Texas New Mexico Power 10-Q 2 Aug 19 2019 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2019	Jul. 26, 2019
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Entity File Number	001-32462
Entity Registrant Name	PNM Resources, Inc.
Entity Tax Identification Number	85-0468296
Entity Incorporation, State or Country Code	NM
Entity Address, Address Line One	414 Silver Ave. SW
Entity Address, City or Town	Albuquerque
Entity Address, State or Province	NM
Entity Address, Postal Zip Code	87102-3289
City Area Code	505
Local Phone Number	241-2700
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	PNM
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		79,653,624,000
Entity Central Index Key	0001108426
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Document Transition Report	false
PNM
Document Information [Line Items]
Entity File Number	001-06986
Entity Registrant Name	PUBLIC SERVICE CO OF NEW MEXICO
Entity Tax Identification Number	85-0019030
Entity Address, Address Line One	414 Silver Ave. SW
Entity Address, City or Town	Albuquerque
Entity Address, State or Province	NM
Entity Address, Postal Zip Code	87102-3289
City Area Code	505
Local Phone Number	241-2700
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding (in shares)		39,117,799,000
Entity Central Index Key	0000081023
Current Fiscal Year End Date	--12-31
Texas-New Mexico Power Company
Document Information [Line Items]
Entity File Number	002-97230
Entity Registrant Name	Texas-New Mexico Power Company
Entity Tax Identification Number	75-0204070
Entity Address, Address Line One	577 N. Garden Ridge Blvd.
Entity Address, City or Town	Lewisville
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75067
City Area Code	972
Local Phone Number	420-4189
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding (in shares)		6,358,000
Entity Central Index Key	0000022767
Current Fiscal Year End Date	--12-31

Condensed Consolidated Statemen

Condensed Consolidated Statements of Earnings - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Electric Operating Revenues:
Contracts with customers	$ 314,917	$ 338,659	$ 630,614	$ 642,010
Operating revenues	330,228	352,313	679,872	670,191
Operating Expenses:
Administrative and general	42,833	43,355	95,170	91,638
Regulatory disallowances and restructuring costs	149,254	1,794	150,599	1,794
Depreciation and amortization	66,065	60,063	131,421	118,785
Transmission and distribution costs	19,195	18,450	35,872	35,406
Taxes other than income taxes	19,809	19,723	40,317	39,602
Total operating expenses	423,843	272,984	736,764	544,730
Operating income (loss)	(93,615)	79,329	(56,892)	125,461
Other Income and Deductions:
Interest income	3,460	4,339	7,048	8,462
Gains (losses) on investment securities	4,599	(1,670)	18,613	(1,382)
Other income	3,350	4,796	6,795	8,265
Other (deductions)	(3,117)	(5,868)	(6,369)	(7,243)
Net other income and deductions	8,292	1,597	26,087	8,102
Interest Charges	29,791	33,321	61,425	66,376
Earnings (Loss) before Income Taxes	(115,114)	47,605	(92,230)	67,187
Income Taxes (Benefits)	(42,831)	5,156	(41,608)	5,939
Net Earnings (Loss)	(72,283)	42,449	(50,622)	61,248
(Earnings) Attributable to Valencia Non-controlling Interest	(3,499)	(4,109)	(6,328)	(7,786)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings (Loss) Available for PNM Common Stock	$ (75,914)	$ 38,208	$ (57,214)	$ 53,198
Net Earnings (Loss) Attributable to PNMR per Common Share:
Basic (dollars per share)	$ (0.95)	$ 0.48	$ (0.72)	$ 0.67
Diluted (dollars per share)	(0.95)	0.48	(0.72)	0.67
Dividends Declared per Common Share (dollars per share)	$ 0.290	$ 0.265	$ 0.580	$ 0.530
Alternative revenue programs
Electric Operating Revenues:
Operating revenues	$ 5,844	$ 5,660	$ 6,480	$ 6,584
Other electric operating revenue
Electric Operating Revenues:
Operating revenues	9,467	7,994	42,778	21,597
Cost of energy
Electric Operating Revenues:
Operating revenues	330,228	352,313	679,872	670,191
Operating Expenses:
Cost of energy and energy production costs	83,782	87,711	205,408	180,267
Energy production costs
Operating Expenses:
Cost of energy and energy production costs	42,905	41,888	77,977	77,238
PNM
Electric Operating Revenues:
Contracts with customers	228,061	254,728	464,002	477,291
Operating revenues	238,219	264,511	507,536	500,742
Operating Expenses:
Administrative and general	40,237	40,922	87,639	84,648
Regulatory disallowances and restructuring costs	149,254	1,794	150,599	1,794
Depreciation and amortization	39,811	38,213	79,036	74,840
Transmission and distribution costs	11,838	10,993	22,471	20,820
Taxes other than income taxes	11,285	11,461	23,295	23,069
Total operating expenses	354,196	211,632	599,221	419,572
Operating income (loss)	(115,977)	52,879	(91,685)	81,170
Other Income and Deductions:
Interest income	3,530	3,381	7,187	5,868
Gains (losses) on investment securities	4,599	(1,670)	18,613	(1,382)
Other income	1,920	2,292	4,552	4,684
Other (deductions)	(2,340)	(3,768)	(4,629)	(5,229)
Net other income and deductions	7,709	235	25,723	3,941
Interest Charges	18,526	19,988	36,886	40,818
Earnings (Loss) before Income Taxes	(126,794)	33,126	(102,848)	44,293
Income Taxes (Benefits)	(43,481)	2,345	(41,508)	1,997
Net Earnings (Loss)	(83,313)	30,781	(61,340)	42,296
(Earnings) Attributable to Valencia Non-controlling Interest	(3,499)	(4,109)	(6,328)	(7,786)
Net Earnings (Loss) Attributable to PNMR	(86,812)	26,672	(67,668)	34,510
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Net Earnings (Loss) Available for PNM Common Stock	(86,944)	26,540	(67,932)	34,246
PNM | Alternative revenue programs
Electric Operating Revenues:
Operating revenues	691	1,789	756	1,854
PNM | Other electric operating revenue
Electric Operating Revenues:
Operating revenues	9,467	7,994	42,778	21,597
PNM | Cost of energy
Operating Expenses:
Cost of energy and energy production costs	58,866	66,361	158,204	137,163
PNM | Energy production costs
Operating Expenses:
Cost of energy and energy production costs	42,905	41,888	77,977	77,238
Texas-New Mexico Power Company
Electric Operating Revenues:
Contracts with customers	86,856	83,931	166,612	164,719
Operating revenues	92,009	87,802	172,336	169,449
Operating Expenses:
Administrative and general	9,097	8,852	20,655	19,561
Depreciation and amortization	20,502	16,113	40,716	32,500
Transmission and distribution costs	7,357	7,457	13,401	14,586
Taxes other than income taxes	7,559	7,201	15,197	14,337
Total operating expenses	69,431	60,973	137,173	124,088
Operating income (loss)	22,578	26,829	35,163	45,361
Other Income and Deductions:
Other income	1,191	2,223	1,940	2,976
Other (deductions)	(460)	(1,391)	(623)	(1,060)
Net other income and deductions	731	832	1,317	1,916
Interest Charges	6,560	7,801	15,361	15,530
Earnings (Loss) before Income Taxes	16,749	19,860	21,119	31,747
Income Taxes (Benefits)	1,482	4,493	1,754	6,968
Net Earnings (Loss) Attributable to PNMR	15,267	15,367	19,365	24,779
Texas-New Mexico Power Company | Alternative revenue programs
Electric Operating Revenues:
Operating revenues	5,153	3,871	5,724	4,730
Texas-New Mexico Power Company | Other electric operating revenue
Electric Operating Revenues:
Operating revenues	0	0	0	0
Texas-New Mexico Power Company | Cost of energy
Operating Expenses:
Cost of energy and energy production costs	$ 24,916	$ 21,350	$ 47,204	$ 43,104

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net Earnings (Loss)	$ (72,283)	$ 42,449	$ (50,622)	$ 61,248
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	6,610	266	11,890	1,098
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(3,674)	(371)	(4,178)	(2,332)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit)	1,381	1,415	2,762	2,826
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $494, $(143), $805, and $(615)	(1,450)		(2,364)
Change in fair market value, net of income tax (expense) benefit of $494, $(143), $805, and $(615)		419		1,805
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(65), $(12), $(133), and $1	190		392
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(65), $(12), $(133), and $1		34		(6)
Total Other Comprehensive Income	3,057	1,763	8,502	3,391
Comprehensive Income (Loss)	(69,226)	44,212	(42,120)	64,639
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,499)	(4,109)	(6,328)	(7,786)
Preferred Stock Dividend Requirements of Subsidiary	(132)	(132)	(264)	(264)
Comprehensive Income (Loss) Attributable to PNMR	(72,857)	39,971	(48,712)	56,589
PNM
Net Earnings (Loss)	(83,313)	30,781	(61,340)	42,296
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense)	6,610	266	11,890	1,098
Reclassification adjustment for (gains) included in net earnings, net of income tax expense	(3,674)	(371)	(4,178)	(2,332)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit)	1,381	1,415	2,762	2,826
Fair Value Adjustment for Cash Flow Hedges:
Total Other Comprehensive Income	4,317	1,310	10,474	1,592
Comprehensive Income (Loss)	(78,996)	32,091	(50,866)	43,888
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,499)	(4,109)	(6,328)	(7,786)
Comprehensive Income (Loss) Attributable to PNMR	$ (82,495)	$ 27,982	$ (57,194)	$ 36,102

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	$ (2,250)	$ (91)	$ (4,048)	$ (374)
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit)	1,251	126	1,423	794
Pension liability adjustment, income tax expense (benefit)	(470)	(482)	(940)	(962)
Change in fair market value, net of income tax (expense) benefit of $311 and $(472)	494		805
Change in fair market value, income tax (expense) benefit		(143)		(615)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(68) and $13	(65)		(133)
Reclassification adjustment for (gains) losses included in net earnings (loss), income tax expense (benefit)		(12)		1
PNM
Unrealized holding gains (losses) arising during the period, income tax (expense) benefit	(2,250)	(91)	(4,048)	(374)
Reclassification adjustment for (gains) losses included in net earnings, income tax expense (benefit)	1,251	126	1,423	794
Pension liability adjustment, income tax expense (benefit)	$ (470)	$ (482)	$ (940)	$ (962)

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash Flows From Operating Activities:
Net earnings	$ (50,622)	$ 61,248
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	148,090	137,020
Deferred income tax expense	(41,930)	5,888
(Gains) losses on investment securities	(18,613)	1,382
Stock based compensation expense	4,526	3,325
Regulatory disallowances and restructuring costs	150,599	1,794
Allowance for equity funds used during construction	(4,158)	(4,641)
Other, net	1,247	1,539
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	4,205	(17,130)
Materials, supplies, and fuel stock	(2,656)	(8,282)
Other current assets	(6,020)	(16,130)
Other assets	21,858	2,603
Accounts payable	(812)	(21,229)
Accrued interest and taxes	(6,180)	(4,865)
Other current liabilities	(6,381)	(1,516)
Other liabilities	(21,288)	(7,106)
Net cash flows from operating activities	171,865	133,900
Cash Flows From Investing Activities:
Additions to utility plant	(293,076)	(245,587)
Proceeds from sales of investment securities	234,011	794,088
Purchases of investment securities	(239,609)	(797,271)
Principal repayments on Westmoreland Loan	0	56,640
Investments in NMRD	(13,250)	(8,000)
Other, net	(187)	(120)
Net cash flows from investing activities	(312,111)	(200,250)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	106,500	(22,800)
Long-term borrowings	475,000	709,652
Repayment of long-term debt	(372,302)	(550,137)
Proceeds from stock option exercise	943	924
Awards of common stock	(9,892)	(12,268)
Dividends paid	(46,463)	(42,480)
Valencia’s transactions with its owner	(7,948)	(8,381)
Refunds paid under transmission interconnection arrangements	(1,661)	(1,661)
Debt issuance costs and other, net	(1,827)	(5,584)
Net cash flows from financing activities	142,350	67,265
Change in Cash, Restricted Cash, and Equivalents	2,104	915
Cash, Restricted Cash, and Equivalents at Beginning of Period	2,122	3,974
Cash, Restricted Cash, and Equivalents at End of Period	4,226	4,889
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	61,539	59,626
Income taxes paid (refunded), net	(2,768)	842
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	30,451	17,303
PNM
Cash Flows From Operating Activities:
Net earnings	(61,340)	42,296
Net earnings	(67,668)	34,510
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	94,467	90,713
Deferred income tax expense	(41,292)	2,342
(Gains) losses on investment securities	(18,613)	1,382
Regulatory disallowances and restructuring costs	150,599	1,794
Allowance for equity funds used during construction	(3,456)	(3,879)
Other, net	1,173	1,539
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	8,778	(12,057)
Materials, supplies, and fuel stock	(2,423)	(7,071)
Other current assets	(1,509)	(17,995)
Other assets	18,132	8,296
Accounts payable	(4,049)	(13,050)
Accrued interest and taxes	3,615	(988)
Other current liabilities	24,019	(11,364)
Other liabilities	(22,483)	(10,300)
Net cash flows from operating activities	145,618	71,658
Cash Flows From Investing Activities:
Additions to utility plant	(157,874)	(120,287)
Proceeds from sales of investment securities	234,011	794,088
Purchases of investment securities	(239,609)	(797,271)
Other, net	1	131
Net cash flows from investing activities	(163,471)	(123,339)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	(200)	(6,200)
Short-term borrowings (repayments) – affiliate, net	(19,800)	4,900
Long-term borrowings	250,000	350,000
Repayment of long-term debt	(200,000)	(350,000)
Dividends paid	(264)	(264)
Valencia’s transactions with its owner	(7,948)	(8,381)
Amounts received under transmission interconnection arrangements	0	68,200
Refunds paid under transmission interconnection arrangements	(1,661)	(1,661)
Debt issuance costs and other, net	(120)	(3,147)
Net cash flows from financing activities	20,007	53,447
Change in Cash, Restricted Cash, and Equivalents	2,154	1,766
Cash, Restricted Cash, and Equivalents at Beginning of Period	85	1,108
Cash, Restricted Cash, and Equivalents at End of Period	2,239	2,874
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	34,308	39,881
Income taxes paid (refunded), net	(3,383)	0
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	13,213	(841)
Texas-New Mexico Power Company
Cash Flows From Operating Activities:
Net earnings	19,365	24,779
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	41,379	33,390
Deferred income tax expense	(8,004)	(900)
Allowance for equity funds used during construction	(680)	(762)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(4,573)	(5,073)
Materials, supplies, and fuel stock	(233)	(1,211)
Other current assets	(7,155)	(378)
Other assets	3,544	(5,603)
Accounts payable	2,442	(4,161)
Accrued interest and taxes	1,175	1,610
Other current liabilities	3,130	5,410
Other liabilities	(1,234)	3,874
Net cash flows from operating activities	49,156	50,975
Cash Flows From Investing Activities:
Additions to utility plant	(124,376)	(115,361)
Net cash flows from investing activities	(124,376)	(115,361)
Cash Flows From Financing Activities:
Revolving credit facilities borrowings (repayments), net	37,500	13,500
Short-term borrowings (repayments) – affiliate, net	1,500	100
Long-term borrowings	225,000	60,000
Repayment of long-term debt	(172,302)	0
Dividends paid	(14,811)	(10,436)
Debt issuance costs and other, net	(1,667)	(478)
Net cash flows from financing activities	75,220	62,686
Change in Cash, Restricted Cash, and Equivalents	0	(1,700)
Cash, Restricted Cash, and Equivalents at Beginning of Period	0	1,700
Cash, Restricted Cash, and Equivalents at End of Period	0	0
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	16,342	13,085
Income taxes paid (refunded), net	615	842
Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$ 12,182	$ 14,886

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 4,226	$ 2,122	$ 4,889	$ 3,974
Accounts receivable, net of allowance for uncollectible accounts	83,669	92,800
Unbilled revenues	60,737	57,092
Other receivables	16,287	11,369
Materials, supplies, and fuel stock	74,490	71,834
Regulatory assets	5,533	4,534
Income taxes receivable	4,875	7,965
Other current assets	49,259	54,808
Total current assets	299,076	302,524
Other Property and Investments:
Investment securities	362,793	328,242
Equity investment in NMRD	40,002	26,564
Other investments	296	297
Non-utility property, net	7,943	3,404
Total other property and investments	411,034	358,507
Utility Plant:
Plant in service, held for future use, and to be abandoned	7,596,976	7,548,581
Less accumulated depreciation and amortization	2,649,617	2,604,177
Net plant in service and plant held for future use	4,947,359	4,944,404
Construction work in progress	202,991	194,427
Nuclear fuel, net of accumulated amortization	95,636	95,798
Net utility plant	5,245,986	5,234,629
Deferred Charges and Other Assets:
Regulatory assets	576,964	598,930
Goodwill	278,297	278,297	278,297
Operating lease right-of-use assets, net of accumulated amortization	143,876
Other deferred charges	93,434	92,664
Total deferred charges and other assets	1,092,571	969,891
Total assets	7,048,667	6,865,551	6,750,089
Current Liabilities:
Short-term debt	342,400	235,900
Current installments of long-term debt	100,187	0
Accounts payable	80,908	112,170
Customer deposits	10,686	10,695
Accrued interest and taxes	55,885	65,156
Regulatory liabilities	7,355	9,446
Operating lease liabilities	27,396
Dividends declared	132	23,231
Other current liabilities	41,592	55,855
Total current liabilities	666,541	512,453
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,672,155	2,670,111
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	591,145	600,719
Regulatory liabilities	875,146	891,428
Asset retirement obligations	176,743	158,674
Accrued pension liability and postretirement benefit cost	92,434	100,375
Operating lease liabilities	116,464
Other deferred credits	171,770	167,668
Total deferred credits and other liabilities	2,023,702	1,918,864
Total liabilities	5,362,398	5,101,428
Commitments and Contingencies (Note 11)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529	11,529
Company common stockholders’ equity:
Common stock	1,148,690	1,153,113
Accumulated other comprehensive income (loss), net of income taxes	(100,182)	(108,684)
Retained earnings	563,640	643,953
Total stockholders' equity	1,612,148	1,688,382
Non-controlling interest in Valencia	62,592	64,212
Total equity	1,674,740	1,752,594	1,788,315	1,761,448
Total liabilities and stockholders' equity	7,048,667	6,865,551
PNM
Current Assets:
Cash and cash equivalents	2,239	85	2,874	1,108
Accounts receivable, net of allowance for uncollectible accounts	55,435	68,603
Unbilled revenues	50,223	47,113
Other receivables	15,353	10,650
Affiliate receivables	8,949	15,871
Materials, supplies, and fuel stock	69,520	67,097
Regulatory assets	0	4,534
Income taxes receivable	9,683	12,850
Other current assets	39,203	43,516
Total current assets	250,605	270,319
Other Property and Investments:
Investment securities	362,793	328,242
Other investments	90	91
Non-utility property, net	2,469	96
Total other property and investments	365,352	328,429
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,601,599	5,623,520
Less accumulated depreciation and amortization	2,026,654	2,006,266
Net plant in service and plant held for future use	3,574,945	3,617,254
Construction work in progress	107,264	134,221
Nuclear fuel, net of accumulated amortization	95,636	95,798
Net utility plant	3,777,845	3,847,273
Deferred Charges and Other Assets:
Regulatory assets	448,946	460,903
Goodwill	51,632	51,632
Operating lease right-of-use assets, net of accumulated amortization	132,057
Other deferred charges	78,653	77,327
Total deferred charges and other assets	711,288	589,862
Total assets	5,105,090	5,035,883
Current Liabilities:
Short-term debt	42,200	42,400
Current installments of long-term debt	100,187	0
Short-term debt - affiliate	0	19,800
Accounts payable	57,852	75,114
Affiliate payables	13,581	164
Customer deposits	10,686	10,695
Accrued interest and taxes	36,215	35,767
Regulatory liabilities	6,437	5,975
Operating lease liabilities	24,092
Dividends declared	132	132
Other current liabilities	25,682	32,976
Total current liabilities	317,064	223,023
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,607,069	1,656,490
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	488,202	502,767
Regulatory liabilities	693,687	713,971
Asset retirement obligations	175,847	157,814
Accrued pension liability and postretirement benefit cost	85,682	92,981
Operating lease liabilities	107,741
Other deferred credits	215,776	215,737
Total deferred credits and other liabilities	1,766,935	1,683,270
Total liabilities	3,691,068	3,562,783
Commitments and Contingencies (Note 11)
Cumulative Preferred Stock of Subsidiary without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529	11,529
Company common stockholders’ equity:
Common stock	1,264,918	1,264,918
Accumulated other comprehensive income (loss), net of income taxes	(99,948)	(110,422)
Retained earnings	174,931	242,863
Total stockholders' equity	1,339,901	1,397,359
Non-controlling interest in Valencia	62,592	64,212
Total equity	1,402,493	1,461,571	1,523,612	1,488,369
Total liabilities and stockholders' equity	5,105,090	5,035,883
Texas-New Mexico Power Company
Current Assets:
Cash and cash equivalents	0	0	0	1,700
Accounts receivable, net of allowance for uncollectible accounts	28,234	24,196
Unbilled revenues	10,514	9,979
Other receivables	2,412	1,721
Affiliate receivables	0	164
Materials, supplies, and fuel stock	4,970	4,737
Regulatory assets	5,533	0
Other current assets	2,045	1,114
Total current assets	53,708	41,911
Other Property and Investments:
Other investments	206	206
Non-utility property, net	4,405	2,240
Total other property and investments	4,611	2,446
Utility Plant:
Plant in service, held for future use, and to be abandoned	1,754,023	1,686,119
Less accumulated depreciation and amortization	503,704	487,734
Net plant in service and plant held for future use	1,250,319	1,198,385
Construction work in progress	86,968	51,459
Net utility plant	1,337,287	1,249,844
Deferred Charges and Other Assets:
Regulatory assets	128,018	138,027
Goodwill	226,665	226,665
Operating lease right-of-use assets, net of accumulated amortization	11,409
Other deferred charges	7,133	6,284
Total deferred charges and other assets	373,225	370,976
Total assets	1,768,831	1,665,177
Current Liabilities:
Short-term debt	55,000	17,500
Short-term debt - affiliate	1,600	100
Accounts payable	14,064	23,804
Affiliate payables	5,484	1,210
Accrued interest and taxes	43,057	41,882
Regulatory liabilities	918	3,471
Operating lease liabilities	2,913
Other current liabilities	4,520	2,861
Total current liabilities	127,556	90,828
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	626,456	575,398
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	133,960	136,238
Regulatory liabilities	181,459	177,458
Asset retirement obligations	896	860
Accrued pension liability and postretirement benefit cost	6,752	7,394
Operating lease liabilities	8,403
Other deferred credits	4,702	2,908
Total deferred credits and other liabilities	336,172	324,858
Total liabilities	1,090,184	991,084
Commitments and Contingencies (Note 11)
Company common stockholders’ equity:
Common stock	64	64
Paid-in-capital	534,166	534,166
Retained earnings	144,417	139,863
Total stockholders' equity	678,647	674,093	$ 648,748	$ 634,405
Total liabilities and stockholders' equity	$ 1,768,831	$ 1,665,177

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Allowance for uncollectible accounts	$ 1,178	$ 1,406
Accumulated depreciation, nuclear fuel	$ 42,410	$ 42,511
Cumulative preferred stock of subsidiary, stated value (in dollars per share)	$ 100	$ 100
Cumulative preferred stock of subsidiary, shares authorized (in shares)	10,000,000	10,000,000
Cumulative preferred stock of subsidiary, shares issued (in shares)	115,293	115,293
Cumulative preferred stock of subsidiary, shares outstanding (in shares)	115,293	115,293
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	120,000,000	120,000,000
Common stock, shares issued (in shares)	79,653,624	79,653,624
Common stock, shares outstanding (in shares)	79,653,624	79,653,624
PNM
Allowance for uncollectible accounts	$ 1,178	$ 1,406
Accumulated depreciation, nuclear fuel	$ 42,410	$ 42,511
Cumulative preferred stock, stated value (in dollars per share)	$ 100	$ 100
Cumulative preferred stock, shares authorized (in shares)	10,000,000	10,000,000
Cumulative preferred stock, shares issued (in shares)	115,293	115,293
Cumulative preferred stock, shares outstanding (in shares)	115,293	115,293
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	40,000,000	40,000,000
Common stock, shares issued (in shares)	39,117,799	39,117,799
Common stock, shares outstanding (in shares)	39,117,799	39,117,799
Texas-New Mexico Power Company
Common stock, par value (in dollars per share)	$ 10	$ 10
Common stock, shares authorized (in shares)	12,000,000	12,000,000
Common stock, shares issued (in shares)	6,358	6,358
Common stock, shares outstanding (in shares)	6,358	6,358

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	Total PNMR Common Stockholders’ Equity	Common Stock	AOCI	Retained Earnings	Non- controlling Interest in Valencia	PNM	PNMTotal PNMR Common Stockholders’ Equity	PNMCommon Stock	PNMAOCI	PNMRetained Earnings	PNMNon- controlling Interest in Valencia	Texas-New Mexico Power Company	Texas-New Mexico Power CompanyCommon Stock	Texas-New Mexico Power CompanyPaid-in Capital	Texas-New Mexico Power CompanyRetained Earnings
Beginning balance at Dec. 31, 2017	$ 1,761,448	$ 1,695,253	$ 1,157,665	$ (95,940)	$ 633,528	$ 66,195	$ 1,488,369	$ 1,422,174	$ 1,264,918	$ (97,093)	$ 254,349	$ 66,195
Beginning balance TNMP at Dec. 31, 2017													$ 634,405	$ 64	$ 504,166	$ 130,175
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss) before subsidiary preferred stock dividends	61,248	53,462			53,462	7,786	42,296	34,510			34,510	7,786
Net earnings							34,510						24,779			24,779
Total other comprehensive income	3,391	3,391		3,391			1,592	1,592		1,592
Subsidiary preferred stock dividends	(264)	(264)			(264)
Dividends declared on preferred stock							(264)	(264)			(264)
Dividends declared on common stock	(21,108)	(21,108)			(21,108)								(10,436)			(10,436)
Proceeds from stock option exercise	924	924	924
Awards of common stock	(12,268)	(12,268)	(12,268)
Stock based compensation expense	3,325	3,325	3,325
Valencia’s transactions with its owner	(8,381)					(8,381)	(8,381)					(8,381)
Ending balance at Jun. 30, 2018	1,788,315	1,722,715	1,149,646	(103,757)	676,826	65,600	1,523,612	1,458,012	1,264,918	(106,709)	299,803	65,600
Ending balance TNMP at Jun. 30, 2018													648,748	64	504,166	144,518
Beginning balance at Mar. 31, 2018	1,749,014	1,683,614	1,150,516	(105,520)	638,618	65,400	1,495,561	1,430,161	1,264,918	(108,019)	273,262	65,400
Beginning balance TNMP at Mar. 31, 2018													642,794	64	504,166	138,564
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss) before subsidiary preferred stock dividends	42,449	38,340			38,340	4,109	30,781	26,673			26,673	4,108
Net earnings							26,672						15,367			15,367
Total other comprehensive income	1,763	1,763		1,763			1,310	1,310		1,310
Subsidiary preferred stock dividends	(132)	(132)			(132)
Dividends declared on preferred stock							(132)	(132)			(132)
Dividends declared on common stock													(9,413)			(9,413)
Proceeds from stock option exercise	122	122	122
Awards of common stock	(1,423)	(1,423)	(1,423)
Stock based compensation expense	431	431	431
Valencia’s transactions with its owner	(3,909)					(3,909)	(3,908)					(3,908)
Ending balance at Jun. 30, 2018	1,788,315	1,722,715	1,149,646	(103,757)	676,826	65,600	1,523,612	1,458,012	1,264,918	(106,709)	299,803	65,600
Ending balance TNMP at Jun. 30, 2018													648,748	64	504,166	144,518
Beginning balance at Dec. 31, 2018	1,752,594	1,688,382	1,153,113	(108,684)	643,953	64,212	1,461,571	1,397,359	1,264,918	(110,422)	242,863	64,212
Beginning balance TNMP at Dec. 31, 2018	1,688,382						1,397,359						674,093	64	534,166	139,863
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss) before subsidiary preferred stock dividends	(50,622)	(56,950)			(56,950)	6,328	(61,340)	(67,668)			(67,668)	6,328
Net earnings							(67,668)						19,365			19,365
Total other comprehensive income	8,502	8,502		8,502			10,474	10,474		10,474
Subsidiary preferred stock dividends	(264)	(264)			(264)
Dividends declared on preferred stock							(264)	(264)			(264)
Dividends declared on common stock	(23,099)	(23,099)			(23,099)								(14,811)			(14,811)
Proceeds from stock option exercise	943	943	943
Awards of common stock	(9,892)	(9,892)	(9,892)
Stock based compensation expense	4,526	4,526	4,526
Valencia’s transactions with its owner	(7,948)					(7,948)	(7,948)					(7,948)
Ending balance at Jun. 30, 2019	1,674,740	1,612,148	1,148,690	(100,182)	563,640	62,592	1,402,493	1,339,901	1,264,918	(99,948)	174,931	62,592
Ending balance TNMP at Jun. 30, 2019	1,612,148						1,339,901						678,647	64	534,166	144,417
Beginning balance at Mar. 31, 2019	1,747,458	1,684,679	1,148,364	(103,239)	639,554	62,779	1,485,307	1,422,528	1,264,918	(104,265)	261,875	62,779
Beginning balance TNMP at Mar. 31, 2019													667,478	64	534,166	133,248
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss) before subsidiary preferred stock dividends	(72,283)	(75,782)			(75,782)	3,499	(83,313)	(86,812)			(86,812)	3,499
Net earnings							(86,812)						15,267			15,267
Total other comprehensive income	3,057	3,057		3,057			4,317	4,317		4,317
Subsidiary preferred stock dividends	(132)	(132)			(132)
Dividends declared on preferred stock							(132)	(132)			(132)
Dividends declared on common stock													(4,098)			(4,098)
Proceeds from stock option exercise	13	13	13
Awards of common stock	(956)	(956)	(956)
Stock based compensation expense	1,269	1,269	1,269
Valencia’s transactions with its owner	(3,686)					(3,686)	(3,686)					(3,686)
Ending balance at Jun. 30, 2019	1,674,740	$ 1,612,148	$ 1,148,690	$ (100,182)	$ 563,640	$ 62,592	1,402,493	$ 1,339,901	$ 1,264,918	$ (99,948)	$ 174,931	$ 62,592
Ending balance TNMP at Jun. 30, 2019	$ 1,612,148						$ 1,339,901						$ 678,647	$ 64	$ 534,166	$ 144,417

Significant Accounting Policies

Significant Accounting Policies and Responsibility for Financial Statements	6 Months Ended
	Jun. 30, 2019
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, 2019 and December 31, 2018 , and the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2019 and 2018, and cash flows for the six months ended June 30, 2019 and 2018 . The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year. The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2018 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2019 financial statement presentation. These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual audited 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 2018 Annual Reports on Form 10-K. GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP. Principles of Consolidation The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 6). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants. PNMR shared services’ expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost and are reflected as general and administrative expenses in the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, equity transactions, and interconnection billings (Note 15). All intercompany transactions and balances have been eliminated. Dividends on Common Stock Dividends on PNMR’s common stock are declared by the 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 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 $0.290 per share in July 2019 and $0.265 per share in July 2018, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. TNMP declared and paid cash dividends on common stock to PNMR of $4.1 million and $14.8 million in the three and six months ended June 30, 2019 and $9.4 million and $10.4 million in the three and six months ended June 30, 2018. Investment in NM Renewable Development, LLC As discussed in Note 1 of the 2018 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 33.9 MW. In July 2019, NMRD entered into agreements to provide power from 1.2 MW of solar-PV facilities, which are expected to be placed in commercial operation in the second half of 2019, to the City of Rio Rancho, New Mexico. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations. In the six months ended June 30, 2019 and 2018, PNMR Development made cash contributions of $13.3 million and $8.0 million to NMRD to be used primarily for its construction activities. On July 22, 2019, PNMR Development made an additional cash contribution to NMRD of $11.0 million . PNMR presents its share of net earnings from NMRD in other income on the Condensed Consolidated Statements of Earnings. Summarized financial information for NMRD is as follows: Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In thousands) Operating revenues $ 1,103 $ 1,098 $ 1,828 $ 1,509 Operating expenses 655 657 1,451 1,006 Net earnings $ 448 $ 441 $ 377 $ 503 Financial Position June 30, December 31, 2019 2018 (In thousands) Current assets $ 2,733 $ 2,581 Net property, plant, and equipment 77,804 50,784 Total assets 80,537 53,365 Current liabilities 533 237 Owners’ equity $ 80,004 $ 53,128 New Accounting Pronouncements Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. In May 2019, the FASB issued transition relief by providing an option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. The Company is in the process of analyzing the impacts of this new standard but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. Accounting Standards Update 2018-18 – Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Segment Information	Segment Information The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. PNM PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale power and transmission rates. TNMP TNMP is an electric utility providing services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP also provides transmission services at regulated rates to other utilities that interconnect with TNMP’s facilities. Corporate and Other The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development, NM Capital, and the equity method investment in NMRD are also included in Corporate and Other. Eliminations of intercompany income and expense transactions are reflected 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 TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended June 30, 2019 Electric operating revenues $ 238,219 $ 92,009 $ — $ 330,228 Cost of energy 58,866 24,916 — 83,782 Utility margin 179,353 67,093 — 246,446 Other operating expenses 255,519 24,013 (5,536 ) 273,996 Depreciation and amortization 39,811 20,502 5,752 66,065 Operating income (loss) (115,977 ) 22,578 (216 ) (93,615 ) Interest income 3,530 — (70 ) 3,460 Other income (deductions) 4,179 731 (78 ) 4,832 Interest charges (18,526 ) (6,560 ) (4,705 ) (29,791 ) Segment earnings (loss) before income taxes (126,794 ) 16,749 (5,069 ) (115,114 ) Income taxes (benefit) (43,481 ) 1,482 (832 ) (42,831 ) Segment earnings (loss) (83,313 ) 15,267 (4,237 ) (72,283 ) Valencia non-controlling interest (3,499 ) — — (3,499 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ (86,944 ) $ 15,267 $ (4,237 ) $ (75,914 ) Six Months Ended June 30, 2019 Electric operating revenues $ 507,536 $ 172,336 $ — $ 679,872 Cost of energy 158,204 47,204 — 205,408 Utility margin 349,332 125,132 — 474,464 Other operating expenses 361,981 49,253 (11,299 ) 399,935 Depreciation and amortization 79,036 40,716 11,669 131,421 Operating income (loss) (91,685 ) 35,163 (370 ) (56,892 ) Interest income 7,187 — (139 ) 7,048 Other income (deductions) 18,536 1,317 (814 ) 19,039 Interest charges (36,886 ) (15,361 ) (9,178 ) (61,425 ) Segment earnings (loss) before income taxes (102,848 ) 21,119 (10,501 ) (92,230 ) Income taxes (benefit) (41,508 ) 1,754 (1,854 ) (41,608 ) Segment earnings (loss) (61,340 ) 19,365 (8,647 ) (50,622 ) Valencia non-controlling interest (6,328 ) — — (6,328 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ (67,932 ) $ 19,365 $ (8,647 ) $ (57,214 ) At June 30, 2019: Total Assets $ 5,105,090 $ 1,768,831 $ 174,746 $ 7,048,667 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended June 30, 2018 Electric operating revenues $ 264,511 $ 87,802 $ — $ 352,313 Cost of energy 66,361 21,350 — 87,711 Utility margin 198,150 66,452 — 264,602 Other operating expenses 107,058 23,510 (5,358 ) 125,210 Depreciation and amortization 38,213 16,113 5,737 60,063 Operating income (loss) 52,879 26,829 (379 ) 79,329 Interest income 3,381 — 958 4,339 Other income (deductions) (3,146 ) 832 (428 ) (2,742 ) Interest charges (19,988 ) (7,801 ) (5,532 ) (33,321 ) Segment earnings (loss) before income taxes 33,126 19,860 (5,381 ) 47,605 Income taxes (benefit) 2,345 4,493 (1,682 ) 5,156 Segment earnings (loss) 30,781 15,367 (3,699 ) 42,449 Valencia non-controlling interest (4,109 ) — — (4,109 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 26,540 $ 15,367 $ (3,699 ) $ 38,208 Three Months Ended June 30, 2018 Electric operating revenues $ 500,742 $ 169,449 $ — $ 670,191 Cost of energy 137,163 43,104 — 180,267 Utility margin 363,579 126,345 — 489,924 Other operating expenses 207,569 48,484 (10,375 ) 245,678 Depreciation and amortization 74,840 32,500 11,445 118,785 Operating income (loss) 81,170 45,361 (1,070 ) 125,461 Interest income 5,868 — 2,594 8,462 Other income (deductions) (1,927 ) 1,916 (349 ) (360 ) Interest charges (40,818 ) (15,530 ) (10,028 ) (66,376 ) Segment earnings (loss) before income taxes 44,293 31,747 (8,853 ) 67,187 Income taxes (benefit) 1,997 6,968 (3,026 ) 5,939 Segment earnings (loss) 42,296 24,779 (5,827 ) 61,248 Valencia non-controlling interest (7,786 ) — — (7,786 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 34,246 $ 24,779 $ (5,827 ) $ 53,198 At June 30, 2018: Total Assets $ 4,994,277 $ 1,583,311 $ 172,501 $ 6,750,089 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to customers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	6 Months Ended
	Jun. 30, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2019 and 2018 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2018 $ 1,939 $ (112,361 ) $ (110,422 ) $ 1,738 $ (108,684 ) Amounts reclassified from AOCI (pre-tax) (5,601 ) 3,702 (1,899 ) 525 (1,374 ) Income tax impact of amounts reclassified 1,423 (940 ) 483 (133 ) 350 Other OCI changes (pre-tax) 15,938 — 15,938 (3,169 ) 12,769 Income tax impact of other OCI changes (4,048 ) — (4,048 ) 805 (3,243 ) Net after-tax change 7,712 2,762 10,474 (1,972 ) 8,502 Balance at June 30, 2019 $ 9,651 $ (109,599 ) $ (99,948 ) $ (234 ) $ (100,182 ) Balance at December 31, 2017, as originally reported $ 13,169 $ (110,262 ) $ (97,093 ) $ 1,153 $ (95,940 ) Cumulative effect adjustment (Note 7) (11,208 ) — (11,208 ) — (11,208 ) Balance at January 1, 2018, as adjusted 1,961 (110,262 ) (108,301 ) 1,153 (107,148 ) Amounts reclassified from AOCI (pre-tax) (3,126 ) 3,788 662 (7 ) 655 Income tax impact of amounts reclassified 794 (962 ) (168 ) 1 (167 ) Other OCI changes (pre-tax) 1,472 — 1,472 2,420 3,892 Income tax impact of other OCI changes (374 ) — (374 ) (615 ) (989 ) Net after-tax change (1,234 ) 2,826 1,592 1,799 3,391 Balance at June 30, 2018 $ 727 $ (107,436 ) $ (106,709 ) $ 2,952 $ (103,757 ) The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities in gains (losses) on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2019
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows: Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands, except per share amounts) Net Earnings (Loss) Attributable to PNMR $ (75,914 ) $ 38,208 $ (57,214 ) $ 53,198 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 263 211 251 208 Average Shares – Basic 79,917 79,865 79,905 79,862 Dilutive Effect of Common Stock Equivalents: (1) Stock options and restricted stock — 114 — 134 Average Shares – Diluted 79,917 79,979 79,905 79,996 Net Earnings (Loss) Per Share of Common Stock: Basic $ (0.95 ) $ 0.48 $ (0.72 ) $ 0.67 Diluted (1) $ (0.95 ) $ 0.48 $ (0.72 ) $ 0.67 (1) Due to the loss in the three and six months ended June 30, 2019, no potentially dilutive shares are reflected in the average number of shares used to compute net earnings (loss) per share of common stock since any impact would be anti-dilutive. At June 30, 2019, PNMR’s potentially dilutive shares consist of stock options and restricted stock (see Note 8).

Electric Operating Revenues

Electric Operating Revenues	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Electric Operating Revenues	Electric Operating Revenues PNMR is an investor-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP. Additional information concerning electric operating revenue is contained in Note 4 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Disaggregation of Revenues A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues. PNM TNMP PNMR Consolidated Three Months Ended June 30, 2019 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 86,328 $ 33,640 $ 119,968 Commercial 98,968 28,058 127,026 Industrial 15,329 5,295 20,624 Public authority 4,596 1,391 5,987 Economy energy service 6,024 — 6,024 Transmission 14,342 17,585 31,927 Miscellaneous 2,474 887 3,361 Total revenues from contracts with customers 228,061 86,856 314,917 Alternative revenue programs 691 5,153 5,844 Other electric operating revenues 9,467 — 9,467 Total Electric Operating Revenues $ 238,219 $ 92,009 $ 330,228 PNM TNMP PNMR Consolidated Six Months Ended June 30, 2019 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 193,629 $ 64,072 $ 257,701 Commercial 184,201 55,487 239,688 Industrial 30,076 10,911 40,987 Public authority 9,307 2,764 12,071 Economy energy service 12,946 — 12,946 Transmission 27,727 31,589 59,316 Miscellaneous 6,116 1,789 7,905 Total revenues from contracts with customers 464,002 166,612 630,614 Alternative revenue programs 756 5,724 6,480 Other electric operating revenues 42,778 — 42,778 Total Electric Operating Revenues $ 507,536 $ 172,336 $ 679,872 Three Months Ended June 30, 2018 Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 99,508 $ 31,315 $ 130,823 Commercial 110,652 28,082 138,734 Industrial 14,597 4,184 18,781 Public authority 5,220 1,399 6,619 Economy energy service 6,378 — 6,378 Transmission 14,108 16,743 30,851 Miscellaneous 4,265 2,208 6,473 Total revenues from contracts with customers 254,728 83,931 338,659 Alternative revenue programs 1,789 3,871 5,660 Other electric operating revenues 7,994 — 7,994 Total Electric Operating Revenues $ 264,511 $ 87,802 $ 352,313 Six Months Ended June 30, 2018 Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 196,676 $ 60,581 $ 257,257 Commercial 193,501 55,234 248,735 Industrial 28,056 8,489 36,545 Public authority 9,855 2,815 12,670 Economy energy service 13,666 — 13,666 Transmission 26,590 33,251 59,841 Miscellaneous 8,947 4,349 13,296 Total revenues from contracts with customers 477,291 164,719 642,010 Alternative revenue programs 1,854 4,730 6,584 Other electric operating revenues 21,597 — 21,597 Total Electric Operating Revenues $ 500,742 $ 169,449 $ 670,191 Contract balances Performance obligations related to contracts with customers are typically satisfied when the energy is delivered and the customer or end-user utilizes the energy. Accounts receivable from customers represent amounts billed to the customer or end-user, including amounts under ARPs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for uncollectible accounts, includes $52.7 million at June 30, 2019 and $61.7 million at December 31, 2018 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers. Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of June 30, 2019 or December 31, 2018. Contract liabilities arise when consideration is received in advance from a customer before satisfying the performance obligations. Therefore, revenue is deferred and not recognized until the obligation is satisfied. Under its Open Access Transmission Tariff, PNM accepts upfront consideration for capacity reservations requested by transmission customers, which requires PNM to defer the customer’s transmission capacity rights for a specific period of time. PNM recognizes the revenue of these capacity reservations over the period the capacity rights have been reserved, which is generally over one year. Other utilities pay PNM and TNMP in advance for the joint-use of their utility poles. These revenues are recognized over the period of time specified in the joint-use contract, typically for one year. Deferred revenues on these arrangements are recorded as contract liabilities. The Company has no other arrangements with remaining performance obligations to which a portion of the transaction price would be required to be allocated. Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows: PNM TNMP PNMR Consolidated (In thousands) Balance at December 31, 2018 $ 349 $ — $ 349 Consideration received in advance of service to be provided 4,157 1,517 5,674 Deferred revenue earned (2,259 ) (776 ) (3,035 ) Balance at June 30, 2019 $ 2,247 $ 741 $ 2,988

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2019
Variable Interest Entities [Abstract]
Variable Interest Entities	Variable Interest Entities GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity (“VIE”). GAAP also requires continual reassessment of the primary beneficiary of a VIE. Additional information concerning PNM’s VIEs is contained in Note 10 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Valencia PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and six months ended June 30, 2019 , PNM paid $5.0 million and $9.9 million for fixed charges and $0.2 million and $0.3 million for variable charges. For the three and six months ended June 30, 2018, PNM paid $4.9 million and $9.8 million for fixed charges and $0.6 million and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, to purchase and own up to 50% of the plant or the VIE. The PPA specifies that the purchase price would be the greater of 50% of book value reduced by related indebtedness or 50% of fair market value. PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third-party entity that owns Valencia is a VIE and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates Valencia in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the Condensed Consolidated Financial Statements of PNM although PNM has no legal ownership interest or voting control of the VIE. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest. Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In thousands) Operating revenues $ 5,177 $ 5,911 $ 10,129 $ 10,679 Operating expenses 1,678 1,802 3,801 2,893 Earnings attributable to non-controlling interest $ 3,499 $ 4,109 $ 6,328 $ 7,786 Financial Position June 30, December 31, 2019 2018 (In thousands) Current assets $ 3,174 $ 2,684 Net property, plant, and equipment 60,003 62,066 Total assets 63,177 64,750 Current liabilities 585 538 Owners’ equity – non-controlling interest $ 62,592 $ 64,212 Westmoreland San Juan Mining, LLC As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland Coal Company (“Westmoreland”), on January 31, 2016, as well as the $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the purchase of SJCC. On May 22, 2018, the full principal outstanding under the Westmoreland Loan was repaid. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan. Prior to its repayment, the Westmoreland Loan resulted in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital were subject to possible loss in the event of default of WSJ. On October 9, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC announcing it had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. On March 15, 2019, Westmoreland emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, the assets of SJCC were sold to Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of WSJ including obligations to PNM under the SJGS CSA and to PNMR under a letter of credit support agreement. See (Note 11). PNMR issued $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. As discussed above, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR for the letters of credit. The letters of credit support results in PNMR being considered to have a variable interest in WSJ LLC since PNMR is subject to possible loss in the event performance by PNMR is required under the letters of credit support. PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that WSJ LLC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS CSA. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations. WSJ LLC is considered to be a VIE. PNMR’s analysis of its arrangements with WSJ LLC concluded that WSJ LLC has the ability to direct its mining operations, which is the factor that most significantly impacts the economic performance of WSJ LLC. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of WSJ LLC, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation. PNM’s involvement through the SJGS CSA, which was assumed by WSJ LLC pursuant to the March 15, 2019 purchase of the assets owned by SJCC by WSJ LLC, is a protective right rather than a participating right and WSJ LLC has the power to direct the activities that most significantly impact the economic performance of WSJ LLC. The SJGS CSA requires WSJ LLC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation. If WSJ LLC is able to mine more efficiently than anticipated, its economic performance will be improved. Conversely, if WSJ LLC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted. Accordingly, PNMR believes WSJ LLC is the primary beneficiary and, therefore, WSJ LLC is not consolidated by either PNMR or PNM. The amounts outstanding under the letter of credit support constitute PNMR’s maximum exposure to loss from the VIE at June 30, 2019

Fair Value of Derivative and Ot

Fair Value of Derivative and Other Financial Instruments	6 Months Ended
	Jun. 30, 2019
Fair Value of Derivative and Other Financial Instruments [Abstract]
Fair Value of Derivative and Other Financial Instruments	Fair Value of Derivative and Other Financial Instruments Additional information concerning energy related derivative contracts and other financial instruments is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk, including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique. Energy Related Derivative Contracts Overview The primary objective for the use of commodity derivative instruments, including energy contracts, options, swaps, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its customers. PNM is exposed to market risk for the needs of its customers not covered under a FPPAC. Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW interest in SJGS Unit 4, which is held as merchant plant as ordered by the NMPRC. PNM has entered into agreements to sell power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022, subject to certain conditions. Under these agreements, PNM is obligated to deliver 36 MW of power only when SJGS Unit 4 is operating. These agreements are not considered derivatives because there is no notional amount due to the unit-contingent nature of the transactions. PNM and Tri-State have a hazard sharing agreement, which expires on May 31, 2022. Under this agreement, each party sells the other party 100 MW of capacity and energy from a designated generation resource on a unit contingent basis, subject to certain performance guarantees. Both the purchases and sales are made at the same market index price. This agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM passes the sales and purchases through to customers under PNM’s FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. TNMP does not enter into energy related derivative contracts. Commodity Risk Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations. PNM monitors the market risk of its commodity contracts in accordance with approved risk and credit policies. Accounting for Derivatives Under derivative accounting and related rules for energy contracts, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the six months ended June 30, 2019 and the year ended December 31, 2018 , PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The derivative contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. PNM has no trading transactions. Commodity Derivatives PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are presented in the following line items on the Condensed Consolidated Balance Sheets: Economic Hedges June 30, December 31, (In thousands) Other current assets $ 1,164 $ 1,083 Other deferred charges 2,028 2,511 3,192 3,594 Other current liabilities (1,142 ) (1,177 ) Other deferred credits (2,028 ) (2,511 ) (3,170 ) (3,688 ) Net $ 22 $ (94 ) Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives. Included in the above table are equal amounts of assets and liabilities aggregating $3.1 million at June 30, 2019 and $3.6 million at December 31, 2018 resulting from PNM’s hazard sharing arrangements with Tri-State. The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial. At June 30, 2019 and December 31, 2018 , PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at June 30, 2019 and December 31, 2018 , amounts posted as cash collateral under margin arrangements were $0.5 million and $1.0 million . At June 30, 2019 and December 31, 2018 , obligations to return cash collateral were $0.9 million and $1.0 million . Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets. PNM has a NMPRC-approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. There were insignificant amounts hedged under this plan as of June 30, 2019 and no amounts were hedged under this plan as of December 31, 2018 . The effects of mark-to-market commodity derivative instruments on PNM’s revenues and cost of energy during the three and six months ended June 30, 2019 and 2018 were less than $0.1 million . Commodity derivatives had no impact on OCI for the periods presented. Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh June 30, 2019 565,000 (42,000 ) December 31, 2018 100,000 — PNM has 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. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral. At June 30, 2019 and December 31, 2018 , PNM had no such contracts in a net liability position. 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. Investment securities are carried at fair value. Investment securities consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 11). At June 30, 2019 and December 31, 2018 , the fair value of investment securities included $318.8 million and $287.1 million for the NDT and $44.0 million and $41.1 million for the mine reclamation trusts. As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, on January 1, 2018 the Company adopted Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10). Accordingly , on January 1, 2018 PNM recorded an after-tax cumulative effect adjustment of $11.2 million to reclassify unrealized holding gains on equity securities held in the NDT and coal mine reclamation trusts from AOCI to retained earnings on the Condensed Consolidated Balance Sheets. After January 1, 2018, all gains and losses resulting from sales and changes in the fair value of equity securities are recognized in earnings. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged. Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table. Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Equity securities: Net gains from equity securities sold $ 2,774 $ 2,502 $ 4,161 $ 5,330 Net gains (losses) from equity securities still held 303 (443 ) 9,905 (307 ) Total net gains on equity securities 3,077 2,059 14,066 5,023 Available-for-sale debt securities: Net gains (losses) on debt securities 1,522 (3,729 ) 4,547 (6,405 ) Net gains (losses) on investment securities $ 4,599 $ (1,670 ) $ 18,613 $ (1,382 ) The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $ (0.8) million and $2.6 for the three and six months ended June 30, 2019 and $(2.6) million and $(3.8) million for the three and six months ended June 30, 2018. Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Proceeds from sales $ 159,551 $ 167,359 $ 234,011 $ 794,088 Gross realized gains $ 10,906 $ 7,549 $ 15,095 $ 13,570 Gross realized (losses) $ (5,802 ) $ (6,192 ) $ (8,972 ) $ (10,869 ) The Company has no available-for-sale debt securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings. At June 30, 2019 , the available-for-sale debt securities held by PNM, had the following final maturities: Fair Value (In thousands) Within 1 year $ 20,868 After 1 year through 5 years 75,642 After 5 years through 10 years 67,572 After 10 years through 15 years 12,886 After 15 years through 20 years 11,747 After 20 years 34,246 $ 222,961 Fair Value Disclosures The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the six months ended June 30, 2019 or the year ended December 31, 2018 . For investment securities, Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For Level 2 fair values, 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. Fair values of Level 2 investments in mutual funds are equal to net asset value. Level 3 investments are comprised of corporate term loans. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. The valuation of Level 3 investments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates, and cash flows. Management of the Company independently verifies the information provided by pricing services. Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) June 30, 2019 Cash and cash equivalents $ 11,055 $ 11,055 $ — $ — Equity securities: Corporate stocks, common 38,391 38,391 — — Corporate stocks, preferred 8,788 2,207 6,581 — Mutual funds and other 81,598 81,558 40 — Available-for-sale debt securities: U.S. Government 35,664 21,971 13,693 — $ 888 International Government 13,582 31 13,551 — 827 Municipals 46,633 — 46,633 — 1,886 Corporate and other 127,082 1,304 122,969 2,809 9,342 $ 362,793 $ 156,517 $ 203,467 $ 2,809 $ 12,943 Commodity derivative assets $ 3,192 $ — $ 3,192 $ — Commodity derivative liabilities (3,170 ) — (3,170 ) — Net $ 22 $ — $ 22 $ — Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) December 31, 2018 Cash and cash equivalents $ 11,472 $ 11,472 $ — $ — Equity securities: Corporate stocks, common 32,997 32,997 — — Corporate stocks, preferred 7,258 1,654 5,604 — Mutual funds and other 70,777 70,777 — — Available-for-sale debt securities: U.S. Government 29,503 18,662 10,841 — $ 1,098 International Government 8,435 — 8,435 — 90 Municipals 53,642 — 53,642 — 489 Corporate and other 114,158 588 111,414 2,156 923 $ 328,242 $ 136,150 $ 189,936 $ 2,156 $ 2,600 Commodity derivative assets $ 3,594 $ — $ 3,594 $ — Commodity derivative liabilities (3,688 ) — (3,688 ) — Net $ (94 ) $ — $ (94 ) $ — A reconciliation of the changes in Level 3 fair value measurements is as follows: Corporate Debt (In thousands) Balance at December 31, 2018 $ 2,156 Actual return on assets sold during the period (48 ) Actual return on assets still held at period end 63 Purchases 1,422 Sales (784 ) Balance at June 30, 2019 $ 2,809 Balance at December 31, 2017 $ — Actual return on assets sold during the period (4 ) Actual return on assets still held at period end (5 ) Purchases 4,011 Sales (1,011 ) Balance at June 30, 2018 $ 2,991 The carrying amounts and fair values of long-term debt, which is not recorded at fair value on the Condensed Consolidated Balance Sheets, are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 June 30, 2019 (In thousands) PNMR $ 2,772,342 $ 2,903,711 $ — $ 2,903,711 $ — PNM $ 1,707,256 $ 1,768,943 $ — $ 1,768,943 $ — TNMP $ 626,456 $ 692,728 $ — $ 692,728 $ — December 31, 2018 PNMR $ 2,670,111 $ 2,703,810 $ — $ 2,703,810 $ — PNM $ 1,656,490 $ 1,668,736 $ — $ 1,668,736 $ — TNMP $ 575,398 $ 597,236 $ — $ 597,236 $ — The carrying amount and fair value of the Company’s other investments presented on the Condensed Consolidated Balance Sheets are not material and not shown in the above table.

Stock-Based Compensation

Stock-Based Compensation	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. The Company has not awarded stock options since 2010. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, awards to employees vest ratably over three years from the grant date of the award. However, awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. Awards of restricted stock to non-employee members of the Board are expensed over a one -year vesting period. The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. Compensation expense for performance-based shares is recognized over the performance period as required service is provided and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At June 30, 2019 , PNMR had unrecognized expense related to stock awards of $6.0 million , which is expected to be recognized over an average of 1.73 years . PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as operating cash flows when used to reduce income taxes payable. The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest. The number of performance shares that ultimately vest cannot be determined until after the performance period ends. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period. The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Six Months Ended June 30, Restricted Shares and Performance Based Shares 2019 2018 Expected quarterly dividends per share $ 0.290 $ 0.265 Risk-free interest rate 2.47 % 2.38 % Market-Based Shares Dividend yield 2.59 % 2.96 % Expected volatility 19.55 % 19.12 % Risk-free interest rate 2.51 % 2.36 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the six months ended June 30, 2019 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2018 166,651 $ 32.93 81,000 $ 11.94 Granted 134,573 37.92 — — Exercised (137,601 ) 31.44 (79,000 ) 11.93 Forfeited — — — — Expired — — — — Outstanding at June 30, 2019 163,623 $ 38.19 2,000 $ 12.22 PNMR’s stock-based compensation program provides for performance and market targets through 2021. In February 2019, the Board approved amendments to exclude certain impacts of the Tax Act on performance metrics for the performance periods ending in 2018 and 2019. These amendments did not impact the Company’s calculation of grant date fair values under the plans, but did increase actual achievement levels for the performance period ending in 2018 from below “threshold” levels to below “target” levels and anticipated achievement levels for the performance period ending in 2019 from below “target” levels to the “maximum” level. Included as granted and exercised in the table above are 47,279 previously awarded shares that were earned for the 2016 through 2018 performance measurement period and ratified by the Board in February 2019 (based upon achieving market targets at below “threshold” levels, weighted at 40% , and performance targets at above “target” levels, together weighted at 60% ). Excluded from the table above are maximums of 130,302 , 146,941 , and 135,678 shares for the three -year performance periods ending in 2019, 2020, and 2021 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible. In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she was to receive 17,953 of the total shares if PNMR achieved specific performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving 17,953 shares in February 2018. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include the restricted stock shares that remain unvested under this retention award agreement. At June 30, 2019 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $0.1 million with a weighted-average remaining contract life of 0.7 years. At June 30, 2019 , no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date. The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Six Months Ended June 30, Restricted Stock 2019 2018 Weighted-average grant date fair value $ 37.92 $ 29.65 Total fair value of restricted shares that vested (in thousands) $ 6,227 $ 8,328 Stock Options Weighted-average grant date fair value of options granted $ — $ — Total fair value of options that vested (in thousands) $ — $ — Total intrinsic value of options exercised (in thousands) $ 2,617 $ 2,968

Financing

Financing	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Financing	Financing The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities or refinance other debt. Each of the Company’s revolving credit facilities and term loans contain a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR and PNMR Development agreements this ratio must be maintained at less than or equal to 70% , and for the PNM and TNMP agreements this ratio must be maintained at less than or equal to 65% . The Company’s revolving credit facilities and term loans generally also contain customary covenants, events of default, cross-default provisions, and change-of-control provisions. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. Additional information concerning financing activities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Financing Activities On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to facilitate the posting of reclamation bonds, which SJCC was required to post in connection with permits relating to the operation of the San Juan mine. On March 15, 2019, WSJ LLC acquired the assets of SJCC following the bankruptcy of Westmoreland. WSJ LLC assumed the obligations to PNMR under the letters of credit support (Note 11). On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which was classified as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows in the six months ended June 30, 2018. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three and six months ended June 30, 2019 PNM recognized $1.0 million and $1.9 million of interest expense under the agreement. During the three and six months ended June 30, 2018, PNM recognized $0.7 million of interest expense under the agreement. At June 30, 2019 , PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million , excluding unpaid interest, is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements. On January 18, 2019, PNM entered into a $250.0 million term loan agreement (the “PNM 2019 Term Loan”) among PNM, the lenders identified therein, and U.S. Bank N.A., as administrative agent. PNM used the proceeds of the PNM 2019 Term Loan to repay the PNM 2017 Term Loan, to reduce short-term borrowings under the PNM Revolving Credit Facility, and for general corporate purposes. The PNM 2019 Term Loan bears interest at a variable rate and must be repaid on or before July 17, 2020. On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement with institutional investors for the sale of $305.0 million aggregate principal amount of four series of TNMP first mortgage bonds (the “TNMP 2019 Bonds”) offered in private placement transactions. TNMP issued $225.0 million of TNMP 2019 Bonds on March 29, 2019 and used the proceeds to repay TNMP’s $172.3 million 9.50% first mortgage bonds at their maturity on April 1, 2019, as well as to repay borrowings under the TNMP Revolving Credit Facility and for general corporate purposes. TNMP issued the remaining $80.0 million of TNMP 2019 Bonds on July 1, 2019 and used the proceeds to repay borrowings under the TNMP Revolving Credit Facility and for general corporate purposes. The TNMP 2019 Bonds are subject to continuing compliance with the representations, warranties and covenants of the TNMP 2019 Bond Purchase Agreement. The terms of the TNMP 2019 Bond Purchase Agreement include customary covenants, including a covenant that requires TNMP to maintain a debt-to-capitalization ratio of less than or equal to 65% , customary events of default, a cross-default provision, and a change-of-control provision. TNMP will have the right to redeem any or all of the TNMP 2019 Bonds prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, borrowings under the $172.3 million 9.50% TNMP first mortgage bonds are reflected as being long-term in the Condensed Consolidated Balance Sheets at December 31, 2018 since TNMP demonstrated its intent and ability to re-finance the agreement on a long-term basis. Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds is as follows: Funding Date Maturity Date Principal Amount Interest Rate (In millions) March 29, 2019 March 29, 2034 $ 75.0 3.79 % March 29, 2019 March 29, 2039 75.0 3.92 % March 29, 2019 March 29, 2044 75.0 4.06 % 225.0 July 1, 2019 July 1, 2029 80.0 3.60 % $ 305.0 At June 30, 2019 , variable interest rates were 3.20% on the $50.0 million PNMR 2018 Two -Year Term Loan, which matures in December 2020, 3.05% on the $250.0 million PNM 2019 Term Loan, which matures in July 2020, 3.10% on the $35.0 million TNMP 2018 Term Loan, which matures in July 2020, and 3.20% on the $90.0 million PNMR Development Term Loan, which matures in November 2020. See discussion of PNM’s SJGS Abandonment Application in Note 12, which includes a request to issue approximately $361 million of energy transition bonds, as provided by the ETA, upon the proposed retirement of SJGS in 2022. Short-term Debt and Liquidity The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million . Both facilities currently expire on October 22, 2023 but contain options to be extended through October 2024, subject to approval by a majority of the lenders. PNM also has the $40.0 million PNM 2017 New Mexico Credit Facility that expires on December 12, 2022. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds and matures on September 23, 2022. On February 22, 2019, PNMR Development amended its $24.5 million revolving credit facility to increase the capacity to $25.0 million and to extend the term until February 24, 2020. On July 22, 2019, the PNMR Development Revolving Credit Facility was amended to increase the capacity to $40.0 million with the option to further increase the capacity to $50.0 million upon 15 -days advance notice. The facility will continue to have the expiration date of February 24, 2020. The PNMR Development Revolving Credit Facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development uses the facility to finance its participation in NMRD and for other activities. Short-term debt outstanding consisted of: June 30, December 31, Short-term Debt 2019 2018 (In thousands) PNM: PNM Revolving Credit Facility $ 27,200 $ 32,400 PNM 2017 New Mexico Credit Facility 15,000 10,000 42,200 42,400 TNMP Revolving Credit Facility 55,000 17,500 PNMR: PNMR Revolving Credit Facility 73,300 20,000 PNMR 2018 One-Year Term Loan 150,000 150,000 PNMR Development Revolving Credit Facility 21,900 6,000 $ 342,400 $ 235,900 At June 30, 2019 , the weighted average interest rate was 3.67% for the PNMR Revolving Credit Facility, 3.15% for the PNMR 2018 One -Year Term Loan, 3.53% for the PNM Revolving Credit Facility, 3.52% for the PNM 2017 New Mexico Credit Facility, 3.16% for the TNMP Revolving Credit Facility, and 3.41% for the PNMR Development Revolving Credit Facility. In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $4.7 million , $2.5 million , and $0.7 million at June 30, 2019 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of June 30, 2019 and December 31, 2018, TNMP had $1.6 million and $0.1 million of intercompany borrowings from PNMR, PNM had zero and $19.8 million of intercompany borrowings from PNMR, and PNMR Development had $0.2 million and $0.5 million of intercompany borrowings from PNMR. In 2017, PNMR entered into three separate four -year hedging agreements whereby it effectively established fixed interest rates of 1.926% , 1.823% , and 1.629% , plus customary spreads over LIBOR for three separate tranches, each of $50.0 million , of its variable rate debt. These hedge agreements are accounted for as cash flow hedges and had fair values of $(0.4) million and less than $0.1 million at June 30, 2019 that are included in other current liabilities and other deferred charges on the Condensed Consolidated Balance Sheets. At December 31, 2018, the hedge agreements had fair values aggregating $1.0 million that are included in other current assets on the Condensed Consolidated Balance Sheets. As discussed in Note 3, changes in the fair value of the cash flow hedge are deferred in AOCI and amounts reclassified to the Condensed Consolidated Statement of Earnings are recorded in interest charges. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement. On January 1, 2019, the Company adopted Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Adoption of the updated standard did not have a significant impact on these cash flow hedges. At July 26, 2019 , PNMR, PNM, TNMP, and PNMR Development had availability of $227.6 million , $368.1 million , $74.9 million , and $7.1 million under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $15.0 million of availability under the PNM 2017 New Mexico Credit Facility. Total availability at July 26, 2019 , on a consolidated basis, was $692.7 million for PNMR. As of July 26, 2019 , PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. As of July 26, 2019, PNMR Development had $0.2 million of intercompany borrowings from PNMR. At July 26, 2019 , PNMR, PNM, and TNMP had invested cash of $0.9 million , zero , and $13.8 million . The Company’s debt arrangements have various maturities and expiration dates. The $150.0 million PNMR 2018 One -Year Term Loan will mature in December 2019. PNM has $100.3 million of long-term debt that must be repriced by June 2020 and the $250.0 million PNM 2019 Term Loan matures in July 2020. In addition, the $35.0 million TNMP 2018 Term Loan matures in July 2020. The Company has no other long-term debt due through August 31, 2020. Additional information on debt maturities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.

Pension and Other Postretiremen

Pension and Other Postretirement Benefit Plans	6 Months Ended
	Jun. 30, 2019
Retirement Benefits [Abstract]
Pension and Other Postretirement Benefit Plans	Pension and Other Postretirement Benefit Plans PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. In accordance with GAAP, the Company presents the service cost component of its net periodic benefit costs in administrative and general expenses and the non-service costs components in other income (deductions), net of amounts capitalized or deferred to regulatory assets and liabilities, on the Condensed Consolidated Statements of Earnings. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of accumulated periodic cost or income to the extent included in retail rates (a “prepaid pension asset”). Additional information concerning pension and OPEB plans is contained in Note 11 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Annual net periodic benefit cost 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 OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 13 $ 21 $ — $ — Interest cost 6,294 6,068 829 860 162 155 Expected return on plan assets (8,527 ) (8,672 ) (1,318 ) (1,353 ) — — Amortization of net (gain) loss 3,880 4,087 169 588 79 90 Amortization of prior service cost (241 ) (241 ) (99 ) (416 ) — — Net Periodic Benefit Cost $ 1,406 $ 1,242 $ (406 ) $ (300 ) $ 241 $ 245 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 26 $ 41 $ — $ — Interest cost 12,587 12,135 1,658 1,720 324 311 Expected return on plan assets (17,051 ) (17,343 ) (2,636 ) (2,707 ) — — Amortization of net (gain) loss 7,759 8,174 338 1,177 158 179 Amortization of prior service cost (483 ) (483 ) (198 ) (832 ) — — Net Periodic Benefit Cost $ 2,812 $ 2,483 $ (812 ) $ (601 ) $ 482 $ 490 PNM did no t make any contributions to its pension plan trust in the six months ended June 30, 2019 and 2018 and does no t anticipate making any contributions to the pension plan in 2019 -2021, but expects to contribute $1.3 million in 2022 and $22.9 million in 2023, based on current law, funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6% . Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. Disbursements allocated to the OPEB trust, a portion of which are funded by PNM and considered to be contributions to the OPEB plan, were $0.7 million and $1.5 million in the three and six months ended June 30, 2019 . However, PNM made no contributions to the OPEB trust in the three and six months ended June 30, 2018. Although PNM does not expect to make any contributions to the OPEB trust in 2019-2023, disbursements attributable to the OPEB plan that are expected to be funded by PNM are estimated to be $3.7 million in 2019 and $13.7 million for 2020-2023. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.7 million in the three and six months ended June 30, 2019 and $0.4 million and $0.9 million in the three and six months ended June 30, 2018 and are expected to total $1.5 million during 2019 and $5.6 million for 2020-2023. TNMP Plans The following table presents the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 13 $ 33 $ — $ — Interest cost 672 656 113 119 8 7 Expected return on plan assets (967 ) (991 ) (129 ) (135 ) — — Amortization of net (gain) loss 235 272 (110 ) (56 ) 4 4 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost (Income) $ (60 ) $ (63 ) $ (113 ) $ (39 ) $ 12 $ 11 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 26 $ 67 $ — $ — Interest cost 1,344 1,312 226 238 16 15 Expected return on plan assets (1,934 ) (1,981 ) (258 ) (271 ) — — Amortization of net (gain) loss 470 544 (220 ) (113 ) 8 8 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost (Income) $ (120 ) $ (125 ) $ (226 ) $ (79 ) $ 24 $ 23 TNMP did no t make any contributions to its pension plan trust in the six months ended June 30, 2019 and 2018 and does no t anticipate making any contributions in 2019 -2023, based on current law, funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6% . Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made no contributions to the OPEB trust in the three and six months ended June 30, 2019 and zero and $0.3 million in the three and six months ended June 30, 2018 . TNMP does not expect to make contributions to the OPEB trust during the period 2019 -2023. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and six months ended June 30, 2019 and 2018 and are expected to total $0.1 million during 2019 and $0.3 million

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Overview There are various claims and lawsuits pending against the Company. In addition, the Company is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory proceedings in the normal course of its business (Note 12). It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows. With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. The Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows. Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Commitments and Contingencies Related to the Environment Nuclear Spent Fuel and Waste Disposal Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the DC Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high-level waste from PVNGS. In August 2014, APS and the DOE entered into a settlement agreement that establishes a process for the payment of claims for costs incurred through December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM records estimated claims on a quarterly basis. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations. PNM estimates that it will incur approximately $57.7 million (in 2016 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the nuclear fuel is consumed. At June 30, 2019 and December 31, 2018 , PNM had a liability for interim storage costs of $12.7 million and $12.4 million , which is included in other deferred credits. PVNGS has sufficient capacity at its on-site Independent Spent Fuel Storage Installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation. The Energy Transition Act On March 22, 2019, the Governor signed into New Mexico state law Senate Bill 489, known as the Energy Transition Act (“ETA”). The ETA became effective as of June 14, 2019 and sets a statewide standard that requires investor-owned electric utilities to have specified percentages of their electric-generating portfolios be provided from renewable and zero-carbon generating resources. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to review and approve utilities’ annual renewable portfolio plans to ensure compliance with the RPS. The ETA also directs the New Mexico Environmental Improvement Board to adopt standards of performance that limit CO 2 emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new or existing coal-fired EGUs with original installed capacities exceeding 300 MW. The ETA provides for a transition from fossil-fuel generation resources to renewable and other carbon-free resources through certain provisions relating to the abandonment of coal-fired generating facilities. These provisions include the use of “energy transition bonds,” which are designed to be highly rated bonds that can be issued to finance certain costs of abandoning coal-fired facilities that are retired prior to January 1, 2023 for facilities operated by a “qualifying utility,” or prior to January 1, 2032 for facilities that are not operated by the qualifying utility. The amount of energy transition bonds that can be issued to recover abandonment costs is limited to the lesser of $375.0 million or 150% of the undepreciated investment of the facility as of the abandonment date. Proceeds provided by energy transition bonds must be used only for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include plant decommissioning and coal mine reclamation costs provided those costs have not previously been recovered from customers or disallowed by the NMPRC or by a court order. See Note 12 for a discussion of the NM Supreme Court’s decision to affirm the NMPRC’s disallowance of certain costs, including the cost of BDT at SJGS, in PNM’s NM 2015 Rate Case. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. Energy transition bonds must be issued under an NMPRC approved financing order, are secured by “energy transition property,” are non-recourse to the issuing utility, and must be repaid by a non-bypassable charge paid by all customers of the issuing utility. These customer charges are subject to an adjustment mechanism designed to provide for timely and complete payment of principal and interest due under the energy transition bonds. The ETA also provides that utilities must obtain NMPRC approval of competitively procured replacement resources. In determining whether to approve replacement resources, the NMPRC must give preference to resources with the least environmental impacts, those with higher ratios of capital costs to fuel costs, and those located in the school district of the abandoned facility able to reduce the cost of reclamation and use for lands previously mined within the county of the EGU to be abandoned. The ETA also provides for the procurement of energy storage facilities and gives utilities discretion to maintain and control these systems to ensure reliable and efficient service. PNM expects the ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. See additional discussion in Note 12 of PNM’s SJGS Abandonment Application. PNM cannot predict the full impact of the ETA or the outcome of its pending and potential future generating resource abandonment and replacement resource filings with the NMPRC. The Clean Air Act Regional Haze In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress by adopting a new SIP every ten years. In the first SIP planning period, states were required to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have been installed by the beginning of 2018. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule. EPA also provided a companion draft guidance document for public comment. The new rule delayed the due date for the next cycle of SIPs from 2019 to 2021, altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures, and gave new authority to federal land managers to seek additional emission reduction measures outside of the states’ planning process. Finally, the rule made several procedural changes to the regional haze program, including changes to the schedule and process for states to file 5 -year progress reports. EPA’s new rule was challenged by numerous parties. On January 19, 2018, EPA filed a motion to hold the case in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for reconsideration of the 2017 rule revisions. On December 20, 2018, EPA released a new guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the CAA and other applicable regulations. SIPs for the second compliance period are due in July 2021. EPA’s decision to revisit the 2017 rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters. SJGS December 2018 Compliance Filing – As discussed in Note 16 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in December 2015 PNM received NMPRC approval for a plan to comply with the EPA regional haze rule at SJGS. Among other things, the NMPRC’s December 2015 order required that, no later than December 31, 2018, PNM make a filing with the NMRPC to determine the extent to which SJGS should continue serving PNM’s customers’ needs after June 30, 2022 (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply but after PNM received firm pricing and other terms for the supply of coal at SJGS, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS. The NMPRC’s December 2015 order also indicated that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM is prohibited from recovering the undepreciated investment of its 132 MW interest and required that PNM’s 65 MW interest in SJGS Unit 4 be treated as excluded merchant plant. PNM is currently depreciating its investments in SJGS through 2053, which reflects the period of time over which the NMPRC has authorized PNM to recover its investment in SJGS from New Mexico retail customers. PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP, PNM’s customers would benefit from the retirement of PNM’s share of SJGS after the current SJGS CSA expires in mid-2022 (Note 12). The December 2018 Compliance Filing also indicated that, pursuant to the terms of the agreements governing SJGS, all of the SJGS owners except for Farmington provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates, and that PNM has provided written notice to SJCC that PNM does not intend to extend the SJGS CSA beyond June 30, 2022. On January 30, 2019, the NMPRC issued an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS by March 1, 2019. PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceed the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that would not be available to PNM by March 1, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order. Various parties intervened in the petition. On June 26, 2019, the NM Supreme Court lifted the stay, denied PNM’s petition without discussion, and vacated oral arguments that had been scheduled for July 9, 2019. See additional discussion of PNM’s July 1, 2019 SJGS Abandonment Application in Note 12. GAAP requires that long-lived assets be tested for impairment when events or changes in circumstances indicate that their carrying value may not be recoverable. As of December 31, 2018, PNM evaluated the events surrounding its future participation in SJGS and determined that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, PNM performed an impairment analysis that assumed SJGS would not continue to operate through 2053, as previously approved by the NMPRC. PNM’s impairment analysis indicated that, pursuant to the NMPRC’s December 2015 order, PNM’s undepreciated 132 MW interest in SJGS Unit 4 at June 30, 2022 will not be recovered from customers; that the estimated future cash flows expected to result from the operation of SJGS Unit 4 through June 30, 2022 are not sufficient to provide for recovery of PNM’s 65 MW merchant interest in the facility; and that it is unlikely PNM will be able to sell or transfer its interests in SJGS to third parties at amounts sufficient to provide for their recovery. As a result, as of December 31, 2018, PNM recorded a pre-tax impairment of its investment in SJGS of approximately $35.0 million , which is reflected as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings in the 2018 Annual Reports on Form 10-K. This amount includes the entire $11.9 million carrying value of PNM’s 65 MW interest in SJGS Unit 4 as of December 31, 2018 and $23.1 million of estimated undepreciated investments in PNM’s 132 MW jurisdictional interest as of June 30, 2022 that will not be recovered from customers. As of June 30, 2019 and December 31, 2018, the net book value of PNM’s investments in SJGS are $364.6 million and $373.6 million . See additional discussion below regarding the increase in PNM’s estimated liability for coal mine reclamation. NEE Complaint – On March 31, 2016, NEE filed a complaint with the NMPRC alleging that PNM failed to comply with its discovery obligation in the case authorizing the shutdown of SJGS Units 2 and 3 and requesting the NMPRC investigate whether financing provided by NM Capital to the former owner of SJCC (the “Westmoreland Loan”) could adversely affect PNM’s ability to provide electric service to its retail customers. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with the former owner of SJCC could be harmful to PNM’s customers. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments noting that the Westmoreland Loan was paid in full on May 22, 2018. On October 11, 2018, PNM notified the NMPRC that the former owner of SJCC, Westmoreland, had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As discussed in Note 6, on March 15, 2019, Westmoreland announced that it had emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, all the assets of SJCC were sold to WSJ LLC. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of Westmoreland including obligations to PNM under the SJGS CSA. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict if the NMPRC will take any further action on these matters or the potential outcome. Four Corners Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016. The court granted an APS motion to intervene in the litigation. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissal in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. Oral arguments for the appeal were held on March 7, 2019. On July 29, 2019, the Ninth Circuit issued a decision affirming the District Court’s dismissal of the case. PNM cannot predict if parties to the lawsuit will appeal this decision. Carbon Dioxide Emissions On August 3, 2015, EPA established standards to limit CO 2 emissions from power plants. EPA took three separate but related actions in which it: (1) established the carbon pollution standards for new, modified, and reconstructed power plants; (2) established the Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule was being re-evaluated, which was granted. On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order put forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order directed the EPA Administrator to review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards (“NSPS”) for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directed the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance. On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposed a legal interpretation concluding that the Clean Power Plan exceeded EPA’s statutory authority. On August 31, 2018, EPA published a proposed rule, informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. On June 19, 2019, EPA released the final version of the Affordable Clean Energy rule. EPA takes three actions in the final rule: (1) finalizes the repeal of the Clean Power Plan; (2) finalizes the Affordable Clean Energy rule; and (3) revises the implementing regulations for all emission guidelines issued under Clean Air Act Section 111(d), which among other things, extends the timing of state plans. The final rule is very similar to the August 2018 proposed rule. EPA set the Best System of Emissions Reduction (“BSER”) for existing coal-fired power plants as heat rate efficiency improvements based on a range of "candidate technologies" that can be applied inside the fence-line. Rather than setting a specific numerical standard of performance, EPA's rule directs states to determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable based on the application of BSER. States will have three years from when the rule is finalized to submit a plan to EPA and then the EPA has one year to approve the plan. If states do not submit a plan or their submitted plan is not acceptable, EPA will have two years to develop a federal plan. While corresponding NSR reform regulations were proposed as part of the EPA’s Affordable Clean Energy proposal, the final rule did not include such reform measures. EPA announced that it will be taking final action on the NSR reform proposal for EGUs in the near future. The Affordable Clean Energy rule is not expected to impact SJGS since EPA’s final approval of a state SIP would occur after the planned shutdown of SJGS in 2022 (subject to NMPRC approval). Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Affordable Clean Energy rule on the Navajo Nation. PNM is currently reviewing the requirements of the Affordable Clean Energy rule and is unable to predict the potential financial or operational impacts on Four Corners. On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule published in October 2015 for fossil fueled power plants. The proposed rule would revise the standards for coal- fired units based on a revised BSER determination that would result in less stringent CO 2 emission performance standards for new, reconstructed, and modified fossil-fueled power plants. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal were due on March 18, 2019. PNM’s review of the GHG emission reductions standards under the Affordable Clean Energy rule and the revised proposed carbon pollution standards rule is ongoing. The Affordable Clean Energy rule has been challenged by several parties and may be impacted by further litigation. As discussed above, SJGS and Four Corners may also be required to comply with additional GHG restrictions issued by the New Mexico Environmental Improvement Board pursuant to the recently enacted ETA. PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance, if any. National Ambient Air Quality Standards (“NAAQS”) The CAA requires EPA to set NAAQS for pollutants reasonably anticipated to endanger public health or welfare. EPA has set NAAQS for certain pollutants, including NOx, SO 2 , ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO 2 NAAQS to include a 1-hour standard while retaining the annual standards for NOx and SO 2 and the 24-hour SO 2 standard. EPA also updated the final particulate matter standard in 2012 and updated the ozone standard in 2015. NOx Standard – On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO 2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO 2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018. SO 2 Standard – On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO 2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO 2 sources to identify maximum 1-hour SO 2 concentrations. This characterization would result in these areas being designated as attainment, nonattainment, or unclassifiable for compliance with the 1-hour SO 2 NAAQS. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO 2 emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required, among other things, that EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule by December 2020. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree. The letters outline the schedule that EPA expects states to follow in moving forward with new SO 2 non-attainment designations. NMED did not receive a letter. On August 11, 2015, EPA released the Data Requirements Rule for SO 2 , telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO 2 NAAQS. On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted its formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO 2 standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO 2 emissions. On February 25, 2019, EPA announced its final decision to retain without changes the primary health-based NAAQS for SOx. Specifically, EPA will retain the current 1-hour standard for SO 2 , which is 75 parts per billion (“ppb”), based on the 3 -year average of the 99th percentile of daily maximum 1-hour SO 2 concentrations. SO 2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS. On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and required the installation of SNCRs. The revised permit also required the reduction of SO 2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO 2, and particulate matter. These reductions help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See a discussion of the regulatory treatment of BDT in Note 12. Ozone Standard – On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data is affected by events outside an area’s control. The proposed rule is important in light of the more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are subject to elevated background ozone transport from natural local sources, such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country. On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016 and recommended designation of a small area in southern Dona Ana County as n

Regulatory and Rate Matters

Regulatory and Rate Matters	6 Months Ended
	Jun. 30, 2019
Regulated Operations [Abstract]
Regulatory and Rate Matters	Regulatory and Rate Matters The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. PNM New Mexico General Rate Cases New Mexico 2015 General Rate Case (“NM 2015 Rate Case”) On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates. The application proposed a revenue increase of $123.5 million , including base non-fuel revenues of $121.7 million . PNM’s application was based on a FTY period beginning October 1, 2015 and proposed a ROE of 10.5% . The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The application included several proposed changes in rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation and included a request for a revenue decoupling pilot program for residential and small commercial customers. PNM requested that the proposed new rates become effective beginning in July 2016. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016 pursuant to the terms of the initial sales-leaseback transactions (Note 13). After additional hearings, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS CSA (Note 11). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA, which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million . In August 2016, the Hearing Examiner in the case issued a recommended decision (the “August 2016 RD”). The August 2016 RD, among other things, recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. As a result, the August 2016 RD recommended the NMPRC disallow recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases aggregating 64.1 MW of PVNGS Unit 2, the undepreciated capital improvements made during the period the 64.1 MW of purchased capacity was leased, rent expense aggregating $18.1 million annually for leases aggregating 114.6 MW of capacity that were extended through January 2023 and 2024 (Note 13), and recovery of the costs of converting SJGS Units 1 and 4 to BDT. On September 28, 2016, the NMPRC issued an order that authorized PNM to implement an increase in non-fuel rates of $61.2 million , effective for bills sent to customers after September 30, 2016. The order generally approved the August 2016 RD, but with certain significant modifications. The modifications to the August 2016 RD included: • Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million ; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued • Recovery of annual rent expenses associated with the 114.6 MW of capacity under the extended leases • Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Specifically, PNM appealed the NMPRC’s determination the PNM was imprudent in certain matters in the case, including the NMPRC’s disallowance of the full purchase price of the 64.1 MW of capacity in PVNGS Unit 2, the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM, the cost of converting SJGS Units 1 and 4 to BDT, and future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases. NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. The issues appealed by the various cross-appellants included, among other things, the NMPRC allowing PNM to recover any of the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and the purchase price for the 64.1 MW in PVNGS Unit 2, the costs incurred under the Four Corners CSA, and the inclusion of the “prepaid pension asset” in rate base. During the pendency of the appeal, PNM evaluated the consequences of the order in the NM 2015 Rate Case and the related appeals to the NM Supreme Court as required under GAAP. These evaluations indicated that it was reasonably possible that PNM would be successful on the issues it was appealing but would not be provided capital costs recovery until the NMPRC acted on a decision of the NM Supreme Court. PNM also evaluated the accounting consequences of the issues being appealed by the cross-appellants and concluded that the issues raised in the cross-appeals did not have substantial merit. In accordance with GAAP, PNM periodically updated its estimate of the amount of time necessary for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. As a result of these evaluations, through March 31, 2019, PNM recorded accumulated pre-tax impairments of its capital investments subject to the appeal in the amount of $19.7 million , which includes pre-tax losses of $1.3 million recorded during the three months ended March 31, 2019 and $1.8 million recorded during the six months ended June 30, 2018. On May 16, 2019, the NM Supreme Court issued its decision on the matters that had been appealed in the NM 2015 Rate Case. The NM Supreme Court rejected the matters appealed by the cross-appellants and affirmed the NMPRC’s disallowance of a portion of the purchase price of the 64.1 MW of capacity in PVNGS Unit 2; the undepreciated costs of capital improvements made during the time that the 64.1 MW capacity was leased by PNM; and the costs to install BDT at SJGS Units 1 and 4. The NM Supreme Court’s decision also ruled that the NMPRC’s decision to permanently disallow recovery of future decommissioning costs related to the 64.1 MW of PVNGS Unit 2 and the 114.6 MW of PVNGS Units 1 and 2 deprived PNM of its rights to due process of law and remanded the case to the NMPRC for further proceedings consistent with the Court’s findings. On July 17, 2019, the NMPRC heard oral argument from parties in the case on how to best proceed with the NM Supreme Court’s remand. At oral argument, parties presented various positions ranging from re-litigating the value of PVNGS resources determined by the NMPRC and affirmed by the NM Supreme Court to re-affirming the NMPRC’s final order with a single modification to address recovery of future PVNGS decommissioning costs in a future case. PNM is unable to predict the outcome of this matter. As a result of the NM Supreme Court’s ruling, PNM recorded a pre-tax impairment of $149.3 million as of June 30, 2019 which is reflected as regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings. The impairment reflects capital costs not previously impaired during the pendency of the appeal and includes $72.6 million for a portion of the purchase price for 64.1 MW in PVNGS Unit 2, $39.3 million of undepreciated capitalized improvements made during the period the 64.1 MW was being leased by PNM, and $37.4 million for BDT on SJGS Units 1 and 4. The impairment was offset by tax impacts of $45.7 million , which are reflected as income taxes on the Condensed Consolidated Statements of Earnings. New Mexico 2016 General Rate Case (“NM 2016 Rate Case”) On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that were at issue in its then pending appeal to the NM Supreme Court. PNM’s original application used a FTY beginning January 1, 2018 and requested an increase in base non-fuel revenues of $99.2 million based on an ROE of 10.125% . The primary drivers of PNM’s revenue deficiency included implementation of modifications to PNM’s resource portfolio, which were approved by the NMPRC in December 2015 as part of the SJGS regional haze compliance plan, infrastructure investments, including environmental upgrades at Four Corners, declines in forecasted energy sales due to successful energy efficiency programs and other economic factors, and updates to FERC/retail jurisdictional allocations. After extensive settlement negotiations and public proceedings, the NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The key terms of the Revised Order include: • An increase in base non-fuel revenues totaling $10.3 million , which includes a reduction to reflect the impact of the decrease in the federal corporate income tax rate and updates to PNM’s cost of debt (aggregating an estimated $47.6 million annually) • A ROE of 9.575% • Returning to customers over a three -year period the benefit of the reduction in the New Mexico corporate income tax rate to the extent attributable to PNM’s retail operations (Note 14) • Disallowing PNM’s ability to collect an equity return on certain investments aggregating $148.1 million at Four Corners, but allowing recovery with a debt-only return • An agreement to not implement non-fuel base rate changes, other than changes related to PNM’s rate riders, with an effective date prior to January 1, 2020 • A requirement to consider the prudency of PNM’s decision to continue its participation in Four Corners in a future proceeding In accordance with the settlement agreement and the NMPRC’s final order, PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019. Investigation/Rulemaking Concerning NMPRC Ratemaking Policies On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed several questions related to establishing and monitoring utilities’ ROEs, the recoverability of regulatory assets, including rate case costs, and whether parties should have access to software used by utilities to support their positions. To date, no agreement has been reached. PNM cannot predict the outcome of this proceeding. Renewable Portfolio Standard Prior to the enactment of the ETA, the REA established a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. As discussed in Note 11, the ETA was enacted on June 14, 2019. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also removes diversity requirements and certain customer caps and exemptions relating to the application of the RPS under the REA. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The ETA sets a RCT of $60 per MWh using an average annual levelized resource cost basis. PNM makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Included in PNM’s approved procurement plans are the following renewable energy resources: • 157 MW of PNM-owned solar-PV facilities, including 50 MW of PNM-owned solar-PV facilities approved by the NMPRC in PNM’s 2018 renewable energy procurement plan that are expected to be placed in commercial operation by the end of 2019 • A PPA through 2044 for the output of New Mexico Wind, having a current aggregate capacity of 204 MW, and a PPA through 2035 for the output of Red Mesa Wind, having an aggregate capacity of 102 MW • A PPA through 2042 for the output of the Lightning Dock Geothermal facility; with a current capacity of 15 MW • Solar distributed generation, aggregating 113.1 MW at June 30, 2019 , owned by customers or third parties from whom PNM purchases any net excess output and RECs • Solar and wind RECs as needed to meet the RPS requirements On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM requested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. The plan also sought a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. PNM filed exceptions contesting the Hearing Examiner’s proposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and rejecting the Hearing Examiner’s recommendations. On November 29, 2017, NMIEC filed an appeal with the NM Supreme Court objecting to the fuel allocation methodology and requested a partial stay of the NMPRC order, which was denied. NEE subsequently filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. On July 5, 2019, the NM Supreme Court approved a motion filed by NMIEC to dismiss its appeal. NEE’s cross-appeal remains open. PNM cannot predict the outcome of this matter. On June 1, 2018, PNM filed its 2019 renewable energy procurement plan. The plan met RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and did not propose any significant new procurements. PNM projects that the plan will be within the RCT in 2019 and will slightly exceed the current RCT in 2020. The NMPRC approved PNM’s 2019 renewable energy procurement plan on November 28, 2018. On June 3, 2019, PNM filed its 2020 renewable energy procurement plan. The plan requests approval of a 20 -year PPA to purchase 140 MW of renewable energy and RECs from the La Joya Wind Facility (“La Joya Wind”), which is expected to be operational by December 31, 2020. PNM intends to utilize the BB2 line to deliver power from the PPA. See additional discussion below under Application For a New 345 kV Transmission Line . As discussed above, the ETA removes certain customer caps and exemptions relating to the application of the RPS under the REA. PNM’s 2020 renewable energy procurement plan requests a variance from the RPS for 2020 and proposes the shortfall be met with excess RECs that will be available under the La Joya Wind PPA in 2021. PNM also submitted proposed adjustments to the current FPPAC methodology for non-renewable fuel allocations to reflect the ETA’s removal of certain customer cost caps associated with the RPS and requested that the fuel clause year be reset to correspond to the January 1 reset date under the renewable energy rider. On July 17, 2019, PNM filed a corrected reconciliation of 2019 and estimated 2020 customer bill impacts that demonstrated the effect of removing certain customer caps and exemptions under the requirements of the newly enacted ETA. The Hearing Examiner issued a response requiring PNM to address why its application should not be dismissed, or alternatively, proposing an extended procedural schedule. PNM’s response proposed the application not be dismissed, that a corrected public notice be issued, and that the procedural schedule be extended by 60 days. On July 30 2019, the Hearing Examiner issued a revised procedural order that extended the review period through January 29, 2019 and set hearings to begin on October 24, 2019. PNM cannot predict the outcome of this matter. Renewable Energy Rider The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In its 2019 renewable energy procurement plan case, which was approved by the NMPRC on November 28, 2018, PNM proposed to collect $49.6 million for the year. The 2019 renewable energy procurement plan became effective on January 1, 2019. PNM recorded revenues from the rider of $12.8 million and $25.5 million in the three and six months ended June 30, 2019 and $10.8 million and $21.7 million in the three and six months ended June 30, 2018. In its 2020 renewable energy procurement plan, PNM proposes to collect $58.9 million for 2020. Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5% , PNM is required to refund the excess to customers during May through December of the following year. PNM did not exceed such limitation in 2018. Energy Efficiency and Load Management Petition for Energy Efficiency Disincentive PNM’s application in the NM 2016 Rate Case had requested a “lost contribution to fixed cost” mechanism to address the disincentives associated with PNM’s energy efficiency programs. In the revised stipulation to that case, PNM agreed to withdraw its proposal for such a mechanism and to address energy efficiency disincentives in a future docket. On March 2, 2018, PNM filed a petition proposing a “lost contribution to fixed cost mechanism” with substantially the same terms as those proposed in the NM 2016 Rate Case application. During the 2019 New Mexico legislative session, the Efficient Use of Energy Act was amended to, among other things, include a decoupling mechanism for disincentives, preclude a reduction to a utility’s ROE based on approval of disincentive or incentive mechanisms, and to establish savings targets for the period 2021 through 2025. On May 6, 2019, PNM submitted a request to the NMPRC to dismiss this matter. PNM will propose a mechanism to address disincentives in a future general rate case filing. The NMPRC approved PNM’s request to dismiss the matter on June 12, 2019, concluding this matter. Integrated Resource Plans NMPRC rules require that investor owned utilities file an IRP every three years . The IRP is required to cover a 20 -year planning period and contain an action plan covering the first four years of that period. 2014 IRP PNM filed its 2014 IRP on July 1, 2014. On July 31, 2014, several parties requested the NMPRC to not accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the then pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources and because they asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. The NMPRC issued an order in August 2014 that docketed a case to determine whether the 2014 IRP complied with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. On May 4, 2016, the NMPRC issued a Notice of Proposed Dismissal, stating that the docket would be closed with prejudice within thirty days unless good cause was shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s 2014 IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter. 2017 IRP PNM filed its 2017 IRP on July 3, 2017. The 2017 IRP addresses the 20 -year planning period from 2017 through 2036 and includes an action plan describing PNM’s plan to implement the 2017 IRP in the four -year period following its filing. The 2017 IRP analyzed several scenarios utilizing assumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP included, among other things, that retiring PNM’s share of SJGS in 2022 and existing ownership in Four Corners in 2031 would provide long-term cost savings for PNM’s customers and that the best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity as well as energy storage, if the economics support it, and wind energy provided additional transmission capacity becomes available. The 2017 IRP also indicated that PNM should retain the currently leased capacity in PVNGS. Protests to the 2017 IRP were filed by several parties. The issues addressed in the protests included the future of PNM’s interests in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. On December 19, 2018, after public hearings and consideration of the Hearing Examiner’s recommendations, the NMPRC issued a final order accepting PNM’s 2017 IRP as compliant with applicable statute and NMPRC rules. On January 18, 2019, the Board of the County of Commissioners for San Juan County, New Mexico, the City of Farmington, New Mexico, and other parties filed a Notice of Appeal with the NM Supreme Court regarding the NMPRC’s final order in PNM’s 2017 IRP. On January 18, 2019, NEE submitted a motion requesting the NMPRC reconsider its acceptance of PNM’s 2017 IRP and alleging informational inadequacy and deficiencies in PNM’s filing, which was deemed denied. On February 19, 2019, NEE filed a motion with the NM Supreme Court to intervene in the appeal and to seek remand of the matter to the NMPRC. On March 11, 2019, PNM filed its response with the NM Supreme Court stating that the NMPRC has already considered and, by operation of law, denied NEE’s motion for reconsideration. On May 10, 2019, the appellants, excluding NEE, filed a motion with the NM Supreme Court to dismiss their appeal, which was supported by PNM. On May 31, 2019, the NM Supreme Court denied NEE’s request to remand the proceeding to the NMPRC and ordered NEE to respond to the motion to dismiss the appeal. On June 4, 2019, NEE responded that it did not oppose the appellants’ request to dismiss their appeal. On July 26, 2019, the NM Supreme Court granted the parties’ motions to dismiss the appeal. This matter is now concluded. As discussed below, on July 1, 2019, PNM submitted its SJGS Abandonment Application with the NMPRC requesting approval to retire SJGS in 2022, for replacement resources, and for the issuance of securitized financing under the ETA. Many of the assumptions and findings included in PNM’s July 1, 2019 filing were consistent with those identified in PNM’s 2017 IRP. The SJGS Abandonment Application and the 2017 IRP are not a final determinations of PNM’s future generation portfolio. PNM will also be required to obtain NMPRC approval of an exit from Four Corners, which PNM will seek at an appropriate time in the future. Likewise, NMPRC approval of new generation resources through CCNs, PPAs, or other applicable filings will be required. PNM cannot predict the outcome of these matters. SJGS Abandonment Application On July 1, 2019, PNM filed a Consolidated Application for the Abandonment and Replacement of SJGS and Related Securitized Financing Pursuant to the ETA (the “SJGS Abandonment Application”). The SJGS Abandonment Application seeks NMPRC approval to retire PNM’s share of SJGS after the existing coal supply and participation agreements end in June 2022, for approval of replacement resources, and for the issuance of “energy transition bonds,” as provided by the ETA. PNM’s application proposes several replacement resource scenarios including PNM’s recommended replacement scenario, which would provide cost savings to customers compared to continued operation of SJGS, preserves system reliability, and is consistent with PNM’s plan to have an emissions-free generation portfolio by 2040. This plan would provide PNM authority to construct and own a 280 MW natural gas-fired peaking plant, to be located on the existing SJGS facility site and 70 MW of battery storage facilities. In addition, PNM’s recommended replacement resource scenario would allow PNM to execute PPAs to procure renewable energy from a total of 350 MW of solar-PV generating facilities and for energy from a total of 60 MW of battery storage facilities. PNM’s application included three other replacement resource scenarios that would place a greater amount of resources in the San Juan area, or result in no new fossil-fueled generating facilities or battery storage facilities. Each of these alternative replacement resource scenarios is expected to result in increased costs to customers and lower expected system reliability when compared to PNM’s recommended replacement resource scenario. The SJGS Abandonment Application includes a request to issue approximately $361 million of energy transition bonds (the “Securitized Bonds”). The amount of Securitized Bonds to be issued will be dependent upon several factors, including NMPRC approval of the SJGS Abandonment Application. Funding under the Securitized bonds is currently expected to include approximately $283 million of forecasted undepreciated investments in SJGS at June 30, 2020, an estimated $28.6 million for plant decommissioning and coal mine reclamation costs, approximately $9.6 million in upfront financing costs, and approximately $20.0 million for job training and severance costs for affected employees. Proceeds from the Securitization Bonds would also be used fund approximately $19.8 million for economic development in the four corners area. As discussed in Note 11, the NM Supreme Court granted a request by PNM to stay a January 30, 2019 NMPRC order requiring PNM’s SJGS abandonment application be filed by March 1, 2019. On June 26, 2019, the NM Supreme Court lifted the stay and denied PNM’s petition without discussion. On July 10, 2019, the NMPRC issued an order requiring the SJGS Abandonment Application be considered in two proceedings, one addressing SJGS abandonment and related financing and the other addressing replacement resources. The NMPRC indicated that PNM’s July 1, 2019 filing is responsive to the January 30, 2019 order but did not indicate if the abandonment and financing proceedings will be evaluated under the requirements of the ETA. The NMPRC’s July 10, 2019 order also extended the deadline to issue the abandonment and financing order to nine months and to issue the replacement resources order to 15 months. On July 22, 2019, Western Resource Advocates filed a motion for clarification, reconsideration, and request for oral argument with the NMPRC. The motion requested the NMPRC clarify whether it intends to evaluate the abandonment and financing proceeding under the requirements of the ETA and, in the event the NMPRC does not intend to apply the ETA to the abandonment and financing proceeding, to reconsider its decision and provide parties an opportunity to present oral argument on the matter. The NMPRC chair responded on July 24, 2019, indicating that the Hearing Examiners assigned to the proceeding would address the issue of law applicable to the approvals sought by PNM in the scheduling orders. On July 25, 2019, the Hearing Examiners issued procedural orders that set a public hearing on SJGS abandonment and related financing for December 10, 2019, a hearing on PNM’s proposed PPA replacement resources on December 2, 2019, and a hearing on the remaining replacement resources on March 2, 2020. The procedural orders also require PNM to file legal brief by August 23, 2019 regarding the extent to which the state constitution might prevent the ETA from applying to the issues in each proceeding, that parties file responses to PNM’s legal briefs by October 18, 2019, and that parties may file testimony on the merits of their claims regarding the SJGS abandonment and replacement resources if the ETA is ultimately determined to not apply to PNM’s application. On July 29, 2019, Western Resource Advocates filed a motion for interlocutory appeal of the July 24, 2019 order indicating that the procedural order will not provide parties adequate time to determine the applicability of the ETA and requesting an expedited decision from the NMPRC stating their intent to review the proceedings under the requirements of the ETA or under prior law. On August 1, 2019, the NMPRC issued a procedural order requiring responses to the interlocutory appeal by August 9, 2019. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and the related mine, as well as the overall political and economic conditions of New Mexico. PNM believes that the ETA applies to all aspects of the SJGS Abandonment Application but cannot predict the outcome of this matter. Joint Petition to Investigate PNM’s Option to Purchase Assets Underlying Certain Leases in PVNGS On April 22, 2019, NEE and other parties, which consist primarily of environmental not-for-profit organizations, filed a joint petition for expedited investigation with the NMPRC. The joint petition requested the NMPRC open an investigation regarding PNM’s option to purchase the assets underlying the PVNGS Unit 1 and 2 leases that will expire in January 2023 and 2024. Various parties filed to participate in the request. On May 8, 2019, the NMPRC issued an order requiring a response from both PNM and NMPRC staff. PNM filed responses indicating, among other things, that the joint petition should be denied and that PNM has not yet made a decision to purchase or return the assets underlying the leases that expire in January 2023 and 2024. The NMPRC has not taken action on the joint petition for investigation. PNM cannot predict the outcome of this matter. Cost Recovery Related to Joining the EIM The California Independent System Operator (“CAISO”) developed the Western Energy Imbalance Market (“EIM”) as a real-time wholesale energy trading market that enables participating electric utilities to buy and sell energy. The EIM aggregates the variability of electricity generation and load for multiple balancing authority areas and utility jurisdictions. In addition, the EIM facilitates greater integration of renewable resources through the aggregation of flexible resources by capturing diversity benefits from the expanded geographic footprint and the expanded potential uses for those resources. In 2018, PNM completed a cost-benefit analysis of participating in the EIM. PNM’s analysis indicated participation in the EIM would provide substantial benefits to retail customers. On A

Lease Commitments

Lease Commitments	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Lease Commitments	Lease Commitments The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 – Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows. Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance Sheets by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings. PVNGS PNM leases interests in Units 1 and 2 of PVNGS. The PVNGS leases were entered into in 1985 and 1986 and initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. The four Unit 1 leases now expire on January 15, 2023 and the one Unit 2 lease now expires on January 15, 2024. The annual lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2. The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements. See Note 12 for information concerning the NMPRC’s treatment of PNM’s purchase of assets underlying 64.1 MW and extension of 114.6 MW of leased capacity in PVNGS Unit 2, the NM Supreme Court’s decision regarding PNM’s appeal of certain matters in the NM 2015 Rate Case, as well as information concerning a joint petition to investigate PNM’s option to purchase additional assets underlying the extended leased capacity in PVNGS. Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors and take title to the leased interests. If such an event had occurred as of June 30, 2019 , amounts due to the lessors under the circumstances described above would be up to $161.2 million , payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid. Land Easements and Rights-of-Ways Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million , subject to adjustment each year based on the Consumer Price Index, through 2029. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million , which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments. Fleet Vehicles and Equipment As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At June 30, 2019 , residual value guarantees on fleet vehicle and equipment leases are $0.5 million , $1.1 million , and $1.6 million for PNM, TNMP, and PNMR. Other The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases. Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below: June 30, 2019 January 1, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating leases: Operating lease assets, net of amortization $ 132,057 $ 11,409 $ 143,876 $ 143,816 $ 12,942 $ 157,440 Current portion of operating lease liabilities 24,092 2,913 27,396 21,589 3,132 25,189 Long-term portion of operating lease liabilities 107,741 8,403 116,464 124,891 9,787 135,174 As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below: June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Financing leases: Non-utility property $ 2,516 $ 2,305 $ 4,821 Accumulated depreciation (143 ) (139 ) (282 ) Non-utility property, net $ 2,373 $ 2,166 $ 4,539 Other current liabilities $ 381 $ 408 $ 789 Other deferred credits 1,678 1,760 3,438 Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below: June 30, 2019 PNM TNMP PNMR Consolidated Weighted average remaining lease term (In years): Operating leases 6.75 4.49 6.55 Financing leases 5.48 5.45 5.46 Weighted average discount rate: Operating leases 3.87 % 3.90 % 3.87 % Financing leases 4.22 % 4.26 % 4.24 % Information for the components of lease expense is as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating lease cost: $ 6,803 $ 815 $ 7,692 $ 14,386 $ 1,713 $ 16,312 Less: amounts capitalized (344 ) (662 ) (1,006 ) (696 ) (1,319 ) (2,015 ) Total operating lease expense $ 6,459 $ 153 $ 6,686 $ 13,690 $ 394 $ 14,297 Financing lease cost: Amortization of right-of-use assets 77 81 158 143 139 282 Interest on lease liabilities 14 17 31 30 34 64 Less: amounts capitalized (41 ) (38 ) (79 ) (82 ) (75 ) (157 ) Total financing lease expense 50 60 110 91 98 189 Variable lease expense 32 — 32 32 — 32 Short-term lease expense 75 2 101 149 5 195 Total lease expense for the period $ 6,616 $ 215 $ 6,929 $ 13,962 $ 497 $ 14,713 Supplemental cash flow information related to the Company’s leases is as follows: Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16,704 $ 529 $ 17,494 Operating cash flows from financing leases 18 20 38 Finance cash flows from financing leases 54 76 130 Non-cash information related to right-of-use assets obtained in exchange for lease obligations: Operating leases $ 143,816 $ 12,942 $ 157,440 Financing leases 2,516 2,305 4,821 Excluded from the operating and financing cash paid for leases above are $0.7 million and $0.1 million at PNM, $1.3 million and $0.1 million at TNMP, and $2.0 million and $0.2 million at PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2019. Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below: As of June 30, 2019 PNM TNMP PNMR Consolidated Financing Operating Financing Operating Financing Operating (In thousands) Remainder of 2019 $ 281 $ 10,529 $ 305 $ 2,014 $ 586 $ 12,877 2020 470 27,033 511 2,993 982 30,543 2021 454 26,499 493 2,398 947 29,152 2022 437 26,235 475 1,846 912 28,255 2023 415 17,457 388 1,281 802 18,879 Later years 316 42,328 381 1,151 696 43,490 Total minimum lease payments 2,373 150,081 2,553 11,683 4,925 163,196 Less: Imputed interest 314 18,248 385 367 698 19,336 Lease liabilities as of June 30, 2019 $ 2,059 $ 131,833 $ 2,168 $ 11,316 $ 4,227 $ 143,860 As of December 31, 2018 Operating leases PNM TNMP PNMR Consolidated (In thousands) 2019 $ 27,691 $ 3,664 $ 31,772 2020 27,000 3,102 30,404 2021 26,462 2,324 29,012 2022 26,217 1,795 28,175 2023 17,447 1,279 18,868 Later years 42,329 1,150 43,489 Total minimum lease payments $ 167,146 $ 13,314 $ 181,720 The above tables include $8.6 million , $12.9 million , and $21.6 million for PNM, TNMP, and PNMR at June 30, 2019 and $7.5 million , $11.0 million , and $18.5 million
Lease Commitments	Lease Commitments The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 – Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows. Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance Sheets by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings. PVNGS PNM leases interests in Units 1 and 2 of PVNGS. The PVNGS leases were entered into in 1985 and 1986 and initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. The four Unit 1 leases now expire on January 15, 2023 and the one Unit 2 lease now expires on January 15, 2024. The annual lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2. The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements. See Note 12 for information concerning the NMPRC’s treatment of PNM’s purchase of assets underlying 64.1 MW and extension of 114.6 MW of leased capacity in PVNGS Unit 2, the NM Supreme Court’s decision regarding PNM’s appeal of certain matters in the NM 2015 Rate Case, as well as information concerning a joint petition to investigate PNM’s option to purchase additional assets underlying the extended leased capacity in PVNGS. Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors and take title to the leased interests. If such an event had occurred as of June 30, 2019 , amounts due to the lessors under the circumstances described above would be up to $161.2 million , payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid. Land Easements and Rights-of-Ways Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million , subject to adjustment each year based on the Consumer Price Index, through 2029. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million , which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments. Fleet Vehicles and Equipment As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At June 30, 2019 , residual value guarantees on fleet vehicle and equipment leases are $0.5 million , $1.1 million , and $1.6 million for PNM, TNMP, and PNMR. Other The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases. Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below: June 30, 2019 January 1, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating leases: Operating lease assets, net of amortization $ 132,057 $ 11,409 $ 143,876 $ 143,816 $ 12,942 $ 157,440 Current portion of operating lease liabilities 24,092 2,913 27,396 21,589 3,132 25,189 Long-term portion of operating lease liabilities 107,741 8,403 116,464 124,891 9,787 135,174 As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below: June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Financing leases: Non-utility property $ 2,516 $ 2,305 $ 4,821 Accumulated depreciation (143 ) (139 ) (282 ) Non-utility property, net $ 2,373 $ 2,166 $ 4,539 Other current liabilities $ 381 $ 408 $ 789 Other deferred credits 1,678 1,760 3,438 Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below: June 30, 2019 PNM TNMP PNMR Consolidated Weighted average remaining lease term (In years): Operating leases 6.75 4.49 6.55 Financing leases 5.48 5.45 5.46 Weighted average discount rate: Operating leases 3.87 % 3.90 % 3.87 % Financing leases 4.22 % 4.26 % 4.24 % Information for the components of lease expense is as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating lease cost: $ 6,803 $ 815 $ 7,692 $ 14,386 $ 1,713 $ 16,312 Less: amounts capitalized (344 ) (662 ) (1,006 ) (696 ) (1,319 ) (2,015 ) Total operating lease expense $ 6,459 $ 153 $ 6,686 $ 13,690 $ 394 $ 14,297 Financing lease cost: Amortization of right-of-use assets 77 81 158 143 139 282 Interest on lease liabilities 14 17 31 30 34 64 Less: amounts capitalized (41 ) (38 ) (79 ) (82 ) (75 ) (157 ) Total financing lease expense 50 60 110 91 98 189 Variable lease expense 32 — 32 32 — 32 Short-term lease expense 75 2 101 149 5 195 Total lease expense for the period $ 6,616 $ 215 $ 6,929 $ 13,962 $ 497 $ 14,713 Supplemental cash flow information related to the Company’s leases is as follows: Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16,704 $ 529 $ 17,494 Operating cash flows from financing leases 18 20 38 Finance cash flows from financing leases 54 76 130 Non-cash information related to right-of-use assets obtained in exchange for lease obligations: Operating leases $ 143,816 $ 12,942 $ 157,440 Financing leases 2,516 2,305 4,821 Excluded from the operating and financing cash paid for leases above are $0.7 million and $0.1 million at PNM, $1.3 million and $0.1 million at TNMP, and $2.0 million and $0.2 million at PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2019. Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below: As of June 30, 2019 PNM TNMP PNMR Consolidated Financing Operating Financing Operating Financing Operating (In thousands) Remainder of 2019 $ 281 $ 10,529 $ 305 $ 2,014 $ 586 $ 12,877 2020 470 27,033 511 2,993 982 30,543 2021 454 26,499 493 2,398 947 29,152 2022 437 26,235 475 1,846 912 28,255 2023 415 17,457 388 1,281 802 18,879 Later years 316 42,328 381 1,151 696 43,490 Total minimum lease payments 2,373 150,081 2,553 11,683 4,925 163,196 Less: Imputed interest 314 18,248 385 367 698 19,336 Lease liabilities as of June 30, 2019 $ 2,059 $ 131,833 $ 2,168 $ 11,316 $ 4,227 $ 143,860 As of December 31, 2018 Operating leases PNM TNMP PNMR Consolidated (In thousands) 2019 $ 27,691 $ 3,664 $ 31,772 2020 27,000 3,102 30,404 2021 26,462 2,324 29,012 2022 26,217 1,795 28,175 2023 17,447 1,279 18,868 Later years 42,329 1,150 43,489 Total minimum lease payments $ 167,146 $ 13,314 $ 181,720 The above tables include $8.6 million , $12.9 million , and $21.6 million for PNM, TNMP, and PNMR at June 30, 2019 and $7.5 million , $11.0 million , and $18.5 million

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, comprehensive changes in United States federal income taxes were enacted through legislation commonly known as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act made many significant modifications to the tax laws, including reducing the federal corporate income tax rate from 35% to 21% effective January 1, 2018. The Tax Act also eliminated federal bonus depreciation for utilities, limited interest deductibility for non-utility businesses and limited the deductibility of officer compensation. During 2018, the IRS issued additional guidance related to certain officer compensation, as well as proposed regulations on interest deductibility that provide a 10% “de minimis” exception that allows entities with predominantly regulated activities to fully deduct interest expenses. In addition, the IRS issued proposed regulations interpreting Tax Act amendments to depreciation provisions of the Internal Revenue Code that allow the Company to claim a bonus depreciation deduction on certain construction projects placed in service subsequent to the third quarter of 2017. See additional discussion of the impacts of the Tax Act in Note 18 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Beginning February 2018, PNM’s NM 2016 Rate Case reflects the reduction in the federal corporate income tax rate, including amortization of excess deferred federal income taxes that are being returned to customers over an average of twenty-three years; and reductions in the New Mexico corporate income tax rate, including amortization of excess deferred state income taxes that are being returned to customers over a three -year period. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the Tax Act beginning on January 1, 2019. See additional discussion of PNM’s NM 2016 Rate Case and TNMP’s 2018 Rate Case in Note 12. As required under GAAP, the Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. In interim periods, income tax expense is calculated by applying the anticipated annual effective tax rate to year-to-date earnings before income taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, including excess tax benefits related to stock awards, be excluded from the estimated annual effective tax rate calculation. At June 30, 2019 , PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2019 would be 8.93% , 11.20% , and 8.81% . The primary permanent difference is the reduction in income tax expense resulting from the amortization of excess deferred federal and state income taxes ordered by the NMPRC in PNM’s NM 2016 Rate Case and the amortization of excess deferred federal income taxes as ordered by the PUCT in TNMP’s 2018 Rate Case. During the three and six months ended June 30, 2019 , income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced by excess tax benefits related to stock awards of $0.1 million and $0.8 million for PNMR, of which less than $0.1 million and $0.5 million was allocated to PNM and less than $0.1 million and $0.2 million was allocated to TNMP.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions PNMR, PNM, TNMP, and NMRD are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. In addition, PNMR provides construction and operations and maintenance services to NMRD, a 50% owned subsidiary of PNMR Development (Note 1), and PNM purchases renewable energy from certain NMRD-owned facilities at a fixed price per MWh of energy produced. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD: Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Services billings: PNMR to PNM $ 22,925 $ 22,471 $ 49,751 $ 46,150 PNMR to TNMP 8,385 8,058 18,443 16,423 PNM to TNMP 114 90 189 177 TNMP to PNMR 36 35 71 70 PNMR to NMRD 54 51 95 130 Renewable energy purchases: PNM from NMRD 949 1,004 1,574 1,374 Interconnection billings: PNM to NMRD — 2,052 — 2,052 PNM to PNMR — 68,200 — 68,200 Interest billings: PNMR to PNM 972 747 1,905 809 PNM to PNMR 77 70 149 136 PNMR to TNMP 10 13 42 22 Income tax sharing payments: PNMR to PNM — — — — TNMP to PNMR — — — —

Goodwill

Goodwill	6 Months Ended
	Jun. 30, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 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. PNMR’s reporting units that currently have goodwill are PNM and TNMP. Additional information concerning the Company’s goodwill is contained in Note 19 of Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price has occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required if, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, GAAP currently requires the entity to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how a goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis. For its annual evaluations performed as of April 1, 2018, PNMR performed a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the PNM 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 the reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2018 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million , exceeded its carrying value by approximately 19% . The 2018 qualitative analysis for the TNMP reporting unit was performed by considering changes in expectations of future financial performance since the April 1, 2016 quantitative analysis that indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million , exceeded its carrying value by approximately 32% as well as by considering the results of the April 1, 2017 qualitative analysis. The 2018 analysis considered events specific to TNMP such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12. Both the PNM quantitative analysis and the TNMP qualitative analysis considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2018 carrying values of PNM or TNMP exceed their fair values. For its annual evaluations performed as of April 1, 2019, PNMR performed qualitative analyses for both the PNM and TNMP reporting units. The qualitative analysis was performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2018 quantitative analysis performed for PNM, as well as the quantitative analysis performed for TNMP at April 1, 2016 and the qualitative analyses through April 1, 2018. This analysis considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including potential outcomes in PNM’s SJGS Abandonment Application, the impacts of the NM Supreme Court’s decision in the appeal of the NM 2015 Rate Case, and other potential impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. The qualitative analysis also considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2019 carrying values of PNM or TNMP exceeded their fair values. PNMR periodically updates its quantitative analysis for both PNM and TNMP. The use of a quantitative approach in a given period in not necessarily an indication that a potential impairment has been identified under a qualitative approach. The annual evaluations performed as of April 1, 2019 and 2018 did not

Significant Accounting Polici_2

Significant Accounting Policies and Responsibility for Financial Statements (Policies)	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Principles of Consolidation	The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates Valencia (Note 6). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.
New Accounting Pronouncements	Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below. The Company does not expect difficulty in adopting these standards by their required effective dates. Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. In May 2019, the FASB issued transition relief by providing an option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. The Company is in the process of analyzing the impacts of this new standard but does not anticipate it will have a significant impact on its financial statements. Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill with its carrying value (including goodwill). If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard. Accounting Standards Update 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. Accounting Standards Update 2018-18 – Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.
Variable Interest Entities

Significant Accounting Polici_3

Significant Accounting Policies and Responsibility for Financial Statements (Tables)	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Marketable Securities	Summarized financial information for NMRD is as follows: Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In thousands) Operating revenues $ 1,103 $ 1,098 $ 1,828 $ 1,509 Operating expenses 655 657 1,451 1,006 Net earnings $ 448 $ 441 $ 377 $ 503 Financial Position June 30, December 31, 2019 2018 (In thousands) Current assets $ 2,733 $ 2,581 Net property, plant, and equipment 77,804 50,784 Total assets 80,537 53,365 Current liabilities 533 237 Owners’ equity $ 80,004 $ 53,128

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2019
Segment Reporting [Abstract]
Summary of Financial Information by Segment	The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended June 30, 2019 Electric operating revenues $ 238,219 $ 92,009 $ — $ 330,228 Cost of energy 58,866 24,916 — 83,782 Utility margin 179,353 67,093 — 246,446 Other operating expenses 255,519 24,013 (5,536 ) 273,996 Depreciation and amortization 39,811 20,502 5,752 66,065 Operating income (loss) (115,977 ) 22,578 (216 ) (93,615 ) Interest income 3,530 — (70 ) 3,460 Other income (deductions) 4,179 731 (78 ) 4,832 Interest charges (18,526 ) (6,560 ) (4,705 ) (29,791 ) Segment earnings (loss) before income taxes (126,794 ) 16,749 (5,069 ) (115,114 ) Income taxes (benefit) (43,481 ) 1,482 (832 ) (42,831 ) Segment earnings (loss) (83,313 ) 15,267 (4,237 ) (72,283 ) Valencia non-controlling interest (3,499 ) — — (3,499 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ (86,944 ) $ 15,267 $ (4,237 ) $ (75,914 ) Six Months Ended June 30, 2019 Electric operating revenues $ 507,536 $ 172,336 $ — $ 679,872 Cost of energy 158,204 47,204 — 205,408 Utility margin 349,332 125,132 — 474,464 Other operating expenses 361,981 49,253 (11,299 ) 399,935 Depreciation and amortization 79,036 40,716 11,669 131,421 Operating income (loss) (91,685 ) 35,163 (370 ) (56,892 ) Interest income 7,187 — (139 ) 7,048 Other income (deductions) 18,536 1,317 (814 ) 19,039 Interest charges (36,886 ) (15,361 ) (9,178 ) (61,425 ) Segment earnings (loss) before income taxes (102,848 ) 21,119 (10,501 ) (92,230 ) Income taxes (benefit) (41,508 ) 1,754 (1,854 ) (41,608 ) Segment earnings (loss) (61,340 ) 19,365 (8,647 ) (50,622 ) Valencia non-controlling interest (6,328 ) — — (6,328 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ (67,932 ) $ 19,365 $ (8,647 ) $ (57,214 ) At June 30, 2019: Total Assets $ 5,105,090 $ 1,768,831 $ 174,746 $ 7,048,667 Goodwill $ 51,632 $ 226,665 $ — $ 278,297 PNM TNMP Corporate and Other PNMR Consolidated (In thousands) Three Months Ended June 30, 2018 Electric operating revenues $ 264,511 $ 87,802 $ — $ 352,313 Cost of energy 66,361 21,350 — 87,711 Utility margin 198,150 66,452 — 264,602 Other operating expenses 107,058 23,510 (5,358 ) 125,210 Depreciation and amortization 38,213 16,113 5,737 60,063 Operating income (loss) 52,879 26,829 (379 ) 79,329 Interest income 3,381 — 958 4,339 Other income (deductions) (3,146 ) 832 (428 ) (2,742 ) Interest charges (19,988 ) (7,801 ) (5,532 ) (33,321 ) Segment earnings (loss) before income taxes 33,126 19,860 (5,381 ) 47,605 Income taxes (benefit) 2,345 4,493 (1,682 ) 5,156 Segment earnings (loss) 30,781 15,367 (3,699 ) 42,449 Valencia non-controlling interest (4,109 ) — — (4,109 ) Subsidiary preferred stock dividends (132 ) — — (132 ) Segment earnings (loss) attributable to PNMR $ 26,540 $ 15,367 $ (3,699 ) $ 38,208 Three Months Ended June 30, 2018 Electric operating revenues $ 500,742 $ 169,449 $ — $ 670,191 Cost of energy 137,163 43,104 — 180,267 Utility margin 363,579 126,345 — 489,924 Other operating expenses 207,569 48,484 (10,375 ) 245,678 Depreciation and amortization 74,840 32,500 11,445 118,785 Operating income (loss) 81,170 45,361 (1,070 ) 125,461 Interest income 5,868 — 2,594 8,462 Other income (deductions) (1,927 ) 1,916 (349 ) (360 ) Interest charges (40,818 ) (15,530 ) (10,028 ) (66,376 ) Segment earnings (loss) before income taxes 44,293 31,747 (8,853 ) 67,187 Income taxes (benefit) 1,997 6,968 (3,026 ) 5,939 Segment earnings (loss) 42,296 24,779 (5,827 ) 61,248 Valencia non-controlling interest (7,786 ) — — (7,786 ) Subsidiary preferred stock dividends (264 ) — — (264 ) Segment earnings (loss) attributable to PNMR $ 34,246 $ 24,779 $ (5,827 ) $ 53,198 At June 30, 2018: Total Assets $ 4,994,277 $ 1,583,311 $ 172,501 $ 6,750,089 Goodwill $ 51,632 $ 226,665 $ — $ 278,297

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	6 Months Ended
	Jun. 30, 2019
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2019 and 2018 is as follows: Accumulated Other Comprehensive Income (Loss) PNM PNMR Unrealized Fair Value Gains on Adjustment Available-for- Pension for Cash Sale Liability Flow Securities Adjustment Total Hedges Total (In thousands) Balance at December 31, 2018 $ 1,939 $ (112,361 ) $ (110,422 ) $ 1,738 $ (108,684 ) Amounts reclassified from AOCI (pre-tax) (5,601 ) 3,702 (1,899 ) 525 (1,374 ) Income tax impact of amounts reclassified 1,423 (940 ) 483 (133 ) 350 Other OCI changes (pre-tax) 15,938 — 15,938 (3,169 ) 12,769 Income tax impact of other OCI changes (4,048 ) — (4,048 ) 805 (3,243 ) Net after-tax change 7,712 2,762 10,474 (1,972 ) 8,502 Balance at June 30, 2019 $ 9,651 $ (109,599 ) $ (99,948 ) $ (234 ) $ (100,182 ) Balance at December 31, 2017, as originally reported $ 13,169 $ (110,262 ) $ (97,093 ) $ 1,153 $ (95,940 ) Cumulative effect adjustment (Note 7) (11,208 ) — (11,208 ) — (11,208 ) Balance at January 1, 2018, as adjusted 1,961 (110,262 ) (108,301 ) 1,153 (107,148 ) Amounts reclassified from AOCI (pre-tax) (3,126 ) 3,788 662 (7 ) 655 Income tax impact of amounts reclassified 794 (962 ) (168 ) 1 (167 ) Other OCI changes (pre-tax) 1,472 — 1,472 2,420 3,892 Income tax impact of other OCI changes (374 ) — (374 ) (615 ) (989 ) Net after-tax change (1,234 ) 2,826 1,592 1,799 3,391 Balance at June 30, 2018 $ 727 $ (107,436 ) $ (106,709 ) $ 2,952 $ (103,757 )

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2019
Earnings Per Share [Abstract]
Computation of Earnings Per Share	Information regarding the computation of earnings per share is as follows: Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands, except per share amounts) Net Earnings (Loss) Attributable to PNMR $ (75,914 ) $ 38,208 $ (57,214 ) $ 53,198 Average Number of Common Shares: Outstanding during period 79,654 79,654 79,654 79,654 Vested awards of restricted stock 263 211 251 208 Average Shares – Basic 79,917 79,865 79,905 79,862 Dilutive Effect of Common Stock Equivalents: (1) Stock options and restricted stock — 114 — 134 Average Shares – Diluted 79,917 79,979 79,905 79,996 Net Earnings (Loss) Per Share of Common Stock: Basic $ (0.95 ) $ 0.48 $ (0.72 ) $ 0.67 Diluted (1) $ (0.95 ) $ 0.48 $ (0.72 ) $ 0.67 (1) Due to the loss in the three and six months ended June 30, 2019, no potentially dilutive shares are reflected in the average number of shares used to compute net earnings (loss) per share of common stock since any impact would be anti-dilutive. At June 30, 2019, PNMR’s potentially dilutive shares consist of stock options and restricted stock (see Note 8).

Electric Operating Revenues (Ta

Electric Operating Revenues (Tables)	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues. PNM TNMP PNMR Consolidated Three Months Ended June 30, 2019 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 86,328 $ 33,640 $ 119,968 Commercial 98,968 28,058 127,026 Industrial 15,329 5,295 20,624 Public authority 4,596 1,391 5,987 Economy energy service 6,024 — 6,024 Transmission 14,342 17,585 31,927 Miscellaneous 2,474 887 3,361 Total revenues from contracts with customers 228,061 86,856 314,917 Alternative revenue programs 691 5,153 5,844 Other electric operating revenues 9,467 — 9,467 Total Electric Operating Revenues $ 238,219 $ 92,009 $ 330,228 PNM TNMP PNMR Consolidated Six Months Ended June 30, 2019 (In thousands) Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 193,629 $ 64,072 $ 257,701 Commercial 184,201 55,487 239,688 Industrial 30,076 10,911 40,987 Public authority 9,307 2,764 12,071 Economy energy service 12,946 — 12,946 Transmission 27,727 31,589 59,316 Miscellaneous 6,116 1,789 7,905 Total revenues from contracts with customers 464,002 166,612 630,614 Alternative revenue programs 756 5,724 6,480 Other electric operating revenues 42,778 — 42,778 Total Electric Operating Revenues $ 507,536 $ 172,336 $ 679,872 Three Months Ended June 30, 2018 Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 99,508 $ 31,315 $ 130,823 Commercial 110,652 28,082 138,734 Industrial 14,597 4,184 18,781 Public authority 5,220 1,399 6,619 Economy energy service 6,378 — 6,378 Transmission 14,108 16,743 30,851 Miscellaneous 4,265 2,208 6,473 Total revenues from contracts with customers 254,728 83,931 338,659 Alternative revenue programs 1,789 3,871 5,660 Other electric operating revenues 7,994 — 7,994 Total Electric Operating Revenues $ 264,511 $ 87,802 $ 352,313 Six Months Ended June 30, 2018 Electric Operating Revenues: Contracts with customers: Retail electric revenue Residential $ 196,676 $ 60,581 $ 257,257 Commercial 193,501 55,234 248,735 Industrial 28,056 8,489 36,545 Public authority 9,855 2,815 12,670 Economy energy service 13,666 — 13,666 Transmission 26,590 33,251 59,841 Miscellaneous 8,947 4,349 13,296 Total revenues from contracts with customers 477,291 164,719 642,010 Alternative revenue programs 1,854 4,730 6,584 Other electric operating revenues 21,597 — 21,597 Total Electric Operating Revenues $ 500,742 $ 169,449 $ 670,191
Contract with Customer, Asset and Liability	Changes during the period in the balances of contract liabilities, which are included in other current liabilities on the Condensed Consolidated Balance Sheets, are as follows: PNM TNMP PNMR Consolidated (In thousands) Balance at December 31, 2018 $ 349 $ — $ 349 Consideration received in advance of service to be provided 4,157 1,517 5,674 Deferred revenue earned (2,259 ) (776 ) (3,035 ) Balance at June 30, 2019 $ 2,247 $ 741 $ 2,988

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2019
Variable Interest Entities [Abstract]
Summarized Financial Information	Summarized financial information for Valencia is as follows: Results of Operations Three Months Ended June 30, Six Months Ended June 30, 2019 2018 2019 2018 (In thousands) Operating revenues $ 5,177 $ 5,911 $ 10,129 $ 10,679 Operating expenses 1,678 1,802 3,801 2,893 Earnings attributable to non-controlling interest $ 3,499 $ 4,109 $ 6,328 $ 7,786 Financial Position June 30, December 31, 2019 2018 (In thousands) Current assets $ 3,174 $ 2,684 Net property, plant, and equipment 60,003 62,066 Total assets 63,177 64,750 Current liabilities 585 538 Owners’ equity – non-controlling interest $ 62,592 $ 64,212

Fair Value of Derivative and _2

Fair Value of Derivative and Other Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value of Derivative and Other Financial Instruments [Abstract]
Summary of Derivatives	PNM’s commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are presented in the following line items on the Condensed Consolidated Balance Sheets: Economic Hedges June 30, December 31, (In thousands) Other current assets $ 1,164 $ 1,083 Other deferred charges 2,028 2,511 3,192 3,594 Other current liabilities (1,142 ) (1,177 ) Other deferred credits (2,028 ) (2,511 ) (3,170 ) (3,688 ) Net $ 22 $ (94 )
Effect of Mark-to-Market on Earnings, Excluding Tax Effects	The effects of mark-to-market commodity derivative instruments on PNM’s revenues and cost of energy during the three and six months ended June 30, 2019 and 2018 were less than $0.1 million . Commodity derivatives had no impact on OCI for the periods presented.
Schedule of Net Buy (Sell) Volume Positions	The table below presents PNM’s net buy (sell) volume positions: Economic Hedges MMBTU MWh June 30, 2019 565,000 (42,000 ) December 31, 2018 100,000 —
Schedule of Gross Realized Gains and Losses	Gains and losses recognized on the Condensed Consolidated Statements of Earnings related to investment securities in the NDT and reclamation trusts are presented in the following table. Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Equity securities: Net gains from equity securities sold $ 2,774 $ 2,502 $ 4,161 $ 5,330 Net gains (losses) from equity securities still held 303 (443 ) 9,905 (307 ) Total net gains on equity securities 3,077 2,059 14,066 5,023 Available-for-sale debt securities: Net gains (losses) on debt securities 1,522 (3,729 ) 4,547 (6,405 ) Net gains (losses) on investment securities $ 4,599 $ (1,670 ) $ 18,613 $ (1,382 ) The proceeds and gross realized gains and losses on the disposition of securities held in the NDT and coal mine reclamation trusts are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the (increase)/decrease in realized impairment losses of $ (0.8) million and $2.6 for the three and six months ended June 30, 2019 and $(2.6) million and $(3.8) million for the three and six months ended June 30, 2018. Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Proceeds from sales $ 159,551 $ 167,359 $ 234,011 $ 794,088 Gross realized gains $ 10,906 $ 7,549 $ 15,095 $ 13,570 Gross realized (losses) $ (5,802 ) $ (6,192 ) $ (8,972 ) $ (10,869 )
Investments Classified by Contractual Maturity Date	At June 30, 2019 , the available-for-sale debt securities held by PNM, had the following final maturities: Fair Value (In thousands) Within 1 year $ 20,868 After 1 year through 5 years 75,642 After 5 years through 10 years 67,572 After 10 years through 15 years 12,886 After 15 years through 20 years 11,747 After 20 years 34,246 $ 222,961
Schedule of Investments	Items recorded at fair value by PNM on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy along with gross unrealized gains on investments in available-for-sale debt securities. GAAP Fair Value Hierarchy Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) June 30, 2019 Cash and cash equivalents $ 11,055 $ 11,055 $ — $ — Equity securities: Corporate stocks, common 38,391 38,391 — — Corporate stocks, preferred 8,788 2,207 6,581 — Mutual funds and other 81,598 81,558 40 — Available-for-sale debt securities: U.S. Government 35,664 21,971 13,693 — $ 888 International Government 13,582 31 13,551 — 827 Municipals 46,633 — 46,633 — 1,886 Corporate and other 127,082 1,304 122,969 2,809 9,342 $ 362,793 $ 156,517 $ 203,467 $ 2,809 $ 12,943 Commodity derivative assets $ 3,192 $ — $ 3,192 $ — Commodity derivative liabilities (3,170 ) — (3,170 ) — Net $ 22 $ — $ 22 $ — Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Unrealized Gains (In thousands) December 31, 2018 Cash and cash equivalents $ 11,472 $ 11,472 $ — $ — Equity securities: Corporate stocks, common 32,997 32,997 — — Corporate stocks, preferred 7,258 1,654 5,604 — Mutual funds and other 70,777 70,777 — — Available-for-sale debt securities: U.S. Government 29,503 18,662 10,841 — $ 1,098 International Government 8,435 — 8,435 — 90 Municipals 53,642 — 53,642 — 489 Corporate and other 114,158 588 111,414 2,156 923 $ 328,242 $ 136,150 $ 189,936 $ 2,156 $ 2,600 Commodity derivative assets $ 3,594 $ — $ 3,594 $ — Commodity derivative liabilities (3,688 ) — (3,688 ) — Net $ (94 ) $ — $ (94 ) $ —
Summary of Level 3 Measurements	A reconciliation of the changes in Level 3 fair value measurements is as follows: Corporate Debt (In thousands) Balance at December 31, 2018 $ 2,156 Actual return on assets sold during the period (48 ) Actual return on assets still held at period end 63 Purchases 1,422 Sales (784 ) Balance at June 30, 2019 $ 2,809 Balance at December 31, 2017 $ — Actual return on assets sold during the period (4 ) Actual return on assets still held at period end (5 ) Purchases 4,011 Sales (1,011 ) Balance at June 30, 2018 $ 2,991
Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value	The carrying amounts and fair values of long-term debt, which is not recorded at fair value on the Condensed Consolidated Balance Sheets, are presented below: GAAP Fair Value Hierarchy Carrying Amount Fair Value Level 1 Level 2 Level 3 June 30, 2019 (In thousands) PNMR $ 2,772,342 $ 2,903,711 $ — $ 2,903,711 $ — PNM $ 1,707,256 $ 1,768,943 $ — $ 1,768,943 $ — TNMP $ 626,456 $ 692,728 $ — $ 692,728 $ — December 31, 2018 PNMR $ 2,670,111 $ 2,703,810 $ — $ 2,703,810 $ — PNM $ 1,656,490 $ 1,668,736 $ — $ 1,668,736 $ — TNMP $ 575,398 $ 597,236 $ — $ 597,236 $ —

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Summary of Activity	The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value: Six Months Ended June 30, Restricted Shares and Performance Based Shares 2019 2018 Expected quarterly dividends per share $ 0.290 $ 0.265 Risk-free interest rate 2.47 % 2.38 % Market-Based Shares Dividend yield 2.59 % 2.96 % Expected volatility 19.55 % 19.12 % Risk-free interest rate 2.51 % 2.36 % The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options, for the six months ended June 30, 2019 : Restricted Stock Stock Options Shares Weighted- Average Grant Date Fair Value Shares Weighted- Average Exercise Price Outstanding at December 31, 2018 166,651 $ 32.93 81,000 $ 11.94 Granted 134,573 37.92 — — Exercised (137,601 ) 31.44 (79,000 ) 11.93 Forfeited — — — — Expired — — — — Outstanding at June 30, 2019 163,623 $ 38.19 2,000 $ 12.22 The following table provides additional information concerning restricted stock activity, including performance-based and market-based shares, and stock options: Six Months Ended June 30, Restricted Stock 2019 2018 Weighted-average grant date fair value $ 37.92 $ 29.65 Total fair value of restricted shares that vested (in thousands) $ 6,227 $ 8,328 Stock Options Weighted-average grant date fair value of options granted $ — $ — Total fair value of options that vested (in thousands) $ — $ — Total intrinsic value of options exercised (in thousands) $ 2,617 $ 2,968

Financing (Tables)

Financing (Tables)	6 Months Ended
	Jun. 30, 2019
Debt Disclosure [Abstract]
Schedule of Maturities of Long-term Debt	Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds is as follows: Funding Date Maturity Date Principal Amount Interest Rate (In millions) March 29, 2019 March 29, 2034 $ 75.0 3.79 % March 29, 2019 March 29, 2039 75.0 3.92 % March 29, 2019 March 29, 2044 75.0 4.06 % 225.0 July 1, 2019 July 1, 2029 80.0 3.60 % $ 305.0
Schedule of Short-term Debt	Short-term debt outstanding consisted of: June 30, December 31, Short-term Debt 2019 2018 (In thousands) PNM: PNM Revolving Credit Facility $ 27,200 $ 32,400 PNM 2017 New Mexico Credit Facility 15,000 10,000 42,200 42,400 TNMP Revolving Credit Facility 55,000 17,500 PNMR: PNMR Revolving Credit Facility 73,300 20,000 PNMR 2018 One-Year Term Loan 150,000 150,000 PNMR Development Revolving Credit Facility 21,900 6,000 $ 342,400 $ 235,900

Pension and Other Postretirem_2

Pension and Other Postretirement Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2019
Retirement Benefits [Abstract]
Schedule of Net Benefit Costs	The following table presents the components of the TNMP Plans’ net periodic benefit cost: Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 13 $ 33 $ — $ — Interest cost 672 656 113 119 8 7 Expected return on plan assets (967 ) (991 ) (129 ) (135 ) — — Amortization of net (gain) loss 235 272 (110 ) (56 ) 4 4 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost (Income) $ (60 ) $ (63 ) $ (113 ) $ (39 ) $ 12 $ 11 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 26 $ 67 $ — $ — Interest cost 1,344 1,312 226 238 16 15 Expected return on plan assets (1,934 ) (1,981 ) (258 ) (271 ) — — Amortization of net (gain) loss 470 544 (220 ) (113 ) 8 8 Amortization of prior service cost — — — — — — Net Periodic Benefit Cost (Income) $ (120 ) $ (125 ) $ (226 ) $ (79 ) $ 24 $ 23 The following table presents the components of the PNM Plans’ net periodic benefit cost: Three Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 13 $ 21 $ — $ — Interest cost 6,294 6,068 829 860 162 155 Expected return on plan assets (8,527 ) (8,672 ) (1,318 ) (1,353 ) — — Amortization of net (gain) loss 3,880 4,087 169 588 79 90 Amortization of prior service cost (241 ) (241 ) (99 ) (416 ) — — Net Periodic Benefit Cost $ 1,406 $ 1,242 $ (406 ) $ (300 ) $ 241 $ 245 Six Months Ended June 30, Pension Plan OPEB Plan Executive Retirement Program 2019 2018 2019 2018 2019 2018 (In thousands) Components of Net Periodic Benefit Cost Service cost $ — $ — $ 26 $ 41 $ — $ — Interest cost 12,587 12,135 1,658 1,720 324 311 Expected return on plan assets (17,051 ) (17,343 ) (2,636 ) (2,707 ) — — Amortization of net (gain) loss 7,759 8,174 338 1,177 158 179 Amortization of prior service cost (483 ) (483 ) (198 ) (832 ) — — Net Periodic Benefit Cost $ 2,812 $ 2,483 $ (812 ) $ (601 ) $ 482 $ 490

Regulatory and Rate Matters (Ta

Regulatory and Rate Matters (Tables)	6 Months Ended
	Jun. 30, 2019
Regulated Operations [Abstract]
Schedule of Rate Increases for Transmission Costs	The following sets forth TNMP’s recent interim transmission cost rate increases: Effective Date Approved Increase in Rate Base Annual Increase in Revenue (In millions) March 14, 2017 30.2 4.8 September 13, 2017 27.5 4.7 March 27, 2018 32.0 0.6 March 21, 2019 111.8 14.3

Lease Commitments (Tables)

Lease Commitments (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Assets and Liabilities, Lessee	Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below: June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Financing leases: Non-utility property $ 2,516 $ 2,305 $ 4,821 Accumulated depreciation (143 ) (139 ) (282 ) Non-utility property, net $ 2,373 $ 2,166 $ 4,539 Other current liabilities $ 381 $ 408 $ 789 Other deferred credits 1,678 1,760 3,438 Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below: June 30, 2019 PNM TNMP PNMR Consolidated Weighted average remaining lease term (In years): Operating leases 6.75 4.49 6.55 Financing leases 5.48 5.45 5.46 Weighted average discount rate: Operating leases 3.87 % 3.90 % 3.87 % Financing leases 4.22 % 4.26 % 4.24 % Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below: June 30, 2019 January 1, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating leases: Operating lease assets, net of amortization $ 132,057 $ 11,409 $ 143,876 $ 143,816 $ 12,942 $ 157,440 Current portion of operating lease liabilities 24,092 2,913 27,396 21,589 3,132 25,189 Long-term portion of operating lease liabilities 107,741 8,403 116,464 124,891 9,787 135,174
Lease, Cost	Information for the components of lease expense is as follows: Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated PNM TNMP PNMR Consolidated (In thousands) Operating lease cost: $ 6,803 $ 815 $ 7,692 $ 14,386 $ 1,713 $ 16,312 Less: amounts capitalized (344 ) (662 ) (1,006 ) (696 ) (1,319 ) (2,015 ) Total operating lease expense $ 6,459 $ 153 $ 6,686 $ 13,690 $ 394 $ 14,297 Financing lease cost: Amortization of right-of-use assets 77 81 158 143 139 282 Interest on lease liabilities 14 17 31 30 34 64 Less: amounts capitalized (41 ) (38 ) (79 ) (82 ) (75 ) (157 ) Total financing lease expense 50 60 110 91 98 189 Variable lease expense 32 — 32 32 — 32 Short-term lease expense 75 2 101 149 5 195 Total lease expense for the period $ 6,616 $ 215 $ 6,929 $ 13,962 $ 497 $ 14,713
Schedule of Leases, Supplemental Cash Flows	Supplemental cash flow information related to the Company’s leases is as follows: Six Months Ended June 30, 2019 PNM TNMP PNMR Consolidated (In thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16,704 $ 529 $ 17,494 Operating cash flows from financing leases 18 20 38 Finance cash flows from financing leases 54 76 130 Non-cash information related to right-of-use assets obtained in exchange for lease obligations: Operating leases $ 143,816 $ 12,942 $ 157,440 Financing leases 2,516 2,305 4,821
Lessee, Operating Lease, Liability, Maturity	Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below: As of June 30, 2019 PNM TNMP PNMR Consolidated Financing Operating Financing Operating Financing Operating (In thousands) Remainder of 2019 $ 281 $ 10,529 $ 305 $ 2,014 $ 586 $ 12,877 2020 470 27,033 511 2,993 982 30,543 2021 454 26,499 493 2,398 947 29,152 2022 437 26,235 475 1,846 912 28,255 2023 415 17,457 388 1,281 802 18,879 Later years 316 42,328 381 1,151 696 43,490 Total minimum lease payments 2,373 150,081 2,553 11,683 4,925 163,196 Less: Imputed interest 314 18,248 385 367 698 19,336 Lease liabilities as of June 30, 2019 $ 2,059 $ 131,833 $ 2,168 $ 11,316 $ 4,227 $ 143,860
Finance Lease, Liability, Maturity	Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below: As of June 30, 2019 PNM TNMP PNMR Consolidated Financing Operating Financing Operating Financing Operating (In thousands) Remainder of 2019 $ 281 $ 10,529 $ 305 $ 2,014 $ 586 $ 12,877 2020 470 27,033 511 2,993 982 30,543 2021 454 26,499 493 2,398 947 29,152 2022 437 26,235 475 1,846 912 28,255 2023 415 17,457 388 1,281 802 18,879 Later years 316 42,328 381 1,151 696 43,490 Total minimum lease payments 2,373 150,081 2,553 11,683 4,925 163,196 Less: Imputed interest 314 18,248 385 367 698 19,336 Lease liabilities as of June 30, 2019 $ 2,059 $ 131,833 $ 2,168 $ 11,316 $ 4,227 $ 143,860
Schedule of Future Minimum Rental Payments for Operating Leases	As of December 31, 2018 Operating leases PNM TNMP PNMR Consolidated (In thousands) 2019 $ 27,691 $ 3,664 $ 31,772 2020 27,000 3,102 30,404 2021 26,462 2,324 29,012 2022 26,217 1,795 28,175 2023 17,447 1,279 18,868 Later years 42,329 1,150 43,489 Total minimum lease payments $ 167,146 $ 13,314 $ 181,720

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2019
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD: Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 (In thousands) Services billings: PNMR to PNM $ 22,925 $ 22,471 $ 49,751 $ 46,150 PNMR to TNMP 8,385 8,058 18,443 16,423 PNM to TNMP 114 90 189 177 TNMP to PNMR 36 35 71 70 PNMR to NMRD 54 51 95 130 Renewable energy purchases: PNM from NMRD 949 1,004 1,574 1,374 Interconnection billings: PNM to NMRD — 2,052 — 2,052 PNM to PNMR — 68,200 — 68,200 Interest billings: PNMR to PNM 972 747 1,905 809 PNM to PNMR 77 70 149 136 PNMR to TNMP 10 13 42 22 Income tax sharing payments: PNMR to PNM — — — — TNMP to PNMR — — — —

Significant Accounting Polici_4

Significant Accounting Policies and Responsibility for Financial Statements (Details)	Jul. 22, 2019USD ($)	Jul. 31, 2019$ / sharesMW	Jul. 31, 2018$ / shares	Jun. 30, 2019USD ($)$ / sharesMW	Jun. 30, 2018USD ($)$ / shares	Jun. 30, 2019USD ($)$ / sharesMW	Jun. 30, 2018USD ($)$ / shares	Sep. 05, 2017MW
Business Acquisition [Line Items]
Payment defaults under agreements				$ 0		$ 0
Dividends declared per common share (dollars per share) | $ / shares			$ 0.265	$ 0.290	$ 0.265	$ 0.580	$ 0.530
Dividends declared on common stock						$ 23,099,000	$ 21,108,000
NMRD
Business Acquisition [Line Items]
Renewable energy capacity in operating (in mw) | MW				33.9		33.9
Texas-New Mexico Power Company
Business Acquisition [Line Items]
Dividends declared on common stock				$ 4,098,000	$ 9,413,000	$ 14,811,000	10,436,000
PNMR Development
Business Acquisition [Line Items]
Solar generation capacity (in megawatts) | MW				30		30		50
PNMR Development | NMRD
Business Acquisition [Line Items]
Ownership percentage				50.00%		50.00%
AEP OnSite Partners | NMRD
Business Acquisition [Line Items]
Ownership percentage				50.00%		50.00%
PNMR Development and AEP OnSite | NMRD
Business Acquisition [Line Items]
Contribution to construction activities						$ 13,300,000	$ 8,000,000
Subsequent event
Business Acquisition [Line Items]
Dividends declared per common share (dollars per share) | $ / shares		$ 0.290
Subsequent event | PNMR Development
Business Acquisition [Line Items]
Solar generation capacity (in megawatts) | MW		1.2
Subsequent event | PNMR Development and AEP OnSite | NMRD
Business Acquisition [Line Items]
Contribution to construction activities	$ 11,000,000

Significant Accounting Polici_5

Significant Accounting Policies and Responsibility for Financial Statements Summarized Financial Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Results of Operations
Operating revenues	$ 330,228	$ 352,313	$ 679,872	$ 670,191
Financial Position
Net property, plant, and equipment	202,991		202,991		$ 194,427
Total assets	7,048,667	6,750,089	7,048,667	6,750,089	6,865,551
Owners’ equity	(1,612,148)		(1,612,148)		(1,688,382)
NMRD
Results of Operations
Operating revenues	1,103	1,098	1,828	1,509
Operating expenses	655	657	1,451	1,006
Net Earnings (Loss) Attributable to PNMR	448	$ 441	377	$ 503
Financial Position
Current assets	2,733		2,733		2,581
Net property, plant, and equipment	77,804		77,804		50,784
Total assets	80,537		80,537		53,365
Current liabilities	533		533		237
Owners’ equity	$ 80,004		$ 80,004		$ 53,128

Segment Information - Summarize

Segment Information - Summarized Financial Information (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)segment	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Segment Reporting Information [Line Items]
Number of operating segments | segment			1
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	$ 330,228	$ 352,313	$ 679,872	$ 670,191
Utility margin	246,446	264,602	474,464	489,924
Other operating expenses	273,996	125,210	399,935	245,678
Depreciation and amortization	66,065	60,063	131,421	118,785
Operating income (loss)	(93,615)	79,329	(56,892)	125,461
Interest income	3,460	4,339	7,048	8,462
Other income (deductions)	4,832	(2,742)	19,039	(360)
Interest charges	(29,791)	(33,321)	(61,425)	(66,376)
Earnings (Loss) before Income Taxes	(115,114)	47,605	(92,230)	67,187
Income taxes (benefit)	(42,831)	5,156	(41,608)	5,939
Net Earnings (Loss)	(72,283)	42,449	(50,622)	61,248
Valencia non-controlling interest	(3,499)	(4,109)	(6,328)	(7,786)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings (Loss) Available for PNM Common Stock	(75,914)	38,208	(57,214)	53,198
Total Assets	7,048,667	6,750,089	7,048,667	6,750,089	$ 6,865,551
Goodwill	278,297	278,297	278,297	278,297	$ 278,297
PNM
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	179,353	198,150	349,332	363,579
Other operating expenses	255,519	107,058	361,981	207,569
Depreciation and amortization	39,811	38,213	79,036	74,840
Operating income (loss)	(115,977)	52,879	(91,685)	81,170
Interest income	3,530	3,381	7,187	5,868
Other income (deductions)	4,179	(3,146)	18,536	(1,927)
Interest charges	(18,526)	(19,988)	(36,886)	(40,818)
Earnings (Loss) before Income Taxes	(126,794)	33,126	(102,848)	44,293
Income taxes (benefit)	(43,481)	2,345	(41,508)	1,997
Net Earnings (Loss)	(83,313)	30,781	(61,340)	42,296
Valencia non-controlling interest	(3,499)	(4,109)	(6,328)	(7,786)
Subsidiary preferred stock dividends	(132)	(132)	(264)	(264)
Net Earnings (Loss) Available for PNM Common Stock	(86,944)	26,540	(67,932)	34,246
Total Assets	5,105,090	4,994,277	5,105,090	4,994,277
Goodwill	51,632	51,632	51,632	51,632
TNMP
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	67,093	66,452	125,132	126,345
Other operating expenses	24,013	23,510	49,253	48,484
Depreciation and amortization	20,502	16,113	40,716	32,500
Operating income (loss)	22,578	26,829	35,163	45,361
Interest income	0	0	0	0
Other income (deductions)	731	832	1,317	1,916
Interest charges	(6,560)	(7,801)	(15,361)	(15,530)
Earnings (Loss) before Income Taxes	16,749	19,860	21,119	31,747
Income taxes (benefit)	1,482	4,493	1,754	6,968
Net Earnings (Loss)	15,267	15,367	19,365	24,779
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings (Loss) Available for PNM Common Stock	15,267	15,367	19,365	24,779
Total Assets	1,768,831	1,583,311	1,768,831	1,583,311
Goodwill	226,665	226,665	226,665	226,665
Corporate and Other
Segment Reporting Information, Profit (Loss) [Abstract]
Utility margin	0	0	0	0
Other operating expenses	(5,536)	(5,358)	(11,299)	(10,375)
Depreciation and amortization	5,752	5,737	11,669	11,445
Operating income (loss)	(216)	(379)	(370)	(1,070)
Interest income	(70)	958	(139)	2,594
Other income (deductions)	(78)	(428)	(814)	(349)
Interest charges	(4,705)	(5,532)	(9,178)	(10,028)
Earnings (Loss) before Income Taxes	(5,069)	(5,381)	(10,501)	(8,853)
Income taxes (benefit)	(832)	(1,682)	(1,854)	(3,026)
Net Earnings (Loss)	(4,237)	(3,699)	(8,647)	(5,827)
Valencia non-controlling interest	0	0	0	0
Subsidiary preferred stock dividends	0	0	0	0
Net Earnings (Loss) Available for PNM Common Stock	(4,237)	(3,699)	(8,647)	(5,827)
Total Assets	174,746	172,501	174,746	172,501
Goodwill	0	0	0	0
Cost of energy
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	330,228	352,313	679,872	670,191
Cost of energy	83,782	87,711	205,408	180,267
Cost of energy | PNM
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	238,219	264,511	507,536	500,742
Cost of energy	58,866	66,361	158,204	137,163
Cost of energy | TNMP
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	92,009	87,802	172,336	169,449
Cost of energy	24,916	21,350	47,204	43,104
Cost of energy | Corporate and Other
Segment Reporting Information, Profit (Loss) [Abstract]
Electric operating revenues	0	0	0	0
Cost of energy	$ 0	$ 0	$ 0	$ 0

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ 1,747,458	$ 1,749,014	$ 1,752,594	$ 1,761,448
Balance, as adjusted					$ 1,761,448
Amounts reclassified from AOCI (pre-tax)			(1,374)	655
Income tax impact of amounts reclassified			350	(167)
Other OCI changes (pre-tax)			12,769	3,892
Income tax impact of other OCI changes			(3,243)	(989)
Total Other Comprehensive Income	3,057	1,763	8,502	3,391
Ending balance	1,674,740	1,788,315	1,674,740	1,788,315
Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(103,239)	(105,520)	(108,684)	(95,940)
Cumulative effect adjustment (Note 7)					(11,208)
Balance, as adjusted					(107,148)
Total Other Comprehensive Income	3,057	1,763	8,502	3,391
Ending balance	(100,182)	(103,757)	(100,182)	(103,757)
Fair Value Adjustment for Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance			1,738
Amounts reclassified from AOCI (pre-tax)			525
Income tax impact of amounts reclassified			(133)
Other OCI changes (pre-tax)			(3,169)
Income tax impact of other OCI changes			805
Total Other Comprehensive Income			(1,972)
Ending balance	(234)		(234)
Fair Value Adjustment for Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance				1,153
Balance, as adjusted					1,153
Amounts reclassified from AOCI (pre-tax)				(7)
Income tax impact of amounts reclassified				1
Other OCI changes (pre-tax)				2,420
Income tax impact of other OCI changes				(615)
Total Other Comprehensive Income				1,799
Ending balance		2,952		2,952
PNM
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	1,485,307	1,495,561	1,461,571	1,488,369
Balance, as adjusted					1,488,369
Amounts reclassified from AOCI (pre-tax)			(1,899)	662
Income tax impact of amounts reclassified			483	(168)
Other OCI changes (pre-tax)			15,938	1,472
Income tax impact of other OCI changes			(4,048)	(374)
Total Other Comprehensive Income	4,317	1,310	10,474	1,592
Ending balance	1,402,493	1,523,612	1,402,493	1,523,612
PNM | Total
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(104,265)	(108,019)	(110,422)	(97,093)
Cumulative effect adjustment (Note 7)					(11,208)
Balance, as adjusted					(108,301)
Total Other Comprehensive Income	4,317	1,310	10,474	1,592
Ending balance	(99,948)	(106,709)	(99,948)	(106,709)
PNM | Unrealized Gains on Available-for-Sale Securities
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance			1,939	13,169
Cumulative effect adjustment (Note 7)					(11,208)
Balance, as adjusted					1,961
Amounts reclassified from AOCI (pre-tax)			(5,601)	(3,126)
Income tax impact of amounts reclassified			1,423	794
Other OCI changes (pre-tax)			15,938	1,472
Income tax impact of other OCI changes			(4,048)	(374)
Total Other Comprehensive Income			7,712	(1,234)
Ending balance	9,651	727	9,651	727
PNM | Pension Liability Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance			(112,361)	(110,262)
Balance, as adjusted					$ (110,262)
Amounts reclassified from AOCI (pre-tax)			3,702	3,788
Income tax impact of amounts reclassified			(940)	(962)
Total Other Comprehensive Income			2,762	2,826
Ending balance	$ (109,599)	$ (107,436)	$ (109,599)	$ (107,436)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Net Earnings Available for PNM Common Stock		$ (75,914)	$ 38,208	$ (57,214)	$ 53,198
Average Number of Common Shares:
Outstanding during period (in shares)		79,654	79,654	79,654	79,654
Vested awards of restricted stock (in shares)	[1]	263	211	251	208
Average Shares – Basic (in shares)		79,917	79,865	79,905	79,862
Dilutive Effect of Common Stock Equivalents:(1)
Stock options and restricted stock (in shares)		0	114	0	134
Average Shares – Diluted (in shares)		79,917	79,979	79,905	79,996
Net Earnings (Loss) Per Share of Common Stock:
Basic (in dollars per share)		$ (0.95)	$ 0.48	$ (0.72)	$ 0.67
Diluted (in dollars per share)		$ (0.95)	$ 0.48	$ (0.72)	$ 0.67
[1]	Due to the loss in the three and six months ended June 30, 2019, no potentially dilutive shares are reflected in the average number of shares used to compute net earnings (loss) per share of common stock since any impact would be anti-dilutive. At June 30, 2019, PNMR’s potentially dilutive shares consist of stock options and restricted stock (see Note 8).

Electric Operating Revenues - N

Electric Operating Revenues - Narrative (Details)	Jun. 30, 2019USD ($)utility	Dec. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Number of regulated utilities | utility	2
Contract assets	$ 0	$ 0
Customer contracts | PNM
Disaggregation of Revenue [Line Items]
Accounts receivable	$ 52,700,000	$ 61,700,000

Electric Operating Revenues - D

Electric Operating Revenues - Disaggregation of revenues (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	$ 314,917	$ 338,659	$ 630,614	$ 642,010
Operating revenues	330,228	352,313	679,872	670,191
PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	228,061	254,728	464,002	477,291
Operating revenues	238,219	264,511	507,536	500,742
TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	86,856	83,931	166,612	164,719
Operating revenues	92,009	87,802	172,336	169,449
Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	119,968	130,823	257,701	257,257
Residential | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	86,328	99,508	193,629	196,676
Residential | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	33,640	31,315	64,072	60,581
Commercial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	127,026	138,734	239,688	248,735
Commercial | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	98,968	110,652	184,201	193,501
Commercial | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	28,058	28,082	55,487	55,234
Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	20,624	18,781	40,987	36,545
Industrial | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	15,329	14,597	30,076	28,056
Industrial | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	5,295	4,184	10,911	8,489
Public authority
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	5,987	6,619	12,071	12,670
Public authority | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4,596	5,220	9,307	9,855
Public authority | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,391	1,399	2,764	2,815
Economy energy service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	6,024	6,378	12,946	13,666
Economy energy service | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	6,024	6,378	12,946	13,666
Economy energy service | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0	0
Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	31,927	30,851	59,316	59,841
Transmission | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	14,342	14,108	27,727	26,590
Transmission | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	17,585	16,743	31,589	33,251
Miscellaneous
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	3,361	6,473	7,905	13,296
Miscellaneous | PNM
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	2,474	4,265	6,116	8,947
Miscellaneous | TNMP
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	887	2,208	1,789	4,349
Alternative revenue programs
Disaggregation of Revenue [Line Items]
Operating revenues	5,844	5,660	6,480	6,584
Alternative revenue programs | PNM
Disaggregation of Revenue [Line Items]
Operating revenues	691	1,789	756	1,854
Alternative revenue programs | TNMP
Disaggregation of Revenue [Line Items]
Operating revenues	5,153	3,871	5,724	4,730
Other electric operating revenues
Disaggregation of Revenue [Line Items]
Operating revenues	9,467	7,994	42,778	21,597
Other electric operating revenues | PNM
Disaggregation of Revenue [Line Items]
Operating revenues	9,467	7,994	42,778	21,597
Other electric operating revenues | TNMP
Disaggregation of Revenue [Line Items]
Operating revenues	$ 0	$ 0	$ 0	$ 0

Electric Operating Revenues - C

Electric Operating Revenues - Changes in contract liabilities (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019USD ($)
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	$ 349
Consideration received in advance of service to be provided	5,674
Deferred revenue earned	(3,035)
Ending balance	2,988
PNM
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	349
Consideration received in advance of service to be provided	4,157
Deferred revenue earned	(2,259)
Ending balance	2,247
TNMP
Change In Contract With Customer Liability [Roll Forward]
Beginning balance	0
Consideration received in advance of service to be provided	1,517
Deferred revenue earned	(776)
Ending balance	$ 741

Variable Interest Entities (Det

Variable Interest Entities (Details)	Feb. 01, 2016USD ($)	Jun. 30, 2019USD ($)MW	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)MW	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)	Jan. 31, 2016USD ($)
Results of Operations
Earnings attributable to non-controlling interest		$ 3,499,000	$ 4,109,000	$ 6,328,000	$ 7,786,000
Financial Position
Current assets		299,076,000		299,076,000		$ 302,524,000
Total assets		7,048,667,000	6,750,089,000	7,048,667,000	6,750,089,000	6,865,551,000
Current liabilities		666,541,000		666,541,000		512,453,000
Owners’ equity – non-controlling interest		62,592,000		62,592,000		64,212,000
PNM
Results of Operations
Earnings attributable to non-controlling interest		3,499,000	4,109,000	6,328,000	7,786,000
Financial Position
Current assets		250,605,000		250,605,000		270,319,000
Total assets		5,105,090,000		5,105,090,000		5,035,883,000
Current liabilities		317,064,000		317,064,000		223,023,000
Owners’ equity – non-controlling interest		62,592,000		62,592,000		64,212,000
PNM | Valencia
Variable Interest Entity [Line Items]
Payment for fixed costs		5,000,000	4,900,000	9,900,000	9,800,000
Payment for variable costs		200,000	600,000	$ 300,000	900,000
Long-term contract option to purchase, ownership percentage (up to)				50.00%
Long-term contract option to purchase, purchase price - percentage of adjusted NBV				50.00%
Long-term contract option to purchase, purchase price - percentage of FMV				50.00%
Results of Operations
Operating revenues		5,177,000	5,911,000	$ 10,129,000	10,679,000
Operating expenses		1,678,000	1,802,000	3,801,000	2,893,000
Earnings attributable to non-controlling interest		3,499,000	$ 4,109,000	6,328,000	$ 7,786,000
Financial Position
Current assets		3,174,000		3,174,000		2,684,000
Net property, plant, and equipment		60,003,000		60,003,000		62,066,000
Total assets		63,177,000		63,177,000		64,750,000
Current liabilities		585,000		585,000		538,000
Owners’ equity – non-controlling interest		$ 62,592,000		$ 62,592,000		$ 64,212,000
PNM | Valencia | Purchased through May 2028
Variable Interest Entity [Line Items]
Number of megawatts purchased (in megawatts) | MW		158		158
NM Capital | San Juan Generating Station | Coal supply
Variable Interest Entity [Line Items]
Loan agreement among several entities	$ 125,000,000
Cash used to support bank letter or credit arrangement		$ 30,300,000		$ 30,300,000			$ 30,300,000

Fair Value of Derivative and _3

Fair Value of Derivative and Other Financial Instruments - Overview and Commodity Derivatives (Details)	Jun. 30, 2019USD ($)MW	Dec. 31, 2018USD ($)
Derivatives, Fair Value [Line Items]
Obligations to return cash	$ 900,000	$ 1,000,000
PNM
Derivatives, Fair Value [Line Items]
Expected exposure to market risk (in megawatts) | MW	65
Power to be sold to third party (in megawatts) | MW	36
Amounts recognized for right to reclaim cash	$ 0	0
Cash collateral under margin arrangements	500,000	1,000,000
PNM | Designated as Hedging Instrument | Commodity derivatives
Derivatives, Fair Value [Line Items]
Other current assets	1,164,000	1,083,000
Other deferred charges	2,028,000	2,511,000
Derivative asset	3,192,000	3,594,000
Other current liabilities	(1,142,000)	(1,177,000)
Other deferred credits	(2,028,000)	(2,511,000)
Derivative liability	(3,170,000)	(3,688,000)
Net	22,000	(94,000)
PNM | Designated as Hedging Instrument | Commodity derivatives | Fuel and purchased power costs
Derivatives, Fair Value [Line Items]
Other current assets		0
PNM | Designated as Hedging Instrument | Commodity derivatives | Hazard sharing arrangement
Derivatives, Fair Value [Line Items]
Derivative asset	$ 3,100,000	$ 3,600,000
Tri-State | PNM
Derivatives, Fair Value [Line Items]
Power to be sold to third party (in megawatts) | MW	100

Fair Value of Derivative and _4

Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
PNM | Designated as Hedging Instrument | Commodity derivatives | Cost of energy
Derivative Instruments, Gain (Loss) [Line Items]
Total gain	$ 0.1	$ 0.1	$ 0.1	$ 0.1

Fair Value of Derivative and _5

Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) MWh in Thousands, MMBTU in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019USD ($)MWhMMBTU	Dec. 31, 2018USD ($)MWhMMBTU
Derivative [Line Items]
Contract in a liability position | $	$ 0	$ 0
PNM | Commodity derivatives | Fair value hedging | Buy
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MMBTU	565	100
PNM | Commodity derivatives | Fair value hedging | Sell
Derivative [Line Items]
Economic Hedges (in mmbtu and mwh) | MWh	42	0

Fair Value of Derivative and _6

Fair Value of Derivative and Other Financial Instruments - Investments in NDT (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Equity securities:
Net gains from equity securities sold	$ 2,774	$ 2,502	$ 4,161	$ 5,330
Net gains (losses) from equity securities still held	303	(443)	9,905	(307)
Total net gains on equity securities	3,077	2,059	14,066	5,023
Available-for-sale debt securities:
Net gains (losses) on debt securities	1,522	(3,729)	4,547	(6,405)
Net gains (losses) on investment securities	$ 4,599	$ (1,670)	$ 18,613	$ (1,382)

Fair Value of Derivative and _7

Fair Value of Derivative and Other Financial Instruments - Available for Sale Securities (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Jan. 01, 2018
Debt Securities, Available-for-sale [Line Items]
Debt securities, available-for-sale, unrealized loss position	$ 0		$ 0
Other than temporary impairments			0
PNM
Debt Securities, Available-for-sale [Line Items]
(Increase)/decrease in other than temporary losses of available-for-sale securities, net portion recognized in earnings	(800,000)	$ (2,600,000)	2,600,000	$ (3,800,000)
Proceeds from sales	159,551,000	167,359,000	234,011,000	794,088,000
Gross realized gains	10,906,000	7,549,000	15,095,000	13,570,000
Gross realized (losses)	(5,802,000)	$ (6,192,000)	(8,972,000)	$ (10,869,000)
Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	362,793,000		362,793,000		$ 328,242,000
Nuclear Decommissioning Trust | Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	318,800,000		318,800,000		287,100,000
Mine Reclamation Trust | Recurring | PNM
Debt Securities, Available-for-sale [Line Items]
Available-for-sale debt securities	$ 44,000,000		$ 44,000,000		$ 41,100,000
Retained Earnings
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)						$ 11,208,000
Retained Earnings | PNM
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)						11,208,000
Accounting Standards Update 2016-01 | Retained Earnings
Debt Securities, Available-for-sale [Line Items]
Cumulative effect adjustment (Note 7)						$ 11,200,000

Fair Value of Derivative and _8

Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) - PNMR and PNM $ in Thousands	Jun. 30, 2019USD ($)
Available-for-Sale
Within 1 year	$ 20,868
After 1 year through 5 years	75,642
After 5 years through 10 years	67,572
After 10 years through 15 years	12,886
After 15 years through 20 years	11,747
After 20 years	34,246
Available-for-sale debt securities	$ 222,961

Fair Value of Derivative and _9

Fair Value of Derivative and Other Financial Instruments - Items Recorded and Presented by Level of Hierarchy (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers between levels	$ 0	$ 0
PNMR	2,903,711,000	2,703,810,000
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	2,903,711,000	2,703,810,000
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	2,772,342,000	2,670,111,000
PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	1,768,943,000	1,668,736,000
PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	1,768,943,000	1,668,736,000
PNM | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
PNM | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	1,707,256,000	1,656,490,000
TNMP
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	692,728,000	597,236,000
TNMP | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
TNMP | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	692,728,000	597,236,000
TNMP | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	0	0
TNMP | Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
PNMR	626,456,000	575,398,000
Recurring | PNM
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	362,793,000	328,242,000
Recurring | PNM | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	156,517,000	136,150,000
Recurring | PNM | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	203,467,000	189,936,000
Recurring | PNM | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	2,809,000	2,156,000
Investments, unrealized gain	12,943,000	2,600,000
Recurring | PNM | Commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	3,192,000	3,594,000
Commodity derivative liabilities	(3,170,000)	(3,688,000)
Net	22,000	(94,000)
Recurring | PNM | Commodity derivatives | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	0	0
Commodity derivative liabilities	0	0
Net	0	0
Recurring | PNM | Commodity derivatives | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	3,192,000	3,594,000
Commodity derivative liabilities	(3,170,000)	(3,688,000)
Net	22,000	(94,000)
Recurring | PNM | Commodity derivatives | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative assets	0	0
Commodity derivative liabilities	0	0
Net	0	0
Recurring | PNM | Cash and cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	11,055,000	11,472,000
Recurring | PNM | Cash and cash equivalents | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	11,055,000	11,472,000
Recurring | PNM | Cash and cash equivalents | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0	0
Recurring | PNM | Cash and cash equivalents | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0	0
Recurring | PNM | Corporate stocks, common
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	38,391,000	32,997,000
Recurring | PNM | Corporate stocks, common | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	38,391,000	32,997,000
Recurring | PNM | Corporate stocks, common | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, common | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, preferred
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	8,788,000	7,258,000
Recurring | PNM | Corporate stocks, preferred | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	2,207,000	1,654,000
Recurring | PNM | Corporate stocks, preferred | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	6,581,000	5,604,000
Recurring | PNM | Corporate stocks, preferred | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Mutual funds and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	81,598,000	70,777,000
Recurring | PNM | Mutual funds and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	81,558,000	70,777,000
Recurring | PNM | Mutual funds and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	40,000	0
Recurring | PNM | Mutual funds and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity securities	0	0
Recurring | PNM | Corporate stocks, common | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | Corporate stocks, preferred | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | Mutual funds and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, unrealized gain
Recurring | PNM | U.S. Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	35,664,000	29,503,000
Recurring | PNM | U.S. Government | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	21,971,000	18,662,000
Recurring | PNM | U.S. Government | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	13,693,000	10,841,000
Recurring | PNM | U.S. Government | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	888,000	1,098,000
Recurring | PNM | International Government
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	13,582,000	8,435,000
Recurring | PNM | International Government | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	31,000	0
Recurring | PNM | International Government | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	13,551,000	8,435,000
Recurring | PNM | International Government | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	827,000	90,000
Recurring | PNM | Municipals
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	46,633,000	53,642,000
Recurring | PNM | Municipals | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Recurring | PNM | Municipals | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	46,633,000	53,642,000
Recurring | PNM | Municipals | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	0	0
Investments, unrealized gain	1,886,000	489,000
Recurring | PNM | Corporate and other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	127,082,000	114,158,000
Recurring | PNM | Corporate and other | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	1,304,000	588,000
Recurring | PNM | Corporate and other | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	122,969,000	111,414,000
Recurring | PNM | Corporate and other | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale debt securities	2,809,000	2,156,000
Investments, unrealized gain	$ 9,342,000	$ 923,000

Fair Value of Derivative and_10

Fair Value of Derivative and Other Financial Instruments - Reconciliation of changes in Level 3 fair value measurements (Details) - Corporate Debt - Level 3 - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning balance	$ 2,156	$ 0
Actual return on assets sold during the period	(48)	(4)
Actual return on assets still held at period end	63	(5)
Purchases	1,422	4,011
Sales	(784)	(1,011)
Ending balance	$ 2,809	$ 2,991

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	1 year
Restricted Stock, Shares
Expired (in shares)	0
Restricted Stock, Weighted- Average Grant Date Fair Value
Expired (in dollars per share)	$ 0
Stock Options, Shares
Outstanding at beginning of period (in shares)	81,000
Granted (in shares)	0
Exercised (in shares)	(79,000)
Forfeited (in shares)	0
Expired (in shares)	0
Outstanding at end of period (in shares)	2,000
Stock Options, Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 11.94
Granted (in dollars per share)	0
Exercised (in dollars per share)	11.93
Forfeited (in dollars per share)	0
Expired (in dollars per share)	0
Outstanding at end of period (in dollars per share)	12.22
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value of options granted (in dollars per share)	$ 0	$ 0
Total fair value of options that vested	$ 0	$ 0
Total intrinsic value of options exercised	2,617	$ 2,968
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2019 and she remains an employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return (in shares)				53,859
Chairman, President, and Chief Executive Officer | Common Stock | Achieves a specific performance target by the end of 2017 and she remains an employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares received if achieves specified improvement in total shareholders return (in shares)				17,953
Restricted Shares and Performance Based Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized expense related to stock awards	$ 6,000
Period of time stock expense is expected to be recognized	1 year 8 months 23 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Expected quarterly dividends per share (in dollars per share)	$ 0.290	$ 0.265
Risk-free interest rate	2.47%	2.38%
Restricted Stock
Restricted Stock, Shares
Outstanding at beginning of period (in shares)	166,651
Granted (in shares)	134,573
Exercised (in shares)	(137,601)
Forfeited (in shares)	0
Expired (in shares)	0
Outstanding at end of period (in shares)	163,623
Restricted Stock, Weighted- Average Grant Date Fair Value
Outstanding at beginning of period (in dollars per share)	$ 32.93
Granted (in dollars per share)	37.92	$ 29.65
Exercised (in dollars per share)	31.44
Forfeited (in dollars per share)	0
Expired (in dollars per share)	0
Outstanding at end of period (in dollars per share)	$ 38.19
Stock Options, Shares
Expired (in shares)	0
Stock Options, Weighted- Average Exercise Price
Expired (in dollars per share)	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted-average grant date fair value (in dollars per share)	$ 37.92	$ 29.65
Total fair value of restricted shares that vested	$ 6,227	$ 8,328
Performance Shares | Executive
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares awarded in year one (in shares)	130,302		47,279
Weighted percentage assigned to achieving market targets			40.00%
Weighted percentage assigned to achieving performance targets			60.00%
Maximum number of shares awarded in year two (in shares)	146,941
Maximum number of shares in year three (in shares)	135,678
Performance period	3 years
Market-Based Shares
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	2.51%	2.36%
Dividend yield	2.59%	2.96%
Expected volatility	19.55%	19.12%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of stock options outstanding	$ 100
Weighted-average remaining contract life	8 months 12 days
Number of outstanding stock options with an exercise price greater than the closing price (in shares)	0
Performance Equity Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Vesting rate	100.00%

Financing - Financing Activitie

Financing - Financing Activities (Details) - USD ($)	Jul. 01, 2019	Apr. 01, 2019	Jan. 18, 2019	Apr. 09, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Mar. 29, 2019	Feb. 26, 2019	Dec. 31, 2018	Jul. 25, 2018	Jul. 20, 2017	Oct. 21, 2016
Debt Instrument [Line Items]
Interest charges					$ 29,791,000	$ 33,321,000	$ 61,425,000	$ 66,376,000
Other deferred credits					$ 171,770,000		$ 171,770,000				$ 167,668,000
PNMR 2016 Two-Year Term Loan
Debt Instrument [Line Items]
Variable interest rate					3.20%		3.20%
Term loans					$ 50,000,000		$ 50,000,000
Term of loan							2 years
PNM
Debt Instrument [Line Items]
Interest charges					18,526,000	19,988,000	$ 36,886,000	40,818,000
Other deferred credits					215,776,000		215,776,000				215,737,000
Term loans					100,300,000		100,300,000
PNM | PNM 2019 Term Loan
Debt Instrument [Line Items]
Aggregate principal amount			$ 250,000,000		250,000,000		$ 250,000,000
PNM | Maximum
Debt Instrument [Line Items]
Maturity term over which financings require regulator approval (more than)							18 months
Texas-New Mexico Power Company
Debt Instrument [Line Items]
Interest charges					6,560,000	7,801,000	$ 15,361,000	$ 15,530,000
Other deferred credits					4,702,000		4,702,000				$ 2,908,000
Texas-New Mexico Power Company | TNMP Term Loan Agreement
Debt Instrument [Line Items]
Aggregate principal amount					$ 35,000,000		$ 35,000,000
Line of credit
Debt Instrument [Line Items]
Ratio of debt to capital (less than or equal to)							65.00%	70.00%
Letter of credit | PNMR | JPM LOC Facility
Debt Instrument [Line Items]
Aggregate principal amount														$ 30,300,000
PNM 2019 Term Loan
Debt Instrument [Line Items]
Interest rate at period end					3.05%		3.05%
Mortgages | Texas-New Mexico Power Company | TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount									$ 225,000,000	$ 305,000,000
Stated interest rate										400.00%
Debt-to-capital ratio			65.00%
Mortgages | Texas-New Mexico Power Company | TNMP Term Loan Agreement
Debt Instrument [Line Items]
Stated interest rate												3.10%
Mortgages | Texas-New Mexico Power Company | PNMR Development Term Loan
Debt Instrument [Line Items]
Stated interest rate					3.20%		3.20%
Unsecured Debt | Texas-New Mexico Power Company | First Mortgage Bonds Due 2019, Series 2009A, at 9 point 50 percent
Debt Instrument [Line Items]
Stated interest rate		9.50%
Extinguishment of debt		$ 172,300,000
Term loan agreement with banks | PNM | PNM 2019 Term Loan | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount													$ 250,000,000
Term loan agreement with banks | Texas-New Mexico Power Company | TNMP Term Loan Agreement | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount													$ 35,000,000
Term loan agreement with banks | Texas-New Mexico Power Company | PNMR Development Term Loan | JPMorgan Chase Bank, N.A. and U.S. Bank National Association
Debt Instrument [Line Items]
Aggregate principal amount					$ 90,000,000		$ 90,000,000
Subsequent event | Mortgages | Texas-New Mexico Power Company | TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount	$ 305,000,000
Subsequent event | Mortgages | Texas-New Mexico Power Company | First Mortgage Bonds 3.60 Percent Due 2029
Debt Instrument [Line Items]
Aggregate principal amount	$ 80,000,000
Stated interest rate	3.60%
Deposit Related To Potential Transmission Interconnections | PNMR Development
Debt Instrument [Line Items]
Amount of related party transaction				$ 68,200,000
Interest charges					1,000,000	$ 700,000	1,900,000	$ 700,000
Other deferred credits					$ 68,200,000		$ 68,200,000
San Juan Generating Station | Subsequent event | PNM
Debt Instrument [Line Items]
Request issuance of energy transition bonds	$ 361,000,000

Financing - TNMP 2019 Bonds (De

Financing - TNMP 2019 Bonds (Details) - TNMP - Mortgages - USD ($)	Jul. 01, 2019	Mar. 29, 2019	Feb. 26, 2019
First Mortgage Bonds 3.79 Percent Due 2034
Debt Instrument [Line Items]
Aggregate principal amount		$ 75,000,000
Stated interest rate		3.79%
First Mortgage Bonds 3.92 Percent Due 2039
Debt Instrument [Line Items]
Aggregate principal amount		$ 75,000,000
Stated interest rate		3.92%
First Mortgage Bonds 4.06 Percent Due 2044
Debt Instrument [Line Items]
Aggregate principal amount		$ 75,000,000
Stated interest rate		4.06%
TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount		$ 225,000,000	$ 305,000,000
Stated interest rate			400.00%
Subsequent event | TNMP 2019 Bond Purchase Agreement
Debt Instrument [Line Items]
Aggregate principal amount	$ 305,000,000
Subsequent event | First Mortgage Bonds 3.60 Percent Due 2029
Debt Instrument [Line Items]
Aggregate principal amount	$ 80,000,000
Stated interest rate	3.60%

Financing - Short-term Debt and

Financing - Short-term Debt and Liquidity (Details)	6 Months Ended	12 Months Ended
	Jun. 30, 2019USD ($)	Dec. 31, 2017USD ($)derivative	Jul. 26, 2019USD ($)	Jul. 22, 2019USD ($)	Jul. 21, 2019USD ($)	Feb. 22, 2019USD ($)	Feb. 21, 2019USD ($)	Jan. 18, 2019USD ($)	Dec. 31, 2018USD ($)
Short-term Debt [Line Items]
Financing capacity						$ 25,000,000	$ 24,500,000
Short-term debt	$ 342,400,000								$ 235,900,000
Letters of credit outstanding	4,700,000
PNMR 2018 One-Year Term Loan
Short-term Debt [Line Items]
Short-term debt	$ 150,000,000								150,000,000
Term of loan	1 year
Debt issued	$ 150,000,000
PNMR 2018 One-Year Term Loan | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.15%
PNMR Development Revolving Credit Facility
Short-term Debt [Line Items]
Short-term debt	$ 21,900,000								6,000,000
Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Term of derivatives		4 years
Debt issued		$ 50,000,000
PNMR Revolving Credit Facility | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.67%
PNM Revolving Credit Facility
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.53%
PNM 2017 New Mexico Credit Facility
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.52%
PNMR Development Revolving Credit Facility | PNMR
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.41%
TNMP Revolving Credit Facility
Short-term Debt [Line Items]
Weighted-average interest rate for short-term debt	3.16%
PNM
Short-term Debt [Line Items]
Short-term debt	$ 42,200,000								42,400,000
Letters of credit outstanding	2,500,000
Short-term debt – affiliate	0								19,800,000
Long-term debt	100,300,000
PNM | Lines of credit
Short-term Debt [Line Items]
NMPRC approved credit facility	40,000,000
Short-term debt	15,000,000								10,000,000
PNM | PNM 2019 Term Loan
Short-term Debt [Line Items]
Debt issued	250,000,000							$ 250,000,000
TNMP
Short-term Debt [Line Items]
Short-term debt	55,000,000								17,500,000
Letters of credit outstanding	700,000
Short-term debt – affiliate	1,600,000								100,000
TNMP | TNMP Term Loan Agreement
Short-term Debt [Line Items]
Debt issued	35,000,000
PNMR Development
Short-term Debt [Line Items]
Short-term debt – affiliate	200,000								500,000
Revolving credit facility
Short-term Debt [Line Items]
Financing capacity	300,000,000
Short-term debt	73,300,000								20,000,000
Revolving credit facility | PNM
Short-term Debt [Line Items]
Financing capacity	400,000,000
Short-term debt	27,200,000								32,400,000
Revolving credit facility | TNMP
Short-term Debt [Line Items]
Financing capacity	75,000,000
Short-term debt	55,000,000								17,500,000
Revolving credit facility | TNMP | First mortgage bonds
Short-term Debt [Line Items]
Collateral amount	75,000,000
Interest rate contract
Short-term Debt [Line Items]
Number of derivatives | derivative		3
Interest rate 1 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate		1.926%
Interest rate 2 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate		1.823%
Interest rate 3 | Variable Rate Short-Term Debt
Short-term Debt [Line Items]
Fixed interest rate		1.629%
Interest rate 3 | Level 2 | Cash Flow Hedge
Short-term Debt [Line Items]
Other current liabilities	(400,000)
Derivative asset	$ 100,000
Derivative, fair value									$ 1,000,000
Subsequent event
Short-term Debt [Line Items]
Financing capacity				$ 50,000,000	$ 40,000,000
Remaining borrowing capacity			$ 692,700,000
Subsequent event | PNMR
Short-term Debt [Line Items]
Remaining borrowing capacity			227,600,000
Consolidated invested cash			900,000
Subsequent event | PNM
Short-term Debt [Line Items]
Remaining borrowing capacity			368,100,000
Consolidated invested cash			0
Subsequent event | PNM | Lines of credit
Short-term Debt [Line Items]
Remaining borrowing capacity			15,000,000
Subsequent event | TNMP
Short-term Debt [Line Items]
Remaining borrowing capacity			74,900,000
Consolidated invested cash			13,800,000
Subsequent event | PNMR Development
Short-term Debt [Line Items]
Short-term debt – affiliate			200,000
Remaining borrowing capacity			$ 7,100,000

Pension and Other Postretirem_3

Pension and Other Postretirement Benefit Plans (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
PNM | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	$ 0	$ 0	$ 0	$ 0
Interest cost	6,294,000	6,068,000	12,587,000	12,135,000
Expected return on plan assets	(8,527,000)	(8,672,000)	(17,051,000)	(17,343,000)
Amortization of net (gain) loss	3,880,000	4,087,000	7,759,000	8,174,000
Amortization of prior service cost	(241,000)	(241,000)	(483,000)	(483,000)
Net Periodic Benefit Cost (Income)	1,406,000	1,242,000	2,812,000	2,483,000
Contributions by employer			0	0
Expected employer contributions for future fiscal years	0		0
Expected employer contributions in year 5	1,300,000		1,300,000
Expected employer contributions in year 6	22,900,000		$ 22,900,000
PNM | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.20%
PNM | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.60%
PNM | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	13,000	21,000	$ 26,000	41,000
Interest cost	829,000	860,000	1,658,000	1,720,000
Expected return on plan assets	(1,318,000)	(1,353,000)	(2,636,000)	(2,707,000)
Amortization of net (gain) loss	169,000	588,000	338,000	1,177,000
Amortization of prior service cost	(99,000)	(416,000)	(198,000)	(832,000)
Net Periodic Benefit Cost (Income)	(406,000)	(300,000)	(812,000)	(601,000)
Contributions by employer	700,000	0	1,500,000	0
Estimated future employer contributions for fiscal year	3,700,000		3,700,000
Estimated employer contributions in year 2-5	13,700,000		13,700,000
PNM | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	162,000	155,000	324,000	311,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	79,000	90,000	158,000	179,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	241,000	245,000	482,000	490,000
Contributions by employer	400,000	400,000	700,000	900,000
Total expected employer contributions for fiscal year	1,500,000		1,500,000
Estimated employer contributions in year 2-5	5,600,000		5,600,000
TNMP | Pension Plan
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	672,000	656,000	1,344,000	1,312,000
Expected return on plan assets	(967,000)	(991,000)	(1,934,000)	(1,981,000)
Amortization of net (gain) loss	235,000	272,000	470,000	544,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	(60,000)	(63,000)	(120,000)	(125,000)
Contributions by employer			0	0
Estimated employer contributions in year 2-5	0		$ 0
TNMP | Pension Plan | Minimum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.20%
TNMP | Pension Plan | Maximum
Components of Net Periodic Benefit Cost
Assumptions used calculating net periodic benefit cost, discount rate			4.60%
TNMP | OPEB Plan
Components of Net Periodic Benefit Cost
Service cost	13,000	33,000	$ 26,000	67,000
Interest cost	113,000	119,000	226,000	238,000
Expected return on plan assets	(129,000)	(135,000)	(258,000)	(271,000)
Amortization of net (gain) loss	(110,000)	(56,000)	(220,000)	(113,000)
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	(113,000)	(39,000)	(226,000)	(79,000)
Contributions by employer	0	0	0	300,000
TNMP | Executive Retirement Program
Components of Net Periodic Benefit Cost
Service cost	0	0	0	0
Interest cost	8,000	7,000	16,000	15,000
Expected return on plan assets	0	0	0	0
Amortization of net (gain) loss	4,000	4,000	8,000	8,000
Amortization of prior service cost	0	0	0	0
Net Periodic Benefit Cost (Income)	12,000	11,000	24,000	23,000
Total expected employer contributions for fiscal year	100,000		100,000
Estimated employer contributions in year 2-5	300,000		300,000
TNMP | Executive Retirement Program | Maximum
Components of Net Periodic Benefit Cost
Contributions by employer	$ 100,000	$ 100,000	$ 100,000	$ 100,000

Commitments and Contingencies -

Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	$ 57.7
Other deferred credits
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	$ 12.7	$ 12.4

Commitments and Contingencies_2

Commitments and Contingencies - The Energy Transition Act (Details) - Electric-Generation Portfolio Standard - Energy Transition Act	Mar. 22, 2019
Required Percentage by 2020
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage	0.20
Required Percentage by 2025
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage	0.40
Required Percentage by 2030
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage	0.50
Required Percentage by 2040
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage	0.80
Required Percentage by 2045
Public Utilities, Commitments And Contingencies [Line Items]
Renewable energy, percentage	1

Commitments and Contingencies_3

Commitments and Contingencies - The Clean Air Act (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)optionT	Feb. 25, 2019parts_per_billion	Dec. 31, 2018USD ($)MW	Feb. 09, 2016state	Oct. 01, 2015parts_per_billion	Sep. 30, 2015parts_per_billion	May 14, 2015lb / MMBTU	Apr. 30, 2013well	Feb. 28, 2013claimstatemine	Dec. 31, 1999state
Public Utilities, Commitments And Contingencies [Line Items]
Number of options for meeting BTA standards | option	7
Clean Air Act related to regional haze
Public Utilities, Commitments And Contingencies [Line Items]
Number of states to address regional haze (in states) | state										50
Potential to emit tons per year of visibility impairing pollution (in tons, more than) | T	250
Clean Power Plan
Public Utilities, Commitments And Contingencies [Line Items]
Number of states that filed a petition against the Clean Power Plan | state				29
PNM | WEG v OSM lawsuit
Public Utilities, Commitments And Contingencies [Line Items]
Number of mines impacted | mine									7
Number of states impacted | state									4
Number of claims for relief, filed | claim									15
PNM | Santa Fe generating station
Public Utilities, Commitments And Contingencies [Line Items]
Number of wells with elevated levels of nitrates | well								3
PNM | San Juan Generating Station Unit 4 | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Net book value	$ 364.6		$ 373.6
Pre-tax impairment of investments			35
Undepreciated investment in ownership to be obtained			11.9
Forecasted undepreciated investment			$ 23.1
PNM | San Juan Generating Station | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Additional ownership to be obtained (in megawatts) | MW			132
PNM | San Juan Generating Station | WEG v OSM lawsuit
Public Utilities, Commitments And Contingencies [Line Items]
Number of claims for relief, filed | claim									2
PNMR Development | San Juan Generating Station Unit 4 | Clean Air Act, SNCR
Public Utilities, Commitments And Contingencies [Line Items]
Potential acquisition of ownership (in megawatts) | MW			65
Maximum | PNM | San Juan Generating Station and Four Corners
Public Utilities, Commitments And Contingencies [Line Items]
Government standard emission limit (in ozone parts per million) | parts_per_billion		75			70	75
San Juan Generating Station | PNM | National Ambient Air Quality Standards
Public Utilities, Commitments And Contingencies [Line Items]
Revised SO2 emissions (in pounds per MMBTU) | lb / MMBTU							0.10

Commitments and Contingencies_4

Commitments and Contingencies - Coal Supply (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Aug. 01, 2016payment	Jan. 31, 2016USD ($)
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	$ 49,259	$ 54,808
PNM
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	39,203	43,516
PNM | Loss on long-term purchase commitment | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	70,000	70,100
Final reclamation, capped amount to be collected		100,000
PNM | Loss on long-term purchase commitment | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Loss contingency accrual	24,300	23,200
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	94,400
PNM | Loss on long-term purchase commitment | San Juan Generating Station | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Estimate of possible loss	40,000
Coal supply | PNM | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Other current assets	26,300
Coal supply | NM Capital | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Requirement to post reclamation bonds	118,700
Cash used to support bank letter or credit arrangement	30,300				$ 30,300
Increase in coal mine decommissioning liability | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded	300
Increase in coal mine decommissioning liability | PNM | Underground and Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		39,200
Increase in coal mine decommissioning liability | PNM | Surface
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		29,800
Increase in coal mine decommissioning liability | PNM | Underground
Public Utilities, Commitments And Contingencies [Line Items]
Regulatory disallowance, additional amount recorded		9,400
Increase in coal mine decommissioning liability | PNM | Loss on long-term purchase commitment
Public Utilities, Commitments And Contingencies [Line Items]
Estimated underpaid surface mining royalties under proposed rate change			$ 2,500
Mine Reclamation Trust | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year	6,100
Reclamation trust funding, year 2	10,200
Reclamation trust funding, year 3	10,900
San Juan Generating Station | Loss on long-term purchase commitment | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Annual funding post-term reclamation trust		10,000
Four Corners | Mine Reclamation Trust | PNM
Public Utilities, Commitments And Contingencies [Line Items]
Required contribution to Reclamation Trust, current fiscal year		$ 2,300
Reclamation trust funding, year 2	$ 2,300
Number of annual installment payments | payment				13

Commitments and Contingencies_5

Commitments and Contingencies - Royalty Rates, Tax Assessment, Insurance and Other Matters (Details)	Mar. 28, 2017	Sep. 30, 2012landowner	Apr. 30, 2010city	Jun. 30, 2019USD ($)generating_unit	Dec. 01, 2015Allotment_Parcel	Jul. 13, 2015a	Jan. 22, 2015Allotment_Parcel	Aug. 31, 2013
Continuous highwall mining | San Juan Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Proposed retroactive surface mining royalty rate								12.50%
Surface mining royalty rate applied				8.00%
Estimated underpaid surface mining royalties under proposed rate change				$ 5,000,000
PNM's share estimated underpaid surface mining royalties under proposed rate change				46.30%
PNM | Navajo Nation Allottee Matters
Public Utilities, Commitments And Contingencies [Line Items]
Number of landowners involved in the appeal | landowner		43
Number of allotments where landowners are revoking rights of way renewal consents (in allotment parcels) | Allotment_Parcel					2		10
Area of land (in acres) | a						15.49
Number of allotment parcels at issue that are not to be condemned | Allotment_Parcel					2
Number of allotment parcels at issue | Allotment_Parcel					5
PNM | Palo Verde Nuclear Generating Station
Public Utilities, Commitments And Contingencies [Line Items]
Number of cities to provide cooling water | city			5
Term of agreement for cooling water			40 years
PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Ownership percentage in nuclear reactor				10.20%
Number of units | generating_unit				3
Maximum potential assessment per incident				$ 41,600,000
Annual payment limitation related to incident				6,200,000
Aggregate amount of all risk insurance				2,800,000,000
Maximum amount under Nuclear Electric Insurance Limited				5,400,000
PNM | Maximum | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				13,900,000,000
Liability insurance coverage sublimit				2,250,000,000
Commercial providers | PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				450,000,000
Industry Wide Retrospective Assessment Program | PNM | Palo Verde Nuclear Generating Station | Nuclear plant
Public Utilities, Commitments And Contingencies [Line Items]
Liability insurance coverage				$ 13,500,000,000
Pending litigation
Public Utilities, Commitments And Contingencies [Line Items]
Written notification to terminate agreement, minimum period of time required	30 days

Regulatory and Rate Matters - P

Regulatory and Rate Matters - PNM (Details)

Jun. 03, 2019MW

May 16, 2019USD ($)MW

Aug. 24, 2018Facilitypower_purchase_agreementMW

Jan. 31, 2018

Jan. 10, 2018USD ($)

Jul. 03, 2017

May 23, 2017

Dec. 07, 2016USD ($)

Sep. 28, 2016USD ($)leaseMW

May 04, 2016

Aug. 27, 2015USD ($)

Aug. 31, 2016USD ($)leaseMW

Jun. 30, 2019USD ($)MW

Mar. 31, 2019USD ($)

Jun. 30, 2018USD ($)

Dec. 31, 2017

Jun. 30, 2019USD ($)MW

Jun. 30, 2018USD ($)

Dec. 31, 2018USD ($)

Mar. 22, 2019

Aug. 22, 2018USD ($)

Aug. 10, 2018kvMW

Mar. 21, 2018MW

Oct. 17, 2017MW

Sep. 05, 2017MW

Jun. 01, 2017GWhMW

Sep. 30, 2016MW

Jan. 31, 2016MW

Public Utilities, Commitments And Contingencies [Line Items]

Income taxes (benefit)

$ 42,831,000

$ (5,156,000)

$ 41,608,000

$ (5,939,000)

Regulatory disallowances and restructuring costs

$ 149,254,000

1,794,000

$ 150,599,000

1,794,000

Percent of non-fuel revenue requirement change implemented

50.00%

Excess return on jurisdictional equity that would require refund

0.50%

0.50%

Ownership percentage

50.00%

50.00%

PNM

Public Utilities, Commitments And Contingencies [Line Items]

Income taxes (benefit)

$ 43,481,000

(2,345,000)

$ 41,508,000

(1,997,000)

Regulatory disallowances and restructuring costs

$ 149,254,000

1,794,000

$ 150,599,000

1,794,000

Planning period covered of IRP

20 years

Action plan, covered period

4 years

PNMR Development

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

30

30

50

Ownership percentage

50.00%

50.00%

Construction of solar generation capacity (in megawatts) | MW

10

10

2015 Electric Rate Case | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Requested rate increase (decrease)

$ 123,500,000

Requested rate increase (decrease) of non-fuel revenue

$ 121,700,000

$ 121,500,000

Requested return on equity

10.50%

Requested rate increase (decrease) for fuel related costs

42,900,000

Requested rate increase (decrease) for non-fuel related revenues

$ 200,000

Approved rate increase (decrease)

$ 61,200,000

Renewable Portfolio Standard | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Number of megawatts of Solar PV facilities | MW

157

157

Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW

50

50

Current output in the geothermal facility (in megawatts) | MW

15

15

Solar generation capacity (in megawatts) | MW

113.1

113.1

KV Transmission Line

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

166

Transmission line and associated facilities generation capacity (in kilovolts) | kv

345

Power purchase agreement term

20 years

Renewable Energy Rider | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Recorded revenues from renewable rider

$ 12,800,000

$ 10,800,000

$ 25,500,000

21,700,000

Revenue from renewable energy rider, year two

$ 58,900,000

Integrated Resource Plan, 2011 | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Frequency of IRP filings

3 years

Planning period covered of IRP

20 years

Energy Imbalance Market | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Initial capital investments to be recovered

$ 20,900,000

Other expenses to be recovered

$ 7,400,000

Facebook Data Center

Public Utilities, Commitments And Contingencies [Line Items]

Power purchase agreement term

25 years

Number of additional PPAs | power_purchase_agreement

2

Facebook Data Center | Casa Mesa Wind

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

50

Facebook Data Center | Avangrid Renewables, LLC

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

166

Facebook Data Center | Route 66 Solar Energy Center

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

100

50

Number of solar facilities | Facility

2

NMPRC

Public Utilities, Commitments And Contingencies [Line Items]

Requested rate increase (decrease)

$ 99,200,000

Requested return on equity

10.125%

Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate

23 years

Action plan, covered period

4 years

NMPRC | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Requested rate increase (decrease)

$ 10,300,000

Requested return on equity

9.575%

Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate

3 years

Requested approval to procure a new solar facilities to be constructed (in megawatts) | MW

50

50

Requested approval to procure additional gigawatt hours in year 1 | GWh

80

Proposed revision to rider that will allow for recovery

$ 49,600,000

Notice of proposed dismissal, period to show good cause

30 days

Required Percentage by 2011 | Renewable Portfolio Standard | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Required percentage of renewable energy in portfolio to electric sales

10.00%

10.00%

Required Percentage by 2015 | Renewable Portfolio Standard | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Required percentage of renewable energy in portfolio to electric sales

15.00%

15.00%

Required Percentage by 2020 | Renewable Portfolio Standard | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Required percentage of renewable energy in portfolio to electric sales

20.00%

20.00%

Required Percentage by 2020 | Energy Transition Act | Electric-Generation Portfolio Standard

Public Utilities, Commitments And Contingencies [Line Items]

Renewable energy, percentage

0.20

Required Percentage by 2025 | Energy Transition Act | Electric-Generation Portfolio Standard

Public Utilities, Commitments And Contingencies [Line Items]

Renewable energy, percentage

0.40

Required Percentage by 2030 | Energy Transition Act | Electric-Generation Portfolio Standard

Public Utilities, Commitments And Contingencies [Line Items]

Renewable energy, percentage

0.50

Required Percentage by 2040 | Energy Transition Act | Electric-Generation Portfolio Standard

Public Utilities, Commitments And Contingencies [Line Items]

Renewable energy, percentage

0.80

Required Percentage by 2045 | Energy Transition Act | Electric-Generation Portfolio Standard

Public Utilities, Commitments And Contingencies [Line Items]

Renewable energy, percentage

1

Maximum | Renewable Portfolio Standard | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Reasonable cost threshold in megawatts per hour

$ 60

$ 60

Palo Verde Nuclear Generating Station, Unit 2 Leases | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Number of megawatts purchased (in megawatts) | MW

64.1

64.1

64.1

64.1

Public utilities, aggregate annual rent expense

$ 18,100,000

Number of megawatts nuclear generation (in megawatts) | MW

114.6

114.6

114.6

114.6

Number of leases under which assets were purchased | lease

3

3

Palo Verde Nuclear Generating Station, Unit 2 Leases | 2015 Electric Rate Case | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Hearing examiner's proposed disallowance of recovery

$ 163,300,000

Initial rate base value

$ 83,700,000

Disallowance of the recovery undepreciated costs of capitalized leasehold improvements

$ 43,800,000

Pre-tax regulatory disallowance

$ 1,300,000

$ 1,800,000

$ 19,700,000

New Mexico Wind | Renewable Portfolio Standard 2014 | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Number of megawatts for wind energy | MW

204

New Mexico Wind | NMPRC | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Requested approval to procure additional gigawatt hours in year 2 | GWh

105

Red Mesa Wind | Renewable Portfolio Standard 2014 | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Number of megawatts for wind energy | MW

102

Lightning Dock Geothermal | NMPRC | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Requested approval to procure additional gigawatt hours in year 1 | GWh

55

Requested approval to procure additional gigawatt hours in year 2 | GWh

77

La Joya Wind | KV Transmission Line

Public Utilities, Commitments And Contingencies [Line Items]

Solar generation capacity (in megawatts) | MW

140

140

Four Corners

Public Utilities, Commitments And Contingencies [Line Items]

Regulatory disallowances and restructuring costs

$ 47,600,000

Regulatory disallowance

$ 148,100,000

New Mexico 2015 Rate Case | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Pre-tax impairment of investments

$ 149,300,000

Undepreciated capitalized improvements

$ 39,300,000

New Mexico 2015 Rate Case | Palo Verde Nuclear Generating Station, Unit 2 Leases | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Number of megawatts purchased (in megawatts) | MW

64.1

Portion of purchase price

$ 72,600,000

Income taxes (benefit)

45,700,000

Leaseholds and Leasehold Improvements | New Mexico 2015 Rate Case | Palo Verde Nuclear Generating Station, Unit 1 and 4 Leases | PNM

Public Utilities, Commitments And Contingencies [Line Items]

Undepreciated capitalized improvements

$ 37,400,000

Regulatory and Rate Matters - S

Regulatory and Rate Matters - SJGS Abandonment Application (Details) - Subsequent event - San Juan Generating Station - PNM $ in Millions	Jul. 01, 2019USD ($)scenarioMW
Public Utilities, General Disclosures [Line Items]
Number of megawatts in natural gas-fired peaking plant (in megawatts) | MW	280
Number of megawatts in battery storage facilities (in megawatts) | MW	70
Solar generation capacity (in megawatts) | MW	350
Number of megawatts in battery storage facilities, replacement resource scenario (in megawatts) | MW	60
Number of replacement resource scenarios | scenario	3
Request issuance of energy transition bonds	$ 361
Forecasted undepreciated investment	283
Plant decommissioning and coal mine reclamation costs	28.6
Upfront financing costs	9.6
Severance costs	20
Proceeds from securitization bonds	$ 19.8

Regulatory and Rate Matters - A

Regulatory and Rate Matters - Application For a New 345 KV Transmission Line and Western Spirit Line (Details) $ in Millions	Jun. 03, 2019MW	May 01, 2019USD ($)kv	Aug. 10, 2018USD ($)kvMW	Mar. 21, 2018MW
KV Transmission Line
Public Utilities, General Disclosures [Line Items]
Transmission line and associated facilities generation capacity (in kilovolts) | kv			345
Solar generation capacity (in megawatts) | MW			166
Estimated cost of project			$ 85
Facebook Data Center
Public Utilities, General Disclosures [Line Items]
Estimated cost of project			$ 39
Estimated cost of project, percentage			46.00%
Facebook Data Center | Avangrid Renewables, LLC
Public Utilities, General Disclosures [Line Items]
Solar generation capacity (in megawatts) | MW				166
Western Spirit Line
Public Utilities, General Disclosures [Line Items]
Transmission line and associated facilities generation capacity (in kilovolts) | kv		345
Estimated cost of project		$ 285
Estimated self-fund amount under agreement		$ 75
La Joya Wind | KV Transmission Line
Public Utilities, General Disclosures [Line Items]
Solar generation capacity (in megawatts) | MW	140		140

Regulatory and Rate Matters - T

Regulatory and Rate Matters - TNMP Narrative (Details) - USD ($) $ in Millions	Dec. 20, 2018	May 30, 2018	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Mar. 01, 2019
Public Utilities, Commitments And Contingencies [Line Items]
Unrecovered investment revenue		$ 20.2
TNMP
Public Utilities, Commitments And Contingencies [Line Items]
Net regulatory liability						$ 37.8
Reduction to revenue			$ 1.2	$ 2.7	$ 5.4
Energy efficiency cost recovery, requested change amount		5.9					$ 5.6
Energy efficiency cost recovery, requested bonus		0.8					$ 0.8
TNMP | 2018 TNMP Rate Case
Public Utilities, Commitments And Contingencies [Line Items]
Requested rate increase (decrease)	$ 10	$ 25.9
Requested return on equity	9.65%	10.50%
Requested cost of debt	6.44%	7.20%
Requested debt capital structure	55.00%	50.00%
Requested equity capital structure	45.00%	50.00%
Investments excluded from rate request	$ 10.6
Refund of federal income tax rates period						5 years

Regulatory and Rate Matters -_2

Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - TNMP - USD ($) $ in Millions	Jul. 23, 2019	Mar. 21, 2019	Mar. 27, 2018	Sep. 13, 2017	Mar. 14, 2017
Transmission Cost of Service Rates
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base					$ 30.2
Annual Increase in Revenue					$ 4.8
PUCT
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease)		$ 111.8	$ 32	$ 27.5
Proposed increase (decrease) in revenues		$ 14.3	$ 0.6	$ 4.7
Subsequent event | Transmission Cost of Service Rates
Public Utilities, General Disclosures [Line Items]
Approved Increase in Rate Base	$ 21.9
Annual Increase in Revenue	$ 3.3

Lease Commitments - Narrative (

Lease Commitments - Narrative (Details) $ in Thousands	1 Months Ended	6 Months Ended
	Apr. 30, 2018USD ($)	Jun. 30, 2019USD ($)	May 16, 2019MW	Dec. 31, 2018USD ($)	Sep. 30, 2016MW	Sep. 28, 2016MW	Aug. 31, 2016MW	Jan. 31, 2016MW	Jan. 16, 2016lease	Jan. 15, 2015lease
Operating Leased Assets [Line Items]
Operating leases, capitalized financing costs, investing activities		$ 2,000
Finance leases, capitalized financing costs, investing activities		200
Lessee, operating lease, unguaranteed residual value		21,600
Operating lease, unguaranteed residual value				$ 18,500
PNM
Operating Leased Assets [Line Items]
Operating leases, capitalized financing costs, investing activities		700
Finance leases, capitalized financing costs, investing activities		100
Lessee, operating lease, unguaranteed residual value		8,600
Operating lease, unguaranteed residual value				$ 7,500
PNM | Palo Verde Nuclear Generating Station, Unit 1 and 4 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring | lease										4
Number of leases under which lease term was extended | lease										4
Annual lease payments during renewal period		16,500
PNM | Navajo Nation
Operating Leased Assets [Line Items]
Annual lease payments		6,000
Right-of-way lease payments	$ 6,900
PNM | Palo Verde Nuclear Generating Station, Unit 2 Leases
Operating Leased Assets [Line Items]
Number of leases, expiring | lease									4
Number of leases under which lease term was extended | lease									1
Annual lease payments during renewal period		1,600
Number of megawatts purchased (in megawatts) | MW					64.1	64.1	64.1	64.1
Number of megawatts nuclear generation (in megawatts) | MW			114.6		114.6	114.6	114.6
PNM | Palo Verde Nuclear Generating Station
Operating Leased Assets [Line Items]
Restriction on conveying, transferring, leasing and dividends				5.00%
Loss contingency, lease arrangements (up to)		161,200
TNMP
Operating Leased Assets [Line Items]
Operating leases, capitalized financing costs, investing activities		1,300
Finance leases, capitalized financing costs, investing activities		100
Lessee, operating lease, unguaranteed residual value		12,900
Operating lease, unguaranteed residual value				$ 11,000
Equipment
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset		1,600
Equipment | PNM
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset		500
Equipment | TNMP
Operating Leased Assets [Line Items]
Operating lease, residual value of leased asset		$ 1,100

Lease Commitments - Operating L

Lease Commitments - Operating Lease Balance Sheet Information (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Jan. 01, 2019
Operating leases:
Operating lease assets, net of amortization	$ 143,876	$ 157,440
Current portion of operating lease liabilities	27,396	25,189
Long-term portion of operating lease liabilities	116,464	135,174
PNM
Operating leases:
Operating lease assets, net of amortization	132,057	143,816
Current portion of operating lease liabilities	24,092	21,589
Long-term portion of operating lease liabilities	107,741	124,891
TNMP
Operating leases:
Operating lease assets, net of amortization	11,409	12,942
Current portion of operating lease liabilities	2,913	3,132
Long-term portion of operating lease liabilities	$ 8,403	$ 9,787

Lease Commitments - Finance Lea

Lease Commitments - Finance Lease Balance Sheet Information (Details) $ in Thousands	Jun. 30, 2019USD ($)
Financing leases:
Non-utility property	$ 4,821
Accumulated depreciation	(282)
Non-utility property, net	4,539
Other current liabilities	789
Other deferred credits	3,438
PNM
Financing leases:
Non-utility property	2,516
Accumulated depreciation	(143)
Non-utility property, net	2,373
Other current liabilities	381
Other deferred credits	1,678
TNMP
Financing leases:
Non-utility property	2,305
Accumulated depreciation	(139)
Non-utility property, net	2,166
Other current liabilities	408
Other deferred credits	$ 1,760

Lease Commitments - Schedule of

Lease Commitments - Schedule of Weighted Average Remaining Lease Terms and Discount Rates (Details)	Jun. 30, 2019
Weighted average remaining lease term (In years):
Operating leases	6 years 6 months 18 days
Financing leases	5 years 5 months 15 days
Weighted average discount rate:
Operating leases	3.87%
Financing leases	4.24%
PNM
Weighted average remaining lease term (In years):
Operating leases	6 years 9 months
Financing leases	5 years 5 months 23 days
Weighted average discount rate:
Operating leases	3.87%
Financing leases	4.22%
TNMP
Weighted average remaining lease term (In years):
Operating leases	4 years 5 months 26 days
Financing leases	5 years 5 months 12 days
Weighted average discount rate:
Operating leases	3.90%
Financing leases	4.26%

Lease Commitments - Components

Lease Commitments - Components of Lease Expense (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lease, Cost [Line Items]
Operating lease cost:	$ 7,692	$ 16,312
Less: amounts capitalized	(1,006)	(2,015)
Total operating lease expense	6,686	14,297
Financing lease cost:
Amortization of right-of-use assets	158	282
Interest on lease liabilities	31	64
Less: amounts capitalized	(79)	(157)
Total financing lease expense	110	189
Variable lease expense	32	32
Short-term lease expense	101	195
Total lease expense for the period	6,929	14,713
PNM
Lease, Cost [Line Items]
Operating lease cost:	6,803	14,386
Less: amounts capitalized	(344)	(696)
Total operating lease expense	6,459	13,690
Financing lease cost:
Amortization of right-of-use assets	77	143
Interest on lease liabilities	14	30
Less: amounts capitalized	(41)	(82)
Total financing lease expense	50	91
Variable lease expense	32	32
Short-term lease expense	75	149
Total lease expense for the period	6,616	13,962
TNMP
Lease, Cost [Line Items]
Operating lease cost:	815	1,713
Less: amounts capitalized	(662)	(1,319)
Total operating lease expense	153	394
Financing lease cost:
Amortization of right-of-use assets	81	139
Interest on lease liabilities	17	34
Less: amounts capitalized	(38)	(75)
Total financing lease expense	60	98
Variable lease expense	0	0
Short-term lease expense	2	5
Total lease expense for the period	$ 215	$ 497

Lease Commitments - Schedule _2

Lease Commitments - Schedule of Supplemental Cash Flows Related to Leases (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019USD ($)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 17,494
Operating cash flows from financing leases	38
Finance cash flows from financing leases	130
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	157,440
Financing leases	4,821
PNM
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	16,704
Operating cash flows from financing leases	18
Finance cash flows from financing leases	54
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	143,816
Financing leases	2,516
TNMP
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	529
Operating cash flows from financing leases	20
Finance cash flows from financing leases	76
Non-cash information related to right-of-use assets obtained in exchange for lease obligations:
Operating leases	12,942
Financing leases	$ 2,305

Lease Commitments - Schedule _3

Lease Commitments - Schedule of Future Expected Lease Payments (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Financing
Remainder of 2019	$ 586
2020	982
2021	947
2022	912
2023	802
Later years	696
Total minimum lease payments	4,925
Less: Imputed interest	698
Lease liabilities as of June 30, 2019	4,227
Operating
Remainder of 2019	12,877
2020	30,543
2021	29,152
2022	28,255
2023	18,879
Later years	43,490
Total minimum lease payments	163,196
Less: Imputed interest	19,336
Lease liabilities as of June 30, 2019	143,860
Operating leases
Remainder of 2019		$ 31,772
2020		30,404
2021		29,012
2022		28,175
2023		18,868
Later years		43,489
Total minimum lease payments		181,720
PNM
Financing
Remainder of 2019	281
2020	470
2021	454
2022	437
2023	415
Later years	316
Total minimum lease payments	2,373
Less: Imputed interest	314
Lease liabilities as of June 30, 2019	2,059
Operating
Remainder of 2019	10,529
2020	27,033
2021	26,499
2022	26,235
2023	17,457
Later years	42,328
Total minimum lease payments	150,081
Less: Imputed interest	18,248
Lease liabilities as of June 30, 2019	131,833
Operating leases
Remainder of 2019		27,691
2020		27,000
2021		26,462
2022		26,217
2023		17,447
Later years		42,329
Total minimum lease payments		167,146
TNMP
Financing
Remainder of 2019	305
2020	511
2021	493
2022	475
2023	388
Later years	381
Total minimum lease payments	2,553
Less: Imputed interest	385
Lease liabilities as of June 30, 2019	2,168
Operating
Remainder of 2019	2,014
2020	2,993
2021	2,398
2022	1,846
2023	1,281
Later years	1,151
Total minimum lease payments	11,683
Less: Imputed interest	367
Lease liabilities as of June 30, 2019	$ 11,316
Operating leases
Remainder of 2019		3,664
2020		3,102
2021		2,324
2022		1,795
2023		1,279
Later years		1,150
Total minimum lease payments		$ 13,314

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	May 23, 2017	Jun. 30, 2019	Jun. 30, 2019
Income Tax Contingency [Line Items]
Effective tax rate			8.93%
Tax benefits related to stock awards		$ 0.1	$ 0.8
TNMP
Income Tax Contingency [Line Items]
Effective tax rate			8.81%
Tax benefits related to stock awards		0.1	$ 0.2
PNM
Income Tax Contingency [Line Items]
Effective tax rate			11.20%
Tax benefits related to stock awards		$ 0.1	$ 0.5
NMPRC
Income Tax Contingency [Line Items]
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate	23 years
NMPRC | PNM
Income Tax Contingency [Line Items]
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate	3 years

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Related Party Transaction [Line Items]
Ownership percentage	50.00%		50.00%
Services billings: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	$ 22,925	$ 22,471	$ 49,751	$ 46,150
Services billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	8,385	8,058	18,443	16,423
Services billings: | PNM to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	114	90	189	177
Services billings: | TNMP to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	36	35	71	70
Services billings: | PNMR to NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	54	51	95	130
Renewable energy purchases: | PNM from NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	949	1,004	1,574	1,374
Interconnection billings: | PNM from NMRD
Related Party Transaction [Line Items]
Amount of related party transaction	0	2,052	0	2,052
Interconnection billings: | PNM to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	0	68,200	0	68,200
Interest billings: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	972	747	1,905	809
Interest billings: | PNMR to TNMP
Related Party Transaction [Line Items]
Amount of related party transaction	10	13	42	22
Interest billings: | PNM to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	77	70	149	136
Income tax sharing payments: | PNMR to PNM
Related Party Transaction [Line Items]
Amount of related party transaction	0	0	0	0
Income tax sharing payments: | TNMP to PNMR
Related Party Transaction [Line Items]
Amount of related party transaction	$ 0	$ 0	$ 0	$ 0

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Apr. 01, 2018
Goodwill [Line Items]
Goodwill	$ 278,297	$ 278,297	$ 278,297
PNM
Goodwill [Line Items]
Goodwill	51,632	51,632		$ 51,600
Goodwill fair value exceeded by its carrying value				19.00%
TNMP
Goodwill [Line Items]
Goodwill	$ 226,665	$ 226,665		$ 226,700
Goodwill fair value exceeded by its carrying value				32.00%

Uncategorized Items - pnm630201

Label	Element	Value
Noncontrolling Interest [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	$ 66,195,000
Noncontrolling Interest [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	66,195,000
Common Stock [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	1,157,665,000
Common Stock [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	1,264,918,000
Retained Earnings [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	644,736,000
Retained Earnings [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	265,557,000
Parent [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	1,695,253,000
Parent [Member] | Public Service Company of New Mexico [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterestAdjustedBalance1	$ 1,422,174,000