10-Q/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(Mark One)

 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

Commission File Number	Name of Registrants, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
001-32462	PNM Resources, Inc.	85-0468296
	(A New Mexico Corporation)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(505) 241-2700
001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(505) 241-2700
002-97230	Texas-New Mexico Power Company	75-0204070
	(A Texas Corporation)
	577 N. Garden Ridge Blvd.
	Lewisville, Texas 75067
	(972) 420-4189

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

PNM Resources, Inc. (“PNMR”)	YES	ü	NO
Public Service Company of New Mexico (“PNM”)	YES	ü	NO
Texas-New Mexico Power Company (“TNMP”)	YES		NO	ü

(NOTE: As a voluntary filer, not subject to the filing requirements, TNMP filed all reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PNMR	YES	ü	NO
PNM	YES	ü	NO
TNMP	YES	ü	NO

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).

	Large accelerated filer		Accelerated filer	Non-accelerated filer		Smaller Reporting Company
PNMR		ü
PNM					ü
TNMP					ü

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES   NO ü

As of August 2, 2011, 86,673,174 shares of common stock, no par value per share, of PNMR were outstanding.

The total number of shares of common stock of PNM outstanding as of August 2, 2011 was 39,117,799 all held by PNMR (and none held by non-affiliates).

The total number of shares of common stock of TNMP outstanding as of August 2, 2011 was 6,358 all held indirectly by PNMR (and none held by non-affiliates).

PNM AND TNMP MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (H) (1) (a) AND (b) OF FORM 10-Q AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION (H) (2).

This combined Form 10-Q is separately filed by PNMR, PNM, and TNMP.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Each registrant makes no representation as to information relating to the other registrants.   When this Form 10-Q is incorporated by reference into any filing with the SEC made by PNMR, PNM, or TNMP, as a registrant, the portions of this Form 10-Q that relate to each other registrant are not incorporated by reference therein.

EXPLANATORY NOTE REGARDING AMENDMENT NO. 1

The purpose of this Amendment No. 1 to the Quarterly Report on Form 10-Q (“Amendment No. 1”) is to amend Part II, Item 6, Exhibits of each registrant's Quarterly Report on Form 10-Q for the period ended June 30, 2011, initially filed with the Securities and Exchange Commission (“SEC”) on August 9, 2011 (the “Original Filings”). This Amendment No. 1 is being filed solely to furnish Exhibit 101 to the Original Filings as required by Rule 405 of Regulation S-T.

In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, the text of the amended Part II, Item 6 is set forth in its entirety herein, including those portions that have not been amended from that set forth in the Original Filings.  This Amendment No. 1 does not otherwise update any information or exhibits as originally filed and does not otherwise reflect events occurring after the filing date of the Original Filings.

Pursuant to Rule 406T of Regulation S-T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

ITEM 6. EXHIBITS

3.1	PNMR	Articles of Incorporation of PNM Resources, as amended to date (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed November 21, 2008)
3.2	PNM	Restated Articles of Incorporation of PNM, as amended through May 31, 2002 (incorporated by reference to Exhibit 3.1.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
3.3	TNMP	Articles of Incorporation of TNMP, as amended through July 7, 2005 (incorporated by reference to Exhibit 3.1.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
3.4	PNMR	Bylaws of PNM Resources, Inc. with all amendments to and including February 17, 2009 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed February 20, 2009)
3.5	PNM	Bylaws of PNM with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to the Company’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)
3.6	TNMP	Bylaws of TNMP as adopted on August 4, 2005 (incorporated by reference to Exhibit 3.2.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
*4.1	PNMR	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNMR, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 15, 2005 PNMR Indenture)
*4.2	PNM	Agreement of Resignation, Appointment and Acceptance, effective as of May 1, 2011, among PNM, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 11, 1998 PNM Indenture)
*4.3	PNM	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNM, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for August 1, 1998 PNM Indenture)
*4.4	TNMP	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among TNMP, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 23, 2009 TNMP Indenture)
*10.1	PNMR	Letter Agreement, dated as of May 5, 2011, between PNM Resources, Inc. and Cascade Investment, L.L.C.
*12.1	PNMR	Ratio of Earnings to Fixed Charges
*12.2	PNMR	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
*12.3	PNM	Ratio of Earnings to Fixed Charges
*12.4	TNMP	Ratio of Earnings to Fixed Charges
*31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2	PNM	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	PNMR, PNM, and TNMP	XBRL Instance Document
101.SCH	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Schema Document
101.CAL	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed with the Original Filings.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)
Date:	September 6, 2011	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

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Capitalization, Short-term Debt (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Short-term Debt [Line Items]
Short-term debt	$ 304,000	$ 222,000
PNM Resources [Member] | Revolving credit facility [Member]
Short-term Debt [Line Items]
Short-term debt	31,000	32,000
PNM Resources [Member] | Local lines of credit [Member]
Short-term Debt [Line Items]
Short-term debt	0	0
Public Service Company of New Mexico [Member]
Short-term Debt [Line Items]
Short-term debt	273,000	190,000
Public Service Company of New Mexico [Member] | Revolving credit facility [Member]
Short-term Debt [Line Items]
Short-term debt	273,000	190,000
Texas-New Mexico Power Company [Member] | Revolving credit facility [Member]
Short-term Debt [Line Items]
Short-term debt	0	0
Line of Credit [Member]
Short-term Debt [Line Items]
Short-term debt	$ 304,000	$ 222,000

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Condensed Consolidated Balance Sheets (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 14,023	$ 15,404
Accounts receivable, net of allowance for uncollectible accounts of $9,275 and $11,178	103,824	97,245
Unbilled revenues	97,513	71,453
Other receivables	46,596	58,901
Affiliate receivables	2,392	1,661
Materials, supplies, and fuel stock	51,370	52,479
Regulatory assets	29,608	36,292
Commodity derivative instruments	18,840	15,999
Income taxes receivable	102,317	97,450
Current portion of accumulated deferred income taxes	886	886
Other current assets	99,919	96,110
Total current assets	567,288	543,880
Other Property and Investments:
Investment in PVNGS lessor notes	90,555	103,871
Investments held by NDT	168,513	156,922
Other investments	15,645	18,791
Non-utility property, net of accumulated depreciation of $2,333 and $2,307	12,317	7,333
Total other property and investments	287,030	286,917
Utility Plant:
Plant in service and plant held for future use	4,959,239	4,860,614
Less accumulated depreciation and amortization	1,665,970	1,626,693
Net plant in service and plant held for future use	3,293,269	3,233,921
Construction work in progress	139,340	137,622
Nuclear fuel, net of accumulated amortization of $29,993 and $26,247	79,906	72,901
Net utility plant	3,512,515	3,444,444
Deferred Charges and Other Assets:
Regulatory assets	478,599	502,467
Goodwill	321,310	321,310
Other intangible assets, net of accumulated amortization of $5,511 and $5,414	26,329	26,425
Commodity derivative instruments	7,754	5,264
Other deferred charges	100,808	94,376
Total deferred charges and other assets	934,800	949,842
Assets	5,301,633	5,225,083
Current Liabilities:
Short-term debt	304,000	222,000
Current installments of long-term debt	2,252	2,252
Accounts payable	111,460	95,969
Accrued interest and taxes	45,852	47,783
Regulatory liabilities	919	724
Commodity derivative instruments	27,285	31,407
Dividends declared	132	11,565
Other current liabilities	97,547	108,424
Total current liabilities	589,447	520,124
Long-term Debt	1,563,916	1,563,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	543,044	540,106
Accumulated deferred investment tax credits	16,930	18,089
Regulatory liabilities	358,141	342,465
Asset retirement obligations	75,483	76,637
Accrued pension liability and postretirement benefit cost	250,671	270,172
Commodity derivative instruments	13,770	12,831
Other deferred credits	149,610	147,616
Total deferred credits and other liabilities	1,407,649	1,407,916
Total liabilities	3,561,012	3,491,635
Commitments and Contingencies (See Note 9)
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
Equity:
Company Convertible Preferred Stock, Series A without mandatory redemption requirements	100,000	100,000
Common stock outstanding	1,290,969	1,290,465
Accumulated other comprehensive income (loss), net of income taxes	(70,691)	(68,666)
Retained earnings	324,217	314,943
Total PNMR common stockholders' equity	1,544,495	1,536,742
Non-controlling interest in Valencia	84,597	85,177
Total equity	1,729,092	1,721,919
Total liabilities and stockholders' equity	5,301,633	5,225,083
Public Service Company of New Mexico [Member]
Current Assets:
Cash and cash equivalents	485	10,336
Accounts receivable, net of allowance for uncollectible accounts of $9,275 and $11,178	53,121	58,785
Unbilled revenues	52,200	39,053
Other receivables	45,494	56,951
Affiliate receivables	9,053	8,605
Materials, supplies, and fuel stock	48,624	49,454
Regulatory assets	26,344	35,835
Commodity derivative instruments	935	1,443
Income taxes receivable	82,662	76,941
Other current assets	49,185	46,635
Total current assets	368,103	384,038
Other Property and Investments:
Investment in PVNGS lessor notes	90,555	103,871
Investments held by NDT	168,513	156,922
Other investments	4,118	5,068
Non-utility property, net of accumulated depreciation of $2,333 and $2,307	976	976
Total other property and investments	264,162	266,837
Utility Plant:
Plant in service and plant held for future use	3,898,460	3,818,722
Less accumulated depreciation and amortization	1,283,394	1,259,957
Net plant in service and plant held for future use	2,615,066	2,558,765
Construction work in progress	121,238	115,628
Nuclear fuel, net of accumulated amortization of $29,993 and $26,247	79,906	72,901
Net utility plant	2,816,210	2,747,294
Deferred Charges and Other Assets:
Regulatory assets	345,728	357,944
Goodwill	51,632	51,632
Commodity derivative instruments	5	0
Other deferred charges	74,314	67,828
Total deferred charges and other assets	471,679	477,404
Assets	3,920,154	3,875,573
Current Liabilities:
Short-term debt	273,000	190,000
Accounts payable	57,003	51,931
Affiliate payables	17,862	8,528
Accrued interest and taxes	27,298	25,773
Regulatory liabilities	919	724
Commodity derivative instruments	1,720	3,110
Dividends declared	3,781	39,254
Current portion of accumulated deferred income taxes	9,783	9,783
Other current liabilities	64,281	65,858
Total current liabilities	455,647	394,961
Long-term Debt	1,055,756	1,055,748
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	440,579	446,657
Accumulated deferred investment tax credits	16,930	18,089
Regulatory liabilities	316,109	299,763
Asset retirement obligations	74,707	75,888
Accrued pension liability and postretirement benefit cost	235,737	253,948
Commodity derivative instruments	1,841	2,009
Other deferred credits	111,122	108,455
Total deferred credits and other liabilities	1,197,025	1,204,809
Total liabilities	2,708,428	2,655,518
Commitments and Contingencies (See Note 9)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements	11,529	11,529
Equity:
Common stock outstanding	1,018,776	1,018,776
Accumulated other comprehensive income (loss), net of income taxes	(68,468)	(66,786)
Retained earnings	165,292	171,359
Total PNMR common stockholders' equity	1,115,600	1,123,349
Non-controlling interest in Valencia	84,597	85,177
Total equity	1,200,197	1,208,526
Total liabilities and stockholders' equity	3,920,154	3,875,573
Texas-New Mexico Power Company [Member]
Current Assets:
Cash and cash equivalents	1	1
Accounts receivable, net of allowance for uncollectible accounts of $9,275 and $11,178	16,740	12,742
Unbilled revenues	7,534	5,734
Other receivables	1,208	1,677
Affiliate receivables	5,316	3,956
Materials, supplies, and fuel stock	2,713	2,787
Regulatory assets	3,264	457
Current portion of accumulated deferred income taxes	1,876	1,876
Other current assets	1,265	618
Total current assets	39,917	29,848
Other Property and Investments:
Other investments	268	282
Non-utility property, net of accumulated depreciation of $2,333 and $2,307	2,240	2,244
Total other property and investments	2,508	2,526
Utility Plant:
Plant in service and plant held for future use	903,429	885,325
Less accumulated depreciation and amortization	313,482	302,333
Net plant in service and plant held for future use	589,947	582,992
Construction work in progress	14,043	12,375
Net utility plant	603,990	595,367
Deferred Charges and Other Assets:
Regulatory assets	132,871	144,522
Goodwill	226,665	226,665
Other deferred charges	12,474	12,029
Total deferred charges and other assets	372,010	383,216
Assets	1,018,425	1,010,957
Current Liabilities:
Short-term debt – affiliate	7,000	1,200
Accounts payable	5,507	5,537
Affiliate payables	3,306	1,015
Accrued interest and taxes	17,150	23,185
Other current liabilities	4,016	3,292
Total current liabilities	36,979	34,229
Long-term Debt	310,650	310,337
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	146,692	142,121
Regulatory liabilities	42,032	42,702
Asset retirement obligations	671	648
Accrued pension liability and postretirement benefit cost	14,934	16,224
Other deferred credits	12,418	11,413
Total deferred credits and other liabilities	216,747	213,108
Total liabilities	564,376	557,674
Commitments and Contingencies (See Note 9)
Equity:
Paid-in-capital	423,042	430,108
Common stock outstanding	64	64
Accumulated other comprehensive income (loss), net of income taxes	(1,918)	(1,485)
Retained earnings	32,861	24,596
Total PNMR common stockholders' equity	454,049	453,283
Total liabilities and stockholders' equity	$ 1,018,425	$ 1,010,957

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Allowance for uncollectible accounts	$ 9,275	$ 11,178
Accumulated depreciation, non-utility property	2,333	2,307
Accumulated depreciation, nuclear fuel	29,993	26,247
Accumulated depreciation, other intangible assets	5,511	5,414
Cumulative preferred stock of subsidiary, stated value	$ 100.00	$ 100.00
Cumulative preferred stock of subsidiary, shares authorized	115,293	115,293
Cumulative preferred stock of subsidiary, shares authorized	10,000,000	50,000
Cumulative preferred stock of subsidiary, shares issued	115,293	115,293
Convertible preferred stock, stated value	$ 0.00	$ 0.00
Convertible preferred stock, shares authorized	10,000,000	10,000,000
Convertible preferred stock, shares issued	477,800	477,800
Convertible preferred stock, shares outstanding	477,800	477,800
Common stock, par value	$ 0.00	$ 0.00
Common stock, shares authorized	120,000,000	120,000,000
Common stock, shares issued	86,673,174	86,673,174
Common stock, shares outstanding	86,673,174	86,673,174
Public Service Company of New Mexico [Member]
Allowance for uncollectible accounts	1,483	1,483
Accumulated depreciation, nuclear fuel	$ 29,993	$ 26,247
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]
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

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Pension and Other Postretirement Benefit Plans (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Public Service Company of New Mexico [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 0	$ 0	$ 0	$ 0
Interest cost	8,202,000	8,518,000	16,402,000	17,037,000
Long-term return on plan assets	(9,269,000)	(9,339,000)	(18,537,000)	(18,677,000)
Amortization of net loss	2,302,000	1,613,000	4,605,000	3,225,000
Amortization of prior service cost	79,000	79,000	158,000	158,000
Net periodic benefit cost	1,314,000	871,000	2,628,000	1,743,000
Defined Benefit Plan, Contributions by Employer	7,500,000	0	13,500,000	6,500,000
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	28,000,000		28,000,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	190,000,000		190,000,000
Public Service Company of New Mexico [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	65,000	105,000	129,000	210,000
Interest cost	1,345,000	1,913,000	2,689,000	3,825,000
Long-term return on plan assets	(1,347,000)	(1,393,000)	(2,694,000)	(2,786,000)
Amortization of net loss	801,000	1,372,000	1,603,000	2,744,000
Amortization of prior service cost	(662,000)	(1,036,000)	(1,324,000)	(2,071,000)
Net periodic benefit cost	202,000	961,000	403,000	1,922,000
Defined Benefit Plan, Contributions by Employer	1,200,000	1,200,000	1,200,000	1,200,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	2,500,000		2,500,000
Public Service Company of New Mexico [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	233,000	263,000	465,000	527,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	23,000	18,000	47,000	35,000
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	256,000	281,000	512,000	562,000
Defined Benefit Plan, Contributions by Employer	400,000	400,000	800,000	700,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	1,500,000		1,500,000
Texas-New Mexico Power Company [Member] | Maximum [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Contributions by Employer	100,000	100,000	100,000	100,000
Texas-New Mexico Power Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	951,000	1,032,000	1,900,000	2,063,000
Long-term return on plan assets	(1,368,000)	(1,449,000)	(2,735,000)	(2,897,000)
Amortization of net loss	86,000	0	173,000	0
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	(331,000)	(417,000)	(662,000)	(834,000)
Defined Benefit Plan, Contributions by Employer	100,000	0	200,000	0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	1,000,000		1,000,000
Defined Benefit Plan, Estimated Future Employer Contributions After Current Fiscal Year	6,500,000		6,500,000
Texas-New Mexico Power Company [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	77,000	72,000	153,000	144,000
Interest cost	163,000	178,000	327,000	356,000
Long-term return on plan assets	(133,000)	(129,000)	(267,000)	(257,000)
Amortization of net loss	(48,000)	(49,000)	(96,000)	(98,000)
Amortization of prior service cost	15,000	15,000	30,000	30,000
Net periodic benefit cost	74,000	87,000	147,000	175,000
Defined Benefit Plan, Contributions by Employer	400,000	600,000	400,000	600,000
Texas-New Mexico Power Company [Member] | Executive Retirement Program [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0	0	0	0
Interest cost	12,000	13,000	23,000	26,000
Long-term return on plan assets	0	0	0	0
Amortization of net loss	0	(1,000)	0	(2,000)
Amortization of prior service cost	0	0	0	0
Net periodic benefit cost	12,000	12,000	23,000	24,000
Defined Benefit Plan Total Expected Employer Contributions for Fiscal Year	$ 100,000		$ 100,000

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Goodwill and Other Intangible Assets

6 Months Ended

Jun. 30, 2011

Goodwill and Other Intangible Assets [Abstract]

Goodwill and Intangible Assets Disclosure [Text Block]

Goodwill and Other Intangible Assets

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 is considered to have an indefinite useful life; therefore, no amortization is recorded. The useful life of the customer list was estimated to be approximately eight years.

The Company evaluates 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. 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. A discounted cash flow methodology is primarily used to estimate the fair value of each 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 for each reporting unit.

For non-amortizing intangibles other than goodwill, the Company compares the fair value of the intangible asset to its recorded value. For goodwill, the first step of the impairment test requires that the Company compare the fair value of each reporting unit with its carrying value, including goodwill. If as a result of this analysis, the Company concludes there is an indication of impairment in a reporting unit having goodwill, the Company is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the Company 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.

The annual evaluations performed as of April 1, 2011 and 2010 did not indicate impairments of the goodwill or other intangible assets of any of the Company’s reporting units. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill, other intangible assets, and impairments is contained in Note 25 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

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Document and Entity Information Document	6 Months Ended
	Jun. 30, 2011	Aug. 02, 2011
Document Information [Line Items]
Entity Registrant Name	PNM RESOURCES INC
Entity Central Index Key	0001108426
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		86,673,174
Public Service Company of New Mexico [Member]
Document Information [Line Items]
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Central Index Key	0000081023
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		39,117,799
Texas-New Mexico Power Company [Member]
Document Information [Line Items]
Entity Registrant Name	TEXAS NEW MEXICO POWER CO
Entity Central Index Key	0000022767
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		6,358

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Stock-Based Compensation (Details) (USD $)	6 Months Ended
	Jun. 30, 2011 years		Jun. 30, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period, Shares	3,948,262
Options, Outstanding at beginning of period, Weighted-Average Exercise Price	$ 18.33
Options, Granted, Shares	0
Options, Granted, Weighted-Average Exercise Price	$ 0.00
Options, Exercised, Shares	(199,683)
Options, Exercised, Weighted-Average Exercise Price	$ 11.01
Options, Forfeited, Shares	(8,333)
Options, Forfeited, Weighted-Average Exercise Price	$ 11.33
Options, Expired, Shares	(47,936)
Options, Expired, Weighted-Average Exercise Price	$ 24.51
Options, Outstanding at end of period, Shares	3,692,310
Options, Outstanding at end of period, Weighted-Average Exercise Price	$ 18.66
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Outstanding at end of period, Aggregate Intrinsic Value	$ 9,793,593	[1]
Options, Outstanding at end of period, Weighted-Average Remaining Contract Life (years)	5.36
Options, Exercisable at end of period, Shares	3,152,000
Options, Exercisable at end of period, Weighted-Average Exercise Price	$ 21.86
Options, Exercisable at end of period, Aggregate Intrinsic Value	6,663,441
Options, Exercisable at end of period, Weighted-Average Remaining Contract Life (years)	4.85
Options, Outstanding at end of period, No intrinsic value	1,978,010
Weighted-average grant date fair value options granted (dollars per share)	$ 0.00		$ 3.05
Total fair value of options that vested	1,189,000		1,027,000
Total intrinsic value of options exercised	2,199,000		329,000
Executive [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options / Restricted Stock available for future grant	560,461
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested Restricted Stock, Granted, Shares	88,913
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options / Restricted Stock available for future grant	4,763,254	[2]
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested Restricted Stock, Nonvested at beginning of period, Shares	237,021
Nonvested Restricted Stock, Nonvested at beginning of period, Weighted-Average Grant-Date Fair Value	$ 9.24
Nonvested Restricted Stock, Granted, Shares	308,985
Nonvested Restricted Stock, Granted, Weighted-Average Grant-Date Fair Value	$ 13.10		$ 9.37
Nonvested Restricted Stock, Vested, Shares	(110,757)
Nonvested Restricted Stock, Vested, Weighted-Average Grant-Date Fair Value	$ 9.69
Nonvested Restricted Stock, Forfeited, Shares	0
Nonvested Restricted Stock, Forfeited, Weighted-Average Grant-Date Fair Value	$ 0.00
Nonvested Restricted Stock, Nonvested at end of period, Shares	435,249
Nonvested Restricted Stock, Nonvested at end of period, Weighted-Average Grant-Date Fair Value	$ 11.91
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 1,073,000		$ 1,308,000
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Expected Quarterly Dividend Rate	$ 0.125		$ 0.125
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.20%		1.36%

[1] At June 30, 2011, the exercise price of 1,978,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

[2] Includes shares available for grants of restricted stock.

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2011

Variable Interest Entities [Abstract]

Noncontrolling Interest Summarized Financial Information [Table Text Block]

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	4,849		$	4,725		$	9,519		$	9,227
Operating expenses	(1,379		)	(1,433		)	(2,867		)	(2,831		)
Earnings attributable to non-controlling interest	$	3,470		$	3,292		$	6,652		$	6,396

Financial Position

	June 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,158	$	2,372
Net property, plant and equipment	82,200		83,617
Total assets	85,358		85,989
Current liabilities	761		812
Owners’ equity – non-controlling interest	$	84,597	$	85,177

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Earnings Per Share (Details) (USD $) In Thousands, except Share data	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Schedule of Earnings Per Share Basic and Diluted [Line Items]
Net Earnings Attributable to PNMR	$ 4,067		$ 22,878		$ 20,704		$ 14,429
Average Number of Common Shares:
Outstanding during period	86,673,000		86,673,000		86,673,000		86,673,000
Equivalents from convertible preferred stock	4,778,000		4,778,000		4,778,000		4,778,000
Vested awards of restricted stock	139,000		109,000		149,000		102,000
Average Shares - Basic	91,590,000		91,560,000		91,600,000		91,553,000
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	546,000	[1]	273,000	[1]	502,000	[1]	141,000	[1]
Average Shares - Diluted	92,136,000		91,833,000		92,102,000		91,694,000
Net Earnings Per Share of Common Stock
Basic (dollars per share)	$ 0.04		$ 0.25		$ 0.23		$ 0.16
Diluted (dollars per share)	$ 0.04		$ 0.25		$ 0.22		$ 0.16
Share Based Compensation Arrangement by Share Based Payment Award Options Outstanding Shares Above Entities Stock Price					1,978,010

[1] Excludes the effect of out-of-the-money options for 1,978,010 shares of common stock at June 30, 2011.

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Fair Value of Derivative and Other Financial Instruments

6 Months Ended

Jun. 30, 2011

Fair Value of Derivative and Other Financial Instruments [Abstract]

Derivatives and Fair Value [Text Block]

Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The Company is exposed to certain risks relating to its ongoing business operations. 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 or fuel used to generate electricity, or to manage anticipated generation capacity in excess of forecasted demand from existing customers. Substantially all of the Company’s energy related derivative contracts manage commodity risk and the Company does not currently engage in speculative trading.

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. The Company 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. The Company monitors the market risk of its commodity contracts using VaR and GEaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

PNM is required to meet the demand and energy needs of its retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the requirements of 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 retail load requirements were to be greater than anticipated. If all or a portion of retail load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

First Choice is 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 are negotiated with each customer. First Choice buys wholesale power in the competitive ERCOT wholesale market and sells power to retail customers in the competitive ERCOT retail market. Many of these retail customers buy power from First Choice for a contracted period of time at a fixed price so First Choice is exposed to price risk if the wholesale power price changes during the time of the contract. First Choice’s strategy is to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. However, if actual fixed price retail loads vary significantly from forecasts (for example, due to extreme weather, other significant load changes or contract breaches), First Choice could have 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 sales and purchases exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal sales and purchases are not marked to market and are reflected in results of operations when the underlying transactions 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. 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. Based on market prices at June 30, 2011, after-tax losses of less than $0.1 million for PNMR and zero for PNM would be reclassified from AOCI into earnings during the next twelve months. However, the actual amount reclassified into earnings may vary due to changes in the timing or nature of the underlying transactions. As of June 30, 2011 and December 31, 2010, the Company is 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 either economic hedges or trading transactions. 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. Trading transactions included speculative transactions, which the Company ceased in 2008, and transactions that lock in margin with no forward market risk and are not economic hedges. Changes in the fair value of these transactions are reflected on a net basis in operating revenues.

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 own 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.

The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements. At June 30, 2011 and December 31, 2010, amounts recognized for the legal right to reclaim cash collateral were $4.6 million and $3.4 million for PNMR and $2.6 million and $3.0 million for PNM. In addition, at June 30, 2011 and December 31, 2010, amounts posted as cash collateral under margin arrangements were $26.7 million and $32.0 million for PNMR and $1.4 million and $2.1 million for PNM. Cash collateral amounts are included in other current assets on the Condensed Consolidated Balance Sheets. PNMR and PNM had no obligations to return cash collateral at June 30, 2011 and December 31, 2010.

Commodity Derivatives

Commodity derivative instruments are summarized as follows:

	PNMR						PNM
	Economic Hedges						Economic Hedges
	June 30, 2011			December 31, 2010			June 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	18,840		$	15,999		$	935		$	1,443
Deferred charges	7,754			5,264			5			—
	26,594			21,263			940			1,443
Current liabilities	(27,285		)	(31,407		)	(1,720		)	(3,110		)
Long-term liabilities	(13,770		)	(12,831		)	(1,841		)	(2,009		)
	(41,055		)	(44,238		)	(3,561		)	(5,119		)
Net	$	(14,461	)	$	(22,975	)	$	(2,621	)	$	(3,676	)

The Company had no trading or designated cash flow hedge transactions at June 30, 2011 and December 31, 2010. On April 20, 2010, PNM received NMPRC approval of a hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.3 million of current assets and $0.1 million of current liabilities at June 30, 2011 and $0.6 million of current assets at December 31, 2010 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets.

The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	June 30,						June 30,					June 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	190		$	(121	)	$	—	$	(36	)	$	—		$	6,539
Cost of energy	(4,594		)	2,720			—		—			(318		)	(771		)
Total gain (loss)	$	(4,404	)	$	2,599		$	—	$	(36	)	$	(318	)	$	5,768
Recognized in OCI												$	318		$	(5,581	)
PNM
Electric operating revenues	$	190		$	(121	)	$	—	$	—		$	—		$	6,539
Cost of energy	(284		)	(37		)	—		—			—			(41		)
Total gain (loss)	$	(94	)	$	(158	)	$	—	$	—		$	—		$	6,498
Recognized in OCI												$	—		$	(6,311	)
Six Months Ended
PNMR
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	(33	)	$	—		$	13,288
Cost of energy	86			(29,229		)	—		—			(249		)	(1,246		)
Total gain (loss)	$	1,420		$	(31,236	)	$	—	$	(33	)	$	(249	)	$	12,042
Recognized in OCI												$	249		$	(4,818	)
PNM
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	—		$	—		$	13,288
Cost of energy	159			(3,662		)	—		—			—			14
Total gain (loss)	$	1,493		$	(5,669	)	$	—	$	—		$	—		$	13,302
Recognized in OCI												$	—		$	(6,078	)

Commodity contract volume positions are presented in Decatherms 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
	Decatherms	MWh
June 30, 2011
PNMR	21,657,500	3,646,080
PNM	1,810,000	(1,237,793	)
December 31, 2010
PNMR	22,767,500	1,693,431
PNM	1,882,500	(990,120	)

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 such counterparty with “adequate assurance” that the Company will perform; and others have no provision for collateral.

The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
June 30, 2011
PNMR	$	9,543	$	2,580	$	1,675
PNM	$	3,047	$	2,580	$	370
December 31, 2010
PNMR	$	8,113	$	—	$	2,642
PNM	$	291	$	—	$	119

Sale of Power from PVNGS Unit 3

In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW.  Under two of the contracts, PNM sold 90 MW of firm capacity and energy.  Under the third contract, PNM sold 45 MW of unit contingent capacity and energy. The term of the contracts was May 1, 2008 through December 31, 2010.  Under the two firm contracts, the two buyers made prepayments of $40.6 million and $30.0 million.  These amounts were recorded as deferred revenue and were amortized over the life of the contracts. The prepayments received under the firm contracts, as well as required subsequent monthly payments on them, are shown as a financing activity in the Condensed Consolidated Statements of Cash Flows as required by GAAP. The firm contracts were accounted for as cash flow hedges and changes in fair value were included in AOCI. The contingent contract was accounted for as a normal sale. Beginning January 1, 2011, PNM is selling its 135 MW interest in PVNGS Unit 3 daily at market prices. PNM has established fixed rates for the majority of these sales through the end of 2011 through financial hedging arrangements that are accounted for as economic hedges.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS. The NDT holds equity and fixed income securities. PNMR and PNM do not have any unrealized losses on available-for-sale securities. The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table.

	June 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	2,525	$	27,986	$	5,108	$	25,491
Domestic growth	19,453		56,245		17,239		48,237
Multinational	405		14,089		2,730		10,670
Fixed income securities:
Municipals	1,630		38,884		837		37,595
U.S. Government	490		21,390		348		21,541
Corporate and other	606		9,195		573		8,402
Cash and equivalents	—		724		—		4,986
	$	25,109	$	168,513	$	26,835	$	156,922

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	46,770		$	15,586		$	94,890		$	36,285
Gross realized gains	$	8,700		$	1,526		$	13,490		$	3,431
Gross realized (losses)	$	(554	)	$	(510	)	$	(2,282	)	$	(1,872	)

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, including the EIP lessor note.

The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value, except for the PVNGS lessor notes shown below. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.

At June 30, 2011, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	1,988	$	—	$	—
After 1 year through 5 years	20,208		139,108		128,034
After 5 years through 10 years	10,784		3,262		—
Over 10 years	36,489		—		—
	$	69,469	$	142,370	$	128,034

The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:

	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,168	$	1,722,785	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	15,645	$	20,766	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,756	$	1,079,797	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	4,118	$	4,432	$	5,068	$	5,563
TNMP
Long-term debt	$	310,650	$	417,378	$	310,337	$	385,220
Other investments	$	268	$	268	$	282	$	282

The fair value of long-term debt shown above was primarily determined using quoted market values, as were certain items included in other investments. To the extent market values were not available, fair value was determined by discounting the cash flows for the instrument using quoted interest rates for comparable instruments.

Other Fair Value Disclosures

The Company determines the fair values of its derivative and other instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity 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 NDT investments, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. Fair values of Level 3 commodity derivatives are determined in a manner similar to those in Level 2, but are at a lower level in the hierarchy due to low transaction volume or market illiquidity that significantly limits the availability of observable market data.

Derivatives and Investments

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets are as follows:

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
June 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	724		$	724		$	—		$	—
Equity securities:
Domestic value	27,986			27,986			—			—
Domestic growth	56,245			56,245			—			—
Multinational	14,089			14,089			—			—
Fixed income securities:
U.S. government	21,390			16,797			4,593			—
Municipals	38,884			—			38,884			—
Corporate and other	9,195			—			9,195			—
Total NDT investments	$	168,513		$	115,841		$	52,672		$	—
PNMR
Commodity derivative assets	$	26,594		$	10,891		$	9,908		$	5,282
Commodity derivative liabilities	(41,055		)	(25,360		)	(14,292		)	(890		)
Net	$	(14,461	)	$	(14,469	)	$	(4,384	)	$	4,392
PNM
Commodity derivative assets	$	940		$	—		$	940		$	—
Commodity derivative liabilities	(3,561		)	—			(3,561		)	—
Net	$	(2,621	)	$	—		$	(2,621	)	$	—

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
December 31, 2010	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	4,986		$	4,986		$	—		$	—
Equity securities:
Domestic value	25,491			25,491			—			—
Domestic growth	48,237			48,237			—			—
Multinational	10,670			10,670			—			—
Fixed income securities:
U.S. government	21,541			16,613			4,928			—
Municipals	37,595			—			37,595			—
Corporate and other	8,402			—			8,402			—
Total NDT investments	$	156,922		$	105,997		$	50,925		$	—
PNMR
Commodity derivative assets	$	21,263		$	8,646		$	12,308		$	272
Commodity derivative liabilities	(44,238		)	(26,378		)	(16,729		)	(1,094		)
Net	$	(22,975	)	$	(17,732	)	$	(4,421	)	$	(822	)
PNM
Commodity derivative assets	$	1,443		$	—		$	1,443		$	—
Commodity derivative liabilities	(5,119		)	—			(5,119		)	—
Net	$	(3,676	)	$	—		$	(3,676	)	$	—

(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $0.5 million for PNMR and zero for PNM at June 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and six months ended June 30, 2011 and 2010.

A reconciliation of the changes in Level 3 fair value measurements is as follows:

	PNMR						PNM
	June 30,						June 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	894		$	85		$	—	$	—
Total gains (losses) included in earnings	3,676			(437		)	—		—
Purchases	2,617			—			—		—
Settlements	(2,795		)	74			—		—
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	1,954		$	(363	)	$	—	$	—
Six Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	5,226			(814		)	—		(128		)
Purchases	2,735			—			—		—
Settlements	(2,747		)	288			—		145
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	3,122		$	(543	)	$	—	$	—

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

	PNMR					PNM
	June 30,					June 30,
	2011		2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,676		(437		)	—		—
Total	$	3,676	$	(437	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	1,954		(363		)	—		—
Total	$	1,954	$	(363	)	$	—	$	—
Six Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	5,226		(814		)	—		(128		)
Total	$	5,226	$	(814	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,122		(543		)	—		—
Total	$	3,122	$	(543	)	$	—	$	—

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.

PNMR SEGMENT INFORMATION

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2011	(In thousands)
Operating revenues	$	239,234		$	50,359		$	126,036		$	(43	)	$	415,586
Intersegment revenues	—			9,598			—			(9,598		)	—
Total revenues	239,234			59,957			126,036			(9,641		)	415,586
Cost of energy	81,497			10,259			91,296			(9,598		)	173,454
Gross margin	157,737			49,698			34,740			(43		)	242,132
Other operating expenses	124,297			25,277			23,630			(2,204		)	171,000
Depreciation and amortization	22,897			10,726			360			4,289			38,272
Operating income (loss)	10,543			13,695			10,750			(2,128		)	32,860
Interest income	4,225			—			31			(22		)	4,234
Other income (deductions)	4,484			259			(273		)	(1,648		)	2,822
Net interest charges	(18,027		)	(7,305		)	(141		)	(5,039		)	(30,512		)
Segment earnings (loss) before income taxes	1,225			6,649			10,367			(8,837		)	9,404
Income taxes (benefit)	(872		)	2,547			3,745			(3,685		)	1,735
Segment earnings (loss)	2,097			4,102			6,622			(5,152		)	7,669
Valencia non-controlling interest	(3,470		)	—			—			—			(3,470		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	(1,505	)	$	4,102		$	6,622		$	(5,152	)	$	4,067
Six Months Ended June 30, 2011
Operating revenues	$	473,472		$	95,387		$	234,486		$	(96	)	$	803,249
Intersegment revenues	—			18,412			—			(18,412		)	—
Total revenues	473,472			113,799			234,486			(18,508		)	803,249
Cost of energy	170,711			20,412			159,250			(18,412		)	331,961
Gross margin	302,761			93,387			75,236			(96		)	471,288
Other operating expenses	227,423			44,981			42,616			(5,556		)	309,464
Depreciation and amortization	46,632			20,987			641			8,485			76,745
Operating income (loss)	28,706			27,419			31,979			(3,025		)	85,079
Interest income	8,282			—			34			(55		)	8,261
Other income (deductions)	9,702			575			(379		)	(3,250		)	6,648
Net interest charges	(36,107		)	(14,604		)	(286		)	(10,130		)	(61,127		)
Segment earnings (loss) before income taxes	10,583			13,390			31,348			(16,460		)	38,861
Income taxes (benefit)	1,522			5,125			11,237			(6,643		)	11,241
Segment earnings (loss)	9,061			8,265			20,111			(9,817		)	27,620
Valencia non-controlling interest	(6,652		)	—			—			—			(6,652		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	2,145		$	8,265		$	20,111		$	(9,817	)	$	20,704
At June 30, 2011:
Total Assets	$	3,920,154		$	1,018,425		$	254,352		$	108,702		$	5,301,633
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	16,514		$	360		$	237		$	1,165		$	18,276

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2010	(In thousands)
Operating revenues	$	243,060		$	42,934		$	119,916		$	(93	)	$	405,817
Intersegment revenues	—			9,635			—			(9,635		)	—
Total revenues	243,060			52,569			119,916			(9,728		)	405,817
Cost of energy	79,639			9,057			72,121			(9,636		)	151,181
Gross margin	163,421			43,512			47,795			(92		)	254,636
Other operating expenses	107,107			19,031			21,253			(3,805		)	143,586
Depreciation and amortization	22,924			10,040			210			4,202			37,376
Operating income (loss)	33,390			14,441			26,332			(489		)	73,674
Interest income	5,081			—			11			(9		)	5,083
Equity in net earnings (loss) of Optim Energy	—			—			—			(3,858		)	(3,858		)
Other income (deductions)	(1,991		)	283			(90		)	(1,546		)	(3,344		)
Net interest charges	(18,385		)	(7,953		)	(387		)	(5,036		)	(31,761		)
Segment earnings (loss) before income taxes	18,095			6,771			25,866			(10,938		)	39,794
Income taxes (benefit)	5,901			2,665			9,313			(4,387		)	13,492
Segment earnings (loss)	12,194			4,106			16,553			(6,551		)	26,302
Valencia non-controlling interest	(3,292		)	—			—			—			(3,292		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	8,770		$	4,106		$	16,553		$	(6,551	)	$	22,878
Six Months Ended June 30, 2010
Operating revenues	$	473,596		$	81,525		$	234,306		$	(215	)	$	789,212
Intersegment revenues	—			19,221			—			(19,221		)	—
Total revenues	473,596			100,746			234,306			(19,436		)	789,212
Cost of energy	166,073			18,107			177,111			(19,222		)	342,069
Gross margin	307,523			82,639			57,195			(214		)	447,143
Other operating expenses	215,900			37,822			41,701			(7,091		)	288,332
Depreciation and amortization	45,776			20,135			473			8,271			74,655
Operating income (loss)	45,847			24,682			15,021			(1,394		)	84,156
Interest income	10,015			—			13			82			10,110
Equity in net earnings (loss) of Optim Energy	—			—			—			(8,210		)	(8,210		)
Other income (deductions)	9,167			630			(98		)	(2,943		)	6,756
Net interest charges	(36,462		)	(15,822		)	(697		)	(10,190		)	(63,171		)
Segment earnings (loss) before income taxes	28,567			9,490			14,239			(22,655		)	29,641
Income taxes (benefit)	8,822			3,740			5,139			(9,149		)	8,552
Segment earnings (loss)	19,745			5,750			9,100			(13,506		)	21,089
Valencia non-controlling interest	(6,396		)	—			—			—			(6,396		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	13,085		$	5,750		$	9,100		$	(13,506	)	$	14,429
At June 30, 2010:
Total Assets	$	3,813,524		$	1,013,131		$	239,035		$	337,832		$	5,403,522
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

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Fair Value of Derivative and Other Financial Instruments, Debt Maturities (Details) (USD $) In Thousands	Jun. 30, 2011
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale debt securities, Within 1 year	$ 1,988
Available-for-sale debt securities, After 1 year through 5 years	20,208
Available-for-sale debt securities, After 5 years through 10 years	10,784
Available-for-sale debt securities, Over 10 years	36,489
Available-for-sale debt securities	69,469
Held-to-maturity Securities, Debt Maturities, Fair Value [Abstract]
Held-to-maturity debt securities, Due within 1 year	0
Held-to-maturity debt securities, After 1 year through 5 years	139,108
Held-to-maturity debt securities, After 5 years through 10 years	3,262
Held-to-maturity debt securities, Over 10 years	0
Held-to-maturity debt securities	142,370
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	0
Held-to-maturity debt securities, After 1 year through 5 years	128,034
Held-to-maturity debt securities, After 5 years through 10 years	0
Held-to-maturity debt securities, Over 10 years	0
Held-to-maturity debt securities	$ 128,034

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Fair Value of Derivative and Other Financial Instruments, Derivative Balance Sheet Information (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	$ 18,840	$ 15,999
Commodity derivative instruments, Deferred charges	7,754	5,264
Commodity derivative instruments, Current liabilities	(27,285)	(31,407)
Commodity derivative instruments, Long-term liabilities	(13,770)	(12,831)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Fuel and Purchased Power Adjustment Clause [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	300	600
Commodity derivative instruments, Current liabilities	(100)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	935	1,443
Commodity derivative instruments, Deferred charges	5	0
Commodity derivative instruments, Assets	940	1,443
Commodity derivative instruments, Current liabilities	(1,720)	(3,110)
Commodity derivative instruments, Long-term liabilities	(1,841)	(2,009)
Commodity derivative instruments, Liabilities	(3,561)	(5,119)
Commodity derivative instruments, Net	(2,621)	(3,676)
Commodity Contract [Member] | Economic hedges [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	18,840	15,999
Commodity derivative instruments, Deferred charges	7,754	5,264
Commodity derivative instruments, Assets	26,594	21,263
Commodity derivative instruments, Current liabilities	(27,285)	(31,407)
Commodity derivative instruments, Long-term liabilities	(13,770)	(12,831)
Commodity derivative instruments, Liabilities	(41,055)	(44,238)
Commodity derivative instruments, Net	(14,461)	(22,975)
Trading transactions [Member]
Derivatives, Fair Value [Line Items]
Number of Derivative Transactions	0	0
Cash flow hedges [Member]
Derivatives, Fair Value [Line Items]
Number of Derivative Transactions	0	0
Public Service Company of New Mexico [Member]
Derivatives, Fair Value [Line Items]
Commodity derivative instruments, Current assets	935	1,443
Commodity derivative instruments, Deferred charges	5	0
Commodity derivative instruments, Current liabilities	(1,720)	(3,110)
Commodity derivative instruments, Long-term liabilities	$ (1,841)	$ (2,009)

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Significant Accounting Policies and Responsibility for Financial Statements (Policies)

6 Months Ended

Jun. 30, 2011

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. In addition, PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

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 is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal 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 proceedings on its results of operations or financial position. It is the Company's policy to accrue for expected liabilities in accordance with GAAP when it is probable that a liability has been incurred and the amount to be incurred is reasonably estimable. 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 adverse effect on its financial condition, results of operations, or cash flows, although the outcome of litigation, investigations, and other legal proceedings is inherently uncertain.

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, is not reasonably estimable. 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 subject to the known uncertainty of litigation. The Company has established appropriate reserves 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.

Additional information concerning commitments and contingencies is contained in Note 16 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance under the contract. PNM estimates that it will incur approximately $42.8 million (in 2010 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS. Such estimate reflects the impact of the extension of the PVNGS operating licenses discussed in Note 13 below. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is consumed. At June 30, 2011 and December 31, 2010, PNM recorded interim storage costs of $15.1 million and $14.8 million in other deferred credits.

The Clean Air Act

Regional Haze

The EPA has established rules addressing regional haze and guidelines for BART determinations. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. In particular, the rules define how an SO₂ emissions trading program developed by the Western Regional Air Partnership, a voluntary organization of western states, tribes, and federal agencies, can be used by western states. New Mexico will be participating in the SO₂ program, which is a trading program that will be implemented if SO₂ reduction milestones are not met.

SJGS

In November 2006, the NMED requested a BART analysis for NOx and particulates for each of the four units at SJGS. PNM submitted its analysis to the NMED in June 2007, recommending against installing additional pollution control equipment on any of the SJGS units beyond those planned at that time, the installation of which was completed in March 2009. PNM subsequently provided additional data in response to requests from the NMED. On June 21, 2010, the NMED filed its proposed regional haze SIP with the EIB. The NMED filing included a finding by the NMED that BART for NOx at SJGS is a technology known as “selective catalytic reduction” (“SCR”) plus “sorbent injection.” PNM disagreed with this proposed BART determination.

As part of its 2007 submission, PNM identified additional control technology alternatives, including SCR, to already planned pollution control equipment upgrades and evaluated the feasibility of these technologies for the purpose of reducing visibility impacts in accordance with EPA's "Guidelines for BART Determinations under the Regional Haze Rules" (“BART Guidelines”). PNM concluded that SCR was not appropriate as BART. Using the EPA's BART Guidelines, PNM estimated the installation of SCR technology at SJGS would cost approximately $750 million to $1 billion for the entire station, of which PNM's share would be 46.3% based on its SJGS ownership percentage. The SCR technology would also increase operating costs at SJGS.

PNM recently contracted with an independent engineering design firm to prepare a detailed conceptual design and cost estimate for installation of SCR at SJGS. That analysis utilized scaled vendor estimates and was submitted to the EPA on July 20, 2011. Although there are certain differences between the two analyses, the new cost estimate is consistent with PNM's earlier BART analysis cost estimate range and continues to support PNM's contention that EPA's SCR cost estimates are unrealistically low.

Under a consent decree it signed with WildEarth Guardians in 2010, the EPA was required to issue a proposed FIP regarding interstate transport for certain states, including New Mexico, by November 11, 2010, which was later extended to December 22, 2010, if no proposed SIP had been submitted. Interstate transport requires states to have adequate provisions to prohibit emissions from adversely affecting air quality in other states. EPA Region 6 issued a proposed interstate transport FIP, which was published in the Federal Register on January 5, 2011. The proposed FIP included a BART determination for NOx controls at SJGS that requires SCR installation on all four units within three years of the final order, rather than the five-year implementation schedule the regional haze rules generally allow and that EPA proposed for Four Corners. The proposed FIP did not require sorbent injection. The proposed FIP provided for a proposed emission limit for NOx at SJGS of 0.05 pounds per MMBTU, whereas the EPA's proposed emission limit for NOx at Four Corners is 0.098 pounds per MMBTU. The public comment period on the proposed FIP ended on April 4, 2011. The deadline for the final FIP was extended to August 5, 2011 pursuant to an agreement between EPA and WildEarth Guardians.

NMED withdrew its June 21, 2010 proposed regional haze SIP on December 17, 2010. On February 28, 2011, the NMED filed a new petition with the EIB to consider an interstate transport SIP and a regional haze SIP. Among other things, the draft regional haze SIP concludes that selective non-catalytic reduction (“SNCR”) controls are BART for SJGS. SNCR controls meet EPA's presumptive NOx BART limit of 0.23 pounds per MMBTU for wall-fired boilers burning sub-bituminous coal. The proposed SIP would require installation of SNCR controls within five years. PNM estimates the installation of SNCR technology at SJGS would cost approximately $77 million for the entire station, of which PNM's share would be 46.3%. The EIB approved the NMED's proposed regional haze and interstate transport SIPs in June 2011 upon conclusion of public hearings and the Governor of New Mexico submitted the SIPs to the EPA on June 24, 2011.

PNM filed extensive technical and legal comments on the proposed FIP with the EPA, including a statement in support of the then-draft SIP. Since the EIB had approved a SIP, PNM believed that the EPA must consider that SIP. Only the interstate transport rule was subject to the August 5, 2011 court-ordered deadline for a final FIP. In order to meet that deadline and at the same time give due consideration to the SIP, the Governor of New Mexico had requested that EPA finalize the FIP associated with the interstate transport rule by August 5, 2011 and stay any action on the proposed FIP for regional haze until New Mexico's SIP revisions had been fully considered and either approved or disapproved. On August 5, 2011, the EPA issued its final FIP which requires SCR technology and allows for a five-year implementation schedule. The final FIP provides for an emission limit for NOx at SJGS of 0.05 pounds per MMBTU. PNM will file an appeal with the United States Court of Appeals for the Tenth Circuit within the required time frame, which is within 60 days after the final FIP is published in the Federal Register. The appeal would not stop the implementation timeframe unless a court issues a stay. As stated above, PNM believes that SCR technology is not appropriate for BART at SJGS and that the state's SIP which calls for SNCR provides reasonable progress toward visibility improvements required under the EPA rules. The EPA indicated on August 5, 2011, that it would continue to review the state's SIP but that the EPA had already evaluated SNCR as part of the FIP and had ruled SNCR out as BART for San Juan.

PNM will seek recovery from its ratepayers of all costs that may ultimately be incurred as a result of the final FIP. While PNM cannot accurately predict the impact of these requirements on PNM's ratepayers until requirements, if any, are finalized, it estimates that the installation of SCR controls would cost the average residential PNM customer approximately $85 for the first yearwith slowly declining costs for an estimated 20 years and that costs to businesses would be higher.

On January 19, 2011, multiple parties filed with the EPA a NOI to sue under the Clean Air Act for the EPA's failure to promulgate a FIP within two years of a finding that certain states, including New Mexico, had failed to make all or part of a required regional haze SIP submittal. The NOI alleges that the deadline for final promulgation of regional haze FIPs or full approval of regional haze SIPs was January 15, 2011. The same parties also filed a separate NOI to sue under the Clean Air Act for EPA's failure to take final action on SIP submissions by multiple states, including New Mexico, within 18 months of receipt of submission.

PNM is unable to predict the ultimate outcome of these matters or what, if any, additional pollution control equipment will ultimately be required or approved for installation for SJGS. If additional equipment is required and/or final requirements result in additional operating costs to be incurred, PNM believes that its access to the capital markets are sufficient to be able to finance the installation and that equipment and financing costs should be recoverable through the ratemaking process and would seek recovery of them. However, PNM can provide no assurance that all such amounts will be recovered from ratepayers. It is possible thatrequirements to comply with the final BART determinations, 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 of individual participants to continue participation in the plant.

Four Corners

EPA Region 9 previously requested that APS, as the operating agent for Four Corners, perform a BART analysis for Four Corners. APS submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA's rulemaking process, the EPA will determine what it believes constitutes BART for Four Corners.

On October 6, 2010, the EPA issued its proposed BART determination for Four Corners. The rule, as proposed, would require the installation of SCR as post-combustion controls on each of Units 1-5 at Four Corners to reduce NOx emissions. As previously disclosed, PNM's total costs could be up to approximately $69.0 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. The EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the coal-fired plant. On November 8, 2010, 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. Completion of the purchase by APS, which is expected to occur in the second half of 2012, is subject to the receipt of various regulatory approvals. Closing is also conditioned on the execution of a new coal supply contract for the lease renewal period described under Coal Supply below and other conditions. Pursuant to an agreement among the Four Corners participants, the other participants had a right of first refusal to purchase shares of SCE's interests proportional to their current ownership percentages. The exercise of this purchase right expired on March 8, 2011 and neither PNM nor any of the other participants exercised this right. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2, and 3 at the plant (PNM has no ownership interest in Four Corners Units 1, 2, and 3).

On November 24, 2010, APS submitted a letter to the EPA proposing an alternative to the EPA's October 2010 BART proposal. Specifically, APS proposed to close Four Corners Units 1, 2, and 3 by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that the EPA agrees to a contemporaneous resolution of Four Corners' obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the NSR program, and NSPS programs of the Clean Air Act.

On February 10, 2011, the EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, the EPA proposed to find that a different alternative emission control strategy, based upon APS's November 2010 proposal, would achieve more progress than the EPA's October 2010 BART proposal. The Supplemental Notice proposes that Units 1, 2, and 3 would close by 2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by the EPA in October 2010. The EPA proposals are subject to public comment. On July 15, 2011, various environmental groups filed a NOI to sue EPA because it failed to promulgate regional haze FIPs for Four Corners and Navajo Generating Station. PNM is not an owner of Navajo Generating Station. The NOI states that the EPA has failed to fulfill its nondiscretionary duty under the Clean Air Act to submit a BART determination for the plants without unreasonable delay. The Clean Air Act requires parties to give EPA 180 days' notice before commencing a lawsuit based on allegations that the EPA unreasonably delayed performance of a nondiscretionary act.

In addition, on February 16, 2010, a group of environmental organizations filed a petition with the DOI and DOA requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners and other plants. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the DOI and DOA, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. On June 30, 2011, the court issued its opinion dismissing the plaintiffs' claims explaining that because the DOI and DOA reached a “definitive decision” to deny the plaintiffs' petitions, the court is unable to grant further relief to the plaintiffs and, therefore, their claims must be dismissed as moot.

The Four Corners participants' obligations to comply with the EPA's final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, the result of the lawsuit mentioned above, 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 proposed BART determination for Four Corners. As proposed, the participant owners of Four Corners will have five years after the EPA issues its final determination to achieve compliance with the BART requirements. PNM is unable to predict the ultimate outcome of this matter.

Ozone Non-Attainment

In March 2009, the NMED published its draft recommendation of area designations for the 2008 revised ozone national ambient air quality standard. The draft recommended that San Juan County, New Mexico be designated as non-attainment for ozone. SJGS is situated in San Juan County. However, the NMED subsequently determined that the monitor indicating high ozone levels was not reliable and did not recommend to the EPA that San Juan County be designated as non-attainment. On January 6, 2010, the EPA announced it would strengthen the 8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). The EPA had intended to establish a new ozone standard by July 31, 2011, but has delayed the announcement of its rule. Depending upon where the standard is set, San Juan County could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county back into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone in the presence of sunlight. As a result, SJGS could be required to put on additional NOx controls as early as 2014. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. A non-attainment designation for Bernalillo County could result in the requirement to reduce NOxemissions from Reeves Station as early as 2014. The Company cannot predict the outcome of this matter 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 the SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes a provision whereby stipulated penalties are assessed 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 for each quarter. As required by the Consent Decree, PNM submitted reports addressing mercury and NOx emission controls for SJGS. Plaintiffs and NMED rejected PNM's reports. PNM disputes the validity of the rejection of the reports. On May 17, 2010, PNM filed a petition with the federal district court seeking a judicial determination on the dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement mercury controls that PNM estimates would increase annual operating costs for the entire station by as much as $42 million. The court held a status conference on November 29, 2010 for purposes of establishing the appropriate process for resolution of the outstanding disputes related to this matter and to discuss other issues raised in PNM's petition. PNM cannot predict the outcome of this matter.

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, enacted in 1995 by the Navajo Nation, 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, Window Rock District, challenging the applicability of the Navajo Acts to Four Corners. The District Court stayed these proceedings pursuant to a request by the parties and the parties are seeking to negotiate a settlement.

In 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations.Each of the Four Corners participants filed a petition with the Navajo Nation Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the outcome of the settlement negotiations mentioned above.

In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement resolving the dispute regarding 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 Clean Air Act. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts.

The Company cannot currently predict the outcome of these matters or the range of their potential impacts.

Section 114 Request

On April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been subject to notices of violation and lawsuits by the EPA. APS has responded to the 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 Notice of Intent to Sue

On May 7, 2010, APS received a NOI to sue from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners.  The NOI alleges NSR related violations and NSPS violations.  Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit.  Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA's lawsuit, if it so desires.  The 60-day period lapsed in July 2010, and the EPA did not take any action.  At this time, the Company cannot predict whether or when Earthjustice might file a lawsuit or, if filed, what the ultimate outcome would be. 

Review of New Sources and Modifications in Indian Country

Pursuant to its authority under the Clean Air Act, in June 2011, the EPA finalized a FIP, which puts in place a pre-construction air permitting program for construction of new and modified small facilities and minor modifications of existing facilities in Indian country.  The FIP will require a source owner or operator to apply for a permit before building a new facility or modifying an existing one if it is determined that the proposed project will increase emissions above any of the minor NSR thresholds included in the rule.  Among other things, sources triggering the rule's source-specific permit requirements will be required to undergo a case-by-case control technology review and, potentially, an air impact quality analysis.  APS and PNM are currently evaluating the potential impact of this rule on Four Corners, which is located on Indian lands.

Endangered Species Act

On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the OSM and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”) consultation with the 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 requests 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.  PNM is not a party to the lawsuit. APS has intervened in the lawsuit and is evaluating the lawsuit to determine its potential impact on Four Corners operations.  PNM is unable to predict the ultimate outcome of this matter.

Cooling Water Intake Structures

The EPA issued its proposed cooling water intake structures rule on April 20, 2011, which would provide national standards applicable to certain cooling water intake structures at existing power plants and other facilities pursuant to the Clean Water Act. The proposed standards are intended 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). To minimize impingement mortality, 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. To minimize entrainment mortality, 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 is subject to a public comment period, which has been extended to August 18, 2011. The EPA is expected to issue a final rule by July 2012. As proposed, existing facilities subject to the rule would have to comply with the impingement mortality requirements as soon as possible, but in no event later than eight years after the effective date of the rule, and would have to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. PNM and APS are performing analyses to determine the 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.

Santa Fe Generating Station

PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath the site of the former Santa Fe Generating Station to determine the source of the contamination pursuant to a 1992 settlement agreement between PNM and the NMED.

PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, to avoid a prolonged legal dispute, PNM entered into settlement agreements with the NMED under which PNM agreed to install a remediation system to treat water from a City of Santa Fe municipal supply well and install an additional extraction well and two new monitoring wells to address gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater meets applicable federal and state standards or until such time as the NMED determines that additional remediation is not required, whichever is earlier. The well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project.

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 the 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. The Company is unable to predict the outcome of this matter.

Coal Combustion Waste Disposal

Regulation

SJCC currently disposes of CCBs consisting of fly ash, bottom ash, and gypsum from SJGS 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 at the mine with federal oversight by the OSM. APS currently 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 the Four Corners plant is regulated by the EPA and the New Mexico State Engineer's Office. 

On May 4, 2010, the EPA issued a proposed rulemaking to regulate CCBs.  The proposal asks for public comment on two approaches for regulating CCBs. One option is to regulate CCBs under Subtitle C of the RCRA as a hazardous waste which allows the EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs under RCRA Subtitle D as a non-hazardous waste. This provides the 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. The EPA has indicated that it will work with the OSM to develop federal regulations for placement of CCBs in minefill operations. The proposed rule also states that the EPA and OSM will consider the recommendations of the National Research Council, which, at the direction of Congress, studied the health, safety, and environmental risks associated with the placement of CCBs in U.S. coal mines.  The 2006 report concluded that the “placement of coal combustion residues in mines as part of coal mine reclamation may be an appropriate option for the disposal of this material.” On June 21, 2010, the EPA published the proposed rule in the Federal Register. The public comment period on the proposed rule ended November 19, 2010. A final rule regarding waste designation for coal ash is not expected from the EPA before mid to late 2012.

The OSM had initially drafted a CCB mine placement rule in late summer 2008, but with the then-impending change in federal administration, the Office of Management and Budget at the White House returned the rule to OSM for re-submittal under the incoming administration. An OSM CCB rulemaking team has been formed to develop a proposed rule. OSM's draft rulemaking schedule targets an April 2012 publication in the Federal Register.

PNM advocates for the non-hazardous regulation of CCBs under Subtitle D of RCRA. PNM is encouraged by the EPA's proposed decision to develop separate federal regulations in conjunction with the OSM's intent to develop regulations for mine placement of CCBs. PNM believes regulatory oversight for this matter should come from the OSM and state mining and mining reclamation agencies. In addition, PNM believes the decision by the EPA to consider the conclusions of the National Research Council study in the development of federal regulations regarding placement of CCBs in minefilling operations is a prudent one. PNM cannot predict the outcome of the EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material adverse impact on its operations, financial position, or cash flows. 

Sierra Club Allegations

In December 2009, PNM and PNMR received a NOI to sue (“RCRA Notice”) under RCRA from the Sierra Club.  The RCRA Notice was also sent to all SJGS owners, to SJCC, which operates the San Juan Mine that supplies coal to SJGS, and to BHP. Additionally, PNM was informed that SJCC and BHP received a separate NOI to sue under the Surface Mine Control and Reclamation Act ("SMCRA") from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are 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 constitutes "open dumping" in violation of RCRA.  The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff's attorney's fees and costs. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club's concerns. If the parties are unable to settle the matter, PNM is prepared to aggressively defend its position in the RCRA litigation.PNM and PNMR cannot predict the outcome of this matter or the range of potential outcomes at the present time.

Gila River Indian Reservation Superfund Site

In April 2008, the EPA informed PNM that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. PNM, along with SRP, APS, and EPE, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. The EPA has settled the matter with the PRPs for past cleanup-related costs involving contamination from the crop dusting. PNM's share of the settlement had no material adverse impact on PNM's financial position, results of operations, or cash flows.

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At June 30, 2011 and December 31, 2010, prepayments for coal, which are included in other current assets, amounted to $28.2 million and $30.9 million. SJCC holds certain federal, state, and private coal leases under an underground coal sales agreement pursuant to which it will supply processed coal for operation of the SJGS through 2017. The coal agreement is a cost plus contract. SJCC is reimbursed for all costs for mining and delivering the coal plus an allocated portion of administrative costs. In addition, SJCC 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 approximately 44.2 million tons of coal during its remaining term, which would supply substantially all the requirements of the SJGS through approximately 2017.

APS purchases all of Four Corners' coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016 with pricing determined using an escalating base-price. APS is currently in discussions with the coal supplier regarding post-2016 coal supply for Four Corners.

In 2010, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the most recent estimates, the final costs of mine reclamation, net of contract buyout costs paid to SJCC and reclamation payments made through June 30, 2011, are estimated to be $54.5 million for the surface mines at both SJGS and Four Corners and $21.7 million for the underground mine at SJGS, in future dollars. PNM made payments against the surface mine liability of $1.3 million and $2.6 million during the three and six months ended June 30, 2011 and $0.9 million and $2.0 million during the three and six months ended June 30, 2010. As of June 30, 2011 and December 31, 2010, obligations of $24.2 million and $25.0 million for surface mine reclamation and $2.9 million and $2.8 million for underground mining activities were recorded in other deferred credits.

PVNGS Liability and Insurance Matters

The PVNGS participants have insurance for public liability exposure for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, the PVNGS participants maintain the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 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. The maximum assessment per reactor under the program for each nuclear incident is $117.5 million, subject to an annual limit of $17.5 million per incident, to be periodically adjusted for inflation. Based on PNM's 10.2% interest in the three PVNGS units, PNM's maximum potential assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for property 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. The property damage and decontamination coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). PNM is subject to retrospective assessments under all NEIL policies if NEIL's losses in any policy year exceed accumulated funds. The maximum amount PNM could incur under the current NEIL policies totals $5.80 million for each retrospective assessment declared by NEIL's Board of Directors due to losses. The insurance coverage discussed in this and the previous paragraph is subject to policy conditions and exclusions.

Water Supply

Because of New Mexico's arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Valencia, Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time.

Severe drought, such as that which occurred during 2002 in the “four corners” region of New Mexico where SJGS and Four Corners are located, can affect the availability of these plants. In future years, if adequate precipitation is not received in the watershed that supplies the four corners region, the plants could be impacted. Consequently, PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines. 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. The current agreements run through December 31, 2012. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement on a long-term supplemental contract relating to water for SJGS and Four Corners with the Jicarilla Apache Nation that runs through 2016. Although the Company does not believe that its operations will be materially affected by the drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how policy, regulations, and legislation may impact the Company 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 the next forty years.

PVNGS Water Supply Litigation

A summons was served on APS in 1986 that required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons. APS' rights and the rights of the other PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. 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 both of 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 adverse 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 entitled “State of New Mexico v. United States, et al.”, in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. PNM was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. In 2005, the Navajo Nation and various parties announced a settlement of the Navajo Nation's surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation.

The United States, the State of New Mexico, and the Navajo Nation have entered into a water rights settlement agreement and the court recently announced the initiation of a new phase of this adjudication. Under the terms of the settlement agreement, the Navajo water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees.  The court has ordered that settlement of the Navajo Nation's claims under the settlement agreement and entry of the proposed decrees be heard first in an expedited inter se proceeding. The Court has set a deadline of September 16, 2011 for interested parties to file a NOI to participate, and a mandatory scheduling conference has been set for October 3, 2011.

PNM's water rights in the San Juan Basin may be affected by the rights recognized as owned by the Navajo Nation in the settlement agreement, and PNM has elected to participate in this proceeding.  It is unknown at the present time how PNM will respond to the claims made in the proposed decrees, although the claims recognized as owned by the Navajo Nation in the settlement agreement and the proposed decrees constitute a significant portion of the water available from sources on the San Juan River and in the San Juan Basin.

The Company 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 other claimants and potential claimants. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders or the range of potential outcomes.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS. PNM argued that SPS' rates for sale of interruptible energy were excessive and that SPS had been overcharging PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a complaint proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices (the “Golden Spread complaint proceeding”). Additionally, in November 2005, SPS filed an electric rate case at FERC proposing to unbundle and raise rates charged to customers effective July 2006. PNM intervened in the case and objected to the proposed rate increase. In September 2006, PNM and SPS filed a settlement agreement providing for resolution of issues relating to rates for sales of interruptible energy, but not resolving the fuel clause issues. In September 2008, FERC issued its order approving the settlement between PNM and SPS.

In April 2008, FERC issued its order in the Golden Spread complaint proceeding. FERC affirmed in part and reversed in part an ALJ's initial decision, which had, among other things, ordered SPS to pay refunds to PNM with respect to the fuel clause issues. FERC affirmed the decision of the ALJ that SPS violated its fuel cost adjustment clause tariffs. However, FERC shortened the refund period applicable to the violation of the fuel cost adjustment clause issues.PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC.

Begay v. PNM et al

A putative class action was filed against PNM and other utilities on February 11, 2009 in the United States District Court in Albuquerque. 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. Plaintiffs, including an allottee association, make broad, general assertions 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.  The plaintiffs, who have sued the defendants for breach of fiduciary duty, seek a constructive trust. They have also included a breach of trust claim against the United States and its Secretary of the Interior.  PNM and the other defendants filed motions to dismiss this action. On March 31, 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. 

On May 10, 2010, Plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs. PNM intends to participate in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. As the administrative appeal process is in its initial stages, PNM cannot predict the outcome of the proceeding at this time or the range of potential outcomes.

Transmission Issues

On November 24, 2009, FERC issued Order 729 approving two Modeling, Data, and Analysis Reliability Standards (“Reliability Standards”) submitted by NERC - MOD-001-1 (Available Transmission System Capability) and MOD-029-1 (Rated System Path Methodology). Both MOD-001-1 and MOD-029-1 require a consistent approach, provided for in the Reliability Standards, to measuring the total transmission capability (“TTC”) of a transmission path. The TTC level established using the two Reliability Standards could result in a reduction in the available transmission capacity currently used by PNM to deliver generation resources necessary for its jurisdictional load and for fulfilling its obligations to third-party users of the PNM transmission system. PNM continues to evaluate its transmission system under the provisions of the two Reliability Standards and consult with other transmission facility owners with whom PNM is interconnected to determine the impact on the capability of its transmission system. PNM is unable to predict the outcome of this matter.

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers that have selected the MOD-029-1 methodology that, while they were still expected to be compliant with the standard on April 1, 2011, NERC has delayed the implementation for "Flow Limited" paths only, until such time as a modification to the standard can be developed that will mitigate the technical concerns identified by the transmission owners and transmission service providers.

On April 20, 2010, Cargill Power Markets, LLC (“Cargill”) filed a complaint with FERC, asserting that PNM improperly processed its transmission service queue and unfairly invalidated a transmission service request by Cargill. On July 29, 2010, FERC issued an order and established a schedule for hearing and settlement procedures. In its order, FERC determined that PNM had improperly invalidated a single Cargill transmission service request submitted on February 21, 2008 and set the issue for hearing to determine an appropriate remedy. However, the hearing is being held in abeyance by FERC to provide time for settlement negotiations under the oversight of a FERC settlement judge. On September 27, 2010, FERC granted rehearing for further consideration. On January 13, 2011, PNM and Cargill filed a settlement agreement with FERC in which PNM agreed to pay Cargill $0.2 million and put Cargill's transmission service request back into the queue. The settlement also left Cargill's and PNM's rehearing requests in place before FERC. One intervenor in the proceeding has contested the settlement. The settlement judge reported to FERC that the settlement is contested. The settlement is before FERC for its consideration. FERC has not yet acted upon the requests for rehearing or settlement. PNM is unable to predict the final outcome of this matter at FERC.

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Condensed Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Unrealized holding gains arising during the period, income tax (expense)	$ (5,827)	$ 1,280	$ (9,280)	$ 58
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	7,892	720	9,962	1,330
Pension liability adjustment, income tax (expense) benefit	(425)	0	601	147
Change in fair market value, income tax (expense)	327	1,197	318	(3,859)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	(215)	4,035	(302)	8,227
Public Service Company of New Mexico [Member]
Unrealized holding gains arising during the period, income tax (expense)	(5,827)	1,280	(9,280)	58
Reclassification adjustment for (gains) included in net earnings (loss), income tax expense	7,892	720	9,962	1,330
Pension liability adjustment, income tax (expense) benefit	(423)	0	432	147
Change in fair market value, income tax (expense)	0	(71)	0	(2,767)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	0	2,540	(11)	5,210
Texas-New Mexico Power Company [Member]
Pension liability adjustment, income tax (expense) benefit	(1)	0	170	0
Change in fair market value, income tax (expense)	307	541	272	891
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)	$ (102)	$ (103)	$ (202)	$ (205)

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Significant Accounting Policies and Responsibility for Financial Statements (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended		1 Months Ended						6 Months Ended			3 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jul. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Apr. 30, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Mar. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jan. 31, 2011 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] Affiliated Entity [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Jun. 30, 2010 Texas-New Mexico Power Company [Member] Affiliated Entity [Member]	Jun. 30, 2011 PNM Resources [Member]	Jun. 30, 2010 PNM Resources [Member]
Dividends Declared per Common Share (dollars per share)	$ 0.125	$ 0.125	$ 0.250	$ 0.250										$ 0.125	$ 0.125
Common Stock Dividends Declared											$ 0
Payments of Dividends, Common Stock					3.6		4.6		39.1			7.1	1.6
Dividends, Common Stock						$ 3.6		$ 4.6		$ 39.1		$ 7.1	$ 1.6

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

Information concerning stock-based compensation plans is contained in Note 13 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted in 2011 and awards of restricted stock have increased.

Stock Options

The following table summarizes activity in stock option plans for the six months ended June 30, 2011:

	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value			Weighted- Average Remaining Contract Life
Outstanding at beginning of period	3,948,262		$	18.33
Granted	—		$	—
Exercised	(199,683	)	$	11.01
Forfeited	(8,333	)	$	11.33
Expired	(47,936	)	$	24.51
Outstanding at end of period	3,692,310		$	18.66	$	9,793,593	(1)	5.36 years
Exercisable at end of period	3,152,000		$	21.86	$	6,663,441		4.85 years
Options available for future grant(2)	4,763,254

(1) At June 30, 2011, the exercise price of 1,978,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

(2) Includes shares available for grants of restricted stock.

The following table provides additional information concerning stock option activity:

	Six Months Ended June 30,
Options for PNMR Common Stock	2011		2010
Weighted-average grant date fair value of options granted	$	—	$	3.05
Total fair value of options that vested (in thousands)	$	1,189	$	1,027
Total intrinsic value of options exercised (in thousands)	$	2,199	$	329

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the six months ended June 30, 2011:

Nonvested Restricted Stock	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period	237,021		$	9.24
Granted	308,985		$	13.10
Vested	(110,757	)	$	9.69
Forfeited	—		$	—
Nonvested at end of period	435,249		$	11.91

Compensation expense for restricted stock and performance stock awards was determined based on the market price of PNMR stock on the date of grant reduced by the present value of future dividends, which will not be received during the vesting period, applied to the total number of shares that were anticipated to fully vest.

The following table provides additional information concerning restricted stock:

	Six Months Ended
	June 30,
Nonvested Restricted Stock	2011			2010
Weighted-average grant date fair value of shares
granted	$	13.10		$	9.37
Total fair value of shares that vested (in thousands)	$	1,073		$	1,308
Expected quarterly dividends per share	$	0.125		$	0.125
Risk-free interest rate	1.20		%	1.36		%

Beginning in 2009, the Company issued performance share agreements to certain executives that are based upon the Company achieving specified performance targets over periods of one to three years. The determination of the number of shares ultimately issued depends on the levels at which the performance criteria are achieved and cannot be determined until after the performance periods end. For the targets based only on 2010 performance, near optimal level was attained resulting in 88,913 shares being awarded in 2011, which will vest evenly from 2012 through 2014 and are included in the number of shares granted in the above table. Excluded from the above table is a maximum of 560,461 shares based on performance targets through 2013 that would be issued and vest upon issuance if all performance criteria are achieved and all executives remain eligible.

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Optim Energy

6 Months Ended

Jun. 30, 2011

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments Disclosure [Text Block]

Optim Energy

Information concerning Optim Energy is discussed in Note 22 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each have a 50 percent ownership interest in Optim Energy, a limited liability company.

Impairment Considerations

Beginning in 2009 and continuing throughout 2010, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. In addition to these adverse market conditions, reported sales of electric generating resources within the ERCOT market area were transacted at prices (per KW of generating capacity) that were substantially below the amounts recorded for the electric generating plants underlying PNMR’s investment in Optim Energy. Under GAAP, these factors were indicators of impairment that required an impairment analysis to be performed by PNMR of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired and PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010. In accordance with GAAP, PNMR has not recorded losses associated with its investment in Optim Energy in 2011 as PNMR has 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) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources and, as of the date of this report, PNMR does not anticipate making additional contributions to Optim Energy. The strategic alternative process is ongoing and no decisions have been reached.

Operational Information

Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit. This facility also provides for bank letters of credit to be issued as credit support for certain contractual arrangements entered into by Optim Energy. Cascade and ECJV have guaranteed Optim Energy’s obligations on this facility and, to secure Optim Energy’s obligation to reimburse Cascade and ECJV for any payments made under the guaranty, have a first lien on all assets of Optim Energy and its subsidiaries.

In January 2010, Optim Energy entered into one-year floating-to-fixed interest rate swaps with an aggregate notional amount of $650.0 million. The effect of these swaps was to convert $650.0 million of borrowings under Optim Energy’s credit facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.33% through January 7, 2011, exclusive of loan guaranty fees. These swaps were accounted for as cash-flow hedges.

PNMR has no commitments or guarantees with respect to Optim Energy.

Summarized financial information for Optim Energy is as follows:

Results of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	77,315		$	86,871		$	151,248		$	192,465
Cost of energy	54,908			61,235			112,875			138,532
Gross margin	22,407			25,636			38,373			53,933
Non-fuel operations and maintenance expenses	9,408			6,450			18,651			16,970
Administrative and general expenses	6,356			4,944			13,293			10,556
Depreciation and amortization expense	13,126			12,852			24,739			24,909
Taxes other than income tax	2,347			3,162			4,717			6,596
Operating income (loss)	(8,830		)	(1,772		)	(23,027		)	(5,098		)
Interest charges	(3,981		)	(4,661		)	(7,965		)	(9,332		)
Other income (deductions)	195			2			263			66
Earnings (loss) before income taxes	(12,616		)	(6,431		)	(30,729		)	(14,364		)
Income taxes(1)	94			36			141			68
Net earnings (loss)	$	(12,710	)	$	(6,467	)	$	(30,870	)	$	(14,432	)
50 percent of net earnings (loss)	$	(6,355	)	$	(3,234	)	$	(15,435	)	$	(7,216	)
Amortization of basis difference in Optim Energy	—			(624		)	—			(994		)
Post-impairment loss not recorded under GAAP	6,355			—			15,435			—
PNMR equity in net earnings (loss) of Optim Energy	$	—		$	(3,858	)	$	—		$	(8,210	)

⁽¹⁾ Represents the Texas Margin Tax, which is considered an income tax under GAAP.

Financial Position

	June 30,			December 31,
	2011			2010
	(In thousands)
Current assets	$	102,851		$	105,413
Net property plant and equipment	908,666			924,354
Other long-term assets	112,196			120,894
Total assets	1,123,713			1,150,661
Current maturities of long-term debt	717,000			—
Other current liabilities	52,220			50,226
Long-term debt	—			717,000
Other long-term liabilities	9,397			7,515
Total liabilities	778,617			774,741
Owners’ equity	$	345,096		$	375,920
50 percent of owners’ equity	$	172,548		$	187,960
PNMR basis difference in Optim Energy	193			216
Impairment of equity investment in Optim Energy	(188,176		)	(188,176		)
Post-impairment loss not recorded under GAAP	15,435			—
PNMR equity investment in Optim Energy	$	—		$	—

Revenue related to power sales and purchases is included net in operating revenues. Costs related to fuel purchases and sales are recorded net in cost of energy.

PNMR had a basis difference between its recorded investment in Optim Energy and 50 percent of Optim Energy’s equity resulting from Optim Energy’s acquisition of the Twin Oaks plant from PNMR in 2007. The portion of the basis difference related to contract amortization ended in 2010 and other basis differences, including a difference related to emission allowances that would have continued through the life of the Twin Oaks plant, were taken into account in the impairment discussed above. The basis difference adjustment detailed above relates mainly to contract amortization with insignificant offsets related to the other minor basis difference components.

Optim Energy individually valued each asset and liability of the Twin Oaks plant acquired from PNMR and the acquisition of Cogen and initially recorded them on its balance sheet at the determined fair value. For both transactions, this accounting resulted in amortization since contracts acquired were out of market and emission allowances, while acquired from government programs without cost to Optim Energy, had market value. Optim Energy recorded amortization of contracts acquired of $3.7 million and $7.3 million for the three months and six months ended June 30, 2011 and $4.2 million and $8.2 million for the three months and six months ended June 30, 2010, which decreased operating revenues. Optim Energy also recorded amortization expense on emission allowances of $1.6 million and $4.1 million for the three months and six months ended June 30, 2011 and $1.3 million and $2.6 million for the three months and six months ended June 30, 2010, which increased cost of energy.

Optim Energy has a hedging program that varies at any given time depending on current market conditions and other factors. Optim Energy has designated a long-term power and steam contract as a normal sale under GAAP. At June 30, 2011, all other transactions are designated as economic hedges that are required to be marked to market.

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Capitalization

6 Months Ended

Jun. 30, 2011

Debt Disclosure [Abstract]

Capitalization

Capitalization

Information concerning financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

Short-term Debt

At June 30, 2011, PNMR and PNM had revolving credit facilities with financing capacities of $542.0 million under the PNMR Facility and $386.0 million under the PNM Facility that primarily expire in August 2012. The financing capacities of the PNMR Facility and the PNM Facility will reduce by $25.0 million and $18.0 million in August 2011 according to their terms. The Company does not believe the scheduled reduction in the facilities will have a significant impact on PNMR’s and PNM’s liquidity. In addition, PNMR has a local line of credit amounting to $5.0 million that expires in August 2012. TNMP has a revolving credit facility with financing capacity of $75.0 million under the TNMP Revolving Credit Facility that expires in December 2015. At June 30, 2011, the weighted average interest rate was 1.44% for the PNMR Facility and 0.84% for the PNM Facility. Short-term debt outstanding consists of:

	June 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	273,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	31,000		32,000
Local lines of credit	—		—
	$	304,000	$	222,000

At August 2, 2011, PNMR, PNM, and TNMP had $455.1 million, $58.8 million, and $74.7 million of availability under their respective revolving credit facilities and local lines of credit, including reductions of availability due to outstanding letters of credit. Total availability at August 2, 2011, on a consolidated basis, was $588.6 million for PNMR. At August 2, 2011, PNMR and PNM had invested cash of $10.3 million and $10.7 million. TNMP had no such investments.

As of June 30, 2011, TNMP had outstanding borrowings of $7.0 million from PNMR under its intercompany loan agreement. At August 2, 2011, TNMP had outstanding borrowings of $5.0 million under its intercompany loan agreement with PNMR.

Financing Activities

In March 2009, TNMP entered into and borrowed $50.0 million under a loan agreement with Union Bank, N. A. (the “2009 Term Loan Agreement”).    Through hedging arrangements, TNMP established fixed interest rates for the 2009 Term Loan Agreement of 6.05% for the first three years and 6.30% thereafter. In January 2010, the relationship was modified to reduce the fixed interest rate to 4.80% through March 31, 2012 and to 5.05% thereafter. This hedge is accounted for as a cash-flow hedge and the June 30, 2011 pre-tax fair value of $2.1 million is included in other current liabilities, except for $1.0 million included in other deferred credits, and in AOCI on the Condensed Consolidated Balance Sheets. The hedge’s December 31, 2010 pre-tax fair value of $1.9 million is included in other current liabilities, except for $0.8 million included in other deferred credits, and in AOCI. Amounts reclassified from AOCI are included in interest charges. The fair value determinations were made using Level 2 inputs under GAAP and were determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.  

Convertible Preferred Stock

In November 2008, PNMR issued 477,800 shares of Series A convertible preferred stock. The Series A convertible preferred stock is convertible into PNMR common stock at a ratio of 10 shares of common stock for each share of preferred stock. The Series A convertible preferred stock is entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The Series A convertible preferred stock is entitled to vote on all matters voted upon by common stockholders, except for the election of the Board. In the event of liquidation of PNMR, preferred holders would receive a preference of $0.10 per common share equivalent. After that preference, common holders would receive an equivalent liquidation preference per share and all remaining distributions would be shared ratably between common and preferred holders using the number of shares of common stock into which the Series A convertible preferred stock is convertible. The terms of the Series A convertible preferred stock result 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 is convertible is included in the weighted average number of common shares outstanding. Similarly, dividends on the Series A convertible preferred stock are considered to be common dividends in the accompanying Condensed Consolidated Financial Statements.

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Pension and Other Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2011

Public Service Company of New Mexico [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

The following table presents the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	105		$	—	$	—
Interest cost	8,202			8,518			1,345			1,913			233		263
Long-term return on plan assets	(9,269		)	(9,339		)	(1,347		)	(1,393		)	—		—
Amortization of net loss	2,302			1,613			801			1,372			23		18
Amortization of prior service cost	79			79			(662		)	(1,036		)	—		—
Net periodic benefit cost	$	1,314		$	871		$	202		$	961		$	256	$	281

	Six Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	129		$	210		$	—	$	—
Interest cost	16,402			17,037			2,689			3,825			465		527
Long-term return on plan assets	(18,537		)	(18,677		)	(2,694		)	(2,786		)	—		—
Amortization of net loss	4,605			3,225			1,603			2,744			47		35
Amortization of prior service cost	158			158			(1,324		)	(2,071		)	—		—
Net periodic benefit cost	$	2,628		$	1,743		$	403		$	1,922		$	512	$	562

Texas-New Mexico Power Company [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs [Table Text Block]

The following table presents the components of the TNMP Plans’ net periodic benefit cost (income):

	Three Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	77		$	72		$	—	$	—
Interest cost	951			1,032			163			178			12		13
Long-term return on plan assets	(1,368		)	(1,449		)	(133		)	(129		)	—		—
Amortization of net (gain) loss	86			—			(48		)	(49		)	—		(1		)
Amortization of prior service cost	—			—			15			15			—		—
Net Periodic Benefit Cost (Income)	$	(331	)	$	(417	)	$	74		$	87		$	12	$	12

	Six Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	153		$	144		$	—	$	—
Interest cost	1,900			2,063			327			356			23		26
Long-term return on plan assets	(2,735		)	(2,897		)	(267		)	(257		)	—		—
Amortization of net (gain) loss	173			—			(96		)	(98		)	—		(2		)
Amortization of prior service cost	—			—			30			30			—		—
Net Periodic Benefit Cost (Income)	$	(662	)	$	(834	)	$	147		$	175		$	23	$	24

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Earnings Per Share

6 Months Ended

Jun. 30, 2011

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share has been presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	4,067	$	22,878	$	20,704	$	14,429
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,778		4,778		4,778		4,778
Vested awards of restricted stock	139		109		149		102
Average Shares - Basic	91,590		91,560		91,600		91,553
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	546		273		502		141
Average Shares - Diluted	92,136		91,833		92,102		91,694
Net Earnings Per Share of Common Stock:
Basic	$	0.04	$	0.25	$	0.23	$	0.16
Diluted	$	0.04	$	0.25	$	0.22	$	0.16

(1) Excludes the effect of out-of-the-money options for 1,978,010 shares of common stock at June 30, 2011.

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Capitalization, Convertible Preferred Stock (Details) (Series A Convertible Preferred Stock [Member], USD $)	1 Months Ended	6 Months Ended
	Nov. 30, 2008	Jun. 30, 2011
Series A Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	477,800
Convertible Preferred Stock, Shares Issued upon Conversion		10
Convertible Preferred Stock, Settlement Terms		Common shares
Preferred Stock, Liquidation Preference Per Share (dollars per share)		$ 0.10

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Condensed Consolidated Statements of Changes in Equity (USD $) In Thousands	Total	Public Service Company of New Mexico [Member]	Texas-New Mexico Power Company [Member]	Preferred Stock, Series A [Member]	Common Stock [Member]	Common Stock [Member] Public Service Company of New Mexico [Member]	Common Stock [Member] Texas-New Mexico Power Company [Member]	Additional Paid-in Capital [Member] Texas-New Mexico Power Company [Member]	AOCI [Member]	AOCI [Member] Public Service Company of New Mexico [Member]	AOCI [Member] Texas-New Mexico Power Company [Member]	Retained Earnings [Member]	Retained Earnings [Member] Public Service Company of New Mexico [Member]	Retained Earnings [Member] Texas-New Mexico Power Company [Member]	Total PNMR Common Stockholders' Equity [Member]	Total PNMR Common Stockholders' Equity [Member] Public Service Company of New Mexico [Member]	Non-controlling Interest in Valencia [Member]	Non-controlling Interest in Valencia [Member] Public Service Company of New Mexico [Member]
Balance at Dec. 31, 2010	$ 1,721,919	$ 1,208,526		$ 100,000	$ 1,290,465	$ 1,018,776			$ (68,666)	$ (66,786)		$ 314,943	$ 171,359		$ 1,536,742	$ 1,123,349	$ 85,177	$ 85,177
Balance TNMP at Dec. 31, 2010	1,536,742	1,123,349	453,283				64	430,108			(1,485)			24,596
Proceeds from stock option exercise	2,172			0	2,172				0			0			2,172		0
Purchases to satisfy awards of common stock	(4,535)			0	(4,535)				0			0			(4,535)		0
Stock based compensation expense	2,867			0	2,867				0			0			2,867		0
Valencia's transactions with its owner	(7,232)	(7,232)		0	0	0			0	0		0	0		0	0	(7,232)	(7,232)
Net earnings before subsidiary preferred stock dividends	27,620	9,061	8,265	0	0	0	0	0	0	0	0	20,968	2,409	8,265	20,968	2,409	6,652	6,652
Subsidiary preferred stock dividends	(264)			0	0				0			(264)			(264)		0
Total other comprehensive income (loss)	(2,025)	(1,682)	(433)	0	0	0	0	0	(2,025)	(1,682)	(433)	0	0	0	(2,025)	(1,682)	0	0
Dividends declared on preferred stock		(264)				0				0			(264)			(264)		0
Dividends declared on common stock	(11,430)	(8,212)	(7,066)	0	0	0	0	(7,066)	0	0	0	(11,430)	(8,212)	0	(11,430)	(8,212)	0	0
Balance TNMP at Jun. 30, 2011	1,544,495	1,115,600	454,049				64	423,042			(1,918)			32,861
Balance at Jun. 30, 2011	1,729,092	1,200,197		100,000	1,290,969	1,018,776			(70,691)	(68,468)		324,217	165,292		1,544,495	1,115,600	84,597	84,597
Balance at Mar. 31, 2011
Net earnings before subsidiary preferred stock dividends	7,669	2,097	4,102
Subsidiary preferred stock dividends	(132)
Total other comprehensive income (loss)	(2,699)	(2,505)	(369)
Balance TNMP at Jun. 30, 2011	1,544,495	1,115,600	454,049
Balance at Jun. 30, 2011	$ 1,729,092	$ 1,200,197

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Significant Accounting Policies and Responsibility for Financial Statements

6 Months Ended

Jun. 30, 2011

Accounting Policies [Abstract]

Significant Accounting Policies and Responsibility for Financial Statements

Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at June 30, 2011 and December 31, 2010, and the consolidated results of operations and comprehensive income for the three months and six months ended June 30, 2011 and 2010, and cash flows for the six months ended June 30, 2011 and 2010. 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 Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. The term “Company” is used when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are indicated as such. Certain amounts in the 2010 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2011 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited, and certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2010 Annual Reports on Form 10-K. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

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. See Note 16.

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. In addition, PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.125 per share in July 2011 and July 2010, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared cash dividends on its common stock to PNMR of $39.1 million in December 2010 that was paid in January 2011, $4.6 million in March 2011 that was paid in April 2011, and $3.6 million in June 2011 that was paid in July 2011. PNM declared no dividends on its common stock in the six months ended June 30, 2010. TNMP declared and paid cash dividends to PNMR of $7.1 million and $1.6 million in the six months ended June 30, 2011 and 2010. TNMP dividends were recorded as reductions of its paid-in-capital.

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Fair Value of Derivative and Other Financial Instruments, Margin, Notional Amounts, Credit Rating (Details) (USD $)	Jun. 30, 2011	Dec. 31, 2010
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 4,600,000	$ 3,400,000
Margin Deposit Assets	26,700,000	32,000,000
Derivative, Collateral, Obligation to Return Cash	0	0
Contractual Liability	9,543,000	8,113,000
Existing Cash Collateral	2,580,000	0
Net Exposure	1,675,000	2,642,000
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	1,810,000	1,882,500
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member] | Derivative Short Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	1,237,793	990,120
Commodity Contract [Member] | Economic hedges [Member] | Derivative Long Position [Member]
Derivative [Line Items]
Volume positions (Decatherms / MWh)	21,657,500	22,767,500
Public Service Company of New Mexico [Member]
Derivative [Line Items]
Derivative, Collateral, Right to Reclaim Cash	2,600,000	3,000,000
Margin Deposit Assets	1,400,000	2,100,000
Derivative, Collateral, Obligation to Return Cash	0	0
Contractual Liability	3,047,000	291,000
Existing Cash Collateral	2,580,000	0
Net Exposure	$ 370,000	$ 119,000

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Capitalization (Tables)

6 Months Ended

Jun. 30, 2011

Debt Disclosure [Abstract]

Schedule of Short-term Debt [Table Text Block]

Short-term debt outstanding consists of:

	June 30,		December 31,
Short-term Debt	2011		2010
	(In thousands)
PNM – Revolving credit facility	$	273,000	$	190,000
TNMP – Revolving credit facility	—		—
PNMR
Revolving credit facility	31,000		32,000
Local lines of credit	—		—
	$	304,000	$	222,000

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Jointly-Owned Electric Generating Plants (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member] Beginning 2016 [Member]	Jun. 30, 2011 Jointly Owned Nuclear Power Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Operating Lease, Original Term			40 years
Operating Lease, Extended Term			20 years
Increase (Decrease) in Asset Retirement Obligations	$ 4.2
Jointly Owned Utility, Lease Payment		$ 0.9

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Subsequent Events (Details) (Public Service Company of New Mexico [Member], Electric Rate Case [Member], USD $) In Millions			6 Months Ended
	Aug. 08, 2011 Settlement of Regulatory Matter [Member]	Aug. 08, 2011 Capital Expenditures [Member] Rate Increase Due to Elimination of Rider [Member]	Jun. 30, 2011 Recorded Pre Tax Loss Not to be Recovered Through FPPAC [Member]	Jun. 30, 2011 Recorded Pre Tax Loss Not To Be Recovered Through Rates [Member]	Feb. 03, 2011 Capital Expenditures [Member]	Jun. 30, 2011	May 31, 2010
Subsequent Event [Line Items]
Amount of Regulatory Costs Not yet Approved					$ 20.0		$ 165.2
Public Utilities, Regulatory Costs Approved	72.10	20.00
Public Utilities, Collection of Regulatory Costs Forgoed of Under Collected Amount						10.0
Subsequent Event, Amount			$ 10.0	$ 7.5

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Capitalization, Financing Activities (Details) (USD $)	6 Months Ended		0 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2009 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] Year One to Year Three [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] After Three Years [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] Term Loan Agreement 2009 [Member] January 2010 to March 2012 [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Secured Debt [Member] After March 2012 [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Current Liabilities [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member] Current Liabilities [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Deferred Credits and Accumulated Other Comprehensive Income [Member]	Dec. 31, 2010 Texas-New Mexico Power Company [Member] Deferred Credits and Accumulated Other Comprehensive Income [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt	$ 0	$ 403,845,000	$ 50,000,000
Debt Instrument, Interest Rate, Stated Percentage				6.05%	6.30%	4.80%	5.05%
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value								$ 2,100,000	$ 1,900,000	$ 1,000,000	$ 800,000

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Variable Interest Entities

6 Months Ended

Jun. 30, 2011

Variable Interest Entities

Variable Interest Entities [Text Block]

Variable Interest Entities

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, including determining the primary beneficiary of a variable interest entity by focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.

On April 18, 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. 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. The term of the PPA is for 20 years beginning June 1, 2008, with the full output of the plant estimated to be 145 MW. During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or of the entity that owns the plant. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed O&M and capacity charges in addition to variable O&M charges under this PPA. For the three months and six months ended June 30, 2011, PNM paid $4.6 million and $9.1 million for fixed charges and $0.3 million and $0.4 million for variable charges. For the three months and six months ended June 30, 2010, PNM paid $4.5 million and $9.0 million for fixed charges and $0.2 million and $0.3 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.

PNM has evaluated the accounting treatment of this arrangement and 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. The significant factors considered in reaching that conclusion are that 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. As the primary beneficiary, PNM has consolidated the entity in its financial statements beginning on the commercial operations date. 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 Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	4,849		$	4,725		$	9,519		$	9,227
Operating expenses	(1,379		)	(1,433		)	(2,867		)	(2,831		)
Earnings attributable to non-controlling interest	$	3,470		$	3,292		$	6,652		$	6,396

Financial Position

	June 30,		December 31,
	2011		2010
	(In thousands)
Current assets	$	3,158	$	2,372
Net property, plant and equipment	82,200		83,617
Total assets	85,358		85,989
Current liabilities	761		812
Owners’ equity – non-controlling interest	$	84,597	$	85,177

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. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. PNM has 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. 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, aggregate $111.4 million as of June 30, 2011 over the remaining terms of the leases. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of June 30, 2011, PNM could have been required to pay the beneficial owners up to approximately $177.0 million, which would result in PNM taking ownership of the leased assets and termination of the leases. PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has recorded no assets or liabilities related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $26.0 million at June 30, 2011 and December 31, 2010 and are included in other current liabilities on the Condensed Consolidated Balance Sheets. For additional information regarding these leases, see Risk Factors, MD&A – Off Balance Sheet Arrangements, and Note 7 of the Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

PNM has evaluated the PVNGS lease arrangements and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since on April 21, 2011 the NRC approved an extension in the operating licenses for the plants for 20 years through 2045 for Unit 1 and 2046 for Unit 2 (see Note 13); 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 term, 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 PNM 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 emit no GHG, resulting from anticipated carbon legislation or regulation.

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered into prior to December 31, 2003 and PNM has been 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 is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. 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 three months and six months ended June 30, 2011, PNM incurred fixed payments of $1.5 million and $2.9 million and variable payments of less than $0.1 million and $0.3 million under the PPA. For the three months and six months ended June 30, 2010, PNM incurred fixed payments of $1.7 million and $3.0 million and variable payments of less than $0.1 million and $0.2 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of June 30, 2011, aggregated $54.1 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. PNM has no other obligations or commitments with respect to Delta.

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Fair Value of Derivative and Other Financial Instruments, Avaialbe for Sale Securities (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	$ 168,513		$ 168,513		$ 156,922
Available-for-sale securities, Unrealized gains	25,109		25,109		26,835
Available-for-sale securities, Unrealized losses	0		0
Proceeds from sales	46,770	15,586	94,890	36,285
Gross realized gains	8,700	1,526	13,490	3,431
Gross realized (losses)	(554)	(510)	(2,282)	(1,872)
Domestic value [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	27,986		27,986		25,491
Available-for-sale securities, Unrealized gains	2,525		2,525		5,108
Domestic growth [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	56,245		56,245		48,237
Available-for-sale securities, Unrealized gains	19,453		19,453		17,239
Multinational [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	14,089		14,089		10,670
Available-for-sale securities, Unrealized gains	405		405		2,730
Municipals [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	38,884		38,884		37,595
Available-for-sale securities, Unrealized gains	1,630		1,630		837
U.S. Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	21,390		21,390		21,541
Available-for-sale securities, Unrealized gains	490		490		348
Corporate and other [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	9,195		9,195		8,402
Available-for-sale securities, Unrealized gains	606		606		573
Cash and equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Fair value	724		724		4,986
Available-for-sale securities, Unrealized gains	0		0		0
Public Service Company of New Mexico [Member]
Schedule of Available-for-sale Securities [Line Items]
Available-for-sale securities, Unrealized losses	$ 0		$ 0

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Fair Value of Derivative and Other Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2011

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 are summarized as follows:

	PNMR						PNM
	Economic Hedges						Economic Hedges
	June 30, 2011			December 31, 2010			June 30, 2011			December 31, 2010
	(In thousands)
Current assets	$	18,840		$	15,999		$	935		$	1,443
Deferred charges	7,754			5,264			5			—
	26,594			21,263			940			1,443
Current liabilities	(27,285		)	(31,407		)	(1,720		)	(3,110		)
Long-term liabilities	(13,770		)	(12,831		)	(1,841		)	(2,009		)
	(41,055		)	(44,238		)	(3,561		)	(5,119		)
Net	$	(14,461	)	$	(22,975	)	$	(2,621	)	$	(3,676	)

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	June 30,						June 30,					June 30,
	2011			2010			2011		2010			2011			2010
Three Months Ended	(In thousands)
PNMR
Electric operating revenues	$	190		$	(121	)	$	—	$	(36	)	$	—		$	6,539
Cost of energy	(4,594		)	2,720			—		—			(318		)	(771		)
Total gain (loss)	$	(4,404	)	$	2,599		$	—	$	(36	)	$	(318	)	$	5,768
Recognized in OCI												$	318		$	(5,581	)
PNM
Electric operating revenues	$	190		$	(121	)	$	—	$	—		$	—		$	6,539
Cost of energy	(284		)	(37		)	—		—			—			(41		)
Total gain (loss)	$	(94	)	$	(158	)	$	—	$	—		$	—		$	6,498
Recognized in OCI												$	—		$	(6,311	)
Six Months Ended
PNMR
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	(33	)	$	—		$	13,288
Cost of energy	86			(29,229		)	—		—			(249		)	(1,246		)
Total gain (loss)	$	1,420		$	(31,236	)	$	—	$	(33	)	$	(249	)	$	12,042
Recognized in OCI												$	249		$	(4,818	)
PNM
Electric operating revenues	$	1,334		$	(2,007	)	$	—	$	—		$	—		$	13,288
Cost of energy	159			(3,662		)	—		—			—			14
Total gain (loss)	$	1,493		$	(5,669	)	$	—	$	—		$	—		$	13,302
Recognized in OCI												$	—		$	(6,078	)

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

The table below presents PNMR’s and PNM’s net buy (sell) volume positions:

	Economic Hedges
	Decatherms	MWh
June 30, 2011
PNMR	21,657,500	3,646,080
PNM	1,810,000	(1,237,793	)
December 31, 2010
PNMR	22,767,500	1,693,431
PNM	1,882,500	(990,120	)

Schedule of Collateral Related to Derivative [Table Text Block]

Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
June 30, 2011
PNMR	$	9,543	$	2,580	$	1,675
PNM	$	3,047	$	2,580	$	370
December 31, 2010
PNMR	$	8,113	$	—	$	2,642
PNM	$	291	$	—	$	119

Available-for-sale Securities [Table Text Block]

The fair value of and gross unrealized gains on investments in available-for-sale securities are presented in the following table.

	June 30, 2011				December 31, 2010
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	2,525	$	27,986	$	5,108	$	25,491
Domestic growth	19,453		56,245		17,239		48,237
Multinational	405		14,089		2,730		10,670
Fixed income securities:
Municipals	1,630		38,884		837		37,595
U.S. Government	490		21,390		348		21,541
Corporate and other	606		9,195		573		8,402
Cash and equivalents	—		724		—		4,986
	$	25,109	$	168,513	$	26,835	$	156,922

Realized gains and losses are determined by specific identification of costs of securities sold.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				(In thousands)
Proceeds from sales	$	46,770		$	15,586		$	94,890		$	36,285
Gross realized gains	$	8,700		$	1,526		$	13,490		$	3,431
Gross realized (losses)	$	(554	)	$	(510	)	$	(2,282	)	$	(1,872	)

Investments Classified by Contractual Maturity Date [Table Text Block]

At June 30, 2011, the available-for-sale and held-to-maturity debt securities had the following final maturities:

	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	1,988	$	—	$	—
After 1 year through 5 years	20,208		139,108		128,034
After 5 years through 10 years	10,784		3,262		—
Over 10 years	36,489		—		—
	$	69,469	$	142,370	$	128,034

Fair Value, by Balance Sheet Grouping [Table Text Block]

The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:

	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,566,168	$	1,722,785	$	1,565,847	$	1,659,674
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	15,645	$	20,766	$	18,791	$	21,675
PNM
Long-term debt	$	1,055,756	$	1,079,797	$	1,055,748	$	1,056,864
Investment in PVNGS lessor notes	$	124,527	$	124,311	$	136,145	$	141,663
Other investments	$	4,118	$	4,432	$	5,068	$	5,563
TNMP
Long-term debt	$	310,650	$	417,378	$	310,337	$	385,220
Other investments	$	268	$	268	$	282	$	282

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block]

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets are as follows:

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
June 30, 2011				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	724		$	724		$	—		$	—
Equity securities:
Domestic value	27,986			27,986			—			—
Domestic growth	56,245			56,245			—			—
Multinational	14,089			14,089			—			—
Fixed income securities:
U.S. government	21,390			16,797			4,593			—
Municipals	38,884			—			38,884			—
Corporate and other	9,195			—			9,195			—
Total NDT investments	$	168,513		$	115,841		$	52,672		$	—
PNMR
Commodity derivative assets	$	26,594		$	10,891		$	9,908		$	5,282
Commodity derivative liabilities	(41,055		)	(25,360		)	(14,292		)	(890		)
Net	$	(14,461	)	$	(14,469	)	$	(4,384	)	$	4,392
PNM
Commodity derivative assets	$	940		$	—		$	940		$	—
Commodity derivative liabilities	(3,561		)	—			(3,561		)	—
Net	$	(2,621	)	$	—		$	(2,621	)	$	—

				Quoted Prices in Active Market for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	Total(1)			(Level 1)			(Level 2)			(Level 3)
December 31, 2010	(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	4,986		$	4,986		$	—		$	—
Equity securities:
Domestic value	25,491			25,491			—			—
Domestic growth	48,237			48,237			—			—
Multinational	10,670			10,670			—			—
Fixed income securities:
U.S. government	21,541			16,613			4,928			—
Municipals	37,595			—			37,595			—
Corporate and other	8,402			—			8,402			—
Total NDT investments	$	156,922		$	105,997		$	50,925		$	—
PNMR
Commodity derivative assets	$	21,263		$	8,646		$	12,308		$	272
Commodity derivative liabilities	(44,238		)	(26,378		)	(16,729		)	(1,094		)
Net	$	(22,975	)	$	(17,732	)	$	(4,421	)	$	(822	)
PNM
Commodity derivative assets	$	1,443		$	—		$	1,443		$	—
Commodity derivative liabilities	(5,119		)	—			(5,119		)	—
Net	$	(3,676	)	$	—		$	(3,676	)	$	—

(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $0.5 million for PNMR and zero for PNM at June 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and six months ended June 30, 2011 and 2010.

Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

A reconciliation of the changes in Level 3 fair value measurements is as follows:

	PNMR						PNM
	June 30,						June 30,
	2011			2010			2011		2010
Three Months Ended	(In thousands)
Balance at beginning of period	$	894		$	85		$	—	$	—
Total gains (losses) included in earnings	3,676			(437		)	—		—
Purchases	2,617			—			—		—
Settlements	(2,795		)	74			—		—
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	1,954		$	(363	)	$	—	$	—
Six Months Ended
Balance at beginning of period	$	(822	)	$	248		$	—	$	(17	)
Total gains (losses) included in earnings	5,226			(814		)	—		(128		)
Purchases	2,735			—			—		—
Settlements	(2,747		)	288			—		145
Balance at end of period	$	4,392		$	(278	)	$	—	$	—
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	3,122		$	(543	)	$	—	$	—

Fair Value, Gains Losses From Level 3 Inputs Effect on Statement of Financial Performance [Table Text Block]

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

	PNMR					PNM
	June 30,					June 30,
	2011		2010			2011		2010
Three Months Ended	(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,676		(437		)	—		—
Total	$	3,676	$	(437	)	$	—	$	—
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	1,954		(363		)	—		—
Total	$	1,954	$	(363	)	$	—	$	—
Six Months Ended
Gains (losses) included in earnings:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	5,226		(814		)	—		(128		)
Total	$	5,226	$	(814	)	$	—	$	(128	)
Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	—	$	—		$	—	$	—
Cost of energy	3,122		(543		)	—		—
Total	$	3,122	$	(543	)	$	—	$	—

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Optim Energy (Tables)

6 Months Ended

Jun. 30, 2011

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investments [Table Text Block]

Summarized financial information for Optim Energy is as follows:

Results of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(In thousands)
Operating revenues	$	77,315		$	86,871		$	151,248		$	192,465
Cost of energy	54,908			61,235			112,875			138,532
Gross margin	22,407			25,636			38,373			53,933
Non-fuel operations and maintenance expenses	9,408			6,450			18,651			16,970
Administrative and general expenses	6,356			4,944			13,293			10,556
Depreciation and amortization expense	13,126			12,852			24,739			24,909
Taxes other than income tax	2,347			3,162			4,717			6,596
Operating income (loss)	(8,830		)	(1,772		)	(23,027		)	(5,098		)
Interest charges	(3,981		)	(4,661		)	(7,965		)	(9,332		)
Other income (deductions)	195			2			263			66
Earnings (loss) before income taxes	(12,616		)	(6,431		)	(30,729		)	(14,364		)
Income taxes(1)	94			36			141			68
Net earnings (loss)	$	(12,710	)	$	(6,467	)	$	(30,870	)	$	(14,432	)
50 percent of net earnings (loss)	$	(6,355	)	$	(3,234	)	$	(15,435	)	$	(7,216	)
Amortization of basis difference in Optim Energy	—			(624		)	—			(994		)
Post-impairment loss not recorded under GAAP	6,355			—			15,435			—
PNMR equity in net earnings (loss) of Optim Energy	$	—		$	(3,858	)	$	—		$	(8,210	)

⁽¹⁾ Represents the Texas Margin Tax, which is considered an income tax under GAAP.

Financial Position

	June 30,			December 31,
	2011			2010
	(In thousands)
Current assets	$	102,851		$	105,413
Net property plant and equipment	908,666			924,354
Other long-term assets	112,196			120,894
Total assets	1,123,713			1,150,661
Current maturities of long-term debt	717,000			—
Other current liabilities	52,220			50,226
Long-term debt	—			717,000
Other long-term liabilities	9,397			7,515
Total liabilities	778,617			774,741
Owners’ equity	$	345,096		$	375,920
50 percent of owners’ equity	$	172,548		$	187,960
PNMR basis difference in Optim Energy	193			216
Impairment of equity investment in Optim Energy	(188,176		)	(188,176		)
Post-impairment loss not recorded under GAAP	15,435			—
PNMR equity investment in Optim Energy	$	—		$	—

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Fair Value of Derivative and Other Financial Instruments, Sale of Power (Details) (Public Service Company of New Mexico [Member], USD $) In Millions, unless otherwise specified	6 Months Ended	32 Months Ended
	Jun. 30, 2011 mw	Dec. 31, 2010 mw
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output	135	135
Firm Contract [Member]
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output		90
Firm Contract 1 [Member]
Sale of Power [Line Items]
Prepayments		40.6
Firm Contract 2 [Member]
Sale of Power [Line Items]
Prepayments		30.0
Contingent Contract [Member]
Sale of Power [Line Items]
Long Term Contract for Sale of Electric Power Plant Output		45

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Option Activity Including Exerciseable and Future Grant Information [Table Text Block]

The following table summarizes activity in stock option plans for the six months ended June 30, 2011:

	Shares		Weighted- Average Exercise Price		Aggregate Intrinsic Value			Weighted- Average Remaining Contract Life
Outstanding at beginning of period	3,948,262		$	18.33
Granted	—		$	—
Exercised	(199,683	)	$	11.01
Forfeited	(8,333	)	$	11.33
Expired	(47,936	)	$	24.51
Outstanding at end of period	3,692,310		$	18.66	$	9,793,593	(1)	5.36 years
Exercisable at end of period	3,152,000		$	21.86	$	6,663,441		4.85 years
Options available for future grant(2)	4,763,254

(1) At June 30, 2011, the exercise price of 1,978,010 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

(2) Includes shares available for grants of restricted stock.

Schedule of Additional Stock Option Activity [Table Text Block]

The following table provides additional information concerning stock option activity:

	Six Months Ended June 30,
Options for PNMR Common Stock	2011		2010
Weighted-average grant date fair value of options granted	$	—	$	3.05
Total fair value of options that vested (in thousands)	$	1,189	$	1,027
Total intrinsic value of options exercised (in thousands)	$	2,199	$	329

Schedule of Nonvested Share Activity [Table Text Block]

The following table summarizes nonvested restricted stock activity for the six months ended June 30, 2011:

Nonvested Restricted Stock	Shares		Weighted- Average Grant-Date Fair Value
Nonvested at beginning of period	237,021		$	9.24
Granted	308,985		$	13.10
Vested	(110,757	)	$	9.69
Forfeited	—		$	—
Nonvested at end of period	435,249		$	11.91

Schedule of Nonvested Share Activity Additional Information [Table Text Block]

The following table provides additional information concerning restricted stock:

	Six Months Ended
	June 30,
Nonvested Restricted Stock	2011			2010
Weighted-average grant date fair value of shares
granted	$	13.10		$	9.37
Total fair value of shares that vested (in thousands)	$	1,073		$	1,308
Expected quarterly dividends per share	$	0.125		$	0.125
Risk-free interest rate	1.20		%	1.36		%

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Regulatory and Rate Matters

6 Months Ended

Jun. 30, 2011

Regulatory and Rate Matters

Regulatory and Rate Matters

Regulatory and Rate Matters

Information concerning regulatory and rate matters is contained in Note 17 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

PNMR

First Choice Request for ERCOT Alternative Dispute Resolution

In June 2008, First Choice filed a request for alternative dispute resolution with ERCOT alleging that ERCOT incorrectly applied its protocols with respect to congestion management during the first quarter of 2008. First Choice requested that ERCOT resolve the dispute by restating certain elements of its first quarter 2008 congestion management data and by refunding to First Choice allegedly overstated congestion management charges. The amount at issue in First Choice's claim can only be determined by running ERCOT market models with corrected inputs but First Choice believes that the amount is significant. ERCOT protocols provide that ERCOT will notify potentially impacted market participants and subsequently consider the merits of First Choice's allegations. PNMR is unable to predict the outcome of this matter.

PNM

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. If the stipulation in the 2010 Electric Rate Case discussed below is approved by the NMPRC, the parties to the stipulation, including the NMPRC staff, will jointly request that the NMPRC take no further action in this matter and close the docket. PNM is unable to predict the outcome of this matter.

Renewable Portfolio Standard

The REA was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified” beginning in 2011 when no less than 20% of the renewable portfolio requirement must be met by wind energy, no less than 20% by solar energy, no less than 10% by other renewable technologies, and no less than 1.5% by distributed generation. The act provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities recovery of 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 has established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increases by 0.25% annually until reaching 3% in 2015.

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. The NMPRC capped recoverable costs at a maximum of $107.7 million. Under the REA, costs incurred pursuant to and consistent with an approved procurement plan are deemed to be reasonable and recoverable in the ratemaking process. Construction of these facilities is underway, the first 7 MW of solar PV were in service at June 30, 2011, and PNM anticipates that all 22 MW will be in service by December 31, 2011. PNM anticipates requesting recovery of these costs from customers through a rate rider. See 2010 Electric Rate Case below.

On July 1, 2010, PNM filed its renewable energy procurement plan for 2011. The 2011 plan proposed the procurement of 250,000 MWh of RECs from another New Mexico public utility for compliance with the renewable portfolio standard in 2011. On October 5, 2010, the NMPRC issued an order rejecting PNM's plan for 2011 as incomplete because certain planning assumptions used in the plan were found to be outdated, and ordered PNM to file a new plan within 60 days. On December 6, 2010, PNM filed a revised 2011 plan that proposed procurement of 423,860 MWh of wind generated RECs, but not the associated energy, from various bidders selected through a RFP process at a total cost of up to $5.5 million. The RECs would be retired for RPS compliance for 2011. The plan, as amended, requested a variance from the diversity requirements for solar and certain “other resources” for 2011 based on the RCT and availability constraints. A public hearing on the plan was held in April 2011. On June 2, 2011, the NMPRC issued an order that rejected PNM's proposal to procure wind RECs and directed PNM to use its best efforts to procure wind energy and associated RECs for 2011 compliance. The NMPRC granted PNM a variance from the resource diversity requirement conditioned upon PNM including in its 2012 procurement plan a proposal that would meet the diversity requirements by April 5, 2013. On July 1, 2011, PNM filed a motion for rehearing based on the NMPRC's disapproval of the use of RECs to meet the RPS requirements, the requirement that PNM meet the diversity requirements without explicit recognition of potential RCT constraints, the failure of the final order to adopt language concerning the relationship of the billing system modifications to the third party provider amendments to the Public Utility Act, and other matters. The NMPRC staff and NMIEC also filed motions for rehearing on the issue of the use of RECs for RPS compliance. The NMPRC granted rehearing on July 14, 2011 and took under advisement the issues raised in the rehearing motions. PNM cannot predict the outcome of this matter.

On April 6, 2011, PNM issued a RFP for renewable energy and RECs of up to 360,000 MWh annually. Proposals were due on June 10, 2011 and PNM is currently analyzing the proposals received. PNM will use these proposals to develop its plan for compliance with the RPS in 2012-2014.

On July 1, 2011, PNM filed its Renewable Energy Portfolio Procurement Plan for 2012. The plan requests approval of a proposed portfolio and the costs that would be incurred under that portfolio of approximately $20.3 million in 2012. The proposed portfolio consists of existing resources and proposes three new procurements. The plan requests a variance from the RPS due to RCT limitations and also requests a variance from the RCT to allow PNM to continue to procure RECs from retail customers under PNM's Solar REC Incentive Program and to procure a small number of RECs from a new hydroelectric resource to be developed by the City of Santa Fe. The plan is diversity compliant based on the reduced RPS, except for non-wind/non-solar resources, which are not currently available. In addition to the proposed procurements and requested variances, the plan describes two other portfolios: one that would be fully compliant with the RPS and a second that would comply with both the full RPS and the diversity requirements for wind, solar, and distributed generation. Each of these portfolios is more costly than PNM's proposed portfolio and the plan does not request approval of them since they would exceed the RCT. PNM cannot predict the outcome of this matter.

NMPRC Rulemaking on Disincentives to Energy Efficiency Programs

The NMPRC approved amendments to its energy efficiency rule on April 8, 2010 to be effective May 3, 2010. The amended rule allows electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per kilowatt for demand savings related to energy efficiency and demand response programs beginning in 2010. The amended rule also required investor-owned electric utilities to make filings by July 1, 2010 that proposed rate design and ratemaking measures to remove regulatory disincentives or barriers to achieve energy efficiency savings. PNM included its proposals in the 2010 Electric Rate Case described below. In the stipulation in the 2010 Electric Rate Case, PNM agreed that any such disincentives would be deemed addressed under the new rates proposed in the stipulation. Under the amended rule, after such measures become effective, the rate adder for energy saving is reduced to $0.005per KWh. The NMAG and NMIEC appealed the NMPRC order adopting the amended rule to the New Mexico Supreme Court and subsequently moved the court for a stay of the NMPRC order, which was denied. The New Mexico Supreme Court issued an opinion on July 27, 2011 annulling and vacating the NMPRC's final order approving the rule amendments and remanded the matter to the NMPRC for further action in accordance with the opinion. The appellees have until August 11, 2011 to request rehearing. PNM cannot predict the ultimate outcome of this matter.

On May 5, 2010, PNM filed proposed tariffs under the amended rule to recover a rate adder related to 2010 efficiency programs. PNM proposed to recover $6.2 million over a twelve-month period following NMPRC approval. The staff of the NMPRC filed testimony recommending the recovery of not more than $4.2 million. A public hearing was held on September 14, 2010 and the NMPRC issued an order on November 29, 2010 authorizing recovery of $4.2 million over 12 months. PNM implemented a rate rider to recover the $4.2 million adder on December 29, 2010. The final order on the PNM 2010 Energy Efficiency Application described below extended the recovery period from 12 to 18 months. If the opinion issued by the Supreme Court on July 27, 2011 is not reheard and changed, PNM will be precluded from continuing this rate rider. Of the $4.2 million authorized for recovery, $1.9 million had been collected as of June 30, 2011.

2010 Energy Efficiency Application

On September 15, 2010, PNM filed an energy efficiency program application for programs to be offered beginning July 1, 2011. PNM requested revisions to existing programs, revisions of estimates of participation and expenditure levels, approval of revised program cost recovery tariff riders, and approval of disincentive/incentive adders for 2011 energy efficiency and demand response programs. The total amount that PNM proposed to recover through the tariff riders was $32.9 million, which included the 2010 programs adder discussed above. Based on testimony filed by other parties, PNM accepted certain modifications to the plan the effect of which was a revised proposed recovery amount of $31.4 million. A public hearing was held in February 2011. The NMPRC issued a final order on June 23, 2011 that rejected the plan modifications proposed by PNM and ordered modifications to some programs in the original plan. The final order also adopted a recommendation by the NMPRC staff that the incentive adder rates of $0.005 per kWh and $10 per KW proposed by PNM be reduced to $0.002 per kWh and $4 per kW. The final order also deferred consideration of certain issues relating to the recovery of past program costs, including whether PNM's demand response programs comply with statutory requirements, to a separate proceeding on PNM's 2010 Annual Electric Energy Efficiency Report. The final order approved a rider recovery amount of $22.8 million, including adder revenues of $5.7 million. The adder revenues include $1.9 million of 2010 efficiency programs discussed above that will not have been collected as of July 27, 2011, the effective date for the new rider rate approved by the NMPRC. The new rider rate of 3.018% was effective with bills rendered July 27, 2011 and PNM anticipates making a further reduction in the rider rate resulting from the Supreme Court decision in the disincentive rulemaking discussed above.

On April 1, 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 in its 2010 Annual Electric Energy Efficiency Report, also filed April 1, 2011. PNM proposed an adjustment to the energy efficiency rider to recover an under-collected balance of $2.6 million. The new energy efficiency rider rate, adjusted for the under collected program costs and adjusted savings, would be increased from 2.441% to 2.839%. After requesting additional information from PNM concerning program costs, the NMPRC suspended the proposed adjusted rates for 180 days commencing on May 1, 2011. The NMPRC concluded that some of the program costs exceeded approved budgets and determined that an evidentiary hearing should be held to consider PNM's recovery of over-budget program costs and certain adder amounts and whether sanctions should be imposed on PNM. In June 2011, PNM and the NMPRC staff reached agreement on issues raised by the reconciliation filing and the NMPRC's suspension order. Under the agreement PNM would be permitted recovery of substantially all of its program costs and would not be subject to any sanctions. PNM and the NMPRC staff have filed testimony supporting the settlement. No party has filed testimony in opposition. In a hearing held in July 2011, although no party raised the issue, the Hearing Examiner questioned the reconciliation of 2009 Energy Efficiency Plan costs. He identified costs of approximately $1.4 million which may have exceeded NMPRC-approved budgets by more than 25% and for which NMPRC approval should have been obtained. Because the issue had not previously been raised, he gave PNM until August 4, 2011 to file contrary evidence. PNM's filing asserts that the cost overruns are not as great as the Hearing Examiner calculated, that the costs were incurred for the provision of cost-effective energy efficiency programs, and that they should be deemed approved. PNM is unable to predict the outcome of this matter.

Investigation on Establishing a Policy Linking Utility Earnings to Quality of Customer Service

On May 28, 2009, the NMPRC ordered an investigation to consider the development of a service quality incentive mechanism for utilities in New Mexico, including PNM. The parties were to look at quality of service mechanisms established in other NMPRC orders, as well as the mechanisms that have been implemented in other states. Following a workshop process, the Hearing Examiner filed a report concluding that present circumstances do not warrant the implementation of a performance based ratemaking mechanism to either reward or penalize utilities for quality of service. Instead, the report recommended that utilities be required to file certain customer service reports annually for a three-year period commencing in 2011. The NMPRC issued an order on March 24, 2011 requiring utilities to file annually reports as recommended in the Hearing Examiner's report. These reports are to be filed annually by June 30 of 2011, 2012, and 2013. PNM made its first annual compliance filing on June 24, 2011.

Rates for Former TNMP Customers in New Mexico

PNM serves the former New Mexico customers of TNMP (“TNMP-NM” or “PNM South”) under rates approved by the NMPRC in its order approving PNMR's acquisition of TNMP. Under that order, rates charged to TNMP-NM customers were set through December 31, 2010. In January 2009, the NMPRC directed PNM to estimate the revenue requirement increase that would be reflected in a TNMP-NM rate application for rates effective January 2011. PNM estimated that the rate increase could be between 40% and 56% depending on fuel costs. In April 2009, the NMPRC directed PNM, the NMPRC staff, and other parties to attempt to reach consensus on ways to mitigate the impact of this potential rate increase and appointed a mediator. Mediation did not result in an agreement. On May 25, 2010, the NMPRC issued an order directing PNM and the NMPRC staff to file testimony addressing certain matters related to cost allocation. A hearing was held in December 2010. In April 2011, the NMPRC issued an order that consolidated this case with the pending 2010 Electric Rate Case discussed below. PNM cannot predict the outcome of this matter.

2010 Electric Rate Case

PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represented a 22% increase for PNM North and a 20% increase for PNM South. The filed revenue requirements were based on a future test period ending December 31, 2011. If the NMPRC were to grant the entire relief requested, PNM proposed to implement the increase in two steps. Phase 1 would have become effective April 1, 2011 (PNM North: $111.1 million, 16%; PNM South: $8.7 million, 14%), and Phase 2 would have become effective January 1, 2012 (PNM North: $41.7 million, 6%; PNM South: $3.6 million, 6%). PNM also proposed to implement a FPPAC for PNM South. This is the first rate case filing in New Mexico proposing a future test year consistent with recent amendments to the Public Utility Act. The NMPRC initially suspended the rates until April 1, 2011. On July 27, 2010, in response to motions filed by the NMPRC staff and other parties, the NMPRC determined that PNM's rate filing was incomplete, ordered PNM to supplement its rate application, directed that the suspension period not begin to run until PNM's rate application was made complete, and extended the suspension period by one month. PNM believed that the order was erroneous both in its assessment of the completeness of PNM's filing and in its application of the governing legal standards. On August 5, 2010, PNM supplemented its rate case application in conformance with the NMPRC's order and also petitioned the New Mexico Supreme Court requesting the Court to vacate the NMPRC's July 27, 2010 order and for other equitable relief. The Supreme Court denied PNM's petition on September 13, 2010. In October 2010, PNM began meeting with the NMPRC staff and other parties to discuss settlement. To accommodate these settlement discussions, the Hearing Examiner and the NMPRC issued orders revising the hearing schedule and extending the suspension period.

On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would have resolved all issues in the 2010 Electric Rate Case and provided a rate path for PNM through 2013. Other parties filed statements opposing the stipulation. This stipulation, which reflected some aspects of a future test year, was subject to approval of the NMPRC. The stipulation would have allowed PNM to increase rates by $45.0 million immediately following approval and by an additional $40.0 million beginning January 1, 2012. The proposed rates were designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers would also be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would be able to recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012 or twelve months after the effective date of the new electric rates and would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and December 31, 2012. PNM's next general rate adjustment could not go into effect before January 1, 2014, except that PNM could file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. In addition, the stipulation would limit the amount that could be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during the period covered by the stipulation. Recovery of costs in excess of the limits would be deferred for collection, without carrying costs, to future periods. If the stipulation was approved, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account as a regulatory disallowance. On February 22, 2011, the NMPRC issued an order requiring PNM to agree to extend the suspension period for an additional three months from August 10, 2011 as a condition for going forward with hearings on the stipulation, in order to accommodate the procedural schedule that would be needed if the stipulation was not ultimately approved. PNM gave notice to the NMPRC on February 25, 2011 that it agreed to extend the suspension period until November 10, 2011. On March 17, 2011, PNM filed a request for interim rates to go into effect on May 15, 2011, which was denied by the NMPRC. Several parties filed testimony in opposition to the stipulation. A public hearing on the stipulation was held in May 2011. The hearing examiner issued a Certification of the Stipulation on June 21, 2011. The hearing examiner recommended approval of most of the terms of the stipulation, including the $85 million rate increase, the implementation of the increase in two phases, the moratorium on rate changes through December 31, 2013 the application of PNM North rate schedules to all New Mexico customers, and approval of a consolidated fuel clause. The hearing examiner, however, recommended disapproval of the capital additions rider and the proposed residential rate design. PNM and other parties filed exceptions to the Certification of the Stipulation. As discussed in Note 16, on August 8, 2011, the NMPRC issued a final order that provides for a $72.1 million rate increase and adopts, approves, and accepts the stipulation with other modifications.

2011 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 must contain an action plan covering the first four years of that period. In its most recent IRP, which was filed on July 18, 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. However, PNM has not entered into any commitments regarding these plans beyond what is otherwise described herein. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Unless a protest demonstrating the need for a hearing is filed within 30 days of that date, the NMPRC is authorized to accept the plan without a hearing. If the NMPRC does not act on the IRP within 45 days after the filing of the IRP, the IRP is deemed accepted as compliant with the rules. PNM is unable to predict the outcome of this matter.

Transmission Rate Case

On October 27, 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually and revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms.  If approved, the rate increase would apply to all of PNM's wholesale electric transmission service customers, which include other utilities, electric co-operatives, and entities that use PNM's transmission system to transmit power at the wholesale level.  The proposed rate increase would not impact PNM's retail customers. On December 29, 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. PNM and other parties to the case have engaged in settlement discussions and will continue the negotiation process under the settlement judge procedures. PNM is unable to predict the outcome of this proceeding.

TNMP

TNMP Competitive Transition Charge True-Up Proceeding

The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover, as a CTC, from its transmission and distribution customers. A 2004 PUCT decision established $87.3 million as TNMP's stranded costs. TNMP and other parties made a series of appeals on the ruling. On June 24, 2011, the Texas Supreme Court denied all petitions for review pending in the case. The decision rejects the argument that TNMP's stranded cost balance should be zero. It also denied TNMP's request to remand the case in order to present further evidence of stranded costs that the PUCT previously refused to consider. TNMP filed a motion for rehearing on July 11, 2011 requesting the Texas Supreme Court to reconsider its decision on TNMP's request to present additional stranded costs. No other party filed a motion for rehearing. TNMP is unable to predict the ultimate outcome of this matter.

Interest Rate Compliance Tariff

Following a revision of the interest rate on TNMP's CTC, TNMP filed a compliance tariff to implement the new 8.31% rate. TNMP's filing proposed to put the new rates into effect on February 1, 2008. Intervenors asserted objections to the compliance filing. PUCT staff urged that the PUCT make the new rate effective as of December 27, 2007 when the PUCT's order establishing the correct rate became final. After regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. TNMP filed an appeal of this order in the District Court in Austin, Texas. A hearing was held on June 17, 2010. On June 28, 2010, the District Court reversed the PUCT decision and remanded the matter back to the PUCT for a determination that is not retroactive. The PUCT and other parties appealed the decision to the Texas 3^rd Court of Appeals and presented oral argument on March 23, 2011. On May 12, 2011, the 3^rd Court of Appeals issued its opinion reversing the District Court and reaffirming the PUCT's decision. TNMP filed its petition for review with the Texas Supreme Court on July 27, 2011. TNMP is unable to predict if the Texas Supreme Court will review the decision or the ultimate outcome of this matter. However, due to the decision of the Texas 3^rd Court of Appeals, TNMP is no longer able to assert that it will ultimately be successful in overturning any ruling that the effective date should be prior to December 27, 2007. Accordingly, TNMP recorded a regulatory disallowance of $3.9 million, before income taxes, in the three months ended June 30, 2011 to reflect the impact of applying the 8.31% rate retroactively.

Advanced Meter System Deployment and Surcharge Request

On May 26, 2010, TNMP filed a request with the PUCT to approve TNMP's proposed advanced meter deployment. The filing also requested a surcharge to collect $157.9 million in costs over 12 years, including recovery of capital expenditures of $70.6 million. Due to changes in the tax law, TNMP filed supplemental testimony on February 16, 2011 to reflect the effects of the bonus depreciation, a new WACC, and other changes. The filing amended the requested surcharge to collect $126.1 million, including capital expenditures of $70.2 million incurred through 2015. On May 18, 2011, the parties announced a settlement that permits TNMP to collect the costs of a $113.3 million advanced meter deployment. The settlement approves a lower cost deployment due principally to the removal of an outage management system from TNMP's proposal. The settlement was approved by the PUCT on July 8, 2011. The final order will permit TNMP to begin collection of a surcharge on August 11, 2011 in order to collect a total of $113.3 million in costs over 12 years.

2010 Rate Case

On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In its request, TNMP also asked for permission to update its catastrophe reserve fund that would be utilized to pay for a utility system's costs in recovering from natural disasters and acts of terrorism. Additionally, TNMP requested a rate rider to recover costs to storm harden its system. On November 8, 2010, the presiding ALJ severed the rate case expense issues into a separate proceeding. In December 2010, the parties announced to the ALJ that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million, a return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 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. On January 26, 2011, the ALJ set a procedural schedule requiring the parties who participated in the 2010 rate case to file testimony supporting their respective incurred expenses. The parties agreed to a settlement of the case, which was approved by the PUCT on May 26, 2011, allowing TNMP to collect $2.8 million over three years beginning July 1, 2011.

Remand of ERCOT Transmission Rates for 1999 and 2000

Following a variety of appeals, the ERCOT transmission rates approved in 1999 and 2000 were recently remanded back to the PUCT.  The issues relevant to TNMP are addressed in three separate dockets, but those proceedings are expected to be heard jointly.  These dockets concern the recalculation of rates for the fourth quarter of 1999 and all of 2000 to correct over-payments made by certain market participants and the recovery of additional, undetermined transmission costs by City Public Service Board of San Antonio. TNMP cannot predict the potential range of outcomes or the ultimate outcome of this matter.

Energy Efficiency

On April 29, 2011, TNMP filed an application for approval of its 2012 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP estimates the costs of its 2012 energy efficiency programs to be $4.4 million and requests to collect this amount based on a per customer charge over 12 months. Additionally, as permitted by the PUCT rules, TNMP's request includes a bonus collection amount of $0.3 million due to the fact that its 2010 energy efficiency programs exceeded the performance goals set by the PUCT. On June 23, 2011, the PUCT issued a supplemental preliminary order clarifying that certain costs totaling $0.4 million that, due to a PUCT rule change, TNMP expects to incur during its current 2011 program should be considered in its energy efficiency 2012 filing and not in the current proceeding. On August 2, 2011, TNMP and the other parties announced a settlement of the material issues in this matter. The settlement allows TNMP to collect the $0.3 million bonus for 2010 and estimated 2012 program costs of $3.4 million and sets, for good cause, TNMP's 2012 demand savings goal at 4.8 MW instead of the 5.9 MW goal that would otherwise apply. The settlement does not alter the current PUCT energy efficiency rules permitting  recovery of any under-collection that might exist after the 2012 program year.

Periodic Rate Adjustment

On May 28, 2011, the Governor of Texas signed Senate Bill 1693, which will allow for an annual periodic rate adjustment to reflect changes in investments in distribution assets. To implement the new statute, the PUCT opened a rule-making proceeding. A proposed rule was published by the PUCT in the Texas Register on July 22, 2011. Comments to the new rule are due on August 8, 2011 with reply comments due on August 12, 2011. If requested, a public hearing may be held on August 15, 2011.

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Optim Energy (Details) (USD $)	3 Months Ended		6 Months Ended				3 Months Ended				6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jan. 31, 2010 Interest Rate Swap [Member] Optim Energy [Member]	Jun. 30, 2011 Optim Energy [Member]		Jun. 30, 2010 Optim Energy [Member]		Jun. 30, 2011 Optim Energy [Member]		Jun. 30, 2010 Optim Energy [Member]		Jan. 07, 2011 Optim Energy [Member]	Dec. 31, 2010 Optim Energy [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage							50.00%				50.00%
Derivative, Fixed Interest Rate															1.33%
Commitments and Contingencies							$ 0				$ 0
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Operating revenues							77,315,000		86,871,000		151,248,000		192,465,000
Cost of energy							54,908,000		61,235,000		112,875,000		138,532,000
Gross margin							22,407,000		25,636,000		38,373,000		53,933,000
Non-fuel operations and maintenance expenses							9,408,000		6,450,000		18,651,000		16,970,000
Administrative and general expenses							6,356,000		4,944,000		13,293,000		10,556,000
Depreciation and amortization expense							13,126,000		12,852,000		24,739,000		24,909,000
Taxes other than income tax							2,347,000		3,162,000		4,717,000		6,596,000
Operating income (loss)							(8,830,000)		(1,772,000)		(23,027,000)		(5,098,000)
Interest charges							(3,981,000)		(4,661,000)		(7,965,000)		(9,332,000)
Other income (deductions)							195,000		2,000		263,000		66,000
Earnings (loss) before income taxes							(12,616,000)		(6,431,000)		(30,729,000)		(14,364,000)
Income taxes							94,000	[1]	36,000	[1]	141,000	[1]	68,000	[1]
Net earnings (loss)							(12,710,000)		(6,467,000)		(30,870,000)		(14,432,000)
50 percent of net earnings (loss)							(6,355,000)		(3,234,000)		(15,435,000)		(7,216,000)
Amortization of basis difference in Optim Energy							0		(624,000)		0		(994,000)
Post-impairment loss not recorded under GAAP							6,355,000		0		15,435,000		0
PNMR equity in net earnings (loss) of Optim Energy	0	(3,858,000)	0	(8,210,000)			0		(3,858,000)		0		(8,210,000)
Equity Method Investment, Summarized Financial Information, Assets [Abstract]
Current assets							102,851,000				102,851,000					105,413,000
Net property plant and equipment							908,666,000				908,666,000					924,354,000
Other long-term assets							112,196,000				112,196,000					120,894,000
Total assets							1,123,713,000				1,123,713,000					1,150,661,000
Equity Method Investment, Summarized Financial Information, Liabilities [Abstract]
Current maturities of long-term debt							717,000,000				717,000,000					0
Other current liabilities							52,220,000				52,220,000					50,226,000
Long-term debt							0				0					717,000,000
Other long-term liabilities							9,397,000				9,397,000					7,515,000
Total liabilities							778,617,000				778,617,000					774,741,000
Equity Method Investment Summarized Financial Information, Equity [Abstract]
Owners’ equity							345,096,000				345,096,000					375,920,000
50 percent of owners’ equity							172,548,000				172,548,000					187,960,000
PNMR basis difference in Optim Energy							193,000				193,000					216,000
Impairment of equity investment in Optim Energy							(188,176,000)				(188,176,000)					(188,176,000)
Post-impairment loss not recorded under GAAP							15,435,000				15,435,000					0
PNMR equity investment in Optim Energy							0				0					0
Notional Amount of Interest Rate Cash Flow Hedge Derivatives						650,000,000
Equity Method Investment, Summarized Financial Information, Amortization of Contracts Acquired							3,700,000		4,200,000		7,300,000		8,200,000
Equity Method Investment, Summarized Financial Information, Amortization of Emission Allowances							$ 1,600,000		$ 1,300,000		$ 4,100,000		$ 2,600,000

[1] Represents the Texas Margin Tax, which is considered an income tax under GAAP.

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Segment Information

6 Months Ended

Jun. 30, 2011

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

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 Electric

PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico as well as the sale of transmission to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. This includes the asset optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale rates.

TNMP Electric

TNMP Electric is an electric utility operating in Texas. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides regulated transmission and distribution services in Texas under the TECA.

First Choice

First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small commercial, and governmental customers. Although First Choice is regulated in certain respects by the PUCT, it is not subject to traditional rate regulation.

Optim Energy

Optim Energy is considered a separate segment for PNMR. PNMR’s investment in Optim Energy is held in the Corporate and Other segment and is accounted for using the equity method of accounting. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. As described in Note 11, PNMR fully impaired its investment in Optim Energy as of December 31, 2010.

Corporate and Other

PNMR Services Company is included in the Corporate and Other segment.

The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.

PNMR SEGMENT INFORMATION

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2011	(In thousands)
Operating revenues	$	239,234		$	50,359		$	126,036		$	(43	)	$	415,586
Intersegment revenues	—			9,598			—			(9,598		)	—
Total revenues	239,234			59,957			126,036			(9,641		)	415,586
Cost of energy	81,497			10,259			91,296			(9,598		)	173,454
Gross margin	157,737			49,698			34,740			(43		)	242,132
Other operating expenses	124,297			25,277			23,630			(2,204		)	171,000
Depreciation and amortization	22,897			10,726			360			4,289			38,272
Operating income (loss)	10,543			13,695			10,750			(2,128		)	32,860
Interest income	4,225			—			31			(22		)	4,234
Other income (deductions)	4,484			259			(273		)	(1,648		)	2,822
Net interest charges	(18,027		)	(7,305		)	(141		)	(5,039		)	(30,512		)
Segment earnings (loss) before income taxes	1,225			6,649			10,367			(8,837		)	9,404
Income taxes (benefit)	(872		)	2,547			3,745			(3,685		)	1,735
Segment earnings (loss)	2,097			4,102			6,622			(5,152		)	7,669
Valencia non-controlling interest	(3,470		)	—			—			—			(3,470		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	(1,505	)	$	4,102		$	6,622		$	(5,152	)	$	4,067
Six Months Ended June 30, 2011
Operating revenues	$	473,472		$	95,387		$	234,486		$	(96	)	$	803,249
Intersegment revenues	—			18,412			—			(18,412		)	—
Total revenues	473,472			113,799			234,486			(18,508		)	803,249
Cost of energy	170,711			20,412			159,250			(18,412		)	331,961
Gross margin	302,761			93,387			75,236			(96		)	471,288
Other operating expenses	227,423			44,981			42,616			(5,556		)	309,464
Depreciation and amortization	46,632			20,987			641			8,485			76,745
Operating income (loss)	28,706			27,419			31,979			(3,025		)	85,079
Interest income	8,282			—			34			(55		)	8,261
Other income (deductions)	9,702			575			(379		)	(3,250		)	6,648
Net interest charges	(36,107		)	(14,604		)	(286		)	(10,130		)	(61,127		)
Segment earnings (loss) before income taxes	10,583			13,390			31,348			(16,460		)	38,861
Income taxes (benefit)	1,522			5,125			11,237			(6,643		)	11,241
Segment earnings (loss)	9,061			8,265			20,111			(9,817		)	27,620
Valencia non-controlling interest	(6,652		)	—			—			—			(6,652		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	2,145		$	8,265		$	20,111		$	(9,817	)	$	20,704
At June 30, 2011:
Total Assets	$	3,920,154		$	1,018,425		$	254,352		$	108,702		$	5,301,633
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310
Additions to utility and non-utility plant included in accounts payable	$	16,514		$	360		$	237		$	1,165		$	18,276

	PNM Electric			TNMP Electric			First Choice			Corporate and Other			Consolidated
Three Months Ended June 30, 2010	(In thousands)
Operating revenues	$	243,060		$	42,934		$	119,916		$	(93	)	$	405,817
Intersegment revenues	—			9,635			—			(9,635		)	—
Total revenues	243,060			52,569			119,916			(9,728		)	405,817
Cost of energy	79,639			9,057			72,121			(9,636		)	151,181
Gross margin	163,421			43,512			47,795			(92		)	254,636
Other operating expenses	107,107			19,031			21,253			(3,805		)	143,586
Depreciation and amortization	22,924			10,040			210			4,202			37,376
Operating income (loss)	33,390			14,441			26,332			(489		)	73,674
Interest income	5,081			—			11			(9		)	5,083
Equity in net earnings (loss) of Optim Energy	—			—			—			(3,858		)	(3,858		)
Other income (deductions)	(1,991		)	283			(90		)	(1,546		)	(3,344		)
Net interest charges	(18,385		)	(7,953		)	(387		)	(5,036		)	(31,761		)
Segment earnings (loss) before income taxes	18,095			6,771			25,866			(10,938		)	39,794
Income taxes (benefit)	5,901			2,665			9,313			(4,387		)	13,492
Segment earnings (loss)	12,194			4,106			16,553			(6,551		)	26,302
Valencia non-controlling interest	(3,292		)	—			—			—			(3,292		)
Subsidiary preferred stock dividends	(132		)	—			—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	8,770		$	4,106		$	16,553		$	(6,551	)	$	22,878
Six Months Ended June 30, 2010
Operating revenues	$	473,596		$	81,525		$	234,306		$	(215	)	$	789,212
Intersegment revenues	—			19,221			—			(19,221		)	—
Total revenues	473,596			100,746			234,306			(19,436		)	789,212
Cost of energy	166,073			18,107			177,111			(19,222		)	342,069
Gross margin	307,523			82,639			57,195			(214		)	447,143
Other operating expenses	215,900			37,822			41,701			(7,091		)	288,332
Depreciation and amortization	45,776			20,135			473			8,271			74,655
Operating income (loss)	45,847			24,682			15,021			(1,394		)	84,156
Interest income	10,015			—			13			82			10,110
Equity in net earnings (loss) of Optim Energy	—			—			—			(8,210		)	(8,210		)
Other income (deductions)	9,167			630			(98		)	(2,943		)	6,756
Net interest charges	(36,462		)	(15,822		)	(697		)	(10,190		)	(63,171		)
Segment earnings (loss) before income taxes	28,567			9,490			14,239			(22,655		)	29,641
Income taxes (benefit)	8,822			3,740			5,139			(9,149		)	8,552
Segment earnings (loss)	19,745			5,750			9,100			(13,506		)	21,089
Valencia non-controlling interest	(6,396		)	—			—			—			(6,396		)
Subsidiary preferred stock dividends	(264		)	—			—			—			(264		)
Segment earnings (loss) attributable to PNMR	$	13,085		$	5,750		$	9,100		$	(13,506	)	$	14,429
At June 30, 2010:
Total Assets	$	3,813,524		$	1,013,131		$	239,035		$	337,832		$	5,403,522
Goodwill	$	51,632		$	226,665		$	43,013		$	—		$	321,310

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Jointly-Owned Electric Generating Plants

6 Months Ended

Jun. 30, 2011

Regulated Operations [Abstract]

Jointly Owned Electric Generating Plants

Jointly-Owned Electric Generating Plants

Information concerning Jointly-Owned Electric Generating Plants is discussed in Note 14 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. As discussed in that note, operation of each of the three PVNGS units requires an operating license from the NRC and a portion of PNM’s interests in PVNGS Units 1 and 2 are held under leases that expire in 2015 and 2016. The NRC issued 40 year operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. In December 2008, APS, on behalf of the PVNGS participants, applied for renewed operating licenses for the PVNGS units for a period of 20 years beyond the expirations of the current licenses. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through 2045 for Unit 1, 2046 for Unit 2, and 2047 for Unit 3. PNM is currently evaluating the impacts of the license extensions.

Information concerning the Company's AROs is contained in Note 15 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. PNM has an ARO for PVNGS that includes the obligation for nuclear decommissioning of that facility. In the second quarter of 2011, PNM adopted a new decommissioning study for PVNGS that reflects updated cash flow estimates and the 20-year license extension, which extends the commencement of decommissioning to 2045. The new study resulted in a $4.2 million decrease to the ARO liability for asset retirements and electric plant in service.

The Four Corners plant site is leased from the Navajo Nation and is also subject to a rights-of-way grant from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to the facility lease with the Navajo Nation, which would extend the Four Corners leasehold interest to 2041. The amendments have been approved by the Navajo Nation Council and signed by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does the related federal rights-of-way grant, which the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process.PNM’s share of the annual lease payments will be $0.9 million beginning in 2016.

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Fair Value of Derivative and Other Financial Instruments, Statement of Earnings Information (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 190	$ (121)	$ 1,334	$ (2,007)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Electric operating revenues [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	6,539	0	13,288
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(284)	(37)	159	(3,662)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cost of energy [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	(41)	0	14
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(94)	(158)	1,493	(5,669)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	6,498	0	13,302
Recognized in OCI	0	(6,311)	0	(6,078)
Commodity Contract [Member] | Electric operating revenues [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	190	(121)	1,334	(2,007)
Commodity Contract [Member] | Electric operating revenues [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	(36)	0	(33)
Commodity Contract [Member] | Electric operating revenues [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	6,539	0	13,288
Commodity Contract [Member] | Cost of energy [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(4,594)	2,720	86	(29,229)
Commodity Contract [Member] | Cost of energy [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	0	0	0
Commodity Contract [Member] | Cost of energy [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(318)	(771)	(249)	(1,246)
Commodity Contract [Member] | Economic hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(4,404)	2,599	1,420	(31,236)
Commodity Contract [Member] | Trading transactions [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	0	(36)	0	(33)
Commodity Contract [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	(318)	5,768	(249)	12,042
Recognized in OCI	318	(5,581)	249	(4,818)
Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			100
Public Service Company of New Mexico [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			$ 0

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

Information regarding the computation of earnings per share is as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	4,067	$	22,878	$	20,704	$	14,429
Average Number of Common Shares:
Outstanding during period	86,673		86,673		86,673		86,673
Equivalents from convertible preferred stock (Note 7)	4,778		4,778		4,778		4,778
Vested awards of restricted stock	139		109		149		102
Average Shares - Basic	91,590		91,560		91,600		91,553
Dilutive Effect of Common Stock Equivalents (1):
Stock options and restricted stock	546		273		502		141
Average Shares - Diluted	92,136		91,833		92,102		91,694
Net Earnings Per Share of Common Stock:
Basic	$	0.04	$	0.25	$	0.23	$	0.16
Diluted	$	0.04	$	0.25	$	0.22	$	0.16

(1) Excludes the effect of out-of-the-money options for 1,978,010 shares of common stock at June 30, 2011.

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash Flows From Operating Activities:
Net earnings	$ 27,620	$ 21,089
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	97,404	89,608
PVNGS firm-sales contract revenue	(2,558)	(28,856)
Bad debt expense	11,732	13,035
Deferred income tax expense (benefit)	17,992	15,649
Equity in net (earnings) loss of Optim Energy	0	8,210
Net unrealized (gains) losses on derivatives	(6,996)	24,752
Realized (gains) on investments held by NDT	(11,797)	(400)
Stock based compensation expense	2,867	1,962
Regulatory disallowances	21,402	0
Other, net	2,115	2,288
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(44,371)	(23,643)
Materials, supplies, and fuel stock	1,109	(1,615)
Other current assets	1,679	(34,909)
Other assets	(257)	(5,739)
Accounts payable	6,101	(476)
Accrued interest and taxes	(6,798)	55,024
Other current liabilities	(10,532)	(44,694)
Other liabilities	(21,972)	(15,083)
Net cash flows from operating activities	84,740	76,202
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(153,168)	(136,296)
Proceeds from sales of investments held by NDT	94,890	36,285
Purchases of investments held by NDT	(96,410)	(37,850)
Return of principal on PVNGS lessor notes	15,374	14,216
Investments in Optim Energy	0	(16,407)
Other, net	760	1,416
Net cash flows from investing activities	(138,554)	(138,636)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	82,000	87,000
Long-term borrowings	0	403,845
Repayment of long-term debt	0	(403,845)
Proceeds from stock option exercise	2,172	778
Purchases to satisfy awards of common stock	(4,535)	(2,269)
Excess tax (shortfall) from stock-based payment arrangements	0	(114)
Dividends paid	(23,127)	(23,127)
Equity transactions with Valencia's owner	(7,232)	(7,019)
Payments received on PVNGS firm-sales contracts	2,558	15,233
Proceeds from transmission interconnection agreements	589	0
Debt issuance costs and other	8	(3,592)
Net cash flows from financing activities	52,433	66,890
Change in Cash and Cash Equivalents	(1,381)	4,456
Cash and Cash Equivalents at Beginning of Period	15,404	14,641
Cash and Cash Equivalents at End of Period	14,023	19,097
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	57,930	61,188
Income taxes paid (refunded), net	(1,775)	(63,408)
Public Service Company of New Mexico [Member]
Cash Flows From Operating Activities:
Net earnings	9,061	19,745
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	63,077	56,975
PVNGS firm-sales contract revenue	(2,558)	(28,856)
Deferred income tax expense (benefit)	8,784	18,777
Net unrealized (gains) losses on derivatives	(1,453)	5,605
Realized (gains) on investments held by NDT	(11,797)	(400)
Regulatory disallowances	17,479	0
Other, net	3,432	4,030
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(8,796)	1,845
Materials, supplies, and fuel stock	830	(1,154)
Other current assets	7,467	(17,477)
Other assets	3,301	3,395
Accounts payable	(2,791)	2,315
Accrued interest and taxes	(4,196)	24,721
Other current liabilities	6,730	(44,593)
Other liabilities	(22,339)	(14,521)
Net cash flows from operating activities	66,231	30,407
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(125,939)	(118,467)
Proceeds from sales of investments held by NDT	94,890	36,285
Purchases of investments held by NDT	(96,410)	(37,850)
Return of principal on PVNGS lessor notes	15,374	14,216
Other, net	1,037	945
Net cash flows from investing activities	(111,048)	(104,871)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	83,000	74,000
Long-term borrowings	0	403,845
Repayment of long-term debt	0	(403,845)
Dividends paid	(43,949)	(264)
Equity transactions with Valencia's owner	(7,232)	(7,019)
Payments received on PVNGS firm-sales contracts	2,558	15,233
Proceeds from transmission interconnection agreements	589	0
Debt issuance costs and other	0	(3,118)
Net cash flows from financing activities	34,966	78,832
Change in Cash and Cash Equivalents	(9,851)	4,368
Cash and Cash Equivalents at Beginning of Period	10,336	1,373
Cash and Cash Equivalents at End of Period	485	5,741
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	35,081	37,656
Income taxes paid (refunded), net	(1,539)	(35,189)
Texas-New Mexico Power Company [Member]
Cash Flows From Operating Activities:
Net earnings	8,265	5,750
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	22,569	22,147
Deferred income tax expense (benefit)	4,805	(3,444)
Regulatory disallowances	3,923	0
Other, net	31	(633)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,798)	(3,240)
Materials, supplies, and fuel stock	74	(494)
Other current assets	(2,243)	(1,153)
Other assets	(657)	(1,730)
Accounts payable	(154)	(1,552)
Accrued interest and taxes	(6,034)	1,598
Other current liabilities	1,628	(1,391)
Other liabilities	(1,078)	(689)
Net cash flows from operating activities	25,331	15,169
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(24,072)	(13,967)
Net cash flows from investing activities	(24,072)	(13,967)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net – affiliate	5,800	500
Dividends paid	(7,066)	(1,644)
Debt issuance costs and other	7	(124)
Net cash flows from financing activities	(1,259)	(1,268)
Change in Cash and Cash Equivalents	0	(66)
Cash and Cash Equivalents at Beginning of Period	1	138
Cash and Cash Equivalents at End of Period	1	72
Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	13,852	14,050
Income taxes paid (refunded), net	$ 3,250	$ 2,940

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New Accounting Pronouncements

6 Months Ended

Jun. 30, 2011

New Accounting Pronouncements [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

New Accounting Pronouncements

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

Accounting Standards Update 2011-04 - Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs

The Financial Accounting Standards Board ("FASB") released amended guidance to provide a consistent definition of fair value and to ensure fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards.  The update changes certain fair value measurement principles, further enhances disclosure requirements related to transfers between hierarchy levels, and increases qualitative disclosures regarding unobservable inputs used in Level 3 measurements, including the sensitivity of recurring Level 3 measurements to changes in significant unobservable inputs. In addition, the update requires disclosure of the level within the fair value hierarchy for fair value disclosures of instruments recorded on an amortized cost basis. The update is required to be applied prospectively and is effective for interim and annual reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement upon its effective date.

Accounting Standards Update 2011-05 - Comprehensive Income: Presentation of Comprehensive Income

The FASB released amended guidance regarding presentation of comprehensive income in financial statements. The update requires entities to report comprehensive income in either one continuous statement of comprehensive income or in two separate but consecutive statements. Under the two-statement approach, the first statement would include components of net income consistent with current guidance, and the second statement would include components of other comprehensive income. Regardless of the approach elected, entities will be required to show the impacts of reclassification adjustments from other comprehensive income in both the statements of net income and the statements in which other comprehensive income is presented. The update is effective for interim and annual reporting periods beginning after December 15, 2011, with early adoption permitted. The Company does not believe this guidance will have a material impact on the Company's financial statements and will comply with this requirement no later than its effective date.

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Fair Value of Derivative and Other Financial Instruments, Carrying Amount and Fair Value (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Public Service Company of New Mexico [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,055,756	$ 1,055,748
Investments in PVNGS lessor notes	124,527	136,145
Other investments	4,118	5,068
Public Service Company of New Mexico [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,079,797	1,056,864
Investments in PVNGS lessor notes	124,311	141,663
Other investments	4,432	5,563
Texas-New Mexico Power Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	310,650	310,337
Other investments	268	282
Texas-New Mexico Power Company [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	417,378	385,220
Other investments	268	282
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,566,168	1,565,847
Investments in PVNGS lessor notes	124,527	136,145
Other investments	15,645	18,791
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,722,785	1,659,674
Investments in PVNGS lessor notes	124,311	141,663
Other investments	$ 20,766	$ 21,675

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Subsequent Events

6 Months Ended

Jun. 30, 2011

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Subsequent Events

PNM's 2010 Electric Rate Case is discussed in Note 10. On August 8, 2011, a majority of the commissioners of the NMPRC signed a final order that adopts, approves, and accepts the stipulation in the 2010 Electric Rate Case with certain modifications. The order provides that, for the order to become effective, PNM and the other signers of the stipulation have until August 12, 2011 to formally accept the modifications or to indicate that they either do not oppose or take no position on the modifications. Therefore, no assurance can be given that the NMPRC's order will become effective. If the signers of the stipulation do not accept the modifications, any one of them could ask the NMPRC to rehear and reconsider the order, or specific aspects of it. Other parties could also request rehearing and reconsideration whether or not the modifications are opposed by any of the signers. PNM cannot predict if any party will request rehearing or the outcome of any such request. If the order does not become effective, PNM would proceed with litigation of the original case, which requested a $165.2 million rate increase, before the NMPRC.

The NMPRC's modifications include:

• A revenue increase for PNM's New Mexico retail customers of $72.1 million that PNM could implement currently, thereby eliminating the phased-in increases contained in the stipulation;

• Elimination of the rider that would have allowed PNM to increase rates in 2013 by up to $20.0 million based on changes in plant-related rate base between June 30, 2010 and December 31, 2012;

• A change in rate design for the residential customer class;

• If approved by the signers, a change in the moratorium on the next general increase in PNM's rates, such that the increase could not become effective before July 1, 2013, rather than January 1, 2014 as specified in the stipulation.

Provisions of the stipulation that the NMPRC did not alter include:

• Allowing PNM to file for recovery of the costs of renewable energy procurement programs through a rate rider;

• Allowing PNM to file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010;

• The proposed convergence of rates for PNM North and PNM South;

• The same FPPAC for PNM North and PNM South customers;

• The agreement among the signers of the stipulation to seek dismissal of the NMPRC's proceeding concerning PNM's replacement power costs recovered through the FPPAC, which is discussed under Emergency FPPAC in Note 10;

• PNM's agreement to forego $10.0 million of the under-collected amount in the FPPAC balancing account.

As a result of the above, PNM recorded a pre-tax loss for the $10.0 million of fuel costs discussed above that will not be recovered through the FPPAC. In addition, PNM recorded a pre-tax loss aggregating $7.5 million for costs that will not be recovered in rates approved by the NMPRC order. These costs primarily relate to rate case expenses for the 2010 Electric Rate Case, expenses related to an audit of fuel and purchased power costs, loss on debt re-acquired in previous years, and the 2010 settlement of claims against DOE related to spent nuclear fuel at PVNGS. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM's Condensed Consolidated Statement of Earnings (Loss).

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Condensed Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net earnings	$ 7,669	$ 26,302	$ 27,620	$ 21,089
Unrealized Gain (Loss) on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	8,892	(1,953)	14,161	(88)
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(12,043)	(1,098)	(15,201)	(2,029)
Pension liability adjustment, net of income tax (expense) benefit	648	0	(966)	(223)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(585)	(1,978)	(562)	5,639
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	389	(6,055)	543	(12,370)
Total Other Comprehensive Income (Loss)	(2,699)	(11,084)	(2,025)	(9,071)
Comprehensive Income (Loss)	4,970	15,218	25,595	12,018
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,470)	(3,292)	(6,652)	(6,396)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Comprehensive Income (Loss) Attributable to PNMR	1,368	11,794	18,679	5,358
Public Service Company of New Mexico [Member]
Net earnings	2,097	12,194	9,061	19,745
Unrealized Gain (Loss) on Investment Securities:
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit	8,892	(1,953)	14,161	(88)
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(12,043)	(1,098)	(15,201)	(2,029)
Pension liability adjustment, net of income tax (expense) benefit	646	0	(659)	(223)
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	0	109	0	4,223
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	0	(3,876)	17	(7,950)
Total Other Comprehensive Income (Loss)	(2,505)	(6,818)	(1,682)	(6,067)
Comprehensive Income (Loss)	(408)	5,376	7,379	13,678
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,470)	(3,292)	(6,652)	(6,396)
Comprehensive Income (Loss) Attributable to PNMR	(3,878)	2,084	727	7,282
Texas-New Mexico Power Company [Member]
Net earnings	4,102	4,106	8,265	5,750
Unrealized Gain (Loss) on Investment Securities:
Pension liability adjustment, net of income tax (expense) benefit	2	0	(307)	0
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit	(555)	(976)	(491)	(1,607)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit)	184	186	365	371
Total Other Comprehensive Income (Loss)	(369)	(790)	(433)	(1,236)
Comprehensive Income (Loss)	$ 3,733	$ 3,316	$ 7,832	$ 4,514

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Pension and Other Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2011

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefit Plans

PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (“PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Information concerning pension and other postretirement plans is contained in Note 12 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.

PNM Plans

The following table presents the components of the PNM Plans’ net periodic benefit cost:

	Three Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	65		$	105		$	—	$	—
Interest cost	8,202			8,518			1,345			1,913			233		263
Long-term return on plan assets	(9,269		)	(9,339		)	(1,347		)	(1,393		)	—		—
Amortization of net loss	2,302			1,613			801			1,372			23		18
Amortization of prior service cost	79			79			(662		)	(1,036		)	—		—
Net periodic benefit cost	$	1,314		$	871		$	202		$	961		$	256	$	281

	Six Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	129		$	210		$	—	$	—
Interest cost	16,402			17,037			2,689			3,825			465		527
Long-term return on plan assets	(18,537		)	(18,677		)	(2,694		)	(2,786		)	—		—
Amortization of net loss	4,605			3,225			1,603			2,744			47		35
Amortization of prior service cost	158			158			(1,324		)	(2,071		)	—		—
Net periodic benefit cost	$	2,628		$	1,743		$	403		$	1,922		$	512	$	562

PNM made contributions to its pension plan trust of $7.5 million and $13.5 million in the three months and six months ended June 30, 2011 and zero and $6.5 million in the three months and six months ended June 30, 2010. PNM anticipates making $28.0 million of additional contributions in 2011.  Based on current law and estimates of portfolio performance, PNM estimates making contributions to its pension plan trust that total $190.0 million for 2012- 2015. The estimated contributions were developed using probabilistically determined discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. PNM contributed $1.2 million to the trust for other postretirement benefits for the three months and six months ended June 30, 2011 and $1.2 million for the three months and six months ended June 30, 2010. PNM expects to make contributions totaling $2.5 million during 2011 to the trust for other postretirement benefits.  Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were $0.4 million and $0.8 million in the three months and six months ended June 30, 2011 and $0.4 million and $0.7 million in the three months and six months ended June 30, 2010 and are expected to total $1.5 million during 2011.

TNMP Plans

The following table presents the components of the TNMP Plans’ net periodic benefit cost (income):

	Three Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	77		$	72		$	—	$	—
Interest cost	951			1,032			163			178			12		13
Long-term return on plan assets	(1,368		)	(1,449		)	(133		)	(129		)	—		—
Amortization of net (gain) loss	86			—			(48		)	(49		)	—		(1		)
Amortization of prior service cost	—			—			15			15			—		—
Net Periodic Benefit Cost (Income)	$	(331	)	$	(417	)	$	74		$	87		$	12	$	12

	Six Months Ended June 30,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2011			2010			2011			2010			2011		2010
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	153		$	144		$	—	$	—
Interest cost	1,900			2,063			327			356			23		26
Long-term return on plan assets	(2,735		)	(2,897		)	(267		)	(257		)	—		—
Amortization of net (gain) loss	173			—			(96		)	(98		)	—		(2		)
Amortization of prior service cost	—			—			30			30			—		—
Net Periodic Benefit Cost (Income)	$	(662	)	$	(834	)	$	147		$	175		$	23	$	24

TNMP made contributions to its pension plan trust of $0.1 million and $0.2 million in the three months and six months ended June 30, 2011 and no contributions in the three months and six months ended June 30, 2010. TNMP anticipates making additional contributions of $1.0 million in 2011. Based on current law and estimates of portfolio performance, TNMP estimates making contributions to its pension plan trust that total $6.5 million for 2012-2015. The estimated contributions were developed using probabilistically determined discount rates and expected returns on assets to calculate the pension liabilities. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate and return on assets. TNMP contributed $0.4 million to the trust for other postretirement benefits for the three months and six months ended June 30, 2011 and $0.6 million for the three months and six months ended June 30, 2010. TNMP does not expect to make additional contributions during 2011 to the trust for other postretirement benefits. Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were less than $0.1 million in the three months and six months ended June 30, 2011 and 2010 and are expected to total $0.1 million during 2011.

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Regulatory and Rate Matters (Details) (USD $)					0 Months Ended									0 Months Ended		1 Months Ended							1 Months Ended			6 Months Ended																	1 Months Ended			1 Months Ended		1 Months Ended			1 Months Ended					3 Months Ended															6 Months Ended
	Jun. 30, 2011 Public Service Company of New Mexico [Member] Maximum [Member] Renewable Portfolio Standard [Member]	May 03, 2010 Public Service Company of New Mexico [Member] Maximum [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per KWh [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Maximum [Member] 2010 Energy Efficiency Application [Member] Per KWh [Member] Originally Filed [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Maximum [Member] 2010 Energy Efficiency Application [Member] Per kilowatt [Member] Originally Filed [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] Maximum [Member] Rates For Former TNMP Customers in New Mexico [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Wind Energy [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Solar Energy [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Renewable Technologies [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Minimum [Member] Renewable Portfolio Standard [Member] Distributed Generation [Member]	May 03, 2010 Public Service Company of New Mexico [Member] Minimum [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per KWh [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Minimum [Member] 2010 Energy Efficiency Application [Member] Per KWh [Member] Amended [Member]	Jun. 23, 2011 Public Service Company of New Mexico [Member] Minimum [Member] 2010 Energy Efficiency Application [Member] Per kilowatt [Member] Amended [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] Minimum [Member] Rates For Former TNMP Customers in New Mexico [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Emergency FPPAC [Member]	Apr. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] mwh	Aug. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] mw	Jun. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] mw	Jun. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2006 [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2011 [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2015 [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Required Percentage by 2020 [Member]	Jul. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Originally Filed [Member] mwh	Dec. 31, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Amended [Member] mwh	Dec. 06, 2010 Public Service Company of New Mexico [Member] Renewable Portfolio Standard [Member] Wind Energy [Member] Amended [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Dec. 29, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	Nov. 29, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	May 31, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	May 05, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]	May 03, 2010 Public Service Company of New Mexico [Member] NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member] Per kilowatt [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Sep. 15, 2010 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Originally Filed [Member]	Apr. 15, 2011 Public Service Company of New Mexico [Member] 2010 Energy Efficiency Application [Member] Amended [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Jun. 21, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Immediate Enaction [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Enaction Beginning 2012 [Member]	Aug. 08, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Settlement of Regulatory Matter [Member]	Feb. 03, 2011 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Capital Expenditures [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase One [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase One [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase Two [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm North [Member] Phase Two [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase One [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase One [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase Two [Member]	May 31, 2010 Public Service Company of New Mexico [Member] 2010 Electric Rate Case [Member] Pnm South [Member] Phase Two [Member]	Oct. 27, 2010 Public Service Company of New Mexico [Member] Transmission Rate Case [Member]	Jun. 24, 2011 Texas-New Mexico Power Company [Member] Competitive Transition Charge True-Up Proceeding [Member]	Dec. 31, 2004 Texas-New Mexico Power Company [Member] Competitive Transition Charge True-Up Proceeding [Member] Stranded Costs [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Interest Rate Compliance Tariff [Member]	Jan. 31, 2008 Texas-New Mexico Power Company [Member] Interest Rate Compliance Tariff [Member]	May 18, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Feb. 26, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	May 26, 2010 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member]	Feb. 26, 2011 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Capital Expenditures [Member]	May 26, 2010 Texas-New Mexico Power Company [Member] Advanced Meter System Deployment and Surcharge Request [Member] Capital Expenditures [Member]	Jan. 27, 2011 Texas-New Mexico Power Company [Member] Rate Case, 2010 [Member]	Aug. 26, 2010 Texas-New Mexico Power Company [Member] Rate Case, 2010 [Member]	May 26, 2011 Texas-New Mexico Power Company [Member] Rate Case Expense Proceeding, 2010 [Member]	Aug. 02, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Jun. 23, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Apr. 29, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member]	Aug. 02, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Related to Performance Goal [Member]	Apr. 29, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Related to Performance Goal [Member]	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Originally Filed [Member] mw	Jun. 30, 2011 Texas-New Mexico Power Company [Member] Energy Efficiency [Member] Amended [Member] mw
Rate Matters [Line Items]
Amount of Regulatory Costs Not yet Approved															$ 8,000,000			$ 20,300,000							$ 5,500,000					$ 6,200,000			$ 32,900,000					$ 165,200,000				$ 20,000,000			$ 111,100,000		$ 41,700,000			$ 8,700,000		$ 3,600,000	$ 11,100,000						$ 126,100,000	$ 157,900,000	$ 70,200,000	$ 70,600,000		$ 20,100,000				$ 4,400,000		$ 300,000
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales																			5.00%	10.00%	15.00%	20.00%
Public Utilities, Required Percentage of Diversification							20.00%	20.00%	10.00%	1.50%
Public Utilities, Reasonable Cost Threshold	3.00%					2.00%
Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold																		0.25%
Public Utilities, Procurment of Energy, Nonmonetary																	22						250,000	423,860
Public Utilities, Regulatory Costs Approved																		107,700,000										4,200,000					31,400,000								72,100,000																	113,300,000					10,250,000		2,800,000	3,400,000			300,000
Public Utilities, Current Operational Usage																		7
Public Utilities, Estimated Operational Usage in Current Fiscal Year																		22
Public Utilities, Maximum Capacity Of Request For Proposal For Renewable Energy And Renewable Energy Certificates Issued																360,000
Public Utilities, Rate Adder Allowed		0.01	0.005	10							0.005	0.002	4																		10	0.03018		0.02441	0.02839
Public Utilities, Regulatory Rate Recommended For Recovery																													4,200,000								85,000,000
Public Utilities, Rate Rider to be Implemented																											4,200,000					22,800,000
Public Utilities, Rate Rider Recovered																										1,900,000
Public Utilities, Adder Revenue to be Implemented																																5,700,000
Public Utilities, Rate Adder Revenue Not Recovered From Previous Year																																1,900,000
Public Utilities, Rate Rider Adjustment																																			2,600,000
Public Utilities, Regulatory Costs That Have Exceeded Approved Costs																																1,400,000
Public Utilities, Percent of Regulatory Costs in Excess of Approved																																0.25
Public Utilities, Regulatory Rate Increase					0.56									0.40																													0.22	0.16		0.06		0.20	0.14		0.06
Public Utilities, Regulatory Costs Proposed, Stipulation Increase																																							45,000,000	40,000,000
Public Utilities, Collection of Regulatory Costs Forgoed of Under Collected Amount																																				10,000,000
Regulatory Assets																																																							87,300,000
Regulatory Assets, Proposed by Company																																																						0
Public Utilities, Proposed Rate																																																									0.0831
Public Utilities, Regulatory Disallowance Before Income Taxes																																																								3,900,000
Public Utilities, Return on Equity																																																															0.10125
Public Utitlities, Debt to Equity Capital Structure, Debt																																																															0.55
Public Utilities, Debt to Equity Capital Structure, Equity																																																															0.45
Amount of Regulatory Costs Not Included From Original Filing																																																																			$ 400,000
Demand Savings Goal																																																																							5.9	4.8

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Goodwill and Other Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2011	Mar. 31, 2010	Dec. 31, 2007 Customer Lists [Member] years
Schedule of Goodwill and Other Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life (years)			8
Goodwill, Impairment Loss	$ 0	$ 0
Impairment of Intangible Assets, Indefinite-lived (Excluding Goodwill)	$ 0	$ 0

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2011

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

See Note 11 for information concerning Optim Energy. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Six Months ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	9,598	$	9,635	$	18,412	$	19,221
Services billings:
PNMR to PNM	24,733		21,913		46,169		43,575
PNMR to TNMP	7,374		5,804		13,955		12,292
PNM to TNMP	160		178		287		278
TNMP to PNMR	44		93		97		214
PNMR to Optim Energy	1,404		1,371		2,804		2,809
Optim Energy to PNMR	9		33		19		51
Income tax sharing payments:
PNMR to PNM	—		35,190		—		35,190
Interest charges:
TNMP to PNMR	26		102		28		185
PNM to PNMR	8		—		36		—
PNMR to PNM	32		—		64		—

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Related Party Transactions

6 Months Ended

Jun. 30, 2011

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

PNMR, PNM, TNMP, and Optim Energy are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR, its subsidiaries, and Optim Energy in accordance with shared services agreements. There is also a services agreement for Optim Energy to provide services to PNMR. Additional information concerning the Company’s related party transactions is contained in Note 20 of Notes to Consolidated Financial Statements in the 2010 Annual Reports on Form 10-K.

See Note 11 for information concerning Optim Energy. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

	Three Months Ended				Six Months ended
	June 30,				June 30,
	2011		2010		2011		2010
	(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	9,598	$	9,635	$	18,412	$	19,221
Services billings:
PNMR to PNM	24,733		21,913		46,169		43,575
PNMR to TNMP	7,374		5,804		13,955		12,292
PNM to TNMP	160		178		287		278
TNMP to PNMR	44		93		97		214
PNMR to Optim Energy	1,404		1,371		2,804		2,809
Optim Energy to PNMR	9		33		19		51
Income tax sharing payments:
PNMR to PNM	—		35,190		—		35,190
Interest charges:
TNMP to PNMR	26		102		28		185
PNM to PNMR	8		—		36		—
PNMR to PNM	32		—		64		—

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Condensed Consolidated Statements of Earnings (Loss) (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Electric Operating Revenues
Affiliate	$ 0	$ 0	$ 0	$ 0
Electric Operating Revenues	415,586	405,817	803,249	789,212
Operating Expenses:
Cost of energy	173,454	151,181	331,961	342,069
Administrative and general	68,795	62,420	127,260	125,205
Energy production costs	47,127	51,811	95,779	105,696
Regulatory disallowances	21,402	0	21,402	0
Depreciation and amortization	38,272	37,376	76,745	74,655
Transmission and distribution costs	18,161	15,672	35,038	29,562
Taxes other than income taxes	15,515	13,683	29,985	27,869
Total operating expenses	382,726	332,143	718,170	705,056
Operating income	32,860	73,674	85,079	84,156
Other Income and Deductions:
Interest income	4,234	5,083	8,261	10,110
Gains (losses) on investments held by NDT	5,894	(1,342)	11,797	400
Other income	809	1,171	1,804	11,370
Equity in net earnings (loss) of Optim Energy	0	(3,858)	0	(8,210)
Other deductions	(3,881)	(3,173)	(6,953)	(5,014)
Net other income (deductions)	7,056	(2,119)	14,909	8,656
Interest Charges	30,512	31,761	61,127	63,171
Earnings before Income Taxes	9,404	39,794	38,861	29,641
Income Taxes (Benefit)	1,735	13,492	11,241	8,552
Net Earnings	7,669	26,302	27,620	21,089
(Earnings) Attributable to Valencia Non-controlling Interest	(3,470)	(3,292)	(6,652)	(6,396)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings Attributable to Company	4,067	22,878	20,704	14,429
Net Earnings Attributable to PNMR per Common Share:
Basic	$ 0.04	$ 0.25	$ 0.23	$ 0.16
Diluted	$ 0.04	$ 0.25	$ 0.22	$ 0.16
Dividends Declared per Common Share	$ 0.125	$ 0.125	$ 0.250	$ 0.250
Public Service Company of New Mexico [Member]
Electric Operating Revenues
Electric Operating Revenues	239,234	243,060	473,472	473,596
Operating Expenses:
Cost of energy	81,497	79,639	170,711	166,073
Administrative and general	38,580	37,498	72,916	75,184
Energy production costs	47,127	51,809	95,779	105,694
Regulatory disallowances	17,479	0	17,479	0
Depreciation and amortization	22,897	22,924	46,632	45,776
Transmission and distribution costs	11,902	10,323	23,509	19,631
Taxes other than income taxes	9,209	7,477	17,740	15,391
Total operating expenses	228,691	209,670	444,766	427,749
Operating income	10,543	33,390	28,706	45,847
Other Income and Deductions:
Interest income	4,225	5,081	8,282	10,015
Gains (losses) on investments held by NDT	5,894	(1,342)	11,797	400
Other income	441	1,145	742	11,182
Other deductions	(1,851)	(1,794)	(2,837)	(2,415)
Net other income (deductions)	8,709	3,090	17,984	19,182
Interest Charges	18,027	18,385	36,107	36,462
Earnings before Income Taxes	1,225	18,095	10,583	28,567
Income Taxes (Benefit)	(872)	5,901	1,522	8,822
Net Earnings	2,097	12,194	9,061	19,745
(Earnings) Attributable to Valencia Non-controlling Interest	(3,470)	(3,292)	(6,652)	(6,396)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings Attributable to Company	(1,373)	8,902	2,409	13,349
Net Earnings (Loss) Available for Company Common Stock	(1,505)	8,770	2,145	13,085
Texas-New Mexico Power Company [Member]
Electric Operating Revenues
Non-affiliates	50,359	42,934	95,387	81,525
Affiliate	9,598	9,635	18,412	19,221
Total electric operating revenues	59,957	52,569	113,799	100,746
Operating Expenses:
Cost of energy	10,259	9,057	20,412	18,107
Administrative and general	10,135	8,818	19,801	18,312
Regulatory disallowances	3,923	0	3,923	0
Depreciation and amortization	10,726	10,040	20,987	20,135
Transmission and distribution costs	6,256	5,348	11,524	9,929
Taxes other than income taxes	4,963	4,865	9,733	9,581
Total operating expenses	46,262	38,128	86,380	76,064
Operating income	13,695	14,441	27,419	24,682
Other Income and Deductions:
Other income	288	309	650	673
Other deductions	(29)	(26)	(75)	(43)
Net other income (deductions)	259	283	575	630
Interest Charges	7,305	7,953	14,604	15,822
Earnings before Income Taxes	6,649	6,771	13,390	9,490
Income Taxes (Benefit)	2,547	2,665	5,125	3,740
Net Earnings	$ 4,102	$ 4,106	$ 8,265	$ 5,750

XML



Variable Interest Entities (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011 mw	Jun. 30, 2010	Dec. 31, 2010	May 30, 2010
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings Attributable to non-controlling interest	$ 3,470,000	$ 3,292,000	$ 6,652,000	$ 6,396,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current Assets	567,288,000		567,288,000		543,880,000
Assets	5,301,633,000	5,403,522,000	5,301,633,000	5,403,522,000	5,225,083,000
Current liabilities	589,447,000		589,447,000		520,124,000
Stockholders' Equity Attributable to Noncontrolling Interest	84,597,000		84,597,000		85,177,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member]
Variable Interest Entity [Line Items]
Operating Leases, Future Minimum Payments Due	111,400,000		111,400,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | Property Lease Guarantee [Member] | Maximum [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Loss Contingency, Range of Possible Loss, Portion Not Accrued	177,000,000		177,000,000
Public Service Company of New Mexico [Member] | Palo Verde Nuclear Generating Station [Member] | PVNGS [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Current	26,000,000		26,000,000
Public Service Company of New Mexico [Member] | Valencia [Member]
Variable Interest Entity [Line Items]
Public Utilities, Power Plant Total Construction Costs						90,000,000
Long Term Contract For Purchase of Power Term of Contract			20 years
Long Term Contract for Purchase of Electric Power Plant, Estimated Total Output (in Megawatts)			145
Long Term Contract For Purchase of Electric Power Fixed Costs	4,600,000	4,500,000	9,100,000	9,000,000
Long Term Contract For Purchase of Electric Power Variable Charges	300,000	200,000	400,000	300,000
Variable Interest Entity, Statement Of Operation [Abstract]
Operating revenues	4,849,000	4,725,000	9,519,000	9,227,000
Operating expenses	1,379,000	1,433,000	2,867,000	2,831,000
Earnings Attributable to non-controlling interest	3,470,000	3,292,000	6,652,000	6,396,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current Assets	3,158,000		3,158,000		2,372,000
Net property, plant and equipment	82,200,000		82,200,000		83,617,000
Assets	85,358,000		85,358,000		85,989,000
Current liabilities	761,000		761,000		812,000
Stockholders' Equity Attributable to Noncontrolling Interest	84,597,000		84,597,000		85,177,000
Public Service Company of New Mexico [Member] | Valencia [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Jointly Owned Utility Plant, Option to Purchase Proportionate Ownership Share	50.00%		50.00%
Valencia [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Operating Leases, Future Minimum Payments Due, Current					26,000,000
Public Service Company of New Mexico [Member] | PVNGS [Member]
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Power Plant Operating Licenses Term			20 years
Public Service Company of New Mexico [Member] | Delta [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Fixed Costs	1,500,000	1,700,000	2,900,000	3,000,000
Long Term Contract For Purchase of Electric Power Variable Charges			300,000	200,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining	54,100,000		54,100,000
Public Service Company of New Mexico [Member] | Delta [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Long Term Contract For Purchase of Electric Power Variable Charges	100,000	100,000
Public Service Company of New Mexico [Member]
Variable Interest Entity, Statement Of Operation [Abstract]
Earnings Attributable to non-controlling interest	3,470,000	3,292,000	6,652,000	6,396,000
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract]
Current Assets	368,103,000		368,103,000		384,038,000
Assets	3,920,154,000		3,920,154,000		3,875,573,000
Current liabilities	455,647,000		455,647,000		394,961,000
Stockholders' Equity Attributable to Noncontrolling Interest	$ 84,597,000		$ 84,597,000		$ 85,177,000

XML



Capitalization, Line of Credit (Details) (USD $)	Aug. 02, 2011	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 588,600,000
Cash and cash equivalents		14,023,000	15,404,000	19,097,000	14,641,000
PNM Resources [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	455,100,000
Cash and cash equivalents	10,300,000
PNM Resources [Member] | Revolving credit facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		542,000,000
Line of Credit Facility, Future Reduction of Current Borrowing Capacity		25,000,000
Short-term Debt, Weighted Average Interest Rate		1.44%
PNM Resources [Member] | Local lines of credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		5,000,000
Public Service Company of New Mexico [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	58,800,000
Cash and cash equivalents	10,700,000	485,000	10,336,000	5,741,000	1,373,000
Public Service Company of New Mexico [Member] | Revolving credit facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		386,000,000
Line of Credit Facility, Future Reduction of Current Borrowing Capacity		18,000,000
Short-term Debt, Weighted Average Interest Rate		0.84%
Texas-New Mexico Power Company [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	74,700,000
Cash and cash equivalents	0	1,000	1,000	72,000	138,000
Short-term debt – affiliate		7,000,000	1,200,000
Texas-New Mexico Power Company [Member] | Affiliated Entity [Member]
Line of Credit Facility [Line Items]
Short-term debt – affiliate	5,000,000	7,000,000
Texas-New Mexico Power Company [Member] | Revolving credit facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 75,000,000

XML



Related Party Transactions (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Electricity, transmission and distribution related services [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 9,598	$ 9,635	$ 18,412	$ 19,221
Service billings [Member] | PNM to TNMP [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	160	178	287	278
Service billings [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	44	93	97	214
Service billings [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	24,733	21,913	46,169	43,575
Service billings [Member] | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	7,374	5,804	13,955	12,292
Service billings [Member] | PNMR to Optim Energy [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	1,404	1,371	2,804	2,809
Service billings [Member] | Optim Energy to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	9	33	19	51
Income tax sharing payments [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	0	35,190	0	35,190
Interest charges [Member] | TNMP to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	26	102	28	185
Interest charges [Member] | PNM to PNMR [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	8	0	36	0
Interest charges [Member] | PNMR to PNM [Member]
Related Party Transaction [Line Items]
Amount of related party transaction	$ 32	$ 0	$ 64	$ 0

XML



Fair Value of Derivative and Other Financial Instruments, Recurring (Details) (USD $) In Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010	Jun. 30, 2011		Jun. 30, 2010	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosure Derivative Reconciling Amount from Contract Value to Fair Value	$ 500			$ 500			$ 100
Fair Value, Level 1 to level 2 Transfers, Amount	0		0	0		0
Fair Value, Level 2 to level 1 Transfers, Amount	0		0	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers Into Level 3	0		0	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	0		0	0		0
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	940	[1]		940	[1]		1,443	[1]
Commodity derivative instruments, Liabilities	(3,561)	[1]		(3,561)	[1]		(5,119)	[1]
Commodity derivative instruments, Net	(2,621)	[1]		(2,621)	[1]		(3,676)	[1]
Public Service Company of New Mexico [Member] | 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			0
Commodity derivative instruments, Liabilities	0			0			0
Commodity derivative instruments, Net	0			0			0
Public Service Company of New Mexico [Member] | 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	940			940			1,443
Commodity derivative instruments, Liabilities	(3,561)			(3,561)			(5,119)
Commodity derivative instruments, Net	(2,621)			(2,621)			(3,676)
Public Service Company of New Mexico [Member] | Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	0			0			0
Commodity derivative instruments, Liabilities	0			0			0
Commodity derivative instruments, Net	0			0			0
Commodity Contract [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	26,594	[1]		26,594	[1]		21,263	[1]
Commodity derivative instruments, Liabilities	(41,055)	[1]		(41,055)	[1]		(44,238)	[1]
Commodity derivative instruments, Net	(14,461)	[1]		(14,461)	[1]		(22,975)	[1]
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	10,891			10,891			8,646
Commodity derivative instruments, Liabilities	(25,360)			(25,360)			(26,378)
Commodity derivative instruments, Net	(14,469)			(14,469)			(17,732)
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	9,908			9,908			12,308
Commodity derivative instruments, Liabilities	(14,292)			(14,292)			(16,729)
Commodity derivative instruments, Net	(4,384)			(4,384)			(4,421)
Commodity Contract [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative instruments, Assets	5,282			5,282			272
Commodity derivative instruments, Liabilities	(890)			(890)			(1,094)
Commodity derivative instruments, Net	4,392			4,392			(822)
Public Service Company of New Mexico [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Disclosure Derivative Reconciling Amount from Contract Value to Fair Value	0			0			0
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	724	[1]		724	[1]		4,986	[1]
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]
NDT Investments	724			724			4,986
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]
NDT Investments	0			0			0
Cash and equivalents [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Domestic value [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	27,986	[1]		27,986	[1]		25,491	[1]
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]
NDT Investments	27,986			27,986			25,491
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]
NDT Investments	0			0			0
Domestic value [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Domestic growth [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	56,245	[1]		56,245	[1]		48,237	[1]
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]
NDT Investments	56,245			56,245			48,237
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]
NDT Investments	0			0			0
Domestic growth [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Multinational [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	14,089	[1]		14,089	[1]		10,670	[1]
Multinational [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	14,089			14,089			10,670
Multinational [Member] | Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Multinational [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
U.S. Government [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	21,390	[1]		21,390	[1]		21,541	[1]
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]
NDT Investments	16,797			16,797			16,613
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]
NDT Investments	4,593			4,593			4,928
U.S. Government [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Municipals [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	38,884	[1]		38,884	[1]		37,595	[1]
Municipals [Member] | Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			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]
NDT Investments	38,884			38,884			37,595
Municipals [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Corporate and other [Member] | Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	9,195	[1]		9,195	[1]		8,402	[1]
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]
NDT Investments	0			0			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]
NDT Investments	9,195			9,195			8,402
Corporate and other [Member] | Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	0			0			0
Measured on a recurring basis [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	168,513	[1]		168,513	[1]		156,922	[1]
Measured on a recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	115,841			115,841			105,997
Measured on a recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	52,672			52,672			50,925
Measured on a recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
NDT Investments	$ 0			$ 0			$ 0

[1] The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $0.5 million for PNMR and zero for PNM at June 30, 2011 and less than $0.1 million for PNMR and zero for PNM at December 31, 2010. There were no transfers between levels for the three months and six months ended June 30, 2011 and 2010.

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Fair Value of Derivative and Other Financial Instruments, Unobservable Input Reconciliation (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 894	$ 85	$ (822)	$ 248
Total gains (losses) included in earnings	3,676	(437)	5,226	(814)
Purchases	2,617	0	2,735	0
Settlements	(2,795)	74	(2,747)	288
Balance at end of period	4,392	(278)	4,392	(278)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	1,954	(363)	3,122	(543)
Public Service Company of New Mexico [Member] | Electric operating revenues [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Electric operating revenues [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Public Service Company of New Mexico [Member] | Cost of energy [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	0	0	0	(128)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	0	0	0	0
Cost of energy [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings	3,676	(437)	5,226	(814)
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	1,954	(363)	3,122	(543)
Public Service Company of New Mexico [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	0	0	0	(17)
Total gains (losses) included in earnings	0	0	0	(128)
Purchases	0	0	0	0
Settlements	0	0	0	145
Balance at end of period	0	0	0	0
Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of period	$ 0	$ 0	$ 0	$ 0

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Commitments and Contingencies (Details) (USD $)																	3 Months Ended		6 Months Ended						6 Months Ended										1 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Public Service Company of New Mexico [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member]	Oct. 31, 2010 Public Service Company of New Mexico [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Maximum [Member] Nuclear Plant [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Commercial Providers [Member] Nuclear Plant [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Industry Wide Retrospective Assessment Program [Member] Nuclear Plant [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Other Deferred Credits [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Palo Verde Nuclear Generating Station [Member] Nuclear Spent Fuel And Waste Disposal [Member]	Jan. 06, 2010 Public Service Company of New Mexico [Member] Maximum [Member] San Juan Generating Station And Four Corners [Member]	May 17, 2010 Public Service Company of New Mexico [Member] Maximum [Member] Citizen Suit Under the Clean Air Act [Member]	Jan. 06, 2010 Public Service Company of New Mexico [Member] Minimum [Member] San Juan Generating Station And Four Corners [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] San Juan Generating Station And Four Corners [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Surface [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Underground [Member] San Juan Generating Station [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Underground [Member] Loss on Long-term Purchase Commitment [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Coal Supply [Member] tons	Jun. 30, 2011 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Dec. 31, 2010 Public Service Company of New Mexico [Member] Coal Supply [Member] San Juan Generating Station [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act related to SCR [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] San Juan Generating Station [Member] Clean Air Act Related to Sncr [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member]	Feb. 10, 2011 Public Service Company of New Mexico [Member] Four Corners [Member]	Nov. 08, 2010 Public Service Company of New Mexico [Member] Four Corners [Member]	Jun. 30, 2011 Public Service Company of New Mexico [Member] Four Corners [Member] Clean Air Act related to Post-Combustion Controls [Member]	Jan. 31, 2011 Public Service Company of New Mexico [Member] Transmissions Issues [Member]	Jun. 30, 2011 Palo Verde Nuclear Generating Station [Member] Nuclear Plant [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss												$ 42,800,000		$ 42,000,000		$ 54,500,000						$ 21,700,000								$ 77,000,000				$ 69,000,000
Public Utilities, Proposed Stack Opacity Limit																															0.10
Loss Contingency Accrual, at Carrying Value										15,100,000	14,800,000						24,200,000		24,200,000		25,000,000		2,900,000	2,800,000
Loss Contingency, Range of Possible Loss, Minimum																													750,000,000
Loss Contingency, Range of Possible Loss, Maximum																													1,000,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share																												46.30%
Public Utilities, Government Proposed Emission Limit (pounds be MMBTU)					0.11																							0.05			0.098	0.098
Public Utilities, Government Standard Emission Limit (pounds per MMBTU, parts per million)			0.23										0.070		0.060													0.05
Public Utilities, Annual Increase in Costs Per Customer			85
Public Utilities, Proposed Opacity Limit Fugitive Dust Emission																															0.20
Public Utilties, Jointly Owned Utility Plant, Sale of Ownership Percentage																																	48.00%
Other current assets	99,919,000	96,110,000	49,185,000	46,635,000																						28,200,000	30,900,000
Long-term Purchase Commitment, Minimum Quantity Required (tons of coal)																									44,200,000
Loss Contingency Accrual, Carrying Value, Payments																	1,300,000	900,000	2,600,000	2,000,000
Public Utilities, Liability Insurance Coverage						12,600,000,000	375,000,000	12,200,000,000
Public Utilities, Maximum Assessment Per Reactor For Each Incident									117,500,000
Public Utilities, Maximum Assessment Per Reactor For Each Incident, Annual Limit									17,500,000
Public Utilities, Ownership Percentage in Nuclear Reactor									10.20%
Public Utilities, Maximum Potential Assessment Per Incident									36,000,000
Public Utilities, Annual Payment Limitation Related to Incident									5,400,000
Public Utilities, Aggregate Amount of All Risk Insurance																																				2,750,000,000
Public Utilities, Maximum Amount under Nuclear Electir Insurance Limited									5,800,000
Litigation Settlement, Gross																																			$ 200,000

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Segment Information (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	$ 415,586	$ 405,817	$ 803,249	$ 789,212
Intersegment revenues	0	0	0	0
Total revenues	415,586	405,817	803,249	789,212
Cost of energy	173,454	151,181	331,961	342,069
Gross margin	242,132	254,636	471,288	447,143
Other operating expenses	171,000	143,586	309,464	288,332
Depreciation and amortization	38,272	37,376	76,745	74,655
Operating income	32,860	73,674	85,079	84,156
Interest income	4,234	5,083	8,261	10,110
Equity in net earnings (loss) of Optim Energy	0	(3,858)	0	(8,210)
Other income (deductions)	2,822	(3,344)	6,648	6,756
Net interest charges	(30,512)	(31,761)	(61,127)	(63,171)
Earnings before Income Taxes	9,404	39,794	38,861	29,641
Income tax expense (benefit)	1,735	13,492	11,241	8,552
Net earnings	7,669	26,302	27,620	21,089
Valencia non-controlling interest	(3,470)	(3,292)	(6,652)	(6,396)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	4,067	22,878	20,704	14,429
Total Assets	5,301,633	5,403,522	5,301,633	5,403,522	5,225,083
Goodwill	321,310	321,310	321,310	321,310	321,310
Additions to utility and non-utility plant included in accounts payable	18,276		18,276
PNM Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	239,234	243,060	473,472	473,596
Intersegment revenues	0	0	0	0
Total revenues	239,234	243,060	473,472	473,596
Cost of energy	81,497	79,639	170,711	166,073
Gross margin	157,737	163,421	302,761	307,523
Other operating expenses	124,297	107,107	227,423	215,900
Depreciation and amortization	22,897	22,924	46,632	45,776
Operating income	10,543	33,390	28,706	45,847
Interest income	4,225	5,081	8,282	10,015
Equity in net earnings (loss) of Optim Energy		0		0
Other income (deductions)	4,484	(1,991)	9,702	9,167
Net interest charges	(18,027)	(18,385)	(36,107)	(36,462)
Earnings before Income Taxes	1,225	18,095	10,583	28,567
Income tax expense (benefit)	(872)	5,901	1,522	8,822
Net earnings	2,097	12,194	9,061	19,745
Valencia non-controlling interest	(3,470)	(3,292)	(6,652)	(6,396)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings Attributable to PNMR	(1,505)	8,770	2,145	13,085
Total Assets	3,920,154	3,813,524	3,920,154	3,813,524
Goodwill	51,632	51,632	51,632	51,632
Additions to utility and non-utility plant included in accounts payable	16,514		16,514
TNMP Electric [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	50,359	42,934	95,387	81,525
Intersegment revenues	9,598	9,635	18,412	19,221
Total revenues	59,957	52,569	113,799	100,746
Cost of energy	10,259	9,057	20,412	18,107
Gross margin	49,698	43,512	93,387	82,639
Other operating expenses	25,277	19,031	44,981	37,822
Depreciation and amortization	10,726	10,040	20,987	20,135
Operating income	13,695	14,441	27,419	24,682
Interest income	0	0	0	0
Equity in net earnings (loss) of Optim Energy		0		0
Other income (deductions)	259	283	575	630
Net interest charges	(7,305)	(7,953)	(14,604)	(15,822)
Earnings before Income Taxes	6,649	6,771	13,390	9,490
Income tax expense (benefit)	2,547	2,665	5,125	3,740
Net earnings	4,102	4,106	8,265	5,750
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Attributable to PNMR	4,102	4,106	8,265	5,750
Total Assets	1,018,425	1,013,131	1,018,425	1,013,131
Goodwill	226,665	226,665	226,665	226,665
Additions to utility and non-utility plant included in accounts payable	360		360
First Choice [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	126,036	119,916	234,486	234,306
Intersegment revenues	0	0	0	0
Total revenues	126,036	119,916	234,486	234,306
Cost of energy	91,296	72,121	159,250	177,111
Gross margin	34,740	47,795	75,236	57,195
Other operating expenses	23,630	21,253	42,616	41,701
Depreciation and amortization	360	210	641	473
Operating income	10,750	26,332	31,979	15,021
Interest income	31	11	34	13
Equity in net earnings (loss) of Optim Energy		0		0
Other income (deductions)	(273)	(90)	(379)	(98)
Net interest charges	(141)	(387)	(286)	(697)
Earnings before Income Taxes	10,367	25,866	31,348	14,239
Income tax expense (benefit)	3,745	9,313	11,237	5,139
Net earnings	6,622	16,553	20,111	9,100
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Attributable to PNMR	6,622	16,553	20,111	9,100
Total Assets	254,352	239,035	254,352	239,035
Goodwill	43,013	43,013	43,013	43,013
Additions to utility and non-utility plant included in accounts payable	237		237
Corporate and Other [Member]
Segment Reporting Information, Profit (Loss) [Abstract]
Electric Operating Revenues	(43)	(93)	(96)	(215)
Intersegment revenues	(9,598)	(9,635)	(18,412)	(19,221)
Total revenues	(9,641)	(9,728)	(18,508)	(19,436)
Cost of energy	(9,598)	(9,636)	(18,412)	(19,222)
Gross margin	(43)	(92)	(96)	(214)
Other operating expenses	(2,204)	(3,805)	(5,556)	(7,091)
Depreciation and amortization	4,289	4,202	8,485	8,271
Operating income	(2,128)	(489)	(3,025)	(1,394)
Interest income	(22)	(9)	(55)	82
Equity in net earnings (loss) of Optim Energy		(3,858)		(8,210)
Other income (deductions)	(1,648)	(1,546)	(3,250)	(2,943)
Net interest charges	(5,039)	(5,036)	(10,130)	(10,190)
Earnings before Income Taxes	(8,837)	(10,938)	(16,460)	(22,655)
Income tax expense (benefit)	(3,685)	(4,387)	(6,643)	(9,149)
Net earnings	(5,152)	(6,551)	(9,817)	(13,506)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings Attributable to PNMR	(5,152)	(6,551)	(9,817)	(13,506)
Total Assets	108,702	337,832	108,702	337,832
Goodwill	0	0	0	0
Additions to utility and non-utility plant included in accounts payable	$ 1,165		$ 1,165