercury Control Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contingent Estimated Annual Mercury Control Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Total Litigation Settlement Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Company Share Litigation Settlement Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Mercury Removal Rate, Percentage

'

'

'

99.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other, net

34,590,000

31,490,000

'

'

'

'

30,510,000

27,457,000

'

'

'

'

'

'

'

'

'

'

'

'

12,300,000

9,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Estimated Increase in Coal Cost, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Annual Funding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000

3,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Expected Funding Annual Requirements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Final Reclamation, capped amount to be collected

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Assets

'

'

'

'

'

'

403,611,000

468,446,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preliminary estimate increased deferral related to mine fire incident

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,400,000

21,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Insurance Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,700,000

'

'

'

'

'

'

Public Utilities, Proposed Retroactive Surface Mining Royalty Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.50%

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.00%

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46.30%

'

'

Public Utilities, SJCC Disputed Mining Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000

'

Public Utilities, PNM Share of SJCC Disputed Mining Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

Public Utilities, PNM Share of SJCC Disputed Mining Costs to pass through FPPAC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000

'

Public Utilities, Potential Unbilled Mining Costs Owed to SJCC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,200,000

'

Public Utilities, Potential Overbilled Mining Costs SJCC Owes to SJGS Owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000

'

Public Utilities, Potential Capital Improvements billed as Mining Costs to SJGS Owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,900,000

'

Public Utilities, PNM Share of arbitration ruling

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46.30%

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33.00%

Public Utilities, FFPAC Percentage of capital improvements billed as mining costs ruled by arbitration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

Public Utilities, Assessed Coal Severance Surtax Penalty and Interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30,000,000

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.00%

'

'

'

'

Public Utilities, Liability Insurance Coverage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,600,000,000

375,000,000

13,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Ownership Percentage in Nuclear Reactor

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Maximum Potential Assessment Per Incident

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Annual Payment Limitation Related to Incident

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Aggregate Amount of All Risk Insurance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,750,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Sublimit Amount under Nuclear Electric Insurance Limited

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Maximum Amount under Nuclear Electic Insurance Limited

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$4,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of allotment parcels' appraisal requested for review

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

58

'

'

'

[1]

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

Regulatory_and_Rate_Matters_De

Regulatory and Rate Matters (Details) (USD $)

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Aug. 11, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Aug. 31, 2010

Dec. 31, 2013

Mar. 31, 2013

Jan. 31, 2014

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2011

Oct. 05, 2012

Dec. 31, 2013

Aug. 11, 2011

Dec. 31, 2011

Aug. 21, 2011

31-May-10

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 20, 2011

Dec. 31, 2013

Dec. 31, 2013

Nov. 29, 2010

Jul. 31, 2011

Jul. 03, 2012

Oct. 27, 2010

Dec. 31, 2013

Dec. 06, 2012

Sep. 15, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jan. 31, 2008

Jan. 27, 2011

Aug. 26, 2010

Jun. 30, 2012

Jun. 30, 2012

Jun. 30, 2012

26-May-11

Aug. 28, 2012

Sep. 30, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2013

Jul. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 23, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 02, 2013

Jan. 31, 2013

Jan. 06, 2014

Renewable Portfolio Standard [Member]

2010 Rate Case [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Texas-New Mexico Power Company [Member]

Delta [Member]

San Juan Generating Station Unit 4 [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Navajo Nation Allottee Matters [Member]

Emergency FPPAC [Member]

La Luz Generating Station [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

Renewable Portfolio Standard [Member]

2014 Wind generated Renewable Energy Credits [Member]

Renewable Portfolio Standard Supplemental Procurement [Member]

Renewable Portfolio Standard Supplemental Procurement Reduction [Member]

Renewable Portfolio Standard Supplemental Procurement Reduction [Member]

Energy Efficient and Load Management [Member]

Energy Efficient and Load Management [Member]

Energy Efficient and Load Management [Member]

Energy Efficient and Load Management [Member]

2010 Electric Rate Case [Member]

2010 Electric Rate Case [Member]

2010 Electric Rate Case [Member]

2010 Electric Rate Case [Member]

FPPAC Continuation Application [Member]

Electric Rate Case [Member]

Electric Rate Case [Member]

Renewable Energy Rider [Member]

Renewable Energy Rider [Member]

Renewable Energy Rider [Member]

Renewable Energy Rider [Member]

Nmprc Rulemaking on Disincentives to Energy Efficiency Programs [Member]

Nmprc Rulemaking on Disincentives to Energy Efficiency Programs [Member]

Nmprc Rulemaking on Disincentives to Energy Efficiency Programs [Member]

Nmprc Rulemaking on Disincentives to Energy Efficiency Programs [Member]

2011 Integrated Resource Plan [Member]

Transmission Rate Case [Member]

Transmission Rate Case [Member]

Formula Transmission Rate Case [Member]

Firm Requirements Wholesale Power Rate Case [Member]

Firm Requirements Wholesale Power Rate Case [Member]

City of Gallup, New Mexico Contract [Member]

Renewable Portfolio Standard 2014 [Member]

2015 Wind generated Renewable Energy Credits [Member]

Interest Rate Compliance Tariff [Member]

Interest Rate Compliance Tariff [Member]

2010 Rate Case [Member]

2010 Rate Case [Member]

Ercot Transmission Rates [Member]

Ercot Transmission Rates [Member]

Ercot Transmission Rates [Member]

2010 Rate Case Expense Proceeding [Member]

Energy Efficiency [Member]

Energy Efficiency [Member]

Energy Efficiency [Member]

Energy Efficiency [Member]

Energy Efficiency [Member]

Energy Efficiency [Member]

August 2013 Transmission Rate Filings [Member]

Advanced Meter System Deployment and Surcharge Request [Member]

Advanced Meter System Deployment and Surcharge Request [Member]

Advanced Meter System Deployment and Surcharge Request [Member]

Advanced Meter System Deployment and Surcharge Request [Member]

Transmission Cost of Service Rates [Member]

January 2014 Transmission Rate Filings [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Public Service Company of New Mexico [Member]

Texas-New Mexico Power Company [Member]

Public Service Company of New Mexico [Member]

MW

mw

MW

MW

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Wind Energy [Member]

Wind Energy [Member]

Solar Energy [Member]

Solar Energy [Member]

Renewable Technologies [Member]

Renewable Technologies [Member]

Distributed Generation [Member]

Distributed Generation [Member]

Required Percentage by 2011 [Member]

Required Percentage by 2015 [Member]

Required Percentage by 2020 [Member]

MWh

MW

MW

Maximum [Member]

Program Costs [Member]

Disincentives / Incentives Adder [Member]

Disincentives / Incentives Adder [Member]

Disincentives / Incentives Adder [Member]

Fuel [Member]

Maximum [Member]

Maximum [Member]

Protests_Filed

MW

MWh

PUCT staff agreed to interim rate relief that will permit TNMP to add uncontested costs to its existing TCRF [Member]

Permited to add costs in a subsequent TCRF if TNMP is successful in contested case [Member]

Minimum [Member]

Maximum [Member]

Applications for Approvals to Purchase Delta [Member]

Clean Air Act, SNCR [Member]

Formula Transmission Rate Case [Member]

Transmission Rate Filings [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

MW

MW

MW

Rate Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Expected Rate Increase Over Previously Approved Rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of allotment parcels' appraisal requested for review

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

58

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

15.00%

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Required Percentage of Diversification

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

20.00%

20.00%

20.00%

5.00%

10.00%

1.50%

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Reasonable Cost Threshold

'

'

'

'

'

'

'

'

'

'

3.00%

2.00%

3.00%

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Procurement of Energy, Nonmonetary

'

'

'

'

'

22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Actual Regulatory Costs for Solar PV Facilities and Demonstration Project

95,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilites, Additional Renewable Procurements Spending Required by NMPRC

'

'

'

'

900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Mega Watts of Solar Photovoltaic Capacity

'

'

'

'

'

'

20

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

1.5

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

45,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Mega Watts of Geothermal Capacity

'

'

'

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Final Cost of Solar Photovoltaic Capacity

'

'

'

'

'

'

'

48,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Mega Watt Hours of Wind Generation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Wind Capacity Planned Purchase Agreement Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of Mega Watts of Wind Energy Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

102

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Rider Rate For 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.0022335

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Rider Rate For 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.0028371

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Order Disapproved Recovery of Costs As Regulatory Agency Had Not Acted on Specific Procurements Proposed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Additional Revenue To be Collected in 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Additional Revenue To be Collected in 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider to be Implemented

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,100,000

'

'

'

'

'

'

'

'

'

'

0.0030468

0.0030468

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rider Rate For 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.0044391

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider Recovered

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,600,000

2,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Program Costs Related To Energy Efficiency

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,200,000

2,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Regulatory Costs Approved

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,200,000

'

'

'

'

'

'

'

'

'

'

'

10,250,000

'

'

'

'

2,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,900,000

'

'

Public Utilities, Lease ownership percentage in EIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Eliminated Recovery of Adder Revenue

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider Net Over-Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider Program Costs Over-Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider Incentives Under-Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Rider Estimated Incentives Under-Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Regulatory Costs Not yet Approved

'

'

8,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

165,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,100,000

3,200,000

'

8,700,000

'

'

'

'

'

'

20,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Regulatory Rate Recommended For Recovery

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

72,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Regulatory Costs to be Collected

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

36,200,000

38,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Regulatory Costs Incurred and Eligible For Recovery, Amount Deferred for Collection in Future Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Pre-Tax Loss Not to be Recovered

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,500,000

'

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Retention Percentage of Sales Margins

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Under-collected balance write-off

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Planning Period Covered of IRP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of protests that were filed to IRP requesting rejection of the plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilites, Number of Mega Watts Natural Gas Peaking Units to be Purchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

132

'

'

'

'

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

'

'

'

40

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Installation Capital Costs

'

'

'

63,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate Base Value

'

'

'

56,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Additional Ownership To Be Obtained, in Megawatts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

78

'

'

'

Public Utilities, Return on Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.25%

10.81%

'

'

'

'

'

'

'

10.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Increase Annual Transmission Service Revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

'

'

'

Public Utilities, Regulatory Rate Increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

39.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Total Revenue Requirement Increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,800,000

'

'

'

'

'

2,900,000

'

'

'

2,900,000

'

Public Utilities, Contract Extension

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Estimated Increase in Revenue over amendment term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Revenue For Power Sold Under Specific Contract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Proposed Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.0831

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Regulatory Disallowance Before Income Taxes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utitlities, Debt to Equity Capital Structure, Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.55

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Debt to Equity Capital Structure, Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Deployment Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

113,300,000

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

142.84

247.48

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000

'

'

'

'

'

'

'

'

'

Public Utilities, Non-standard metering ongoing expenses monthly charge

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

38.99

'

'

'

'

'

'

'

'

'

Gain Contingency, Additional Transmission Costs Requested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,200,000

1,600,000

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Program Implementation Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,800,000

'

2,600,000

'

2,700,000

3,400,000

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Recovery Period of Program Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'11 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Program Implementation Costs, Bonus

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000

300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Unapproved 2014 Program Implementation Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Unapproved 2014 Program Implementation Costs, Expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Unapproved 2014 Program Implementation Costs, Bonus

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Unapproved 2014 Program Implementation Costs, Overcollection refund

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Increase in Total Base to Reflect Changes in Invested Capital

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26,400,000

'

'

'

'

'

'

Public Utilities, Additional Revenue from Proposed Rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$18,100,000

'

'

'

'

'

$18,200,000

'

'

'

$21,900,000

'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Electricity, transmission and distribution related services [Member] | TNMP to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	$0	$0	$33,813
Service billings [Member] | TNMP to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	7	15	164
Service billings [Member] | PNMR to PNM [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	92,597	99,986	98,914
Service billings [Member] | PNMR to TNMP [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	28,937	29,110	29,353
Service billings [Member] | PNM to TNMP [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	562	595	550
Service billings [Member] | PNMR to Optim Energy [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	0	0	4,083
Service billings [Member] | Optim Energy to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	0	0	23
Income tax sharing payments [Member] | TNMP to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	3,643	0	0
Income tax sharing payments [Member] | PNMR to PNM [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	77,433	63,114	0
Income tax sharing payments [Member] | PNMR to TNMP [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	0	1,951	0
Interest charges [Member] | TNMP to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	481	137	40
Interest charges [Member] | PNM to PNMR [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amount of related party transaction	$4	$1	$54

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	($81,630)	($66,856)	($68,666)
Amounts reclassified from AOCI (pre-tax)	-5,385	-32,476	-27,511
Income tax impact of amounts reclassified	2,137	12,865	11,027
Other OCI changes (pre-tax)	44,276	8,036	30,335
Income tax impact of other OCI changes	-17,538	-3,199	-12,041
Total Other Comprehensive Income (Loss)	23,490	-14,774	1,810
Ending Balance	-58,140	-81,630	-66,856
Percentage of Pension Liability Adjustment Capitalized into Construction Work In Process	18.70%	'	'
Percentage of Pension Liability Adjustment Capitalized into Other Accounts	3.00%	'	'
Public Service Company of New Mexico [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-81,414	-66,798	-66,786
Amounts reclassified from AOCI (pre-tax)	-5,592	-32,658	-30,946
Income tax impact of amounts reclassified	2,210	12,930	12,251
Other OCI changes (pre-tax)	44,555	8,464	30,926
Income tax impact of other OCI changes	-17,636	-3,352	-12,243
Total Other Comprehensive Income (Loss)	23,537	-14,616	-12
Ending Balance	-57,877	-81,414	-66,798
Texas-New Mexico Power Company [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-216	-58	-1,485
Amounts reclassified from AOCI (pre-tax)	207	182	3,010
Income tax impact of amounts reclassified	-73	-65	-1,073
Other OCI changes (pre-tax)	-279	-428	-793
Income tax impact of other OCI changes	98	153	283
Total Other Comprehensive Income (Loss)	-47	-158	1,427
Ending Balance	-263	-216	-58
Accumulated Net Unrealized Investment Gain (Loss) [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	16,406	15,634	16,211
Amounts reclassified from AOCI (pre-tax)	-11,956	-37,269	-35,251
Income tax impact of amounts reclassified	4,734	14,755	13,956
Other OCI changes (pre-tax)	27,419	38,548	34,295
Income tax impact of other OCI changes	-10,855	-15,262	-13,577
Total Other Comprehensive Income (Loss)	9,342	772	-577
Ending Balance	25,748	16,406	15,634
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Public Service Company of New Mexico [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	16,406	15,634	16,211
Amounts reclassified from AOCI (pre-tax)	-11,956	-37,269	-35,251
Income tax impact of amounts reclassified	4,734	14,755	13,956
Other OCI changes (pre-tax)	27,419	38,548	34,295
Income tax impact of other OCI changes	-10,855	-15,262	-13,577
Total Other Comprehensive Income (Loss)	9,342	772	-577
Ending Balance	25,748	16,406	15,634
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Texas-New Mexico Power Company [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	0	0	0
Amounts reclassified from AOCI (pre-tax)	0	0	0
Income tax impact of amounts reclassified	0	0	0
Other OCI changes (pre-tax)	0	0	0
Income tax impact of other OCI changes	0	0	0
Total Other Comprehensive Income (Loss)	0	0	0
Ending Balance	0	0	0
Accumulated Defined Benefit Plans Adjustment [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-97,820	-82,432	-83,254
Amounts reclassified from AOCI (pre-tax)	6,364	4,611	4,292
Income tax impact of amounts reclassified	-2,524	-1,825	-1,699
Other OCI changes (pre-tax)	17,136	-30,084	-2,958
Income tax impact of other OCI changes	-6,781	11,910	1,187
Total Other Comprehensive Income (Loss)	14,195	-15,388	822
Ending Balance	-83,625	-97,820	-82,432
Accumulated Defined Benefit Plans Adjustment [Member] | Public Service Company of New Mexico [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-97,820	-82,432	-82,981
Amounts reclassified from AOCI (pre-tax)	6,364	4,611	4,278
Income tax impact of amounts reclassified	-2,524	-1,825	-1,694
Other OCI changes (pre-tax)	17,136	-30,084	-3,369
Income tax impact of other OCI changes	-6,781	11,910	1,334
Total Other Comprehensive Income (Loss)	14,195	-15,388	549
Ending Balance	-83,625	-97,820	-82,432
Accumulated Defined Benefit Plans Adjustment [Member] | Texas-New Mexico Power Company [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	0	0	-275
Amounts reclassified from AOCI (pre-tax)	0	0	13
Income tax impact of amounts reclassified	0	0	-5
Other OCI changes (pre-tax)	0	0	414
Income tax impact of other OCI changes	0	0	-147
Total Other Comprehensive Income (Loss)	0	0	275
Ending Balance	0	0	0
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-216	-58	-1,623
Amounts reclassified from AOCI (pre-tax)	207	182	3,448
Income tax impact of amounts reclassified	-73	-65	-1,230
Other OCI changes (pre-tax)	-279	-428	-1,002
Income tax impact of other OCI changes	98	153	349
Total Other Comprehensive Income (Loss)	-47	-158	1,565
Ending Balance	-263	-216	-58
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Public Service Company of New Mexico [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	0	0	-16
Amounts reclassified from AOCI (pre-tax)	0	0	27
Income tax impact of amounts reclassified	0	0	-11
Other OCI changes (pre-tax)	0	0	0
Income tax impact of other OCI changes	0	0	0
Total Other Comprehensive Income (Loss)	0	0	16
Ending Balance	0	0	0
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Texas-New Mexico Power Company [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'	'	'
Beginning Balance	-216	-58	-1,210
Amounts reclassified from AOCI (pre-tax)	207	182	2,997
Income tax impact of amounts reclassified	-73	-65	-1,068
Other OCI changes (pre-tax)	-279	-428	-1,207
Income tax impact of other OCI changes	98	153	430
Total Other Comprehensive Income (Loss)	-47	-158	1,152
Ending Balance	($263)	($216)	($58)

Optim_Energy_Details

Optim Energy (Details) (USD $)	9 Months Ended
	Sep. 30, 2011	Dec. 31, 2012	Sep. 23, 2011	Sep. 22, 2011	Jan. 04, 2012
	Optim Energy [Member]	Optim Energy [Member]	Optim Energy [Member]	Optim Energy [Member]	Optim Energy [Member]
Schedule of Equity Method Investments [Line Items]	'	'	'	'	'
Equity method investment,ownership percentage	'	'	'	50.00%	'
PNMR equity investment in Optim Energy	'	$0	'	'	'
Cost method investment, ownership percentage	'	'	1.00%	'	'
Ownership percentage, sold	'	'	'	'	1.00%
Cost Method Investments	'	'	'	'	0
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]	'	'	'	'	'
Operating revenues	256,800,000	'	'	'	'
Gross margin	84,700,000	'	'	'	'
Net earnings (loss)	$21,400,000	'	'	'	'

Goodwill_and_Other_Intangible_1

Goodwill and Other Intangible Assets; Impairments (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2012

Apr. 02, 2012

Dec. 31, 2008

Dec. 31, 2013

Apr. 03, 2013

Dec. 31, 2012

Apr. 02, 2012

Dec. 31, 2008

Customer Lists [Member]

Customer Lists [Member]

Trade Names [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]

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]

First Choice [Member]

Schedule of Goodwill and Other Intangible Assets [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Finite-Lived Intangible Asset, Useful Life

'

'

'

'8 years

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

$278,297,000

$278,297,000

$278,297,000

'

'

'

'

$226,665,000

$226,665,000

'

'

$51,632,000

'

$51,632,000

'

'

Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount

'

'

'

'

'

'

'

'

'

26.00%

'

'

27.00%

'

15.00%

'

Goodwill, Reporting Unit, Sensitivity analysis, Percentage Increase in Expected Return on Equity

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

Goodwill, Reporting Unit, Sensitivity analysis, Reduced Percentage of Fair Value in Excess of Carrying Value

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

'

Goodwill, Impairment Loss

'

'

'

'

'

'

34,500,000

'

'

'

51,100,000

'

'

'

'

88,800,000

Impairment of Intangible Assets, Indefinite-lived (Excluding Goodwill)

'

'

'

'

'

42,600,000

'

'

'

'

'

'

'

'

'

'

Impairment of Intangible Assets, Finite-lived

'

'

'

'

$4,800,000

'

'

'

'

'

'

'

'

'

'

'

Quarterly_Operating_Results_Un2

Quarterly Operating Results (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	'	'	'	'	'	'	'	'	'	'	$1,700,619
Operating revenues	322,929	399,730	347,599	317,665	322,758	390,411	323,860	305,374	1,387,923	1,342,403	1,700,619
Operating income	40,532	117,739	77,867	50,704	36,736	118,150	65,106	53,729	286,842	273,721	257,299
Net earnings	11,397	58,814	31,383	13,962	12,573	61,976	25,099	20,477	115,556	120,125	190,934
Earnings Attributable to PNMR	7,648	54,555	27,678	10,626	9,091	57,864	21,512	17,080	100,507	105,547	176,359
Net Earnings Attributable to PNMR per Common Share:	'	'	'	'	'	'	'	'	'	'	'
Basic (dollars per share)	$0.10	$0.68	$0.35	$0.13	$0.11	$0.73	$0.27	$0.21	$1.26	$1.32	$1.98
Diluted (dollars per share)	$0.10	$0.68	$0.34	$0.13	$0.11	$0.72	$0.27	$0.21	$1.25	$1.31	$1.96
Public Service Company of New Mexico [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	252,702	326,026	279,690	257,894	260,023	321,731	260,094	250,416	1,116,312	1,092,264	1,057,289
Operating income	18,427	95,217	58,302	37,239	20,135	96,973	46,669	42,105	209,185	205,882	161,443
Net earnings	6,256	51,950	29,697	14,773	9,293	54,891	20,340	21,077	102,676	105,601	68,538
Earnings Attributable to PNMR	2,639	47,823	26,124	11,569	5,943	50,911	16,885	17,812	88,155	91,551	54,491
Texas-New Mexico Power Company [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Electric Domestic Regulated Revenue	70,227	73,704	67,909	59,771	62,736	68,680	63,766	54,958	271,611	250,140	204,045
Operating revenues	'	'	'	'	'	'	'	'	271,611	250,140	237,858
Operating income	17,210	22,254	19,667	13,054	15,862	20,970	18,897	11,791	72,185	67,520	63,842
Earnings Attributable to PNMR	$6,919	$10,106	$8,339	$3,726	$6,634	$9,084	$8,018	$3,011	$29,090	$26,747	$22,257

Schedule_I_Condensed_Financial2

Schedule I - Condensed Financial Information of Parent Company (Statements of Earnings) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating Expenses	'	'	'	'	'	'	'	'	$1,101,081	$1,068,682	$1,443,320
Operating income	40,532	117,739	77,867	50,704	36,736	118,150	65,106	53,729	286,842	273,721	257,299
Other Income and Deductions:	'	'	'	'	'	'	'	'	'	'	'
Other income	'	'	'	'	'	'	'	'	10,572	12,746	5,309
Other (deductions)	'	'	'	'	'	'	'	'	-21,552	-17,636	-24,715
Net other income and deductions	'	'	'	'	'	'	'	'	9,675	22,159	180,019
Earnings before Income Taxes	'	'	'	'	'	'	'	'	175,069	175,035	312,469
Income Tax Expense (Benefit)	'	'	'	'	'	'	'	'	59,513	54,910	121,535
Net Earnings (Loss) Attributable to Company	7,648	54,555	27,678	10,626	9,091	57,864	21,512	17,080	100,507	105,547	176,359
PNM Resources [Member]	'	'	'	'	'	'	'	'	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Non-affiliates	'	'	'	'	'	'	'	'	0	0	0
Operating Expenses	'	'	'	'	'	'	'	'	941	3,287	20,547
Operating income	'	'	'	'	'	'	'	'	-941	-3,287	-20,547
Other Income and Deductions:	'	'	'	'	'	'	'	'	'	'	'
Equity in earnings of subsidiaries	'	'	'	'	'	'	'	'	116,634	117,900	205,215
Other income	'	'	'	'	'	'	'	'	769	670	59
Other (deductions)	'	'	'	'	'	'	'	'	-22,825	-20,904	-34,124
Net other income and deductions	'	'	'	'	'	'	'	'	94,578	97,666	171,150
Earnings before Income Taxes	'	'	'	'	'	'	'	'	93,637	94,379	150,603
Income Tax Expense (Benefit)	'	'	'	'	'	'	'	'	-6,870	-11,168	-25,756
Net Earnings (Loss) Attributable to Company	'	'	'	'	'	'	'	'	$100,507	$105,547	$176,359

Schedule_I_Condensed_Financial3

Schedule I - Condensed Financial Information of Parent Company (Statement of Cash flow) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows From Operating Activities:	'	'	'
Net earnings (loss)	$100,507	$105,547	$176,359
Depreciation and amortization	208,173	206,499	195,366
Deferred income tax expense	60,430	56,243	124,424
(Gain) on reacquired debt	3,253	0	9,209
Stock based compensation expense	5,320	3,585	6,556
Changes in certain assets and liabilities:	'	'	'
Other current assets	8,577	-2,598	-21,979
Other assets	-12,801	-30,778	-15,835
Accounts payable	4,484	14,020	20,969
Accrued interest and taxes	91,537	255	7,304
Other current liabilities	-19,648	-19,905	3,460
Other liabilities	-61,262	-70,743	-6,735
Net cash flows from operating activities	386,587	281,349	292,240
Cash Flows From Investing Activities:	'	'	'
Utility plant additions	-348,039	-308,909	-326,931
Other, net	4,096	4,943	-17
Net cash flows from investing activities	-331,446	-285,895	19,778
Cash Flows From Financing Activities:	'	'	'
Short-term borrowings (repayments), net	-9,500	-24,000	-139,300
Repayment of long-term debt	-29,468	-22,387	-110,752
Purchase of preferred stock	0	0	-73,475
Purchase of common stock	0	0	-125,683
Proceeds from stock option exercise	4,618	11,684	5,622
Purchases to satisfy awards of common stock	-13,807	-25,168	-10,104
Dividends paid	-51,508	-45,137	-45,656
Net cash flows from financing activities	-61,593	-1,560	-312,331
Change in Cash and Cash Equivalents	-6,452	-6,106	-313
Cash and Cash Equivalents at Beginning of Year	8,985	15,091	15,404
Cash and Cash Equivalents at End of Year	2,533	8,985	15,091
Supplemental Cash Flow Disclosures:	'	'	'
Interest paid	99,382	113,265	116,391
Income taxes paid (refunded), net	-95,327	5,302	-5,527
PNM Resources [Member]	'	'	'
Cash Flows From Operating Activities:	'	'	'
Net earnings (loss)	100,507	105,547	176,359
Depreciation and amortization	4,192	5,000	7,654
Deferred income tax expense	-51,820	-46,632	-34,396
Equity in (earnings) loss of subsidiaries	-116,634	-117,900	-205,215
(Gain) on reacquired debt	3,253	0	9,209
Stock based compensation expense	5,320	3,585	6,556
Changes in certain assets and liabilities:	'	'	'
Other current assets	28,460	-43,638	42,687
Other assets	46,558	34,096	59,975
Accounts payable	620	8	-1
Accrued interest and taxes	-9,266	-28,855	27,348
Other current liabilities	-146	3,876	4,765
Other liabilities	-27,756	-29,601	-12,854
Net cash flows from operating activities	-16,712	-114,514	82,087
Cash Flows From Investing Activities:	'	'	'
Utility plant additions	-960	-7,524	0
Investments in subsidiaries	-13,800	0	-43,000
Investments in Optim Energy	0	0	0
Cash dividends from subsidiaries	158,772	61,406	285,757
Net cash flows from investing activities	144,012	53,882	242,757
Cash Flows From Financing Activities:	'	'	'
Short-term borrowings (repayments), net	-37,600	120,900	-15,300
Short-term borrowings (repayments) – affiliate, net	0	0	300
Repayment of long-term debt	-29,468	-2,387	-60,391
Purchase of preferred stock	0	0	-73,475
Purchase of common stock	0	0	-125,683
Proceeds from stock option exercise	4,618	11,684	5,622
Purchases to satisfy awards of common stock	-13,807	-25,168	-10,104
Excess tax (shortfall) from stock-based payment arrangements	0	0	0
Dividends paid	-50,980	-44,609	-45,128
Other, net	0	0	-747
Net cash flows from financing activities	-127,237	60,420	-324,906
Change in Cash and Cash Equivalents	63	-212	-62
Cash and Cash Equivalents at Beginning of Year	29	241	303
Cash and Cash Equivalents at End of Year	92	29	241
Supplemental Cash Flow Disclosures:	'	'	'
Interest paid	14,510	15,007	19,215
Income taxes paid (refunded), net	$22,378	$1,501	$5,454

Schedule_I_Condensed_Financial4

Schedule I - Condensed Financial Information of Parent Company (Balance Sheets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Assets	'	'	'	'
Cash and cash equivalents	$2,533	$8,985	$15,091	$15,404
Income taxes receivable	7,066	101,477	'	'
Other, net	34,590	31,490	'	'
Total current assets	401,539	442,191	'	'
Property, plant and equipment, net of accumulated depreciation of $9,167 and $8,262	3,933,911	3,746,487	'	'
Other Long-term assets	1,835	5,599	'	'
Total Assets	5,500,210	5,372,583	5,204,613	'
Liabilities and Stockholders' Equity	'	'	'	'
Short-term debt	149,200	158,700	'	'
Current maturities of long-term debt	75,000	2,530	'	'
Accrued interest and taxes	49,600	52,003	'	'
Other current liabilities	77,105	75,407	'	'
Total current liabilities	492,671	434,103	'	'
Long-term Debt	1,670,420	1,669,760	'	'
Total liabilities	3,738,083	3,672,024	'	'
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369	1,182,819	'	'
Accumulated other comprehensive income (loss), net of tax	-58,140	-81,630	-66,856	-68,666
Retained earnings	553,340	506,998	'	'
Total PNMR common stockholders' equity	1,673,569	1,608,187	'	'
Total liabilities and stockholders' equity	5,500,210	5,372,583	'	'
PNM Resources [Member]	'	'	'	'
Assets	'	'	'	'
Cash and cash equivalents	92	29	241	303
Intercompany receivables	136,387	108,875	'	'
Income taxes receivable	14,989	41,434	'	'
Other, net	8,544	2,204	'	'
Total current assets	160,012	152,542	'	'
Property, plant and equipment, net of accumulated depreciation of $9,167 and $8,262	26,601	25,642	'	'
Long-term Investments	0	3,651	'	'
Investment in subsidiaries	1,683,321	1,688,168	'	'
Other Long-term assets	53,892	49,302	'	'
Total long-term assets	1,763,814	1,766,763	'	'
Total Assets	1,923,826	1,919,305	'	'
Liabilities and Stockholders' Equity	'	'	'	'
Short-term debt	100,000	137,600	'	'
Short-term debt-affiliate	8,819	8,819	'	'
Current maturities of long-term debt	0	2,530	'	'
Accrued interest and taxes	2,797	3,127	'	'
Other current liabilities	16,876	13,218	'	'
Total current liabilities	128,492	165,294	'	'
Long-term Debt	118,766	142,592	'	'
Other long-term liabilities	2,999	3,232	'	'
Total liabilities	250,257	311,118	'	'
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369	1,182,819	'	'
Accumulated other comprehensive income (loss), net of tax	-58,140	-81,630	'	'
Retained earnings	553,340	506,998	'	'
Total PNMR common stockholders' equity	1,673,569	1,608,187	'	'
Total liabilities and stockholders' equity	$1,923,826	$1,919,305	'	'

Schedule_I_Condensed_Financial5

Schedule I - Condensed Financial Information of Parent Company (Parenthetical) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Nov. 04, 2011
In Thousands, except Share data, unless otherwise specified
Condensed Financial Statements, Captions [Line Items]	'	'	'
Common stock, par value	$0	$0	'
Common stock, shares authorized	120,000,000	120,000,000	'
Common stock, shares issued	79,653,624	79,653,624	'
Common stock, shares outstanding	79,653,624	79,653,624	7,019,550
PNM Resources [Member]	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Accumulated Depreciation	$9,167	$8,262	'
Common stock, par value	$0	$0	'
Common stock, shares authorized	120,000,000	120,000,000	'
Common stock, shares issued	79,653,624	79,653,624	'
Common stock, shares outstanding	79,653,624	79,653,624	'

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'		'
Balance at beginning of year	$1,751	$1,778	[1]	$11,178
Charged to costs and expenses	2,849	3,367		24,116
Charged to other accounts	0	0		0
Write-offs and other	3,177	3,394	[1]	33,516
Balance at end of year	1,423	1,751		1,778	[1]
Public Service Company of New Mexico [Member]	'	'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'		'
Balance at beginning of year	1,751	1,778		1,483
Charged to costs and expenses	2,864	3,384		3,736
Charged to other accounts	0	0		0
Write-offs and other	3,192	3,411		3,441
Balance at end of year	1,423	1,751		1,778
Texas-New Mexico Power Company [Member]	'	'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'		'
Balance at beginning of year	0	0		0
Charged to costs and expenses	-15	-17		33
Charged to other accounts	0	0		0
Write-offs and other	-15	-17		33
Balance at end of year	0	0		0
First Choice [Member]	'	'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'		'
Write-offs and other	'	'		$11,818
[1]	Includes reduction of $11,818 due to the sale of First Choice on November 1, 2011.