Cover Page - USD ($) $ in Billions	12 Months Ended
Cover Page - USD ($) $ in Billions	Dec. 31, 2019	Jan. 31, 2020	Jun. 30, 2019
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-14514
Entity Registrant Name	Consolidated Edison, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	13-3965100
Entity Address, Address Line One	4 Irving Place,
Entity Address, City or Town	New York,
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10003
City Area Code	(212)
Local Phone Number	460-4600
Title of 12(b) Security	Common Shares ($.10 par value)
Trading Symbol	ED
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	No
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 29.1
Entity Common Stock, Shares Outstanding		333,775,472
Amendment Flag	false
Document Fiscal Year Focus	2019
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Entity Central Index Key	0001047862
Documents Incorporated by Reference	Documents Incorporated By Reference Portions of Con Edison’s definitive proxy statement for its Annual Meeting of Stockholders to be held on May 18, 2020, to be filed with the Commission pursuant to Regulation 14A, not later than 120 days after December 31, 2019, is incorporated in Part III of this report.
CECONY
Document Information [Line Items]
Entity File Number	1-1217
Entity Registrant Name	Consolidated Edison Company of New York, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	13-5009340
Entity Address, Address Line One	4 Irving Place,
Entity Address, City or Town	New York,
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10003
City Area Code	(212)
Local Phone Number	460-4600
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Amendment Flag	false
Document Fiscal Year Focus	2019
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Entity Central Index Key	0000023632

Consolidated Income Statement - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
OPERATING REVENUES
Total operating revenues	$ 12,574	$ 12,337	$ 12,033
OPERATING EXPENSES
Depreciation and amortization	1,684	1,438	1,341
Taxes, other than income taxes	2,406	2,266	2,155
TOTAL OPERATING EXPENSES	9,898	9,804	9,260
Gain on sale of solar electric production project in 2017	0	0	1
Gain on acquisition of Sempra Solar Holdings, LLC	0	131	0
OPERATING INCOME	2,676	2,664	2,774
OTHER INCOME (DEDUCTIONS)
Investment income	96	119	111
Other income	45	17	15
Allowance for equity funds used during construction	14	12	11
Other deductions	(104)	(210)	(185)
TOTAL OTHER INCOME (DEDUCTIONS)	51	(62)	(48)
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,727	2,602	2,726
INTEREST EXPENSE
Interest on long-term debt	888	780	726
Other interest	116	49	11
Allowance for borrowed funds used during construction	(13)	(10)	(8)
NET INTEREST EXPENSE	991	819	729
INCOME BEFORE INCOME TAX EXPENSE	1,736	1,783	1,997
INCOME TAX EXPENSE	296	401	472
NET INCOME	1,440	1,382	1,525
Income attributable to non-controlling interest	97	0	0
NET INCOME FOR COMMON STOCK	$ 1,343	$ 1,382	$ 1,525
Net income per common share — basic (in dollars per share)	$ 4.09	$ 4.43	$ 4.97
Net income per common share — diluted (in dollars per share)	$ 4.08	$ 4.42	$ 4.94
AVERAGE NUMBER OF SHARES OUTSTANDING — BASIC (in shares)	328.5	311.7	307.1
AVERAGE NUMBER OF SHARES OUTSTANDING — DILUTED (in shares)	329.5	312.9	308.8
CECONY
OPERATING REVENUES
Total operating revenues	$ 10,821	$ 10,680	$ 10,468
OPERATING EXPENSES
Depreciation and amortization	1,373	1,276	1,195
Taxes, other than income taxes	2,295	2,156	2,057
TOTAL OPERATING EXPENSES	8,473	8,326	7,919
OPERATING INCOME	2,348	2,354	2,549
OTHER INCOME (DEDUCTIONS)
Investment income	40	13	14
Allowance for equity funds used during construction	12	11	10
Other deductions	(87)	(167)	(161)
TOTAL OTHER INCOME (DEDUCTIONS)	(35)	(143)	(137)
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,313	2,211	2,412
INTEREST EXPENSE
Interest on long-term debt	672	662	615
Other interest	67	36	14
Allowance for borrowed funds used during construction	(11)	(9)	(6)
NET INTEREST EXPENSE	728	689	623
INCOME BEFORE INCOME TAX EXPENSE	1,585	1,522	1,789
INCOME TAX EXPENSE	335	326	685
NET INCOME FOR COMMON STOCK	1,250	1,196	1,104
Electric
OPERATING REVENUES
Total operating revenues	8,694	8,612	8,612
Electric \| CECONY
OPERATING REVENUES
Total operating revenues	8,062	7,971	7,972
Gas
OPERATING REVENUES
Total operating revenues	2,391	2,327	2,133
OPERATING EXPENSES
Operating costs	880	1,041	808
Gas \| CECONY
OPERATING REVENUES
Total operating revenues	2,132	2,078	1,901
OPERATING EXPENSES
Operating costs	606	643	510
Steam
OPERATING REVENUES
Total operating revenues	627	631	595
Steam \| CECONY
OPERATING REVENUES
Total operating revenues	627	631	595
Non-utility
OPERATING REVENUES
Total operating revenues	862	767	693
Power
OPERATING EXPENSES
Operating costs	1,546	1,644	1,601
Power \| CECONY
OPERATING EXPENSES
Operating costs	1,357	1,433	1,415
Fuel
OPERATING EXPENSES
Operating costs	207	263	216
Fuel \| CECONY
OPERATING EXPENSES
Operating costs	207	263	216
Other operations and maintenance
OPERATING EXPENSES
Operating costs	3,175	3,152	3,139
Other operations and maintenance \| CECONY
OPERATING EXPENSES
Operating costs	$ 2,635	$ 2,555	$ 2,526

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 1,343	$ 1,382	$ 1,525
Net Income	1,440	1,382	1,525
INCOME ATTRIBUTABLE TO NON-CONTROLLING INTEREST	(97)	0	0
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	(5)	10	1
Other income, net of taxes	2	0	0
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(3)	10	1
COMPREHENSIVE INCOME	1,340	1,392	1,526
CECONY
Net income	1,250	1,196	1,104
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	(3)	1	1
Other income, net of taxes	2	0	0
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(1)	1	1
COMPREHENSIVE INCOME	$ 1,249	$ 1,197	$ 1,105

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

+ References

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+ Details

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
OPERATING ACTIVITIES
Net Income	$ 1,440	$ 1,382	$ 1,525
Net income	1,343	1,382	1,525
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,684	1,438	1,341
Deferred income taxes	308	408	485
Rate case amortization and accruals	(116)	(117)	(124)
Common equity component of allowance for funds used during construction	(14)	(12)	(11)
Net derivative (gains)/losses	27	8	(4)
(Gain) on Sale of Assets	(14)	0	0
Unbilled revenue and net unbilled revenue deferrals	(3)	18	(113)
(Gain) on sale of retail electric supply business and solar electric production projects	0	0	(1)
(Gain) on existing project interests due to acquisition of Sempra Solar Holdings, LLC	0	(131)	0
Other non-cash items, net	(18)	115	5
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	23	(140)	9
Materials and supplies, including fuel oil and gas in storage	6	(20)	5
Revenue decoupling mechanism receivable	(76)	0	0
Other receivables and other current assets	54	(62)	0
Taxes receivable	29	27	15
Prepayments	(73)	(7)	(19)
Accounts payable	10	(46)	95
Pensions and retiree benefits obligations, net	357	325	414
Pensions and retiree benefits contributions	(357)	(479)	(467)
Accrued taxes	10	(49)	44
Accrued interest	24	(35)	(7)
Superfund and environmental remediation costs, net	(9)	(19)	(14)
Distributions from equity investments	57	107	108
System benefit charge	20	92	101
Deferred charges, noncurrent assets and other regulatory assets	(492)	(393)	2,376
Deferred credits and other regulatory liabilities	278	436	(2,524)
Other current and noncurrent liabilities	(21)	(151)	128
NET CASH FLOWS FROM OPERATING ACTIVITIES	3,134	2,695	3,367
INVESTING ACTIVITIES
Utility construction expenditures	(3,238)	(3,251)	(3,028)
Cost of removal less salvage	(295)	(258)	(248)
Non-utility construction expenditures	(248)	(246)	(415)
Acquisition of Sempra Solar Holdings, LLC, net of cash acquired	0	(1,488)	0
Proceeds from sale of assets	192	5	34
Other investing activities	22	34	37
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,782)	(5,471)	(3,710)
FINANCING ACTIVITIES
Net (payment)/issuance of short-term debt	(874)	1,989	(477)
Issuance of long-term debt	3,017	3,030	1,697
Retirement of long-term debt	(1,195)	(1,938)	(434)
Debt issuance costs	(32)	(61)	(19)
Common stock dividends	(924)	(842)	(803)
Issuance of common shares - public offering	825	705	343
Issuance of common shares for stock plans	54	53	51
Distribution to noncontrolling interest	(12)	2	(1)
NET CASH FLOWS FROM FINANCING ACTIVITIES	859	2,938	357
CASH, TEMPORARY CASH INVESTMENTS AND RESTRICTED CASH:
NET CHANGE FOR THE PERIOD	211	162	14
BALANCE AT BEGINNING OF PERIOD	1,006	844	830
BALANCE AT END OF PERIOD	1,217	1,006	844
Cash paid/(received) during the period for:
Interest	876	805	725
Income taxes	(26)	0	(29)
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	336	369	432
Issuance of common shares for dividend reinvestment	47	47	46
Electric and Gas Transmission Projects
INVESTING ACTIVITIES
Investments in/acquisitions of projects	(205)	(248)	(45)
Renewable Electric Production Projects
INVESTING ACTIVITIES
Investments in/acquisitions of projects	(10)	(19)	(45)
CECONY
OPERATING ACTIVITIES
Net income	1,250	1,196	1,104
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,373	1,276	1,195
Deferred income taxes	128	354	575
Rate case amortization and accruals	(117)	(133)	(142)
Common equity component of allowance for funds used during construction	(12)	(11)	(10)
(Gain) on Sale of Assets	(14)	0	0
Unbilled revenue and net unbilled revenue deferrals	(3)	(4)	(17)
Other non-cash items, net	7	13	(59)
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	3	(153)	15
Materials and supplies, including fuel oil and gas in storage	11	(17)	(17)
Revenue decoupling mechanism receivable	(76)	0	0
Other receivables and other current assets	54	(96)	23
Accounts receivables from affiliated companies	141	(150)	45
Prepayments	(61)	(9)	(8)
Accounts payable	(7)	(27)	125
Accounts payable to affiliated companies	(4)	7	0
Pensions and retiree benefits obligations, net	330	293	370
Pensions and retiree benefits contributions	(325)	(440)	(420)
Accrued taxes	11	(47)	52
Accrued taxes to affiliated companies	0	(72)	(47)
Accrued interest	1	(1)	2
Superfund and environmental remediation costs, net	(12)	(18)	(12)
System benefit charge	18	86	85
Deferred charges, noncurrent assets and other regulatory assets	(486)	(314)	2,212
Deferred credits and other regulatory liabilities	306	549	(2,242)
Other current and noncurrent liabilities	(14)	(78)	37
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,502	2,204	2,866
INVESTING ACTIVITIES
Utility construction expenditures	(3,028)	(3,051)	(2,840)
Cost of removal less salvage	(288)	(255)	(240)
Proceeds from sale of assets	192	0	0
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,124)	(3,306)	(3,080)
FINANCING ACTIVITIES
Net (payment)/issuance of short-term debt	(55)	1,042	(450)
Issuance of long-term debt	1,300	2,740	1,200
Retirement of long-term debt	(475)	(1,836)	0
Debt issuance costs	(21)	(30)	(15)
Capital contribution by parent	900	120	301
Dividend to parent	(912)	(846)	(796)
NET CASH FLOWS FROM FINANCING ACTIVITIES	737	1,190	240
CASH, TEMPORARY CASH INVESTMENTS AND RESTRICTED CASH:
NET CHANGE FOR THE PERIOD	115	88	26
BALANCE AT BEGINNING OF PERIOD	818	730	704
BALANCE AT END OF PERIOD	933	818	730
Cash paid/(received) during the period for:
Interest	676	662	602
Income taxes	73	195	108
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	285	299	351
Software Licenses
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Capital expenditures incurred but unpaid as of end of period	80	100	0
Software Licenses \| CECONY
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Capital expenditures incurred but unpaid as of end of period	76	95	0
Equipment
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Capital expenditures incurred but unpaid as of end of period	33	0	0
Equipment \| CECONY
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Capital expenditures incurred but unpaid as of end of period	$ 33	$ 0	$ 0

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and temporary cash investments	$ 981	$ 895
Accounts receivable - customers, less allowance for uncollectible accounts	1,236	1,267
Other receivables, less allowance for uncollectible accounts	184	285
Taxes receivable	20	49
Accrued unbilled revenue	599	514
Fuel oil, gas in storage, materials and supplies, at average cost	352	358
Prepayments	260	187
Regulatory assets	128	76
Restricted cash	236	111
Revenue decoupling mechanism receivable	76	0
Other current assets	200	122
TOTAL CURRENT ASSETS	4,272	3,864
INVESTMENTS	2,065	1,766
UTILITY PLANT, AT ORIGINAL COST
General	3,562	3,331
TOTAL	48,136	45,371
Less: Accumulated depreciation	10,322	9,769
Net	37,814	35,602
Construction work in progress	1,937	1,978
NET UTILITY PLANT	39,751	37,580
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	3,829	4,000
Construction work in progress	309	169
NET PLANT	43,889	41,749
OTHER NONCURRENT ASSETS
Goodwill	446	440
Intangible assets, less accumulated amortization of $126 and $29 in 2019 and 2018, respectively	1,557	1,654
Operating lease right-of-use-asset	857
Regulatory assets	4,859	4,294
Other deferred charges and noncurrent assets	134	153
TOTAL OTHER NONCURRENT ASSETS	7,853	6,541
TOTAL ASSETS	58,079	53,920
CURRENT LIABILITIES
Long-term debt due within one year	1,446	650
Term Loan	0	825
Notes payable	1,692	1,741
Accounts payable	1,164	1,187
Customer deposits	346	351
Accrued taxes	76	61
Accrued interest	153	129
Accrued wages	102	109
Fair value of derivative liabilities	123	50
Regulatory liabilities	102	114
System benefit charge	647	627
Operating lease liabilities	65
Other current liabilities	371	363
TOTAL CURRENT LIABILITIES	6,287	6,207
NONCURRENT LIABILITIES
Provision for injuries and damages	130	146
Pensions and retiree benefits	1,516	1,228
Superfund and other environmental costs	734	779
Asset retirement obligations	425	450
Fair value of derivative liabilities	105	16
Deferred income taxes and unamortized investment tax credits	6,227	5,820
Operating lease liabilities	809
Regulatory liabilities	4,827	4,641
Other deferred credits and noncurrent liabilities	279	299
TOTAL NONCURRENT LIABILITIES	15,052	13,379
LONG-TERM DEBT	18,527	17,495
EQUITY
Common shareholders’ equity	18,022	16,726
Noncontrolling interest	191	113
TOTAL EQUITY (See Statement of Equity)	18,213	16,839
TOTAL LIABILITIES AND EQUITY	58,079	53,920
Electric
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	31,866	30,378
Gas
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	10,107	9,100
Steam
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	2,601	2,562
CECONY
CURRENT ASSETS
Cash and temporary cash investments	933	818
Accounts receivable - customers, less allowance for uncollectible accounts	1,153	1,163
Other receivables, less allowance for uncollectible accounts	120	211
Taxes receivable	0	5
Accrued unbilled revenue	477	392
Accounts receivable from affiliated companies	73	214
Fuel oil, gas in storage, materials and supplies, at average cost	293	304
Prepayments	178	117
Regulatory assets	113	64
Revenue decoupling mechanism receivable	76
Other current assets	127	69
TOTAL CURRENT ASSETS	3,543	3,357
INVESTMENTS	461	385
UTILITY PLANT, AT ORIGINAL COST
General	3,271	3,056
TOTAL	45,090	42,508
Less: Accumulated depreciation	9,490	8,988
Net	35,600	33,520
Construction work in progress	1,812	1,850
NET UTILITY PLANT	37,412	35,370
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	2	4
NET PLANT	37,414	35,374
OTHER NONCURRENT ASSETS
Goodwill	245	245
Operating lease right-of-use-asset	601	0
Regulatory assets	4,487	3,923
Other deferred charges and noncurrent assets	51	69
TOTAL OTHER NONCURRENT ASSETS	5,139	3,992
TOTAL ASSETS	46,557	43,108
CURRENT LIABILITIES
Long-term debt due within one year	350	475
Notes payable	1,137	1,192
Accounts payable	956	977
Customer deposits	334	339
Accounts payable to affiliated companies	13	17
Accrued taxes	71	55
Accrued interest	113	112
Accrued wages	92	99
Fair value of derivative liabilities	81	25
Regulatory liabilities	63	73
System benefit charge	587	569
Operating lease liabilities	54
Other current liabilities	280	267
TOTAL CURRENT LIABILITIES	4,131	4,200
NONCURRENT LIABILITIES
Provision for injuries and damages	125	141
Pensions and retiree benefits	1,241	952
Superfund and other environmental costs	654	693
Asset retirement obligations	362	292
Fair value of derivative liabilities	65	6
Deferred income taxes and unamortized investment tax credits	6,000	5,739
Operating lease liabilities	551
Regulatory liabilities	4,427	4,258
Other deferred credits and noncurrent liabilities	240	241
TOTAL NONCURRENT LIABILITIES	13,665	12,322
LONG-TERM DEBT	14,614	13,676
EQUITY
Common shareholders’ equity	14,147	12,910
TOTAL LIABILITIES AND EQUITY	46,557	43,108
CECONY \| Electric
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	29,989	28,595
CECONY \| Gas
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	9,229	8,295
CECONY \| Steam
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	$ 2,601	$ 2,562

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounts receivable - customers, allowance for uncollectible accounts	$ 70	$ 62
Other receivables, allowance for uncollectible accounts	4	5
Non-utility property, accumulated depreciation	391	275
Intangible assets, accumulated amortization	126	29
CECONY
Accounts receivable - customers, allowance for uncollectible accounts	65	57
Other receivables, allowance for uncollectible accounts	3	3
Non-utility property, accumulated depreciation	$ 25	$ 25

Consolidated Statement of Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Retained Earnings	Treasury Stock	Capital Stock Expense	Accumulated Other Comprehensive Income/(Loss)	Noncontrolling Interest	CECONY	CECONY Common Stock	CECONY Additional Paid-In Capital	CECONY Retained Earnings	CECONY Repurchased Con Edison Stock	CECONY Capital Stock Expense	CECONY Accumulated Other Comprehensive Income/(Loss)
BALANCE AS OF BEGINNING OF PERIOD (in shares) at Dec. 31, 2016		305,000,000								235,000,000
BALANCE AS OF BEGINNING OF PERIOD at Dec. 31, 2016	$ 14,306	$ 33	$ 5,854	$ 9,559	$ (1,038)	$ (83)	$ (27)	$ 8							$ (7)
BALANCE AS OF BEGINNING OF PERIOD at Dec. 31, 2016									$ 11,829	$ 589	$ 4,347	$ 7,923	$ (962)	$ (61)	(7)
TREASURY STOCK, BALANCE AS OF BEGINNING OF PERIOD (in shares) at Dec. 31, 2016					23,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,525								1,104			1,104
Net Income	1,525			1,525
Common stock dividends	(849)			(849)					(796)			(796)
Issuance of common shares - public offering (in shares)		5,000,000
Issuance of common shares - public offering	343	$ 1	344			(2)
Issuance of common shares for stock plans	100		100
Capital contribution by parent									301		302			(1)
Other comprehensive income	1						1		1						1
Noncontrolling interest	(1)							(1)
BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2017		310,000,000								235,000,000
BALANCE AS OF END OF PERIOD at Dec. 31, 2017	15,425	$ 34	6,298	10,235	$ (1,038)	(85)	(26)	7							(6)
BALANCE AS OF END OF PERIOD at Dec. 31, 2017									12,439	$ 589	4,649	8,231	(962)	(62)	(6)
TREASURY STOCK, BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2017					23,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,382								1,196			1,196
Net Income	1,382			1,382
Common stock dividends	(889)			(889)					(846)			(846)
Issuance of common shares - public offering (in shares)		11,000,000
Issuance of common shares - public offering	705		719			(14)
Issuance of common shares for stock plans	100		100
Capital contribution by parent									120		120
Other comprehensive income	10						10		1						1
Noncontrolling interest	$ 106							106
BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2018	320,960,396	321,000,000								235,488,094
BALANCE AS OF END OF PERIOD at Dec. 31, 2018	$ 16,839	$ 34	7,117	10,728	$ (1,038)	(99)	(16)	113							(5)
BALANCE AS OF END OF PERIOD at Dec. 31, 2018	16,726								12,910	$ 589	4,769	8,581	(962)	(62)	(5)
TREASURY STOCK, BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2018					23,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,343								1,250			1,250
Net Income	1,440			1,343				97
Common stock dividends	(971)			(971)					(912)			(912)
Issuance of common shares - public offering (in shares)		12,000,000
Issuance of common shares - public offering	825	$ 1	835			(11)
Issuance of common shares for stock plans	102		102
Capital contribution by parent									900		900
Other comprehensive income	(3)						(3)		$ (1)						(1)
Noncontrolling interest	$ (19)							(19)
BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2019	332,629,597	333,000,000							235,488,094	235,000,000
BALANCE AS OF END OF PERIOD at Dec. 31, 2019	$ 18,213	$ 35	$ 8,054	$ 11,100	$ (1,038)	$ (110)	$ (19)	$ 191							(6)
BALANCE AS OF END OF PERIOD at Dec. 31, 2019	$ 18,022								$ 14,147	$ 589	$ 5,669	$ 8,919	$ (962)	$ (62)	$ (6)
TREASURY STOCK, BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2019					23,000,000

Consolidated Statement of Capitalization - USD ($) shares in Millions, $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Schedule of Capitalization, Equity [Line Items]
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS (in shares)	333	321
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS	$ 18,041	$ 16,742
Pension plan liability adjustments, net of taxes	(17)	(12)
Unrealized losses on derivatives qualified as cash flow hedges, less reclassification adjustment for gains/(losses) included in net income and reclassification adjustment for unrealized losses included in regulatory assets, net of taxes	(2)	(4)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(19)	(16)
Equity	18,022	16,726
Noncontrolling interest	191	113
TOTAL EQUITY (See Statement of Equity)	$ 18,213	$ 16,839
CECONY
Schedule of Capitalization, Equity [Line Items]
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS (in shares)	235	235
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS	$ 14,153	$ 12,915
Unrealized losses on derivatives qualified as cash flow hedges, less reclassification adjustment for gains/(losses) included in net income and reclassification adjustment for unrealized losses included in regulatory assets, net of taxes	(6)	(5)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(6)	(5)
Equity	14,147	12,910
TOTAL SHAREHOLDER’S EQUITY (See Statement of Shareholder’s Equity)	$ 14,147	$ 12,910

Consolidated Statement of Capitalization - Long-term Debt - USD ($)
$ in Millions

Dec. 31, 2019

Dec. 31, 2018

Schedule of Capitalization, Long-term Debt [Line Items]

Other long-term debt

$ 974

$ 304

Unamortized debt expense

(141)

(152)

Unamortized debt discount

(37)

(33)

TOTAL

19,973

18,145

Less: Long-term debt due within one year

1,446

650

TOTAL LONG-TERM DEBT

18,527

17,495

TOTAL CAPITALIZATION

36,549

34,221

CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Unamortized debt expense

(115)

(107)

Unamortized debt discount

(36)

(32)

TOTAL

14,964

14,151

Less: Long-term debt due within one year

350

475

TOTAL LONG-TERM DEBT

14,614

13,676

TOTAL CAPITALIZATION

$ 28,761

26,586

Copper Mountain Solar 2

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.52%

TOTAL PROJECT DEBT

^[1]

$ 224

230

Coram

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

^[1]

$ 150

160

Coram | Minimum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.96%

Coram | Maximum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.52%

Copper Mountain Solar 3

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.61%

TOTAL PROJECT DEBT

^[1]

$ 289

298

CED Southwest

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.72%

TOTAL PROJECT DEBT

^[1]

$ 456

Wind Holdings

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.41%

TOTAL PROJECT DEBT

$ 123

137

Copper Mountain Solar 1

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.81%

TOTAL PROJECT DEBT

^[1]

$ 67

Mesquite Solar 1

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

$ 193

208

Mesquite Solar 1 | Minimum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.24%

Mesquite Solar 1 | Maximum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.03%

Texas Solar 4

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

$ 56

Texas Solar 4 | Minimum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.28%

Texas Solar 4 | Maximum

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.95%

California Solar 2

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.94%

TOTAL PROJECT DEBT

$ 98

103

California Solar 3

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.07%

TOTAL PROJECT DEBT

$ 86

California Solar

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.78%

TOTAL PROJECT DEBT

$ 184

190

California Solar 4

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.82%

TOTAL PROJECT DEBT

$ 297

Broken Bow II

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.82%

TOTAL PROJECT DEBT

$ 68

Texas Solar 5

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.53%

TOTAL PROJECT DEBT

$ 145

150

Texas Solar 7

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.21%

TOTAL PROJECT DEBT

$ 199

206

Upton County Solar

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

TOTAL PROJECT DEBT

$ 90

Other project debt

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

Project Debt

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

2,737

2,076

Debentures

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL

15,990

15,500

Debentures | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL

$ 14,665

13,840

Debentures | Debenture Series 2009A, 4.96% Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.96%

TOTAL

$ 0

Debentures | Debenture Series 2009B, 6.65% Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.65%

TOTAL

$ 0

475

Debentures | Debenture Series 2009B, 6.65% Due 2019 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.65%

TOTAL

$ 0

475

Debentures | Debenture 2017A, 2.00 Percent, Due 2019

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.00%

TOTAL

$ 0

400

Debentures | Debenture Series 2010A, 4.45% Due 2020

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

TOTAL

$ 350

350

Debentures | Debenture Series 2010A, 4.45% Due 2020 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

TOTAL

$ 350

350

Debentures | Debenture Series 2016A, 2.00% Due 2021

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.00%

TOTAL

$ 500

500

Debentures | Debenture 2018C, 2.75 Percent, Due 2021

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.35%

TOTAL

^[2]

$ 640

640

Debentures | Debenture 2018C, 2.75 Percent, Due 2021 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.35%

TOTAL

$ 640

640

Debentures | Debenture 2014B, 3.30 Percent, Due 2024

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.30%

TOTAL

$ 250

250

Debentures | Debenture 2014B, 3.30 Percent, Due 2024 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.30%

TOTAL

$ 250

250

Debentures | Debenture Series 2016B, 2.90% Due 2026

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.90%

TOTAL

$ 250

250

Debentures | Debenture Series 2016B, 2.90% Due 2026 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.90%

TOTAL

$ 250

250

Debentures | Debenture Series 1997F, 6.50% Due 2027

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.50%

TOTAL

$ 80

Debentures | Debenture Series 2017B, 3.125% Due 2027

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.125%

TOTAL

$ 350

350

Debentures | Debenture Series 2017B, 3.125% Due 2027 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.125%

TOTAL

$ 350

350

Debentures | Debenture Series 2018A, 3.80% Due 2028

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.80%

TOTAL

$ 300

300

Debentures | Debenture Series 2018A, 3.80% Due 2028 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.80%

TOTAL

$ 300

300

Debentures | Debenture Series 2018D, 4.00% Due 2028

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.00%

TOTAL

$ 500

500

Debentures | Debenture Series 2018D, 4.00% Due 2028 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.00%

TOTAL

$ 500

500

Debentures | Debenture 2019B, 2.94 Percent, Due 2029

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

2.94%

TOTAL

$ 44

Debentures | Debenture Series 2003A, 5.875% Due 2033

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.875%

TOTAL

$ 175

175

Debentures | Debenture Series 2003A, 5.875% Due 2033 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.875%

TOTAL

$ 175

175

Debentures | Debenture Series 2003C, 5.10% Due 2033

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.10%

TOTAL

$ 200

200

Debentures | Debenture Series 2003C, 5.10% Due 2033 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.10%

TOTAL

$ 200

200

Debentures | Debenture Series 2004B, 5.70% Due 2034

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 200

200

Debentures | Debenture Series 2004B, 5.70% Due 2034 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 200

200

Debentures | Debenture Series 2005A, 5.30% Due 2035

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

TOTAL

$ 350

350

Debentures | Debenture Series 2005A, 5.30% Due 2035 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.30%

TOTAL

$ 350

350

Debentures | Debenture Series 2005B, 5.25% Due 2035

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.25%

TOTAL

$ 125

125

Debentures | Debenture Series 2005B, 5.25% Due 2035 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.25%

TOTAL

$ 125

125

Debentures | Debenture Series 2006A, 5.85% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

TOTAL

$ 400

400

Debentures | Debenture Series 2006A, 5.85% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.85%

TOTAL

$ 400

400

Debentures | Debenture Series 2006B, 6.20% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.20%

TOTAL

$ 400

400

Debentures | Debenture Series 2006B, 6.20% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.20%

TOTAL

$ 400

400

Debentures | Debenture Series 2006E, 5.70% Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 250

250

Debentures | Debenture Series 2006E, 5.70% Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 250

250

Debentures | Debenture Series 2007A, 6.30% Due 2037

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.30%

TOTAL

$ 525

525

Debentures | Debenture Series 2007A, 6.30% Due 2037 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.30%

TOTAL

$ 525

525

Debentures | Debenture 2008B, 6.75 Percent, Due 2038

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.75%

TOTAL

$ 600

600

Debentures | Debenture 2008B, 6.75 Percent, Due 2038 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.75%

TOTAL

$ 600

600

Debentures | Debenture 2009B, 6.00 Percent, Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

6.00%

TOTAL

$ 60

Debentures | Debenture 2009C, 5.50 Percent, Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

TOTAL

$ 600

600

Debentures | Debenture 2009C, 5.50 Percent, Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

TOTAL

$ 600

600

Debentures | Debenture 2019C, 3.46 Percent, Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.46%

TOTAL

$ 38

Debentures | Debenture 2010B, 5.70 Percent, Due 2040

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 350

350

Debentures | Debenture 2010B, 5.70 Percent, Due 2040 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.70%

TOTAL

$ 350

350

Debentures | Debenture 2010B, 5.50 Percent, Due 2040

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

5.50%

TOTAL

$ 115

115

Debentures | Debenture 2012A, 4.20 Percent, Due 2042

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.20%

TOTAL

$ 400

400

Debentures | Debenture 2012A, 4.20 Percent, Due 2042 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.20%

TOTAL

$ 400

400

Debentures | Debenture 2013A, 3.95 Percent, Due 2043

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.95%

TOTAL

$ 700

700

Debentures | Debenture 2013A, 3.95 Percent, Due 2043 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.95%

TOTAL

$ 700

700

Debentures | Debenture 2014A, 4.45 Percent, Due 2044

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

TOTAL

$ 850

850

Debentures | Debenture 2014A, 4.45 Percent, Due 2044 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.45%

TOTAL

$ 850

850

Debentures | Debenture 2015A, 4.50 Percent, Due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

TOTAL

$ 650

650

Debentures | Debenture 2015A, 4.50 Percent, Due 2045 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

TOTAL

$ 650

650

Debentures | Debenture 2015A, 4.95 Percent, Due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.95%

TOTAL

$ 120

120

Debentures | Debenture Series 2015B, 4.69% due 2045

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.69%

TOTAL

$ 100

100

Debentures | Debenture 2016A, 3.85 Percent, Due 2046

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.85%

TOTAL

$ 550

550

Debentures | Debenture 2016A, 3.85 Percent, Due 2046 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.85%

TOTAL

$ 550

550

Debentures | Debenture Series 2016A. 3.88% Due 2046

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.88%

TOTAL

$ 75

Debentures | Debenture Series 2017A, 3.875% Due 2047

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.875%

TOTAL

$ 500

500

Debentures | Debenture Series 2017A, 3.875% Due 2047 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.875%

TOTAL

$ 500

500

Debentures | Debenture Series 2018E, 4.65% Due 2048

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.65%

TOTAL

$ 600

600

Debentures | Debenture Series 2018E, 4.65% Due 2048 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.65%

TOTAL

$ 600

600

Debentures | Debenture Series 2018A, 4.35% Due 2048

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.35%

TOTAL

$ 125

125

Debentures | Debenture Series 2018B, 4.35% Due 2048

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.35%

TOTAL

$ 25

Debentures | Debenture 2019A, 4.125 Percent, Due 2049

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.125%

TOTAL

$ 700

Debentures | Debenture 2019A, 4.125 Percent, Due 2049 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.125%

TOTAL

$ 700

Debentures | Debenture 2019A, 3.73 Percent, Due 2049

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.73%

TOTAL

$ 43

Debentures | Debenture Series 2014C, 4.625% Due 2054

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.625%

TOTAL

$ 750

750

Debentures | Debenture Series 2014C, 4.625% Due 2054 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.625%

TOTAL

$ 750

750

Debentures | Debenture Series 2016C, 4.30% Due 2056

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.30%

TOTAL

$ 500

500

Debentures | Debenture Series 2016C, 4.30% Due 2056 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.30%

TOTAL

$ 500

500

Debentures | Debenture Series 2017C, 4.00% Due 2057

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.00%

TOTAL

$ 350

350

Debentures | Debenture Series 2017C, 4.00% Due 2057 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.00%

TOTAL

$ 350

350

Debentures | Debenture Series 2018B, 4.50% Due 2058

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

TOTAL

$ 700

700

Debentures | Debenture Series 2018B, 4.50% Due 2058 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

4.50%

TOTAL

$ 700

700

Debentures | Debenture 2019B, 3.70 Percent, Due 2059

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.70%

TOTAL

$ 600

Debentures | Debenture 2019B, 3.70 Percent, Due 2059 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

3.70%

TOTAL

$ 600

Tax-Exempt Debt

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL PROJECT DEBT

450

Tax-Exempt Debt | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

TOTAL

$ 450

450

Tax-Exempt Debt | Tax Exempt Debt Series 2010A Due 2036

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.63%

TOTAL PROJECT DEBT

^[2]

$ 225

225

Tax-Exempt Debt | Tax Exempt Debt Series 2010A Due 2036 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.63%

TOTAL

^[3]

$ 225

225

Tax-Exempt Debt | Tax Exempt Debt Series 2004C, 1.663% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.63%

TOTAL PROJECT DEBT

^[2]

$ 99

Tax-Exempt Debt | Tax Exempt Debt Series 2004C, 1.663% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.63%

TOTAL

^[3]

$ 99

Tax-Exempt Debt | Tax-Exempt Debt Series 2005A, 1.627% Due 2039

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.59%

TOTAL PROJECT DEBT

^[2]

$ 126

126

Tax-Exempt Debt | Tax-Exempt Debt Series 2005A, 1.627% Due 2039 | CECONY

Schedule of Capitalization, Long-term Debt [Line Items]

Interest Rate

1.59%

TOTAL

^[3]

$ 126

[1]	December 31, 2019 effective rates shown, reflecting variable interest rates on the debt that are reset quarterly or semi-annually and the effect of applicable interest rate swaps, if any
[2]	Rates reset weekly or quarterly; December 31, 2019 rates shown.
[3]	Rates reset weekly or quarterly; December 31, 2019 rates shown.

General	12 Months Ended
General	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	General These combined notes accompany and form an integral part of the separate consolidated financial statements of each of the two separate registrants: Consolidated Edison, Inc. and its subsidiaries (Con Edison) and Consolidated Edison Company of New York, Inc. and its subsidiaries (CECONY). CECONY is a subsidiary of Con Edison and as such its financial condition and results of operations and cash flows, which are presented separately in the CECONY consolidated financial statements, are also consolidated, along with those of Orange and Rockland Utilities, Inc. (O&R), Con Edison Clean Energy Businesses, Inc. (together with its subsidiaries, the Clean Energy Businesses) and Con Edison Transmission, Inc. (together with its subsidiaries, Con Edison Transmission) in Con Edison’s consolidated financial statements. The term “Utilities” is used in these notes to refer to CECONY and O&R. As used in these notes, the term “Companies” refers to Con Edison and CECONY and, except as otherwise noted, the information in these combined notes relates to each of the Companies. However, CECONY makes no representation as to information relating to Con Edison or the subsidiaries of Con Edison other than itself. Con Edison has two regulated utility subsidiaries: CECONY and O&R. CECONY provides electric service and gas service in New York City and Westchester County. The company also provides steam service in parts of Manhattan. O&R, along with its regulated utility subsidiary, provides electric service in southeastern New York and northern New Jersey and gas service in southeastern New York. Con Edison Clean Energy Businesses, Inc., which through its subsidiaries develop, own and operate renewable and energy infrastructure projects and provide energy-related products and services to wholesale and retail customers. In December 2018, the Clean Energy Businesses acquired Sempra Solar Holdings, LLC. Con Edison Transmission, Inc. invests in electric transmission facilities through its subsidiary, Consolidated Edison Transmission, LLC (CET Electric), and invests in gas pipeline and storage facilities through its subsidiary Con Edison Gas Pipeline and Storage, LLC (CET Gas). See Note U.

Summary of Significant Accounting Policies and Other Matters

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies and Other Matters

Principles of Consolidation

The Companies’ consolidated financial statements include the accounts of their respective majority-owned subsidiaries, and variable interest entities (see Note Q), as required. All intercompany balances and intercompany transactions have been eliminated.

Accounting Policies

The accounting policies of Con Edison and its subsidiaries conform to generally accepted accounting principles in the United States of America (GAAP). For the Utilities, these accounting principles include the accounting rules for regulated operations and the accounting requirements of the Federal Energy Regulatory Commission (FERC) and the state regulators having jurisdiction.

The accounting rules for regulated operations specify the economic effects that result from the causal relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under the accounting rules for regulated operations. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under the accounting rules for regulated operations.

The Utilities’ principal regulatory assets and liabilities are detailed in Note B. The Utilities are receiving or being credited with a return on all of their regulatory assets for which a cash outflow has been made, and are paying or being charged with a return on all of their regulatory liabilities for which a cash inflow has been received. The Utilities’ regulatory assets and liabilities at December 31, 2019 are recoverable from customers, or to be applied for customer benefit, in accordance with rate provisions that have been approved by state regulators.

Other significant accounting policies of the Companies are referenced below in this Note A and in the notes that follow.

Revenue Recognition

The following table presents, for the years ended December 31, 2019 and 2018, revenue from contracts with customers as defined in Accounting Standards Codification (ASC) Topic 606, "Revenue from Contracts with Customers," as well as additional revenue from sources other than contracts with customers, disaggregated by major source. Revenue was recognized for the year ended December 31, 2017 under ASC Topic 605, “Revenue Recognition,” and was materially consistent with revenue that would have been recognized under Topic 606.



	2019				2018
(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)	Total operating revenues	Revenues from contracts with customers		Other revenues (a)	Total operating revenues
CECONY
Electric	$7,913		$149	$8,062	$7,920		$51	$7,971
Gas	2,097		35	2,132	2,052		26	2,078
Steam	610		17	627	625		6	631
Total CECONY	$10,620		$201	$10,821	$10,597		$83	$10,680
O&R
Electric	627		7	634	647		(5)	642
Gas	247		12	259	256		(7)	249
Total O&R	$874		$19	$893	$903		$(12)	$891
Clean Energy Businesses
Renewables	575	(b)	—	575	329	(b)	—	329
Energy services	71		—	71	95		—	95
Other	—		211	211	—		339	339
Total Clean Energy Businesses	$646		$211	$857	$424		$339	$763
Con Edison Transmission	4		—	4	4		—	4
Other (c)	—		(1)	(1)	—		(1)	(1)
Total Con Edison	$12,144		$430	$12,574	$11,928		$409	$12,337

(a) For the Utilities, this includes revenue from alternative revenue programs, such as the revenue decoupling mechanisms under their New York electric and gas rate plans.For the Clean Energy Businesses, this includes revenue from wholesale services.

(b) Included within the total for Renewables revenue at the Clean Energy Businesses is $14 million and $103 million for the years ended December 31, 2019 and 2018, respectively, of revenue related to engineering, procurement and construction services.

Revenues are recorded as energy is delivered, generated or services are provided and billed to customers, except for services under percentage-of-completion contracts. Amounts billed are recorded in accounts receivable - customers, with payment generally due the following month. Con Edison’s and the Utilities’ accounts receivable - customers balance also reflects the Utilities’ purchase of receivables from energy service companies to support retail choice programs. Accrued revenues not yet billed to customers are recorded as accrued unbilled revenues.

The Utilities have the obligation to deliver electricity, gas and steam energy to their customers. As the energy is immediately available for use upon delivery to the customer, the energy and its delivery are identifiable as a single performance obligation. The Utilities recognize revenues as this performance obligation is satisfied over time as the Utilities deliver, and the customers simultaneously receive and consume, the energy. The amount of revenues recognized reflects the consideration the Utilities expect to receive in exchange for delivering the energy. Under their tariffs, the transaction price for full-service customers includes the Utilities’ energy cost and for all customers includes delivery charges determined based on customer class and in accordance with established tariffs and guidelines of the New York State Public Service Commission (NYSPSC) or the New Jersey Board of Public Utilities (NJBPU), as applicable. Accordingly, there is no unsatisfied performance obligation associated with these customers. The transaction price is applied to the Utilities’ revenue generating activities through the customer billing process. Because energy is delivered over time, the Utilities use output methods that recognize revenue based on direct measurement of the value transferred, such as units delivered, which provides an accurate measure of value for the energy delivered. The Utilities accrue revenues at the end of each month for estimated energy delivered but not yet billed to customers. The Utilities defer over a 12-month period net interruptible gas revenues, other than those authorized by the NYSPSC to be retained by the Utilities, for refund to firm gas sales and transportation customers.

The Clean Energy Businesses recognize revenue for the sale of energy from renewable electric production projects as energy is generated and billed to counterparties; accrue revenues at the end of each month for energy generated but not yet billed to counterparties; and recognize revenue as energy is delivered and services are provided for managing energy supply assets leased from others and managing the dispatch, fuel requirements and risk management activities for generating plants and merchant transmission in the northeastern United States. The Clean Energy Businesses also recognize revenue for providing energy-efficiency services to government and commercial customers, and recognize revenue for engineering, procurement and construction services, under the percentage-of-completion method of revenue recognition.

Sales and profits on each percentage-of-completion contract are recorded each month based on the ratio of actual cumulative costs incurred to the total estimated costs at completion of the contract, multiplied by the total estimated contract revenue, less cumulative revenues recognized in prior periods (the ‘‘cost-to-cost’’ method). The impact of revisions of contract estimates, which may result from contract modifications, performance or other reasons, are recognized on a cumulative catch-up basis in the period in which the revisions are made.



	2019			2018
(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)		Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1,	$29	$20		$58	$87
Additions (c)	86	1		144	38
Subtractions (c)	86	4	(d)	173	105	(d)
Ending balance as of December 31,	$29	$17		$29	$20

(a)

Unbilled contract revenue represents accumulated incurred costs and earned profits on contracts (revenue arrangements), which have been recorded as revenue, but have not yet been billed to customers, and which represent contract assets as defined in Topic 606. Substantially all accrued unbilled contract revenue is expected to be collected within one year. Unbilled contract revenue arises from the cost-to-cost method of revenue recognition. Unbilled contract revenue from fixed-price type contracts is converted to billed receivables when amounts are invoiced to customers according to contractual billing terms, which generally occur when deliveries or other performance milestones are completed.


(b)	Unearned revenue represents a liability for billings to customers in excess of earned revenue, which are contract liabilities as defined in Topic 606.


(c)	Additions for unbilled contract revenue and subtractions for unearned revenue represent additional revenue earned. Additions for unearned revenue and subtractions for unbilled contract revenue represent billings. Activity also includes appropriate balance sheet classification for the period.


(d)	Of the subtractions from unearned revenue, $4 million and $50 million was included in the balance as of January 1, 2019 and 2018, respectively.

As of December 31, 2019, the aggregate amount of the remaining fixed performance obligations of the Clean Energy Businesses, under contracts with customers for energy services is $82 million, of which $46 million will be recognized within the next two years, and the remaining $36 million will be recognized pursuant to long-term service and maintenance agreements.

CECONY’s electric and gas rate plans and O&R’s New York electric and gas rate plans each contain a revenue decoupling mechanism under which the company’s actual energy delivery revenues are compared with the authorized delivery revenues and the difference accrued, with interest, for refund to, or recovery from, customers, as applicable. See “Rate Plans” in Note B.

The NYSPSC requires utilities to record gross receipts tax revenues and expenses on a gross income statement presentation basis (i.e., included in both revenue and expense). The recovery of these taxes is generally provided for in the revenue requirement within each of the respective NYSPSC approved rate plans. Total excise taxes (inclusive of gross receipts taxes) recorded in operating revenues were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$323	$330	$302
CECONY	312	318	292

Other Receivables

Other Receivables includes costs related to aid provided by the Utilities in the restoration of power in Puerto Rico in the aftermath of September 2017 hurricanes. Such costs have fully been billed to the appropriate authorities. As of December 31, 2019, Con Edison and CECONY other receivables' balances related to such costs were $8 million.

Plant and Depreciation

Utility Plant

Utility plant is stated at original cost. The cost of repairs and maintenance is charged to expense and the cost of betterments is capitalized. The capitalized cost of additions to utility plant includes indirect costs such as engineering, supervision, payroll taxes, pensions, other benefits and an allowance for funds used during construction (AFUDC). The original cost of property is charged to expense over the estimated useful lives of the assets. Upon retirement, the original cost of property is charged to accumulated depreciation. See Note R.

Rates used for AFUDC include the cost of borrowed funds and a reasonable rate of return on the Utilities’ own funds when so used, determined in accordance with regulations of the FERC or the state public utility regulatory authority having jurisdiction. The rate is compounded semiannually, and the amounts applicable to borrowed funds are treated as a reduction of interest charges, while the amounts applicable to the Utilities’ own funds are credited to other income (deductions). The AFUDC rates for CECONY were 5.1 percent, 5.4 percent and 5.5 percent for 2019, 2018 and 2017, respectively. The AFUDC rates for O&R were 5.3 percent, 2.2 percent and 2.5 percent for 2019, 2018 and 2017, respectively.

The Utilities generally compute annual charges for depreciation using the straight-line method for financial statement purposes, with rates based on average service lives and net salvage factors. The average depreciation rates for CECONY were 3.2 percent for 2019 and 3.1 percent for 2018 and 2017. The average depreciation rates for O&R were 3.0 percent for 2019 and 2.9 percent for 2018 and 2017.

The estimated lives for utility plant for CECONY range from 5 to 95 years for electric, 5 to 90 years for gas, 5 to 80 years for steam and 5 to 55 years for general plant. For O&R, the estimated lives for utility plant range from 5 to 75 years for electric and gas and 5 to 50 years for general plant.

At December 31, 2019 and 2018, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Electric
Generation	$591	$593	$591	$592
Transmission	3,634	3,333	3,380	3,106
Distribution	20,676	19,750	19,602	18,716
General	43	—	43	—
Gas (a)	8,617	7,714	7,961	7,107
Steam	1,813	1,830	1,813	1,830
General	2,365	2,306	2,143	2,102
Held for future use	75	76	67	67
Construction work in progress	1,937	1,978	1,812	1,850
Net Utility Plant	$39,751	$37,580	$37,412	$35,370

(a) Primarily distribution.

General utility plant of Con Edison and CECONY included $93 million and $88 million, respectively, at December 31, 2019, and $100 million and $95 million, respectively at December 31, 2018, related to a May 2018 acquisition of software licenses. The estimated aggregate annual amortization expense for Con Edison and CECONY is $7 million. The accumulated amortization for Con Edison and CECONY was $10 million at December 31, 2019 and was $3 million at December 31, 2018.

Under the Utilities’ rate plans, the aggregate annual depreciation allowance for the period ended December 31, 2019 was $1,417 million, including $1,332 million under CECONY’s electric, gas and steam rate plans that have been approved by the NYSPSC.

Non–Utility Plant

Non-utility plant is stated at original cost. For Con Edison, non-utility plant consists primarily of the Clean Energy Businesses’ renewable electric production projects. For the Utilities, non-utility plant consists of land and conduit for telecommunication use. Depreciation on these assets is computed using the straight-line method for financial statement purposes over their estimated useful lives, which is 10 years.

Goodwill

Con Edison tests goodwill for impairment at least annually or whenever there is a triggering event. There is an option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying a two-step, quantitative goodwill impairment test. Con Edison has elected to perform the qualitative assessment for substantially all of its goodwill and, if needed, applies the two-step quantitative approach. The first step of the quantitative goodwill impairment test compares the estimated fair value of a reporting unit with its carrying value, including goodwill. If the estimated fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is considered not impaired. If the carrying value exceeds the estimated fair value of the reporting unit, the second step is performed to measure the amount of impairment loss, if any. The second step requires a calculation of the implied fair value of goodwill. In 2019, Con Edison recorded no impairment charge on goodwill. See Note K.

Long–Lived and Intangible Assets

The Companies test long-lived and intangible assets for recoverability when events or changes in circumstances indicate that the carrying value of long-lived or intangible assets may not be recoverable. The carrying amount of a long-lived asset or intangible asset with a definite life is deemed not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. In the event a test indicates that such cash flows cannot be expected to be sufficient to fully recover the assets, the assets are considered impaired and written down to their estimated fair value.

Con Edison's intangible assets with definite lives consist primarily of power purchase agreements, which were identified as part of purchase price allocations associated with acquisitions made by the Clean Energy Businesses in 2016 and 2018. At December 31, 2019 and 2018, intangible assets arising from power purchase agreements, including the PG&E PPAs (discussed below), were $1,554 million and $1,651 million, net of accumulated amortization of $119 million and $22 million, respectively, and are being amortized over the life of each agreement. Excluding power purchase agreements, Con Edison’s other intangible assets were $3 million, net of accumulated amortization of $7 million, at December 31, 2019 and 2018. CECONY’s other intangible assets were immaterial at December 31, 2019 and 2018. Con Edison recorded amortization expense related to its intangible assets of $99 million in 2019, $14 million in 2018 and $9 million in 2017. Con Edison expects amortization expense to be $100 million per year over the next five years. Con Edison recorded $2 million of impairment charges in 2018. No impairment charges were recorded on Con Edison's long-lived assets or intangible assets with definite lives in 2019 or 2017.

In January 2019, Pacific Gas and Electric Company (PG&E) filed in the United States Bankruptcy Court for the Northern District of California for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The output of certain of the Clean Energy Businesses' renewable electric production projects with an aggregate generating capacity of 680 MW (AC) (PG&E Projects) is sold to PG&E under long-term power purchase agreements (PG&E PPAs). Most of the PG&E PPAs have contract prices that are higher than estimated market prices. PG&E, as a debtor in possession, may assume or reject the PG&E PPAs, subject to review by the bankruptcy court.

In January 2020, PG&E and certain PG&E shareholders submitted a plan of reorganization to the bankruptcy court. The plan includes the assumption by PG&E of all of its power purchase agreements. The plan is subject to, among other things: confirmation by the bankruptcy court by June 30, 2020 (or any extension of the date by which PG&E’s bankruptcy must be resolved for PG&E to participate in the insurance fund described below); approval by the California Public Utilities Commission (CPUC) of PG&E’s implementation of the plan and participation in the insurance fund; PG&E obtaining funding for distributions under the plan; and the continuation in full force and effect of the September 2019 subrogation claims restructuring support agreement, the December 2019 tort claimants restructuring support agreement and the January 2020 noteholder restructuring support agreement. The plan is

supported by the parties to these restructuring support agreements, subject to their terms, and includes the assumption by PG&E of all of its power purchase agreements. A plan of reorganization can be revoked, amended, withdrawn or delayed prior to its confirmation by the bankruptcy court. Bankruptcy court approval is required for a plan of reorganization to be sent to creditors for consideration.

In January and May 2019, FERC issued orders (which PG&E is challenging) affirming its jurisdiction to review and approve the modification or abrogation of wholesale power contracts that are the subject of rejection in bankruptcy. In June 2019, the bankruptcy court ruled that FERC does not have concurrent jurisdiction with it and that FERC’s January and May 2019 orders are of no force and effect in the bankruptcy proceeding. FERC and additional parties, including the Clean Energy Businesses, are challenging the bankruptcy court’s June 2019 ruling in appeals that are pending in the United States Court of Appeals for the Ninth Circuit.

In July 2019, California enacted a law addressing future California wildfires. The law includes provisions for the establishment of wildfire liquidity and insurance funds and possible limitation of future wildfire liabilities for California utilities. PG&E, Southern California Edison Company and San Diego Gas & Electric Company have agreed to participate in the insurance fund. PG&E’s participation will require bankruptcy court approval and is conditioned on, among other things, resolution of PG&E’s bankruptcy by June 30, 2020, and a determination by the CPUC that PG&E’s bankruptcy reorganization plan is consistent with the state’s climate goals as required under the California Renewables Portfolio Standard Program and related procurement requirements of the state.

The PG&E bankruptcy is an event of default under the PG&E PPAs. Unless the lenders for the related project debt otherwise agree, distributions from the related projects to the Clean Energy Businesses will not be made during the pendency of the bankruptcy. See “Reconciliation of Cash, Temporary Cash Investments and Restricted Cash,” below.

At December 31, 2019 and 2018, Con Edison’s consolidated balance sheet included $819 million and $885 million of net non-utility plant relating to the PG&E Projects, $1,057 million and $1,125 million of intangible assets relating to the PG&E PPAs, $282 million and $292 million of net non-utility plant of additional projects that secure the related project debt and $1,001 million and $1,050 million of non-recourse related project debt, respectively. See "Long-term Debt" in Note C. Con Edison has tested whether its net non-utility plant relating to the PG&E Projects and intangible assets relating to the PG&E PPAs have been impaired. The projected future cash flows used in the test reflected Con Edison’s expectation that the PG&E PPAs are not likely to be rejected. Based on the test, Con Edison has determined that there was no impairment. If, in the future, one or more of the PG&E PPAs is rejected or any such rejection becomes likely, there will be an impairment of the related intangible assets and could be an impairment of the related non-utility plant. The amount of any such impairment could be material.

Recoverable Energy Costs

The Utilities generally recover all of their prudently incurred fuel, purchased power and gas costs, including hedging gains and losses, in accordance with rate provisions approved by the applicable state public utility regulators. If the actual energy supply costs for a given month are more or less than the amounts billed to customers for that month, the difference in most cases is recoverable from or refundable to customers. Differences between actual and billed electric and steam supply costs and costs of its electric demand management programs are generally deferred for charge or refund to customers during the next billing cycle (normally within one or two months). For the Utilities’ gas costs, differences between actual and billed gas costs during the 12-month period ending each August are charged or refunded to customers during a subsequent 12-month period.

New York Independent System Operator (NYISO)

The Utilities purchase electricity through the wholesale electricity market administered by the NYISO. The difference between purchased power and related costs initially billed to the Utilities by the NYISO and the actual cost of power subsequently calculated by the NYISO is refunded by the NYISO to the Utilities, or paid to the NYISO by the Utilities. The reconciliation payments or receipts are recoverable from or refundable to the Utilities’ customers.

Certain other payments to or receipts from the NYISO are also subject to reconciliation, with shortfalls or amounts in excess of specified rate allowances recoverable from or refundable to customers. These include proceeds from the sale through the NYISO of transmission rights on CECONY’s transmission system (transmission congestion contracts or TCCs).

Temporary Cash Investments

Temporary cash investments are short-term, highly-liquid investments that generally have maturities of three months or less at the date of purchase. They are stated at cost, which approximates market. The Companies consider temporary cash investments to be cash equivalents.

Investments

Investments consist primarily of the investments of Con Edison Transmission that are accounted for under the equity method, and the fair value of the Utilities’ supplemental retirement income plan and deferred income plan assets. Equity method investments are subject to the accounting rules which would require the recognition of a decrease in value other than for a temporary decline. The following investment assets are included in the Companies' consolidated balance sheets at December 31, 2019 and 2018:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019		2018
CET Gas investment in Stagecoach Gas Services, LLC	$924	$948		$—		$—
CET Gas investment in Mountain Valley Pipeline, LLC (a)	602	363	—		—
Supplemental retirement income plan assets (b)	397	326	371		301
Deferred income plan assets	81	75	81		75
CET Electric investment in New York Transco, LLC	59	52	—		—
Other	2	2	9		9
Total investments	$2,065	$1,766	$461		$385


(a)	See Note U.


(b)	See Note E.

Pension and Other Postretirement Benefits

The accounting rules for retirement benefits require an employer to recognize an asset or liability for the overfunded or underfunded status of its pension and other postretirement benefit plans. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. The accounting rules generally require employers to recognize all unrecognized prior service costs and credits and unrecognized actuarial gains and losses in accumulated other comprehensive income/(loss) (OCI), net of tax. Such amounts will be adjusted as they are subsequently recognized as components of total periodic benefit cost or income pursuant to the current recognition and amortization provisions.

For the Utilities’ pension and other postretirement benefit plans, regulatory accounting treatment is generally applied in accordance with the accounting rules for regulated operations. Unrecognized prior service costs or credits and unrecognized actuarial gains and losses are recorded to regulatory assets or liabilities, rather than OCI. See Notes E and F.

The total periodic benefit costs are recognized in accordance with the accounting rules for retirement benefits. Investment gains and losses are recognized in expense over a 15-year period and other actuarial gains and losses are recognized in expense over a 10-year period, subject to the deferral provisions in the rate plans.

In accordance with the Statement of Policy issued by the NYSPSC and its current electric, gas and steam rate plans, CECONY defers for payment to or recovery from customers the difference between such expenses and the amounts for such expenses reflected in rates. O&R also defers such difference pursuant to its New York rate plans. See Note B.

The Companies calculate the expected return on pension and other postretirement benefit plan assets by multiplying the expected rate of return on plan assets by the market-related value (MRV) of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments that are to be made during the year. The accounting rules allow the MRV of plan assets to be either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. The Companies use a calculated value when determining the MRV of the plan assets that adjusts for 20 percent of the difference

between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which the Companies apply the expected return.

Federal Income Tax

In accordance with accounting rules for income taxes, the Companies have recorded an accumulated deferred federal income tax liability at current tax rates for temporary differences between the book and tax basis of assets and liabilities. In accordance with rate plans, the Utilities have recovered amounts from customers for a portion of the tax liability they will pay in the future as a result of the reversal or “turn-around” of these temporary differences. As to the remaining deferred tax liability, the Utilities had established regulatory assets for the net revenue requirements to be recovered from customers for the related future tax expense pursuant to the NYSPSC's 1993 Policy Statement approving accounting procedures consistent with accounting rules for income taxes and providing assurances that these future increases in taxes will be recoverable in rates.

Upon enactment of the Tax Cuts and Jobs Act of 2017 on December 22, 2017 (the TCJA), the Companies re-measured their deferred tax assets and liabilities based upon the 21 percent corporate income tax rate under the TCJA. The tax effects of changes in tax laws are to be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For the Utilities, in accordance with their New York rate plans and the accounting rules for regulated operations, the change in deferred taxes was recorded as either an offset to a regulatory asset or a regulatory liability. For Con Edison’s other businesses, the change in deferred taxes was reflected as a decrease in income tax expense, which increased Con Edison's net income. See “Other Regulatory Matters” and “Regulatory Assets and Liabilities” in Note B and Note L.

Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction to future federal income tax expense.

Con Edison and its subsidiaries file a consolidated federal income tax return. The consolidated income tax liability is allocated to each member of the consolidated group using the separate return method. Each member pays or receives an amount based on its own taxable income or loss in accordance with a consolidated tax allocation agreement. Tax loss and tax credit carryforwards are allocated among members in accordance with consolidated tax return regulations.

State Income Tax

Con Edison and its subsidiaries file a combined New York State Corporation Business Franchise Tax Return. Similar to a federal consolidated income tax return, the income of all entities in the combined group is subject to New York State taxation, after adjustments for differences between federal and New York law and apportionment of income among the states in which the company does business. Each member’s share of the New York State tax is based on its own New York State taxable income or loss.

Research and Development Costs

Research and development costs are charged to operating expenses as incurred. Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$24	$24	$24
CECONY	23	23	23

Earnings Per Common Share

Con Edison presents basic and diluted earnings per share (EPS) on the face of its consolidated income statement. Basic EPS is calculated by dividing earnings available to common shareholders (“Net income for common stock” on Con Edison’s consolidated income statement) by the weighted average number of Con Edison common shares outstanding during the period. In the calculation of diluted EPS, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock.

Potentially dilutive securities for Con Edison consist of restricted stock units and deferred stock units for which the average market price of the common shares for the period was greater than the exercise price (see Note M) and its common shares that are subject to forward sale agreements (see Note C). Before the issuance of common shares upon settlement of the forward sale agreements, the shares will be reflected in the company’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of common shares used in calculating diluted earnings per share is deemed to be increased by the excess, if any, of the number of shares that would be issued upon physical settlement of the forward sale agreements over the number of shares that could be purchased by the company in the market (based on the average market price during the period) using the proceeds due upon physical settlement (based on the adjusted forward sale price at the end of the reporting period).

Basic and diluted EPS for Con Edison are calculated as follows:



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts/Shares in Millions)	2019	2018	2017
Net income for common stock	$1,343	$1,382	$1,525
Weighted average common shares outstanding – basic	328.5	311.7	307.1
Add: Incremental shares attributable to effect of potentially dilutive securities	1.0	1.2	1.7
Adjusted weighted average common shares outstanding – diluted	329.5	312.9	308.8
Net Income per common share – basic	$4.09	$4.43	$4.97
Net Income per common share – diluted	$4.08	$4.42	$4.94

The computation of diluted EPS for the years ended December 31, 2019 and 2018 excludes immaterial amounts of performance share awards that were not included because of their anti-dilutive effect.

Estimates

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 and 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 differ from those estimates.

Changes in Accumulated Other Comprehensive Income/(Loss) by Component

Changes to accumulated other comprehensive income/(loss) (OCI) for Con Edison and CECONY are as follows:



(Millions of Dollars)	Con Edison	CECONY
Accumulated OCI, net of taxes, at December 31, 2016 (a)	$(27)	$(7)
OCI before reclassifications, net of tax of $3 and $1 for Con Edison and CECONY, respectively	(4)	—
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(3) and $(1) for Con Edison and CECONY, respectively (a)(b)	5	1
Total OCI, net of taxes, at December 31, 2017	1	1
Accumulated OCI, net of taxes, at December 31, 2017 (a)	$(26)	$(6)
OCI before reclassifications, net of tax of $3 for Con Edison	4	—
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(2) for Con Edison (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2018	10	1
Accumulated OCI, net of taxes, at December 31, 2018 (a)	$(16)	$(5)
OCI before reclassifications, net of tax of $(6) and $(1) for Con Edison and CECONY, respectively	(10)	(3)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(2) for Con Edison (a)(b)	7	2
Total OCI, net of taxes, at December 31, 2019	(3)	(1)
Accumulated OCI, net of taxes, at December 31, 2019 (a)	$(19)	$(6)

(a) Tax reclassified from accumulated OCI is reported in the income tax expense line item of the consolidated income statement.

(b) For the portion of unrecognized pension and other postretirement benefit costs relating to the Utilities, costs are recorded into, and amortized out of, regulatory assets and liabilities instead of OCI. The net actuarial losses and prior service costs recognized during the period are included in the computation of total periodic pension and other postretirement benefit cost. See Notes E and F.

Reconciliation of Cash, Temporary Cash Investments and Restricted Cash

Cash, temporary cash investments and restricted cash are presented on a combined basis in the Companies’ consolidated statements of cash flows. At December 31, 2019 and 2018, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Cash and temporary cash investments	$981	$895	$933	$818
Restricted cash (a)	236	111	—	—
Total cash, temporary cash investments and restricted cash	$1,217	$1,006	$933	$818

(a)

Restricted cash included cash of the Clean Energy Businesses' renewable electric production project subsidiaries ($236 million and $109 million at December 31, 2019 and 2018, respectively) that, under the related project debt agreements, is either restricted until the various maturity dates of the project debt to being used for normal operating expenses and capital expenditures, debt service, and required reserves or restricted as a result of the PG&E bankruptcy. During the pendency of the PG&E bankruptcy, unless the lenders for the related project debt otherwise agree, cash may not be distributed from the related projects to the Clean Energy Businesses. See "Long-Lived and Intangible Assets,” above and "Long-term Debt" in Note C. In addition, restricted cash included O&R's New Jersey utility subsidiary, Rockland Electric Company transition bond charge collections, net of principal, interest, trustee and service fees ($2 million at December 31, 2018).

Regulatory Matters

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Regulatory Matters

Rate Plans

The Utilities provide service to New York customers according to the terms of tariffs approved by the NYSPSC. Tariffs for service to customers of Rockland Electric Company (RECO), O&R’s New Jersey regulated utility subsidiary, are approved by the NJBPU. The tariffs include schedules of rates for service that limit the rates charged by the Utilities to amounts that recover from their customers costs approved by the regulator, including capital costs, of providing service to customers as defined by the tariff. The tariffs implement rate plans adopted by state utility regulators in rate orders issued at the conclusion of rate proceedings. Pursuant to the Utilities’ rate plans, there generally can be no change to the charges to customers during the respective terms of the rate plans other than specified adjustments provided for in the rate plans. The Utilities’ rate plans each cover specified periods, but rates determined pursuant to a plan generally continue in effect until a new rate plan is approved by the state utility regulator.

Common provisions of the Utilities’ New York rate plans include:

Recoverable energy costs that allow the Utilities to recover on a current basis the costs for the energy they supply with no mark-up to their full-service customers.

Cost reconciliations that reconcile pension and other postretirement benefit costs, environmental remediation costs, property taxes, variable rate tax-exempt debt and certain other costs to amounts reflected in delivery rates for such costs. In addition, changes in the Utilities' costs not reflected in rates, in excess of certain amounts, resulting from changes in tax or other law, rule, regulation, order, or other requirement or interpretation are deferred as a regulatory asset or regulatory liability to be reflected in the Utilities' next rate plan or in a manner to be determined by the NYSPSC. Also, the Utilities generally retain the right to petition for recovery or accounting deferral of extraordinary and material cost increases and provision is sometimes made for the utility to retain a share of cost reductions, for example, property tax refunds.

Revenue decoupling mechanisms that reconcile actual energy delivery revenues to the authorized delivery revenues approved by the NYSPSC. The difference is accrued with interest for refund to, or recovery from customers, as applicable.

Earnings sharing that require the Utilities to defer for customer benefit a portion of earnings over specified rates of return on common equity. There is no symmetric mechanism for earnings below specified rates of return on common equity.

Negative revenue adjustments for failure to meet certain performance standards relating to service, reliability, safety and other matters.

Positive revenue adjustments for achievement of performance standards related to achievement of clean energy goals, safety and other matters.

Net utility plant reconciliations that require deferral as a regulatory liability of the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates. There is generally no symmetric mechanism if actual average net utility plant balances are more than amounts reflected in rates.

Rate base, as reflected in the rate plans, is, in general, the sum of the Utilities’ net plant, working capital and certain regulatory assets less deferred taxes and certain regulatory liabilities. For each rate plan, the NYSPSC uses a forecast of the average rate base for each year that new rates would be in effect (“rate year”).

Weighted average cost of capital is determined based on the authorized common equity ratio, return on common equity, cost of long-term debt and cost of customer deposits reflected in each rate plan. For each rate plan, the revenues designed to provide the utility a return on invested capital for each rate year are determined by multiplying each utility rate base by its pre–tax weighted average cost of capital. The Utilities’ actual return on common equity will reflect their actual operations for each rate year, and may be more or less than the authorized return on equity reflected in their rate plans (and if more, may be subject to earnings sharing).

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	January 2017 – December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $195 million (b) Yr. 2 – $155 million (b) Yr. 3 – $155 million (b)	Yr. 1 – $113 million (c) Yr. 2 – $370 million (c) Yr. 3 – $326 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million	Yr. 1 – $267 million (d) Yr. 2 – $269 million (d) Yr. 3 – $272 million (d)
Other revenue sources	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 – $28 million Yr. 2 – $47 million Yr. 3 – $64 million In 2017, 2018 and 2019, the company recorded $13 million, $25 million and $43 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved $5 million of incentives for service terminations in 2017, 2018 and 2019 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded $3 million and $7 million of incentives for service terminations, respectively.	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $69 million Yr. 2 - $74 million Yr. 3 - $79 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017, 2018 and 2019, the company deferred for customer benefit $45 million, $(6) million and $169 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues.
Recoverable energy costs	Continuation of current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 – $376 million Yr. 2 – $341 million Yr. 3 – $352 million In 2017 and 2018, the company did not record any negative revenue adjustments. In 2019, the company recorded negative revenue adjustments of $15 million.	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 - $450 million Yr. 2 - $461 million Yr. 3 - $476 million



Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (g). In 2017, 2018 and 2019, the company deferred $35 million, $189 million and $10 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 – $21,689 million Yr. 2 – $22,338 million Yr. 3 – $23,002 million AMI: Yr. 1 – $126 million Yr. 2 – $257 million Yr. 3 – $415 million The company deferred $0.4 million as a regulatory asset in 2017. In 2018 and 2019, $0.4 and $11.8 million was deferred as a regulatory liability, respectively.	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $24,491 million Yr. 2 - $25,092 million Yr. 3 - $25,708 million AMI: Yr. 1 - $572 million Yr. 2 - $740 million Yr. 3 - $806 million (h)
Average rate base	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million	Yr. 1 - $21,660 million Yr. 2 - $22,783 million Yr. 3 - $23,926 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent Yr. 3 – 8.82 percent
Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, the company had no earnings above the threshold but recorded a positive adjustment related to 2016 of $5.7 million in earnings. In 2018 and 2019, the company had no earnings sharing above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)

In January 2020, the NYSPSC approved the October 2019 Joint Proposal for CECONY's electric rate plan for January 2020 through December 2022. If at the end of any semi-annual period ending June 30 and December 31, Con Edison’s investments in its non-utility businesses exceed 15 percent of its total consolidated revenues, assets or cash flow, or if the ratio of holding company debt to total consolidated debt rises above 20 percent, CECONY is required to notify the NYSPSC and submit a ring-fencing plan or a demonstration why additional ring-fencing measures (see Note S) are not necessary.

(b)

The electric base rate increases were in addition to a $48 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan. At the NYSPSC’s option, these increases were implemented with increases of $199 million in each rate year. Base rates reflect recovery by the company of certain costs of its energy efficiency, system peak reduction and electric vehicle programs (Yr. 1 - $20.5 million; Yr. 2 - $49 million; and Yr. 3 - $107.5 million) over a 10-year period, including the overall pre-tax rate of return on such costs.

(c)

Base rates reflect recovery by the company of certain costs of its energy efficiency, Reforming the Energy Vision demonstration projects, non-wire alternative projects (including the Brooklyn Queens demand management program), and off-peak electric vehicle charging programs (Yr. 1 - $206 million; Yr. 2 - $245 million; and Yr. 3 - $251 million) over a ten-year period, including the overall pre-tax rate of return on such costs.

(d)

Amounts reflect amortization of the 2018 tax savings under the federal Tax Cuts and Jobs Act of 2017 (TCJA) allocable to CECONY’s electric customers ($377 million) over a three-year period ($126 million annually), the protected portion of the regulatory liability for excess deferred income taxes allocable to CECONY’s electric customers ($1,663 million) over the remaining lives of the related assets ($49 million in Yr. 1, $50 million in Yr. 2, and $53 million in Yr. 3) and the unprotected portion of the net regulatory liability ($784 million) over five years ($157 million annually). Amounts also reflect amortization of the regulatory asset for deferred MTA power reliability costs ($238 million) over a five-year period ($48 million annually).


(e)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr 1 - 10.0 basis points; Yr 2 - 7.5 basis points; and Yr 3 - 5.0 basis points.

(f)

In general, if actual expenses for municipal infrastructure support (other than company labor) are below the amounts reflected in rates the company will defer the difference for credit to customers, and if the actual expenses are above the amount reflected in rates the company will defer for recovery from customers 80 percent of the difference subject to a maximum deferral, subject to certain conditions, of

30 percent of the amount reflected in the January 2017-December 2019 rate plan and 15 percent of the amount reflected in the January 2020-December 2022 rate plan.


(g)	In addition, the NYSPSC staff has commenced a focused operations audit to investigate the income tax accounting of CECONY and other New York utilities. Any NYSPSC-ordered adjustment to CECONY’s income tax accounting will be refunded to or collected from customers, as determined by the NYSPSC. See "Other Regulatory Matters," below.


(h)	Reconciliation of net utility plant for AMI will be done on a combined basis for electric and gas.


(i)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



CECONY – Gas
Effective period	January 2017 - December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $(5) million (b) Yr. 2 – $92 million Yr. 3 – $90 million	Yr. 1 – $84 million (c) Yr. 2 – $122 million (c) Yr. 3 – $167 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million	Yr. 1 – $45 million (d) Yr. 2 – $43 million (d) Yr. 3 – $10 million (d)
Other revenue sources	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential incentives if performance targets related to gas leak backlog, leak prone pipe and service terminations are met: Yr. 1 – $7 million Yr. 2 – $8 million Yr. 3 – $8 million In 2017, 2018 and 2019, the company achieved incentives of $7 million, $6 million and $7 million, respectively, that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded incentives of $5 million and $9 million, respectively, for gas leak backlog, leak prone pipe and service terminations.	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential earnings adjusted mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $20 million Yr. 2 - $22 million Yr. 3 - $25 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017, 2018 and 2019, the company deferred $3 million, $12 million and $10 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues, modified to be calculated based upon revenue per customer class instead of revenue per customer.
Recoverable energy costs	Continuation of current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 – $68 million Yr. 2 – $63 million Yr. 3 – $70 million In 2017 and 2018, the company recorded negative revenue adjustments of $5 million and $4 million, respectively. In 2019, the company did not record any negative revenue adjustments.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $81 million Yr. 2 - $88 million Yr. 3 - $96 million
Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g) In 2017, 2018 and 2019, the company deferred $2 million of net regulatory liabilities, $44 million of net regulatory assets and $18 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 – $5,844 million Yr. 2 – $6,512 million Yr. 3 – $7,177 million AMI: Yr. 1 – $27 million Yr. 2 – $57 million Yr. 3 – $100 million In 2017 and 2018 the company deferred $2.2 million as regulatory liabilities. In 2019, the company deferred $1.7 million as a regulatory liability.	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 - $8,108 million Yr. 2 - $8,808 million Yr. 3 - $9,510 million AMI: Yr. 1 - $142 million Yr. 2 - $183 million Yr. 3 - $211 million (h)
Average rate base	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million	Yr. 1 - $7,171 million Yr. 2 - $7,911 million Yr. 3 - $8,622 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent Yr. 3 – 8.72 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, 2018 and 2019, the company had no earnings above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)

In January 2020, the NYSPSC approved the October 2019 Joint Proposal for CECONY's gas rate plan for January 2020 through December 2022. If at the end of any semi-annual period ending June 30 and December 31, Con Edison’s investments in its non-utility businesses exceed 15 percent of its total consolidated revenues, assets or cash flow, or if the ratio of holding company debt to total consolidated debt rises above 20 percent, CECONY is required to notify the NYSPSC and submit a ring-fencing plan or a demonstration why additional ring-fencing measures (see Note S) are not necessary.


(b)	The gas base rate decrease was offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.

(c)

The gas base rate increases shown above will be implemented with increases of $47 million in Yr. 1; $176 million in Yr. 2; and $170 million in Yr. 3 in order to levelize customer bill impacts. Base rates reflect recovery by the company of certain costs of its energy efficiency program (Yr. 1 - $30 million; Yr. 2 - $37 million; and Yr. 3 - $40 million) over a ten-year period, including the overall pre-tax rate of return on such costs.

(d)

Amounts reflect amortization of the remaining 2018 TCJA tax savings allocable to CECONY’s gas customers ($63 million) over a two year period ($32 annually), the protected portion of the regulatory liability for excess deferred income taxes allocable to CECONY’s gas customers ($725 million) over the remaining lives of the related assets ($14 million in Yr. 1, $14 million in Yr. 2, and $12 million in Yr. 3) and the unprotected portion of the net regulatory liability ($107 million) over five years ($21 million annually)


(e)-(i)	See footnotes (e) - (i) to the table under “CECONY Electric,” above.



CECONY – Steam
Effective period		January 2014 – December 2016 (a)
Base rate changes		Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b) Yr. 4 – None Yr. 5 – None Yr. 6 – None
Amortizations to income of net regulatory (assets) and liabilities		$37 million over three years
Recoverable energy costs		Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments		Potential charges (up to $1 million annually) if certain steam performance targets are not met. In years 2014 through 2019, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016, 2017, 2018 and 2019, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, $1 million of net regulatory assets and $8 million of net regulatory liabilities, respectively.
Net utility plant reconciliations		Target levels reflected in rates were: Production: Yr. 1 – $1,752 million Yr. 2 – $1,732 million Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million Yr. 2 – $11 million Yr. 3 – $25 million The company reduced its regulatory liability by $0.1 million in 2014 and immaterial amounts in 2015 and 2016 and no deferrals were recorded in 2017, 2018 and 2019.
Average rate base		Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)		Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity		9.3 percent
Actual return on common equity (d)		Yr. 1 – 9.82 percent Yr. 2 – 10.88 percent Yr. 3 – 10.54 percent Yr. 4 – 9.51 percent Yr. 5 – 11.73 percent Yr. 6 – 10.45 percent
Earnings sharing		Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $11.5 million and $7.8 million above the threshold in 2015 and 2016, respectively. In 2017, actual earnings were $8.5 million above the threshold, offset in part by a positive adjustment related to 2016 of $4 million. In 2018, actual earnings were $16.5 million above the threshold, and an additional $1.1 million related to 2017 was recorded. In 2019 actual earnings were $5 million above the threshold, offset in part by an adjustment related to 2018 of $2.3 million.
Cost of long-term debt		Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio		48 percent


(a)	Rates determined pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.


(b)	The impact of these base rate changes was deferred which resulted in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.


(d)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Electric
Effective period	November 2015 - October 2017 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $9.3 million Yr. 2 – $8.8 million Yr. 3 – None	Yr. 1 – $13.4 million (e) Yr. 2 – $8.0 million (e) Yr. 3 – $5.8 million (e)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $(8.5) million (b) Yr. 2 – $(9.4) million (b) Yr. 3 – None	Yr. 1 – $(1.5) million (f) Yr. 2 – $(1.5) million (f) Yr. 3 – $(1.5) million (f)
Other revenue sources		Potential earnings adjustment mechanism incentives for peak reduction, energy efficiency, Distributed Energy Resources utilization and other potential incentives of up to: Yr. 1 - $3.6 million Yr. 2 - $4.0 million Yr. 3 - $4.2 million Potential incentive if performance target related to service terminations is met: $0.5 million annually. In 2019, the company recorded $2.6 million of earnings adjustment mechanism incentives for energy efficiency and $0.2 million of incentives for service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred for the customer’s benefit an immaterial amount, $6.3 million as regulatory liabilities, $11.2 million as regulatory asset and $0.5 million as regulatory asset, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2019 the company deferred $0.1 million as a regulatory asset.
Recoverable energy costs	Continuation of current rate recovery of purchased power costs.	Continuation of current rate recovery of purchased power costs.
Negative revenue adjustments	Potential charges (up to $4 million annually) if certain performance targets are not met. In 2015 the company recorded $1.25 million in negative revenue adjustments. In 2016, 2017 and 2018, the company did not record any negative revenue adjustments.	Potential charges if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million Yr. 2 - $4.4 million Yr. 3 - $4.5 million In 2019, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2015, 2016 and 2017, the company deferred $0.3 million, $7.4 million and $3.2 million as net decreases to regulatory assets, respectively. In 2018, the company deferred $5 million as a net regulatory asset.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), major storms, the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $4.3 million as a net regulatory asset.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $928 million (c) Yr. 2 – $970 million (c) The company increased/(reduced) its regulatory asset by $2.2 million, $(1.9) million, $(1.9) million and $1.4 million in 2015, 2016, 2017 and 2018, respectively.	Target levels reflected in rates were: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $1,008 million Yr. 2 - $1,032 million Yr. 3 - $1,083 million AMI (j): Yr. 1 - $48 million Yr. 2 - $58 million Yr. 3 - $61 million The company increased regulatory asset by an immaterial amount in 2019.
Average rate base	Yr. 1 – $763 million Yr. 2 – $805 million Yr. 3 – $805 million	Yr. 1 – $878 million Yr. 2 – $906 million Yr. 3 – $948 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 percent	Yr. 1 – 9.6 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $6.1 million, $0.3 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates determined pursuant to this rate plan continued in effect until the subsequent rate plan became effective.

(b)

$59.3 million of the regulatory asset for deferred storm costs is to be recovered from customers over a 5 year period, including $11.85 million in each of years 1 and 2, $1 million of the regulatory asset for such costs will not be recovered from customers, and all outstanding issues related to Superstorm Sandy and other past major storms prior to November 2014 are resolved. Approximately $4 million of regulatory assets for property tax and interest rate reconciliations will not be recovered from customers. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes electric AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.

(d)

If at the end of any year, Con Edison’s investments in its non-utility businesses exceed 15 percent of Con Edison’s total consolidated revenues, assets or cash flow, or if the ratio of holding company debt to total consolidated debt rises above 20 percent, O&R is required to notify the NYSPSC and submit a ring-fencing plan or a demonstration why additional ring-fencing measures (see Note S) are not necessary.


(e)	The electric base rate increases shown above will be implemented with increases of: Yr. 1 - $8.6 million; Yr. 2 - $12.1 million; and Yr. 3 - $12.2 million.

(f)

Reflects amortization of, among other things, the company’s net benefits under the TCJA prior to January 1, 2019, amortization of net regulatory liability for future income taxes and reduction of previously incurred regulatory assets for environmental remediation costs. Also, for electric, reflects amortization over a six year period of previously incurred incremental major storm costs. See "Other Regulatory Matters," below.


(g)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr. 1 - 10.0 basis points; Yr. 2 - 7.5 basis points; and Yr. 3 - 5.0 basis points.


(h)	Energy efficiency costs are expensed as incurred. Such costs are subject to a downward-only reconciliation over the terms of the electric and gas rate plans. The company will defer for the benefit of customers any cumulative shortfall over the terms of the electric and gas rate plans between actual expenditures and the levels provided in rates.


(i)	In addition, amounts reflected in rates relating to income taxes and excess deferred federal income tax liability balances will be reconciled (i.e., refunded to or collected from customers) to any final, non-appealable NYSPSC-ordered findings in its investigation of O&R’s income tax accounting. See “Other Regulatory Matters,” in Note B.


(j)	Net plant reconciliation for AMI expenditures will be implemented for a single category of AMI capital expenditures that includes amounts allocated to both electric and gas customers.


(k)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Gas
Effective period	November 2015 – October 2018 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge	Yr. 1 – $(7.5) million (e) Yr. 2 – $3.6 million (e) Yr. 3 – $0.7 million (e)
Amortization to income of net regulatory (assets) and liabilities	Yr. 1 – $(1.7) million (b) Yr. 2 – $(2.1) million (b) Yr. 3 – $(2.5) million (b)	Yr. 1 – $1.8 million (f) Yr. 2 – $1.8 million (f) Yr. 3 – $1.8 million (f)
Other revenue sources		Continuation of retention of annual revenues from non-firm customers of up to $4.0 million, with variances to be shared 80 percent by customers and 20 percent by company. Potential earnings adjustment mechanism incentives of up to $0.3 million annually. Potential incentives if performance targets related to gas leak backlog, leak prone pipe, emergency response, damage prevention and service terminations are met: Yr. 1 - $1.2 million; Yr. 2 - $1.3 million; and Yr. 3 - $1.3 million. In 2019, the company recorded $0.3 million of earnings adjustment mechanism incentives for energy efficiency and $0.7 million of incentives for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred $0.8 million of regulatory assets, $6.2 million of regulatory liabilities, $1.7 million of regulatory liabilities and $6.3 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2019, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $4.9 million in Yr. 3) if certain performance targets are not met. In 2015, 2016 and 2017, the company did not record any negative revenue adjustments. In 2018, the company recorded a $0.1 million negative revenue adjustment.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $5.5 million; Yr. 2 - $5.7 million; and Yr. 3 - $6.0 million. In 2019, the company recorded a $0.2 million negative revenue adjustment.
Cost reconciliations	In 2015 and 2016, the company deferred $4.5 million and $6.6 million as net regulatory liabilities and assets, respectively. In 2017 and 2018, the company deferred $3.5 million and $7.4 million as net regulatory liabilities, respectively.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $6 million as net regulatory liabilities.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $492 million (c) Yr. 2 – $518 million (c) Yr. 3 – $546 million (c) No deferral was recorded for 2015 and immaterial amounts were recorded as regulatory liabilities in 2016 and 2017. In 2018, the company deferred $0.4 million as regulatory asset.	Target levels reflected in rates were: Gas average net plant target excluding AMI: Yr. 1 - $593 million Yr. 2 - $611 million Yr. 3 - $632 million AMI (j): Yr. 1 - $20 million Yr. 2 - $24 million Yr. 3 - $25 million In 2019, the company deferred an immaterial amount as regulatory asset.
Average rate base	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million	Yr. 1 – $454 million Yr. 2 – $476 million Yr. 3 – $498 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 percent	Yr. 1 – 8.9 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $4 million, $0.2 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates pursuant to this rate plan continued in effect until the subsequent rate plan became effective.


(b)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes gas AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.

(d)


(e)	The gas base rate changes shown above will be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

(f)-(k) See footnotes (f) - (k) to the table under “O&R New York - Electric,” above.

In January 2020, the NJBPU approved an electric rate increase, effective February 1, 2020, of $12 million for RECO. The following table contains a summary of the terms of the distribution rate plans.



RECO
Effective period	March 2017 – January 2020	February 2020
Base rate changes	Yr. 1 – $1.7 million	Yr. 1 – $12 million
Amortization to income of net regulatory (assets) and liabilities	$0.2 million over three years and continuation of $(25.6) million of deferred storm costs over four years which expired on July 31, 2018 (a)	$4.8 million over four years.
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	Yr. 1 – $178.7 million	Yr. 1 – $229.9 million
Weighted average cost of capital (after-tax)	7.47 percent	7.11 percent
Authorized return on common equity	9.6 percent	9.5 percent
Actual return on common equity	Yr. 1 – 7.5 percent Yr. 2 – 5.7 percent
Cost of long-term debt	5.37 percent	4.88 percent
Common equity ratio	49.7 percent	48.32 percent


(a)	In January 2016, the NJBPU approved RECO’s plan to spend $15.7 million in capital over three years to harden its electric system against storms, the costs of which RECO, beginning in 2017, is collecting through a customer surcharge.

In November 2017, FERC approved a September 2017 settlement agreement among RECO, the New Jersey Division of Rate Counsel and the NJBPU that increases RECO's annual transmission revenue requirement from $11.8 million to $17.7 million, effective April 2017. The revenue requirement reflects a return on common equity of 10.0 percent.

Other Regulatory Matters

In August 2018, the NYSPSC ordered CECONY to begin on January 1, 2019 to credit the company's electric and gas customers, and to begin on October 1, 2018 to credit its steam customers, with the net benefits of the federal Tax Cuts and Jobs Act of 2017 (TCJA) as measured based on amounts reflected in its rate plans prior to the enactment of the TCJA in December 2017. The net benefits include the revenue requirement impact of the reduction in the corporate federal income tax rate to 21 percent, the elimination for utilities of bonus depreciation and the amortization of excess deferred federal income taxes.

CECONY, under its electric rate plan that was approved in January 2020, is amortizing its TCJA net benefits prior to January 1, 2019 allocable to its electric customers ($377 million) over a three-year period, the “protected” portion of its net regulatory liability for future income taxes related to certain accelerated tax depreciation benefits allocable to its electric customers ($1,663 million) over the remaining lives of the related assets and the remainder, or “unprotected” portion of the net regulatory liability allocable to its electric customers ($784 million) over a five-year period. CECONY, under its gas rate plan that was approved in January 2020, is amortizing its remaining TCJA net benefits prior to January 1, 2019 allocable to its gas customers ($63 million) over a two-year period, the protected portion of its net regulatory liability for future income taxes allocable to its gas customers ($725 million) over the remaining lives of the related assets and the unprotected portion of the net regulatory liability allocable to its gas customers ($107 million) over a five-year period. See footnote (d) to the CECONY - Electric and Gas tables under “Rate Plans,” above.

CECONY's net benefits prior to October 1, 2018 allocable to the company’s steam customers ($15 million) are being amortized over a three-year period. CECONY’s net regulatory liability for future income taxes, including both the protected and unprotected portions, allocable to the company’s steam customers ($185 million) is being amortized over the remaining lives of the related assets (with the amortization period for the unprotected portion subject to review in its next steam rate proceeding).

O&R, under its current electric and gas rate plans, has reflected its TCJA net benefits in its electric and gas rates beginning as of January 1, 2019. Under the rate plans, O&R is amortizing its net benefits prior to January 1, 2019 ($22 million) over a three-year period, the protected portion of its net regulatory liability for future income taxes ($123 million) over the remaining lives of the related assets and the unprotected portion ($30 million) over a fifteen-year period. See "Rate Plans," above.

In January 2018, the NYSPSC issued an order initiating a focused operations audit of the income tax accounting of certain utilities, including CECONY and O&R. The Utilities are unable to estimate the amount or range of their possible loss related to this matter. At December 31, 2019, the Utilities had not accrued a liability related to this matter.

In March 2018, Winter Storms Riley and Quinn caused damage to the Utilities’ electric distribution systems and interrupted service to approximately 209,000 CECONY customers, 93,000 O&R customers and 44,000 RECO customers. At December 31, 2019, CECONY's costs related to March 2018 storms, including Riley and Quinn, amounted to $134 million, including operation and maintenance expenses reflected in its electric rate plan ($15 million), operation and maintenance expenses charged against a storm reserve pursuant to its electric rate plan ($84 million), capital expenditures ($29 million) and removal costs ($6 million). At December 31, 2019, O&R and RECO costs related to 2018 storms amounted to $43 million and $17 million, respectively, most of which were deferred as regulatory assets pursuant to their electric rate plans. In January 2019, O&R began recovering its deferred storm costs over a six-year period in accordance with its New York electric rate plan. The NYSPSC investigated the preparation and response to the storms by CECONY, O&R, and other New York electric utilities, including all aspects of their emergency response plans. In April 2019, following the issuance of a NYSPSC staff report on the investigation, the NYSPSC ordered the utilities to show cause why the NYSPSC should not commence a penalty action against them for violating their emergency response plans. The Utilities are unable to estimate the amount or range of their possible loss related to this matter. At December 31, 2019, the Utilities had not accrued a liability related to this matter.

In July 2018, the NYSPSC commenced an investigation into the rupture of a CECONY steam main located on Fifth Avenue and 21^st Street in Manhattan. Debris from the incident included dirt and mud containing asbestos. The response to the incident required the closing of buildings and streets for various periods. The NYSPSC has commenced an investigation. As of December 31, 2019, with respect to the incident, the company incurred operating costs of $17 million for property damage, clean-up and other response costs and invested $9 million in capital and retirement costs. The company is unable to estimate the amount or range of its possible loss related to the incident. At December 31, 2019, the company had not accrued a liability related to the incident.

In March 2019, the NYSPSC ordered CECONY to show cause why the NYSPSC should not commence a penalty action and prudence proceeding against CECONY for alleged violations of gas operator qualification, performance, and inspection requirements. At December 31, 2019, the company had accrued a $10 million liability related to this matter.

On July 13, 2019, electric service was interrupted to approximately 72,000 CECONY customers on the west side of Manhattan. The NYSPSC and the Northeast Power Coordinating Council, a regional reliability entity, are investigating the July 13, 2019 power outage. Pursuant to the major outage reliability performance provisions of its electric rate plan, as a result of the July 13, 2019 power outage, the company recorded a $5 million negative revenue adjustment. The NYSPSC is also investigating other CECONY power outages that occurred in July 2019, primarily in the Flatbush area of Brooklyn. Primarily due to these outages, pursuant to the rate plan’s annual non-network outage frequency and non-network outage duration reliability performance provisions, the company recorded a $10 million negative revenue adjustment. The company is unable to estimate the amount or range of its possible additional loss related to these power outages.

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2019 and 2018 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Regulatory assets
Unrecognized pension and other postretirement costs	$2,541	$2,238	$2,403	$2,111
Environmental remediation costs	732	810	647	716
Revenue taxes	321	291	308	278
MTA power reliability deferral	248	229	248	229
Property tax reconciliation	219	101	210	86
System peak reduction and energy efficiency programs	131	72	130	70
Deferred derivative losses	83	17	76	11
Municipal infrastructure support costs	75	67	75	67
Pension and other postretirement benefits deferrals	71	73	47	56
Deferred storm costs	77	76	—	—
Brooklyn Queens demand management program	39	39	39	39
Meadowlands heater odorization project	35	36	35	36
Unamortized loss on reacquired debt	28	36	26	34
Preferred stock redemption	22	23	22	23
Recoverable REV demonstration project costs	21	20	19	18
Gate station upgrade project	19	17	19	17
Non-wire alternative projects	14	3	14	3
Workers’ compensation	3	5	3	5
O&R transition bond charges	—	2	—	—
Other	180	139	166	124
Regulatory assets – noncurrent	4,859	4,294	4,487	3,923
Deferred derivative losses	128	36	113	29
Recoverable energy costs	—	40	—	35
Regulatory assets – current	128	76	113	64
Total Regulatory Assets	$4,987	$4,370	$4,600	$3,987
Regulatory liabilities
Future income tax*	$2,426	$2,515	$2,275	$2,363
Allowance for cost of removal less salvage	989	928	843	790
TCJA net benefits	471	434	454	411
Net unbilled revenue deferrals	199	117	199	117
Net proceeds from sale of property	173	6	173	6
Energy efficiency portfolio standard unencumbered funds	122	127	118	122
Pension and other postretirement benefit deferrals	75	62	46	40
System benefit charge carrying charge	48	27	44	24
Property tax refunds	45	45	45	45
BQDM and REV Demo reconciliations	27	18	26	18
Earnings sharing - electric, gas and steam	22	36	15	27
Settlement of gas proceedings	10	15	10	15
Unrecognized other postretirement costs	9	7	—	7
Settlement of prudence proceeding	8	37	8	37
Property tax reconciliation	—	36	—	36
Other	203	231	171	200
Regulatory liabilities – noncurrent	4,827	4,641	4,427	4,258
Refundable energy costs	44	31	12	8
Deferred derivative gains	34	30	34	29
Revenue decoupling mechanism	24	53	17	36
Regulatory liabilities—current	102	114	63	73
Total Regulatory Liabilities	$4,929	$4,755	$4,490	$4,331

* See "Federal Income Tax" in Note A, "Other Regulatory Matters," above, and Note L.

Unrecognized pension and other postretirement costs represent the net regulatory asset associated with the accounting rules for retirement benefits. See Note A.

Revenue taxes represent the timing difference between taxes collected and paid by the Utilities to fund mass transportation.

MTA power reliability deferral represents CECONY’s costs in excess of those reflected in its prior electric rate plan to take certain actions relating to the electrical equipment that serves the Metropolitan Transportation Authority (MTA) subway system. The company is recovering this regulatory asset pursuant to its current electric rate plan. See footnote (d) to the CECONY - Electric table under “Rate Plans,” above.

Deferred storm costs represent response and restoration costs, other than capital expenditures, in connection with Superstorm Sandy and other major storms that were deferred by the O&R.

Settlement of prudence proceeding represents the remaining amount to be credited to customers pursuant to a Joint Proposal, approved by the NYSPSC in April 2016, with respect to the prudence of certain CECONY expenditures and related matters.

Settlement of gas proceedings represents the amount to be credited to customers pursuant to a settlement agreement approved by the NYSPSC in February 2017 related to CECONY’s practices of qualifying persons to perform plastic fusions on gas facilities and alleged violations of gas safety violations identified by the NYSPSC staff in its investigation of a March 2014 Manhattan explosion and fire (see Note H).

The NYSPSC has authorized CECONY to accrue unbilled electric, gas and steam revenues. CECONY has deferred the net margin on the unbilled revenues for the future benefit of customers by recording a regulatory liability of $199 million and $117 million at December 31, 2019 and 2018, respectively, for the difference between the unbilled revenues and energy cost liabilities.

Electricity Purchase Agreements

The Utilities have electricity purchase agreements with non-utility generators and others for generating capacity. The Utilities recover their purchased power costs in accordance with provisions approved by the applicable state public utility regulators. See “Recoverable Energy Costs” in Note A. The Utilities also conducted auctions and have entered into various other electricity purchase agreements. Assuming performance by the parties to the electricity purchase agreements, the Utilities are obligated over the terms of the agreements to make capacity and other fixed payments.

The future capacity and other fixed payments under the electricity purchase agreements are estimated to be as follows:



(Millions of Dollars)	2020	2021	2022	2023	2024	All Years Thereafter
Con Edison	$172	$101	$62	$57	$55	$546
CECONY	169	99	62	57	55	546

For energy delivered under most of the electricity purchase agreements, CECONY is obligated to pay variable prices. The company’s payments under its agreements for capacity, energy and other fixed payments in 2019, 2018 and 2017 were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019		2018	2017
Indian Point (a)		$—	$6	$211
Linden Cogeneration (b)	—		—	114
Astoria Generating Company (c)	116		179	92
Brooklyn Navy Yard (d)	115		124	117
Cogen Technologies	—		9	18
Total	$231		$318	$552

(a) Contract term ended in 2018.

(b) Contract term ended in 2017.

(d) Contract for plant output, which started in 1996 and ends in 2036.

Capitalization

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Capitalization

Common Stock

Con Edison is authorized to issue 500,000,000 shares of its common stock and CECONY is authorized to issue 340,000,000 of its common stock. At December 31, 2019 and 2018, 332,629,597 and 320,960,396 shares, respectively, of Con Edison common stock were outstanding. At December 31, 2019 and 2018, 235,488,094 million shares of CECONY common stock were outstanding, all of which were owned by Con Edison. At December 31, 2019 and 2018, Con Edison had 23,210,700 treasury shares, including 21,976,200 shares of Con Edison stock that CECONY purchased prior to 2001 in connection with Con Edison’s stock repurchase plan. CECONY presents in the financial statements the cost of the Con Edison stock it owns as a reduction of common shareholder’s equity.

In November 2018, Con Edison entered into forward sale agreements relating to 14,973,492 shares of its common stock. In December 2018, the company issued 9,324,123 shares for $705 million upon physical settlement of shares subject to the forward sale agreements. In March 2019, Con Edison issued 5,649,369 shares of its common stock for $425 million upon physical settlement of the remaining shares subject to the forward sale agreements.

In May 2019, Con Edison entered into a forward sale agreement relating to 5,800,000 shares of its common stock. In June 2019, the company issued 4,750,000 shares for $400 million upon physical settlement of shares subject to the forward sale agreement. At December 31, 2019, 1,050,000 shares remained subject to the forward sale agreement. In January 2020, the company issued 1,050,000 shares for $88 million upon physical settlement of the remaining shares subject to the forward sale agreement.

Capitalization of Con Edison

Con Edison's capitalization shown on its Consolidated Statement of Capitalization includes its outstanding common stock and long-term debt and the outstanding long-term debt of the Utilities and the Clean Energy Businesses.

Dividends

In accordance with NYSPSC requirements, the dividends that the Utilities generally pay are limited to not more than 100 percent of their respective income available for dividends calculated on a two–year rolling average basis. See Note S. Excluded from the calculation of “income available for dividends” are non-cash charges to income resulting from accounting changes or charges to income resulting from significant unanticipated events. The restriction also does not apply to dividends paid in order to transfer to Con Edison proceeds from major transactions, such as asset sales, or to dividends reducing each utility subsidiary’s equity ratio to a level appropriate to its business risk.

Long-term Debt

Long-term debt maturing in the period 2020-2024 is as follows:



(Millions of Dollars)	Con Edison		CECONY
2020	$518	(a)	$350
2021	1,967		640
2022	437		—
2023	316		—
2024	385		250

(a)

Amount shown includes $73 million of PG&E-related project debt that is amortizing and scheduled to be repaid in 2020. Amount shown does not include $928 million of PG&E-related project debt that, as a result of the PG&E bankruptcy, was reclassified during the first quarter of 2019 on Con Edison’s consolidated balance sheet from long-term debt to long-term debt due within one year. See “Long-Lived and Intangible Assets” in Note A.

CECONY has issued $450 million of tax–exempt debt through the New York State Energy Research and Development Authority (NYSERDA) that currently bear interest at a rate determined weekly and is subject to tender by bondholders for purchase by the company.

The carrying amounts and fair values of long-term debt at December 31, 2019 and 2018 are:



(Millions of Dollars)	2019		2018
Long-Term Debt (including current portion) (a)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$19,973	$22,738	$18,145	$18,740
CECONY	$14,964	$17,505	$14,151	$14,685


(a)	Amounts shown are net of unamortized debt expense and unamortized debt discount of $178 million and $151 million for Con Edison and CECONY, respectively, as of December 31, 2019 and $185 million and $139 million for Con Edison and CECONY, respectively, as of December 31, 2018.

The fair values of the Companies' long-term debt have been estimated primarily using available market information and at December 31, 2019 are classified as Level 2 (see Note P).

At December 31, 2019, and 2018, the Clean Energy Businesses had $2,737 million and $2,076 million, respectively of non-recourse debt secured by the pledge of the applicable renewable energy production projects including $1,001 million and $1,050 million, respectively, of PG&E-related project debt. As a result of the January 2019 PG&E bankruptcy (see "Long-Lived and Intangible Assets" in Note A), the lenders for the PG&E-related project debt may, upon written notice, declare principal and interest on the PG&E-related project debt to be due and payable immediately and, if such amounts are not timely paid, foreclose on the related projects. The company is seeking to negotiate agreements with the PG&E-related project debt lenders pursuant to which the lenders would defer exercising these remedies.

Significant Debt Covenants

The significant debt covenants under the financing arrangements for the Companies' debentures and Con Edison's notes and February 2019 $825 million, two-year variable-rate term loan include obligations to pay principal and interest when due and covenants not to consolidate with or merge into any other entity unless certain conditions are met. In addition, the notes include a covenant that the company shall continue its utility business in New York City, the term loan includes a covenant that, subject to certain exceptions, the company and its subsidiaries will not mortgage, lien, pledge or otherwise encumber its assets, and the notes and term loan provide that the company shall not permit its ratio of consolidated debt to consolidated total capital to exceed certain amounts (0.675 to 1 for the notes and 0.65 for the term loan) and include cross default provisions with respect to the failure by the company or any material subsidiary to make one or more payments in respect of material financial obligations (in excess of an aggregate $100 million of debt for the notes and $150 million of debt or derivative obligations for the term loan, excluding non-recourse debt) of the company (or any of its material subsidiaries, in the case of the notes) and the occurrence of an event or condition which results in the acceleration of the maturity of any material debt (in excess of an aggregate $100 million for the notes and $150 million for the term loan, not including non-recourse debt) of the company (or any of its material subsidiaries, in the case of the notes) or enables the holders of such debt to accelerate the maturity thereof. The Companies' debentures have no cross default provisions. The tax–exempt financing arrangements of CECONY are subject to covenants for the debentures discussed above and the covenants discussed below. The Companies were in compliance with their significant debt covenants at December 31, 2019.

The tax-exempt financing arrangements involved the issuance of uncollateralized promissory notes of CECONY to NYSERDA in exchange for the net proceeds of a like amount of tax–exempt bonds with substantially the same terms sold to the public by NYSERDA. The tax-exempt financing arrangements include covenants with respect to the tax–exempt status of the financing, including covenants with respect to the use of the facilities financed. The arrangements include provisions for the maintenance of liquidity and credit facilities, the failure to comply with which would, except as otherwise provided, constitute an event of default for the debt to which such provisions applied.

The failure to comply with debt covenants would, except as otherwise provided, constitute an event of default for the debt to which such provisions applied. If an event of default were to occur, the principal and accrued interest on the debt to which such event of default applied and, in the case of the Con Edison notes, a make-whole premium might and, in the case of certain events of default would, become due and payable immediately.

The liquidity and credit facilities currently in effect for the tax–exempt financing include covenants that the ratio of debt to total capital of CECONY will not at any time exceed 0.65 to 1 and that, subject to certain exceptions, CECONY will not mortgage, lien, pledge or otherwise encumber its assets. Certain of the facilities also include as events of default, defaults in payments of other debt obligations in excess of specified levels ($150 million or $100 million, depending on the facility).

Short-Term Borrowing	12 Months Ended
Short-Term Borrowing	Dec. 31, 2019
Debt Disclosure [Abstract]
Short-Term Borrowing	Short-Term Borrowing In December 2016, Con Edison and the Utilities entered into a credit agreement (Credit Agreement), under which banks are committed to provide loans and letters of credit on a revolving credit basis. The Credit Agreement, as amended in 2019, expires in December 2023. There is a maximum of $2,250 million of credit available through December 2022 and $2,200 million of credit available from then through December 2023. The full amount is available to CECONY and $1,000 million (subject to increase up to $1,500 million) is available to Con Edison, including up to $1,200 million of letters of credit. The Credit Agreement supports the Companies’ commercial paper programs. The Companies have not borrowed under the Credit Agreement. At December 31, 2019, Con Edison had $1,692 million of commercial paper outstanding, of which $1,137 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2019 was 2.0 percent for both Con Edison and CECONY. At December 31, 2018, Con Edison had $1,741 million of commercial paper outstanding of which $1,192 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2018 was 3.0 percent for both Con Edison and CECONY. At December 31, 2019 and 2018, no loans were outstanding under the Credit Agreement. An immaterial amount of letters of credit were outstanding under the Credit Agreement as of December 31, 2019 and 2018. The banks’ commitments under the Credit Agreement are subject to certain conditions, including that there be no event of default. The commitments are not subject to maintenance of credit rating levels or the absence of a material adverse change. Upon a change of control of, or upon an event of default by one of the Companies, the banks may terminate their commitments with respect to that company, declare any amounts owed by that company under the Credit Agreement immediately due and payable and require that company to provide cash collateral relating to the letters of credit issued for it under the Credit Agreement. Events of default for a company include that company exceeding at any time of a ratio of consolidated debt to consolidated total capital of 0.65 to 1 (at December 31, 2019 this ratio was 0.51 to 1 for Con Edison and 0.53 to 1 for CECONY); that company having liens on its assets in an aggregate amount exceeding five percent of its consolidated total capital, subject to certain exceptions; that company or any of its material subsidiaries failing to make one or more payments in respect of material financial obligations (in excess of an aggregate $150 million of debt or derivative obligations other than non-recourse debt) of that company; the occurrence of an event or condition which results in the acceleration of the maturity of any material debt (in excess of an aggregate $150 million of debt other than non-recourse debt) of that company or enables the holders of such debt to accelerate the maturity thereof; and other customary events of default. Interest and fees charged for the revolving credit facilities and any loans made or letters of credit issued under the Credit Agreement reflect the Companies’ respective credit ratings. The Companies were in compliance with their covenants at December 31, 2019. See Note S for information about short-term borrowing between related parties.

Pension Benefits

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Pension Benefits

Con Edison maintains a tax-qualified, non-contributory pension plan that covers substantially all employees of CECONY, O&R and Con Edison Transmission and certain employees of the Clean Energy Businesses. The plan is designed to comply with the Internal Revenue Code and the Employee Retirement Income Security Act of 1974. Con Edison also maintains additional non–qualified supplemental pension plans.

Total Periodic Benefit Cost

The components of the Companies’ total periodic benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost – including administrative expenses	$250	$290	$263	$232	$272	$246
Interest cost on projected benefit obligation	601	561	591	564	525	554
Expected return on plan assets	(988)	(1,033)	(968)	(936)	(979)	(917)
Recognition of net actuarial loss	518	688	595	492	651	563
Recognition of prior service cost/(credit)	(17)	(17)	(17)	(19)	(19)	(19)
TOTAL PERIODIC BENEFIT COST	$364	$489	$464	$333	$450	$427
Cost capitalized	(108)	(127)	(181)	(102)	(119)	(169)
Reconciliation to rate level	(15)	(92)	(34)	(12)	(100)	(41)
Total expense recognized	$241	$270	$249	$219	$231	$217

In March 2017, the FASB issued amendments to the guidance for retirement benefits through ASU 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” The Companies adopted ASU 2017-07 beginning on January 1, 2018. The guidance requires that components of net periodic benefit cost other than service cost be presented outside of operating income on consolidated income statements, and that only the service cost component is eligible for capitalization. Accordingly, the service cost components are included in the line "Other operations and maintenance" and the non-service cost components are included in the line “Other deductions” in the Companies' consolidated income statements. As permitted by a practical expedient under ASU 2017-07, the Companies applied the presentation requirements retrospectively for both pension and other postretirement benefit costs using amounts disclosed in prior-period financial statements as appropriate estimates.

Funded Status

The funded status at December 31, 2019, 2018 and 2017 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
Service cost – excluding administrative expenses	245	286	259	228	267	241
Interest cost on projected benefit obligation	601	561	591	564	525	554
Net actuarial loss/(gain)	2,191	(1,219)	1,231	2,076	(1,159)	1,171
Plan amendments	15	—	6	—	—	—
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$16,792	$14,449	$15,536	$15,750	$13,542	$14,567
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
Actual return on plan assets	2,556	(536)	2,041	2,425	(507)	1,935
Employer contributions	350	473	450	318	434	412
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
Administrative expenses	(39)	(46)	(43)	(37)	(44)	(41)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$15,608	$13,450	$14,274	$14,790	$12,744	$13,519
FUNDED STATUS	$(1,184)	$(999)	$(1,262)	$(960)	$(798)	$(1,048)
Unrecognized net loss	$2,604	$2,464	$2,760	$2,466	$2,338	$2,624
Unrecognized prior service costs	(173)	(205)	(223)	(202)	(222)	(242)
Accumulated benefit obligation	15,015	13,030	13,897	14,010	12,161	12,972

The increase in the pension liability at Con Edison and CECONY of $185 million and $162 million, respectively, compared with December 31, 2018, was primarily due to an increase in the plan’s projected benefit obligation as a result of a decrease in the discount rate, partially offset by an increase in plan assets as a result of the actual return on plan assets. For Con Edison, this increase in pension liability corresponds with an increase to regulatory assets of $167 million for unrecognized net losses and unrecognized prior service costs associated with the Utilities consistent with the accounting rules for regulated operations, a debit to OCI of $10 million (net of taxes) for the unrecognized net losses, and an immaterial change to OCI (net of taxes) for the unrecognized prior service costs associated with the Clean Energy Businesses, Con Edison Transmission, and RECO.

For CECONY, the increase in pension liability corresponds with an increase to regulatory assets of $147 million for unrecognized net losses and unrecognized prior service costs consistent with the accounting rules for regulated operations, and also a debit to OCI of $2 million (net of taxes) for unrecognized net losses, and an immaterial change to OCI (net of taxes) for the unrecognized prior service costs associated with certain employees of the Clean Energy Businesses and Con Edison Transmission who previously worked for CECONY.

A portion of the unrecognized net loss and prior service cost for the pension plan, equal to $701 million and $(16) million, respectively, will be recognized from accumulated OCI and the regulatory asset into net periodic benefit cost over the next year for Con Edison. Included in these amounts are $663 million and $(20) million, respectively, for CECONY.

At December 31, 2019 and 2018, Con Edison’s investments include $397 million and $326 million, respectively, held in external trust accounts for benefit payments pursuant to the supplemental retirement plans. Included in these amounts for CECONY were $371 million and $301 million, respectively. See Note P. The accumulated benefit obligations for the supplemental retirement plans for Con Edison and CECONY were $395 million and $360 million as of December 31, 2019 and $316 million and $285 million as of December 31, 2018, respectively.

Assumptions

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	3.35	%	4.25	%	3.70	%
Rate of compensation increase
CECONY	3.80	%	4.25	%	4.25	%
O&R	3.20	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Expected return on plan assets	7.00	%	7.50	%	7.50	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%

The expected return assumption reflects anticipated returns on the plan’s current and future assets. The Companies’ expected return was based on an evaluation of the current environment, market and economic outlook, relationships between the economy and asset class performance patterns, and recent and long-term trends in asset class performance. The projections were based on the plan’s target asset allocation.

Discount Rate Assumption

To determine the assumed discount rate, the Companies use a model that produces a yield curve based on yields on selected highly rated (Aa or higher by either Moody’s or Standard & Poor’s) corporate bonds. Bonds with insufficient liquidity, bonds with questionable pricing information and bonds that are not representative of the overall market are excluded from consideration. For example, the bonds used in the model cannot be callable (with the exception of "make whole" callable bonds), and the amount of the bond issue outstanding must be in excess of $50 million. The spot rates defined by the yield curve and the plan’s projected benefit payments are used to develop a weighted average discount rate.

Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$744	$756	$770	$788	$801	$4,181
CECONY	688	699	713	728	741	3,883

Expected Contributions

Based on estimates as of December 31, 2019, the Companies expect to make contributions to the pension plans during 2020 of $472 million (of which $433 million is to be made by CECONY). The Companies’ policy is to fund the total periodic benefit cost of the qualified plan to the extent tax deductible and to also contribute to the non-qualified supplemental plans.

Plan Assets

The asset allocations for the pension plan at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	45% - 55%	51	%	51	%	58	%
Debt Securities	33% - 43%	38	%	39	%	33	%
Real Estate	10% - 14%	11	%	10	%	9	%
Total	100%	100	%	100	%	100	%

Con Edison has established a pension trust for the investment of assets to be used for the exclusive purpose of providing retirement benefits to participants and beneficiaries and payment of plan expenses.

Pursuant to resolutions adopted by Con Edison’s Board of Directors, the Management Development and Compensation Committee of the Board of Directors (the Committee) has general oversight responsibility for Con Edison’s pension and other employee benefit plans. The pension plan’s named fiduciaries have been granted the authority to control and manage the operation and administration of the plans, including overall responsibility for the investment of assets in the trust and the power to appoint and terminate investment managers.

The investment objectives of the Con Edison pension plan are to maintain a level and form of assets adequate to meet benefit obligations to participants, to achieve the expected long-term total return on the trust assets within a prudent level of risk and maintain a level of volatility that is not expected to have a material impact on the company’s expected contribution and expense or the company’s ability to meet plan obligations. The assets of the plan have no significant concentration of risk in one country (other than the United States), industry or entity.

The strategic asset allocation is intended to meet the objectives of the pension plan by diversifying its funds across asset classes, investment styles and fund managers. An asset/liability study typically is conducted every few years to determine whether the current strategic asset allocation continues to represent the appropriate balance of expected risk and reward for the plan to meet expected liabilities. Each study considers the investment risk of the asset allocation and determines the optimal asset allocation for the plan. The target asset allocation for 2020 reflects the results of such a study conducted in 2018.

Individual fund managers operate under written guidelines provided by Con Edison, which cover such areas as investment objectives, performance measurement, permissible investments, investment restrictions, trading and execution, and communication and reporting requirements. Con Edison management regularly monitors, and the named fiduciaries review and report to the Committee regarding, asset class performance, total fund performance, and compliance with asset allocation guidelines. Management changes fund managers and rebalances the portfolio as appropriate. At the direction of the named fiduciaries, such changes are reported to the Committee.

Assets measured at fair value on a recurring basis are summarized below as defined by the accounting rules for fair value measurements (see Note P).

The fair values of the pension plan assets at December 31, 2019 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,652		$—	$3,652
International Equity (b)	3,354	—		3,354
U.S. Government Issued Debt (c)	—	1,496		1,496
Corporate Bonds Debt (d)	—	3,260		3,260
Structured Assets Debt (e)	—	173		173
Other Fixed Income Debt (f)	—	955		955
Cash and Cash Equivalents (g)	—	326		326
Futures (h)	—	—		—
Total investments within the fair value hierarchy	$7,006	$6,210		$13,216
Investments measured at NAV per share (n)
Private Equity (i)				555
Real Estate (j)				1,806
Hedge Funds (k)				270
Total investments valued using NAV per share				$2,631
Funds for retiree health benefits (l)	(110)	(98)		(208)
Funds for retiree health benefits measured at NAV per share (l)(n)				(42)
Total funds for retiree health benefits				$(250)
Investments (excluding funds for retiree health benefits)	$6,896	$6,112		$15,597
Pending activities (m)				11
Total fair value of plan net assets				$15,608


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	U.S. Government Issued Debt includes agency and treasury securities.


(d)	Corporate Bonds Debt consists of debt issued by various corporations.


(e)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(f)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(g)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(h)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(i)	Private Equity consists of global equity funds that are not exchange-traded.


(j)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)

The Companies set aside funds for retiree health benefits through a separate account within the pension trust, as permitted under Section 401(h) of the Internal Revenue Code of 1986, as amended. In accordance with the Code, the plan’s investments in the 401(h) account may not be used for, or diverted to, any purpose other than providing health benefits for retirees. The net assets held in the 401(h) account are calculated based on a pro-rata percentage allocation of the net assets in the pension plan. The related obligations for health benefits are not included in the pension plan’s obligations and are included in the Companies’ other postretirement benefit obligation. See Note F.


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.


(n)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

The fair values of the pension plan assets at December 31, 2018 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,515	$10	$3,525
International Equity (b)	2,896	—	2,896
U.S. Government Issued Debt (c)	—	1,886	1,886
Corporate Bonds Debt (d)	—	2,619	2,619
Structured Assets Debt (e)	—	6	6
Other Fixed Income Debt (f)	—	121	121
Cash and Cash Equivalents (g)	160	556	716
Futures (h)	568	—	568
Total investments within the fair value hierarchy	$7,139	$5,198	$12,337
Investments measured at NAV per share (n)
Private Equity (i)			440
Real Estate (j)			1,310
Hedge Funds (k)			255
Total investments valued using NAV per share			$2,005
Funds for retiree health benefits (l)	(118)	(86)	(204)
Funds for retiree health benefits measured at NAV per share (l)(n)			(33)
Total funds for retiree health benefits			$(237)
Investments (excluding funds for retiree health benefits)	$7,021	$5,112	$14,105
Pending activities (m)			(655)
Total fair value of plan net assets			$13,450

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2019 by asset category.

The Companies also offer a defined contribution savings plan that covers substantially all employees and made contributions to the plan as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$49	$45	$40
CECONY	42	39	35

Other Postretirement Benefits

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Other Postretirement Benefits

The Utilities and Con Edison Transmission currently have contributory comprehensive hospital, medical and prescription drug programs for eligible retirees, their dependents and surviving spouses.

CECONY also has a contributory life insurance program for bargaining unit employees and provides basic life insurance benefits up to a specified maximum at no cost to certain retired management employees. O&R has a non-contributory life insurance program for retirees. Certain employees of the Clean Energy Businesses and Con Edison Transmission are eligible to receive benefits under these programs.

Total Periodic Benefit Cost

The components of the Companies’ total periodic postretirement benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost	$18	$20	$20	$13	$14	$13
Interest cost on accumulated other postretirement benefit obligation	44	42	46	36	34	38
Expected return on plan assets	(66)	(73)	(69)	(54)	(63)	(61)
Recognition of net actuarial loss/(gain)	(9)	8	2	(10)	3	(3)
Recognition of prior service credit	(2)	(6)	(17)	(2)	(2)	(11)
TOTAL PERIODIC POSTRETIREMENT BENEFIT CREDIT	$(15)	$(9)	$(18)	$(17)	$(14)	$(24)
Cost capitalized	(7)	(8)	8	(5)	(6)	10
Reconciliation to rate level	12	8	(4)	7	9	(2)
Total credit recognized	$(10)	$(9)	($14)	$(15)	$(11)	($16)

For information about the adoption of ASU 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” see Note E.

Funded Status

The funded status of the programs at December 31, 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,114	$1,219	$1,198	$913	$985	$1,007
Service cost	18	20	20	13	14	13
Interest cost on accumulated postretirement benefit obligation	44	42	46	36	34	38
Amendments	(14)	—	—	—	—	—
Net actuarial loss/(gain)	264	(70)	53	252	(32)	16
Benefits paid and administrative expenses, net of subsidies	(110)	(135)	(134)	(100)	(125)	(124)
Participant contributions	41	38	36	40	37	35
BENEFIT OBLIGATION AT END OF YEAR	$1,357	$1,114	$1,219	$1,154	$913	$985
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$885	$1,039	$975	$759	$893	$851
Actual return on plan assets	198	(66)	150	165	(54)	130
Employer contributions	7	6	17	6	6	8
Employer group waiver plan subsidies	23	34	34	22	32	30
Participant contributions	40	37	35	40	37	35
Benefits paid	(127)	(165)	(172)	(120)	(155)	(161)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$1,026	$885	$1,039	$872	$759	$893
FUNDED STATUS	$(331)	$(229)	$(180)	$(282)	$(154)	$(92)
Unrecognized net loss/(gain)	$155	$14	$(47)	$149	$(2)	$(85)
Unrecognized prior service costs	(19)	(8)	(14)	(3)	(5)	(7)

The increase in the other postretirement benefits liability at Con Edison and CECONY of $102 million and $128 million, respectively, compared with December 31, 2018, was primarily due to an increase in the plans' projected benefit obligation as a result of an increase in net actuarial loss, partially offset by an increase in plan assets as a result of the actual return on plan assets. For Con Edison, this increased liability corresponds with an increase to regulatory assets of $134 million for unrecognized net losses and unrecognized prior service costs associated with the Utilities consistent with the accounting rules for regulated operations, a credit to OCI of $6 million (net of taxes) for the unrecognized net losses and a debit to OCI of $1 million (net of taxes) for the unrecognized prior service costs associated with the Clean Energy Businesses, Con Edison Transmission, and RECO.

For CECONY, the increase in liability corresponds with an increase to regulatory assets of $153 million for unrecognized net losses and the unrecognized prior service costs associated with the company consistent with the accounting rules for regulated operations, and also immaterial changes to OCI for the unrecognized net losses and the unrecognized prior service costs associated with eligible employees of the Clean Energy Businesses and Con Edison Transmission who previously worked for CECONY.

A portion of the unrecognized net losses and prior service costs for the other postretirement benefits, equal to $27 million and $(3) million, respectively, will be recognized from accumulated OCI and the regulatory asset into net periodic benefit cost over the next year for Con Edison. Included in these amounts are $22 million and $(2) million, respectively, for CECONY.

Assumptions

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	3.10	%	4.15	%	3.55	%
O&R	3.35	%	4.30	%	3.70	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Expected Return on Plan Assets	6.80	%	7.50	%	7.50	%

Refer to Note E for descriptions of the basis for determining the expected return on assets, investment policies and strategies and the assumed discount rate.

The health care cost trend rate used to determine net periodic benefit cost for the years ended December 31, 2019, 2018 and 2017 was 5.40 percent, 5.60 percent and 5.80 percent, respectively, which is assumed to decrease gradually to 4.50 percent by 2024 and remain at that level thereafter. The health care cost trend rate used to determine benefit obligations as of December 31, 2019, 2018 and 2017 was 5.20 percent, 5.40 percent and 5.60 percent, respectively, which is assumed to decrease gradually to 4.50 percent by 2024 and remain at that level thereafter.

A one-percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2019:



	Con Edison		CECONY
	One-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$60	$(17)	$33	$3
Effect on service cost and interest cost components for 2019	1	—	(1)	2

Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years, net of receipt of governmental subsidies and participant contributions:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$96	$95	$93	$92	$91	$422
CECONY	87	85	83	82	80	368

Expected Contributions

Based on estimates as of December 31, 2019, Con Edison and CECONY expect to make a contribution of $6 million (substantially all of which is to be made by CECONY) to the other postretirement benefit plans in 2020. The Companies’ policy is to fund the total periodic benefit cost of the plans to the extent tax deductible.

Plan Assets

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	42%-80%	54	%	52	%	60	%
Debt Securities	20%-58%	46	%	48	%	40	%
Total	100%	100	%	100	%	100	%

Con Edison has established postretirement health and life insurance benefit plan trusts for the investment of assets to be used for the exclusive purpose of providing other postretirement benefits to participants and beneficiaries.

Refer to Note E for a discussion of Con Edison’s investment policy for its benefit plans.

The fair values of the plans' assets at December 31, 2019 by asset category as defined by the accounting rules for fair value measurements (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$404	$404
Other Fixed Income Debt (b)	—		331	331
Cash and Cash Equivalents (c)	—		23	23
Total investments		$—	$758	$758
Funds for retiree health benefits (d)	110		98	208
Investments (including funds for retiree health benefits)		$110	$856	$966
Funds for retiree health benefits measured at net asset value (d)(e)				42
Pending activities (f)				18
Total fair value of plan net assets				$1,026


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Bloomberg Barclays U.S. Long Credit Index and an active separately managed fund indexed to the Bloomberg Barclays U.S. Long Credit Index.


(c)	Cash and Cash Equivalents include short-term investments and money markets.

(d)


(e)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.


(f)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year-end.

The fair values of the plans' assets at December 31, 2018 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$322	$322
Other Fixed Income Debt (b)	—		289	289
Cash and Cash Equivalents (c)	—		14	14
Total investments		$—	$625	$625
Funds for retiree health benefits (d)	118		86	204
Investments (including funds for retiree health benefits)		$118	$711	$829
Funds for retiree health benefits measured at net asset value (d)(e)				33
Pending activities (f)				23
Total fair value of plan net assets				$885

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2019 by asset category.

Environmental Matters

12 Months Ended

Dec. 31, 2019

Environmental Remediation Obligations [Abstract]

Environmental Matters

Superfund Sites

Hazardous substances, such as asbestos, polychlorinated biphenyls (PCBs) and coal tar, have been used or generated in the course of operations of the Utilities and their predecessors and are present at sites and in facilities and equipment they currently or previously owned, including sites at which gas was manufactured or stored.

The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 and similar state statutes (Superfund) impose joint and several liability, regardless of fault, upon generators of hazardous substances for investigation and remediation costs (which include costs of demolition, removal, disposal, storage, replacement, containment and monitoring) and natural resource damages. Liability under these laws can be material and may be imposed for contamination from past acts, even though such past acts may have been lawful at the time they occurred. The sites at which the Utilities have been asserted to have liability under these laws, including their manufactured gas plant sites and any neighboring areas to which contamination may have migrated, are referred to herein as “Superfund Sites.”

For Superfund Sites where there are other potentially responsible parties and the Utilities are not managing the site investigation and remediation, the accrued liability represents an estimate of the amount the Utilities will need to pay to investigate and, where determinable, discharge their related obligations. For Superfund Sites (including the manufactured gas plant sites) for which one of the Utilities is managing the investigation and remediation, the accrued liability represents an estimate of the company’s share of the undiscounted cost to investigate the sites and, for sites that have been investigated in whole or in part, the cost to remediate the sites, if remediation is necessary and if a reasonable estimate of such cost can be made. Remediation costs are estimated in light of the information available, applicable remediation standards and experience with similar sites.

The accrued liabilities and regulatory assets related to Superfund Sites at December 31, 2019 and 2018 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Accrued Liabilities:
Manufactured gas plant sites	$640	$689	$561	$603
Other Superfund Sites	94	90	93	90
Total	$734	$779	$654	$693
Regulatory assets	$732	$810	$647	$716

Most of the accrued Superfund Site liability relates to sites that have been investigated, in whole or in part. However, for some of the sites, the extent and associated cost of the required remediation has not yet been determined. As investigations progress and information pertaining to the required remediation becomes available,

the Utilities expect that additional liability may be accrued, the amount of which is not presently determinable but may be material. The Utilities are permitted to recover or defer as regulatory assets (for subsequent recovery through rates) prudently incurred site investigation and remediation costs.

Environmental remediation costs incurred related to Superfund Sites at December 31, 2019 and 2018 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Remediation costs incurred	$19	$25	$13	$18

Insurance and other third party recoveries received by Con Edison or CECONY were immaterial in 2019 and 2018.

Con Edison and CECONY estimate that in 2020 they will incur costs for remediation of approximately $46 million and $43 million, respectively. The Companies are unable to estimate the time period over which the remaining accrued liability will be incurred because, among other things, the required remediation has not been determined for some of the sites.

In 2019, Con Edison and CECONY estimated that for their manufactured gas plant sites (including CECONY’s Astoria site), the aggregate undiscounted potential liability for the investigation and remediation of coal tar and/or other environmental contaminants could range up to $2.8 billion and $2.6 billion, respectively. These estimates were based on the assumption that there is contamination at all sites, including those that have not yet been fully investigated and additional assumptions about the extent of the contamination and the type and extent of the remediation that may be required. Actual experience may be materially different.

Asbestos Proceedings

Suits have been brought in New York State and federal courts against the Utilities and many other defendants, wherein a large number of plaintiffs sought large amounts of compensatory and punitive damages for deaths and injuries allegedly caused by exposure to asbestos at various premises of the Utilities. The suits that have been resolved, which are many, have been resolved without any payment by the Utilities, or for amounts that were not, in the aggregate, material to them. The amounts specified in all the remaining thousands of suits total billions of dollars; however, the Utilities believe that these amounts are greatly exaggerated, based on the disposition of previous claims. At December 31, 2019, Con Edison and CECONY have accrued their estimated aggregate undiscounted potential liabilities for these suits and additional suits that may be brought over the next 15 years as shown in the following table. These estimates were based upon a combination of modeling, historical data analysis and risk factor assessment. Courts have begun, and unless otherwise determined on appeal may continue, to apply different standards for determining liability in asbestos suits than the standard that applied historically. As a result, the Companies currently believe that there is a reasonable possibility of an exposure to loss in excess of the liability accrued for the suits. The Companies are unable to estimate the amount or range of such loss. In addition, certain current and former employees have claimed or are claiming workers’ compensation benefits based on alleged disability from exposure to asbestos. CECONY is permitted to defer as regulatory assets (for subsequent recovery through rates) costs incurred for its asbestos lawsuits and workers’ compensation claims.

The accrued liability for asbestos suits and workers’ compensation proceedings (including those related to asbestos exposure) and the amounts deferred as regulatory assets for the Companies at December 31, 2019 and 2018 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$78	$79	$73	$75
Regulatory assets – workers’ compensation	$3	$5	$3	$5

Other Material Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Other Material Contingencies

Manhattan Explosion and Fire

On March 12, 2014, two multi-use five-story tall buildings located on Park Avenue between 116th and 117th Streets in Manhattan were destroyed by an explosion and fire. CECONY had delivered gas to the buildings through service lines from a distribution main located below ground on Park Avenue. Eight people died and more than 50 people were injured. Additional buildings were also damaged. The National Transportation Safety Board (NTSB) investigated. The parties to the investigation included the company, the City of New York, the Pipeline and Hazardous Materials Safety Administration and the NYSPSC. In June 2015, the NTSB issued a final report concerning the incident, its probable cause and safety recommendations. The NTSB determined that the probable cause of the incident was (1) the failure of a defective fusion joint at a service tee (which joined a plastic service line to a plastic distribution main) installed by the company that allowed gas to leak from the distribution main and migrate into a building where it ignited and (2) a breach in a City sewer line that allowed groundwater and soil to flow into the sewer, resulting in a loss of support for the distribution main, which caused it to sag and overstressed the defective fusion joint. The NTSB also made safety recommendations, including recommendations to the company that addressed its procedures for the preparation and examination of plastic fusions, training of its staff on conditions for notifications to the City’s Fire Department and extension of its gas main isolation valve installation program. In February 2017, the NYSPSC approved a settlement agreement with the company related to the NYSPSC's investigations of the incident and the practices of qualifying persons to perform plastic fusions. Pursuant to the agreement, the company is providing $27 million of future benefits to customers (for which it has accrued a regulatory liability) and will not recover from customers $126 million of costs for gas emergency response activities that it had previously incurred and expensed. Approximately eighty suits are pending against the company seeking generally unspecified damages and, in some cases, punitive damages, for wrongful death, personal injury, property damage and business interruption. The company has notified its insurers of the incident and believes that the policies in force at the time of the incident will cover the company’s costs, in excess of a required retention (the amount of which is not material), to satisfy any liability it may have for damages in connection with the incident. The company is unable to estimate the amount or range of its possible loss for damages related to the incident. At December 31, 2019, the company had not accrued a liability for damages related to the incident.

Other Contingencies

For information about the PG&E bankruptcy, see "Long-Lived and Intangible Assets" in Note A. Also, for additional contingencies, see “Other Regulatory Matters” in Note B and "Uncertain Tax Positions" in Note L.

Guarantees

Con Edison and its subsidiaries have entered into various agreements providing financial or performance assurance primarily to third parties on behalf of their subsidiaries. Maximum amounts guaranteed by Con Edison under these agreements totaled $1,831 million and $2,439 million at December 31, 2019 and 2018, respectively.

A summary, by type and term, of Con Edison’s total guarantees under these other agreements at December 31, 2019 is as follows:



Guarantee Type	0 – 3 years	4 – 10 years	> 10 years		Total
	(Millions of Dollars)
Con Edison Transmission	$387	$186		$—	$573
Energy transactions	419	51	209		679
Renewable electric production projects	70	9	431		510
Other	69	—	—		69
Total	$945	$246	$640		$1,831

Con Edison Transmission – Con Edison has guaranteed payment by CET Electric of the contributions CET Electric agreed to make to New York Transco LLC (NY Transco). CET Electric owns a 45.7 percent interest in NY Transco. In April 2019, the New York Independent System Operator (NYISO) selected a transmission project that was jointly proposed by National Grid and NY Transco. The siting, construction and operation of the project will require approvals and permits from appropriate governmental agencies and authorities, including the NYSPSC. The NYISO indicated it will work with the developers to enter into agreements for the development and operation of the projects, including a schedule for entry into service by December 2023. Guarantee amount shown includes the maximum possible required amount of CET Electric’s contributions for this project as calculated based on the

assumptions that the project is completed at 175 percent of its estimated costs and NY Transco does not use any debt financing for the project. Also included within the table above are guarantees for $25 million from Con Edison on behalf of CET Gas in relation to Mountain Valley Pipeline (MVP), LLC, a company developing a proposed gas transmission project in West Virginia and Virginia. See Note U.

Energy Transactions — Con Edison guarantees payments on behalf of the Clean Energy Businesses in order to facilitate physical and financial transactions in electricity, gas, pipeline capacity, transportation, oil, renewable energy credits and energy services. To the extent that liabilities exist under the contracts subject to these guarantees, such liabilities are included in Con Edison’s consolidated balance sheet.

Renewable Electric Production Projects – Con Edison and the Clean Energy Businesses guarantee payments on behalf of their wholly-owned subsidiaries associated with their investment in, or development for others of, solar and wind energy facilities. See Note U.

Other – Other guarantees include $70 million in guarantees provided by Con Edison to Travelers Insurance Company for indemnity agreements for surety bonds in connection with operation of solar energy facilities and energy service projects of the Clean Energy Businesses.

Electricity Purchase Agreements

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Electricity Purchase Agreements

Regulatory Matters

Rate Plans

Common provisions of the Utilities’ New York rate plans include:

Recoverable energy costs that allow the Utilities to recover on a current basis the costs for the energy they supply with no mark-up to their full-service customers.

Negative revenue adjustments for failure to meet certain performance standards relating to service, reliability, safety and other matters.

Positive revenue adjustments for achievement of performance standards related to achievement of clean energy goals, safety and other matters.

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	January 2017 – December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $195 million (b) Yr. 2 – $155 million (b) Yr. 3 – $155 million (b)	Yr. 1 – $113 million (c) Yr. 2 – $370 million (c) Yr. 3 – $326 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million	Yr. 1 – $267 million (d) Yr. 2 – $269 million (d) Yr. 3 – $272 million (d)
Other revenue sources	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 – $28 million Yr. 2 – $47 million Yr. 3 – $64 million In 2017, 2018 and 2019, the company recorded $13 million, $25 million and $43 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved $5 million of incentives for service terminations in 2017, 2018 and 2019 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded $3 million and $7 million of incentives for service terminations, respectively.	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $69 million Yr. 2 - $74 million Yr. 3 - $79 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017, 2018 and 2019, the company deferred for customer benefit $45 million, $(6) million and $169 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues.
Recoverable energy costs	Continuation of current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 – $376 million Yr. 2 – $341 million Yr. 3 – $352 million In 2017 and 2018, the company did not record any negative revenue adjustments. In 2019, the company recorded negative revenue adjustments of $15 million.	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 - $450 million Yr. 2 - $461 million Yr. 3 - $476 million



Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (g). In 2017, 2018 and 2019, the company deferred $35 million, $189 million and $10 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 – $21,689 million Yr. 2 – $22,338 million Yr. 3 – $23,002 million AMI: Yr. 1 – $126 million Yr. 2 – $257 million Yr. 3 – $415 million The company deferred $0.4 million as a regulatory asset in 2017. In 2018 and 2019, $0.4 and $11.8 million was deferred as a regulatory liability, respectively.	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $24,491 million Yr. 2 - $25,092 million Yr. 3 - $25,708 million AMI: Yr. 1 - $572 million Yr. 2 - $740 million Yr. 3 - $806 million (h)
Average rate base	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million	Yr. 1 - $21,660 million Yr. 2 - $22,783 million Yr. 3 - $23,926 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent Yr. 3 – 8.82 percent
Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, the company had no earnings above the threshold but recorded a positive adjustment related to 2016 of $5.7 million in earnings. In 2018 and 2019, the company had no earnings sharing above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)

(b)

(c)

(d)


(e)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr 1 - 10.0 basis points; Yr 2 - 7.5 basis points; and Yr 3 - 5.0 basis points.

(f)

30 percent of the amount reflected in the January 2017-December 2019 rate plan and 15 percent of the amount reflected in the January 2020-December 2022 rate plan.


(g)	In addition, the NYSPSC staff has commenced a focused operations audit to investigate the income tax accounting of CECONY and other New York utilities. Any NYSPSC-ordered adjustment to CECONY’s income tax accounting will be refunded to or collected from customers, as determined by the NYSPSC. See "Other Regulatory Matters," below.


(h)	Reconciliation of net utility plant for AMI will be done on a combined basis for electric and gas.


(i)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



CECONY – Gas
Effective period	January 2017 - December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $(5) million (b) Yr. 2 – $92 million Yr. 3 – $90 million	Yr. 1 – $84 million (c) Yr. 2 – $122 million (c) Yr. 3 – $167 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million	Yr. 1 – $45 million (d) Yr. 2 – $43 million (d) Yr. 3 – $10 million (d)
Other revenue sources	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential incentives if performance targets related to gas leak backlog, leak prone pipe and service terminations are met: Yr. 1 – $7 million Yr. 2 – $8 million Yr. 3 – $8 million In 2017, 2018 and 2019, the company achieved incentives of $7 million, $6 million and $7 million, respectively, that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded incentives of $5 million and $9 million, respectively, for gas leak backlog, leak prone pipe and service terminations.	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential earnings adjusted mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $20 million Yr. 2 - $22 million Yr. 3 - $25 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017, 2018 and 2019, the company deferred $3 million, $12 million and $10 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues, modified to be calculated based upon revenue per customer class instead of revenue per customer.
Recoverable energy costs	Continuation of current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 – $68 million Yr. 2 – $63 million Yr. 3 – $70 million In 2017 and 2018, the company recorded negative revenue adjustments of $5 million and $4 million, respectively. In 2019, the company did not record any negative revenue adjustments.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $81 million Yr. 2 - $88 million Yr. 3 - $96 million
Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g) In 2017, 2018 and 2019, the company deferred $2 million of net regulatory liabilities, $44 million of net regulatory assets and $18 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 – $5,844 million Yr. 2 – $6,512 million Yr. 3 – $7,177 million AMI: Yr. 1 – $27 million Yr. 2 – $57 million Yr. 3 – $100 million In 2017 and 2018 the company deferred $2.2 million as regulatory liabilities. In 2019, the company deferred $1.7 million as a regulatory liability.	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 - $8,108 million Yr. 2 - $8,808 million Yr. 3 - $9,510 million AMI: Yr. 1 - $142 million Yr. 2 - $183 million Yr. 3 - $211 million (h)
Average rate base	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million	Yr. 1 - $7,171 million Yr. 2 - $7,911 million Yr. 3 - $8,622 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent Yr. 3 – 8.72 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, 2018 and 2019, the company had no earnings above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)


(b)	The gas base rate decrease was offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.

(c)

(d)


(e)-(i)	See footnotes (e) - (i) to the table under “CECONY Electric,” above.



CECONY – Steam
Effective period		January 2014 – December 2016 (a)
Base rate changes		Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b) Yr. 4 – None Yr. 5 – None Yr. 6 – None
Amortizations to income of net regulatory (assets) and liabilities		$37 million over three years
Recoverable energy costs		Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments		Potential charges (up to $1 million annually) if certain steam performance targets are not met. In years 2014 through 2019, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016, 2017, 2018 and 2019, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, $1 million of net regulatory assets and $8 million of net regulatory liabilities, respectively.
Net utility plant reconciliations		Target levels reflected in rates were: Production: Yr. 1 – $1,752 million Yr. 2 – $1,732 million Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million Yr. 2 – $11 million Yr. 3 – $25 million The company reduced its regulatory liability by $0.1 million in 2014 and immaterial amounts in 2015 and 2016 and no deferrals were recorded in 2017, 2018 and 2019.
Average rate base		Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)		Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity		9.3 percent
Actual return on common equity (d)		Yr. 1 – 9.82 percent Yr. 2 – 10.88 percent Yr. 3 – 10.54 percent Yr. 4 – 9.51 percent Yr. 5 – 11.73 percent Yr. 6 – 10.45 percent
Earnings sharing		Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $11.5 million and $7.8 million above the threshold in 2015 and 2016, respectively. In 2017, actual earnings were $8.5 million above the threshold, offset in part by a positive adjustment related to 2016 of $4 million. In 2018, actual earnings were $16.5 million above the threshold, and an additional $1.1 million related to 2017 was recorded. In 2019 actual earnings were $5 million above the threshold, offset in part by an adjustment related to 2018 of $2.3 million.
Cost of long-term debt		Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio		48 percent


(a)	Rates determined pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.


(b)	The impact of these base rate changes was deferred which resulted in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.


(d)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Electric
Effective period	November 2015 - October 2017 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $9.3 million Yr. 2 – $8.8 million Yr. 3 – None	Yr. 1 – $13.4 million (e) Yr. 2 – $8.0 million (e) Yr. 3 – $5.8 million (e)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $(8.5) million (b) Yr. 2 – $(9.4) million (b) Yr. 3 – None	Yr. 1 – $(1.5) million (f) Yr. 2 – $(1.5) million (f) Yr. 3 – $(1.5) million (f)
Other revenue sources		Potential earnings adjustment mechanism incentives for peak reduction, energy efficiency, Distributed Energy Resources utilization and other potential incentives of up to: Yr. 1 - $3.6 million Yr. 2 - $4.0 million Yr. 3 - $4.2 million Potential incentive if performance target related to service terminations is met: $0.5 million annually. In 2019, the company recorded $2.6 million of earnings adjustment mechanism incentives for energy efficiency and $0.2 million of incentives for service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred for the customer’s benefit an immaterial amount, $6.3 million as regulatory liabilities, $11.2 million as regulatory asset and $0.5 million as regulatory asset, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2019 the company deferred $0.1 million as a regulatory asset.
Recoverable energy costs	Continuation of current rate recovery of purchased power costs.	Continuation of current rate recovery of purchased power costs.
Negative revenue adjustments	Potential charges (up to $4 million annually) if certain performance targets are not met. In 2015 the company recorded $1.25 million in negative revenue adjustments. In 2016, 2017 and 2018, the company did not record any negative revenue adjustments.	Potential charges if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million Yr. 2 - $4.4 million Yr. 3 - $4.5 million In 2019, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2015, 2016 and 2017, the company deferred $0.3 million, $7.4 million and $3.2 million as net decreases to regulatory assets, respectively. In 2018, the company deferred $5 million as a net regulatory asset.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), major storms, the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $4.3 million as a net regulatory asset.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $928 million (c) Yr. 2 – $970 million (c) The company increased/(reduced) its regulatory asset by $2.2 million, $(1.9) million, $(1.9) million and $1.4 million in 2015, 2016, 2017 and 2018, respectively.	Target levels reflected in rates were: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $1,008 million Yr. 2 - $1,032 million Yr. 3 - $1,083 million AMI (j): Yr. 1 - $48 million Yr. 2 - $58 million Yr. 3 - $61 million The company increased regulatory asset by an immaterial amount in 2019.
Average rate base	Yr. 1 – $763 million Yr. 2 – $805 million Yr. 3 – $805 million	Yr. 1 – $878 million Yr. 2 – $906 million Yr. 3 – $948 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 percent	Yr. 1 – 9.6 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $6.1 million, $0.3 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates determined pursuant to this rate plan continued in effect until the subsequent rate plan became effective.

(b)


(c)	Excludes electric AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.

(d)


(e)	The electric base rate increases shown above will be implemented with increases of: Yr. 1 - $8.6 million; Yr. 2 - $12.1 million; and Yr. 3 - $12.2 million.

(f)


(g)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr. 1 - 10.0 basis points; Yr. 2 - 7.5 basis points; and Yr. 3 - 5.0 basis points.


(h)	Energy efficiency costs are expensed as incurred. Such costs are subject to a downward-only reconciliation over the terms of the electric and gas rate plans. The company will defer for the benefit of customers any cumulative shortfall over the terms of the electric and gas rate plans between actual expenditures and the levels provided in rates.


(i)	In addition, amounts reflected in rates relating to income taxes and excess deferred federal income tax liability balances will be reconciled (i.e., refunded to or collected from customers) to any final, non-appealable NYSPSC-ordered findings in its investigation of O&R’s income tax accounting. See “Other Regulatory Matters,” in Note B.


(j)	Net plant reconciliation for AMI expenditures will be implemented for a single category of AMI capital expenditures that includes amounts allocated to both electric and gas customers.


(k)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Gas
Effective period	November 2015 – October 2018 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge	Yr. 1 – $(7.5) million (e) Yr. 2 – $3.6 million (e) Yr. 3 – $0.7 million (e)
Amortization to income of net regulatory (assets) and liabilities	Yr. 1 – $(1.7) million (b) Yr. 2 – $(2.1) million (b) Yr. 3 – $(2.5) million (b)	Yr. 1 – $1.8 million (f) Yr. 2 – $1.8 million (f) Yr. 3 – $1.8 million (f)
Other revenue sources		Continuation of retention of annual revenues from non-firm customers of up to $4.0 million, with variances to be shared 80 percent by customers and 20 percent by company. Potential earnings adjustment mechanism incentives of up to $0.3 million annually. Potential incentives if performance targets related to gas leak backlog, leak prone pipe, emergency response, damage prevention and service terminations are met: Yr. 1 - $1.2 million; Yr. 2 - $1.3 million; and Yr. 3 - $1.3 million. In 2019, the company recorded $0.3 million of earnings adjustment mechanism incentives for energy efficiency and $0.7 million of incentives for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred $0.8 million of regulatory assets, $6.2 million of regulatory liabilities, $1.7 million of regulatory liabilities and $6.3 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2019, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $4.9 million in Yr. 3) if certain performance targets are not met. In 2015, 2016 and 2017, the company did not record any negative revenue adjustments. In 2018, the company recorded a $0.1 million negative revenue adjustment.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $5.5 million; Yr. 2 - $5.7 million; and Yr. 3 - $6.0 million. In 2019, the company recorded a $0.2 million negative revenue adjustment.
Cost reconciliations	In 2015 and 2016, the company deferred $4.5 million and $6.6 million as net regulatory liabilities and assets, respectively. In 2017 and 2018, the company deferred $3.5 million and $7.4 million as net regulatory liabilities, respectively.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $6 million as net regulatory liabilities.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $492 million (c) Yr. 2 – $518 million (c) Yr. 3 – $546 million (c) No deferral was recorded for 2015 and immaterial amounts were recorded as regulatory liabilities in 2016 and 2017. In 2018, the company deferred $0.4 million as regulatory asset.	Target levels reflected in rates were: Gas average net plant target excluding AMI: Yr. 1 - $593 million Yr. 2 - $611 million Yr. 3 - $632 million AMI (j): Yr. 1 - $20 million Yr. 2 - $24 million Yr. 3 - $25 million In 2019, the company deferred an immaterial amount as regulatory asset.
Average rate base	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million	Yr. 1 – $454 million Yr. 2 – $476 million Yr. 3 – $498 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 percent	Yr. 1 – 8.9 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $4 million, $0.2 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates pursuant to this rate plan continued in effect until the subsequent rate plan became effective.


(b)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes gas AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.

(d)


(e)	The gas base rate changes shown above will be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

(f)-(k) See footnotes (f) - (k) to the table under “O&R New York - Electric,” above.

In January 2020, the NJBPU approved an electric rate increase, effective February 1, 2020, of $12 million for RECO. The following table contains a summary of the terms of the distribution rate plans.



RECO
Effective period	March 2017 – January 2020	February 2020
Base rate changes	Yr. 1 – $1.7 million	Yr. 1 – $12 million
Amortization to income of net regulatory (assets) and liabilities	$0.2 million over three years and continuation of $(25.6) million of deferred storm costs over four years which expired on July 31, 2018 (a)	$4.8 million over four years.
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	Yr. 1 – $178.7 million	Yr. 1 – $229.9 million
Weighted average cost of capital (after-tax)	7.47 percent	7.11 percent
Authorized return on common equity	9.6 percent	9.5 percent
Actual return on common equity	Yr. 1 – 7.5 percent Yr. 2 – 5.7 percent
Cost of long-term debt	5.37 percent	4.88 percent
Common equity ratio	49.7 percent	48.32 percent


(a)	In January 2016, the NJBPU approved RECO’s plan to spend $15.7 million in capital over three years to harden its electric system against storms, the costs of which RECO, beginning in 2017, is collecting through a customer surcharge.

Other Regulatory Matters

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2019 and 2018 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Regulatory assets
Unrecognized pension and other postretirement costs	$2,541	$2,238	$2,403	$2,111
Environmental remediation costs	732	810	647	716
Revenue taxes	321	291	308	278
MTA power reliability deferral	248	229	248	229
Property tax reconciliation	219	101	210	86
System peak reduction and energy efficiency programs	131	72	130	70
Deferred derivative losses	83	17	76	11
Municipal infrastructure support costs	75	67	75	67
Pension and other postretirement benefits deferrals	71	73	47	56
Deferred storm costs	77	76	—	—
Brooklyn Queens demand management program	39	39	39	39
Meadowlands heater odorization project	35	36	35	36
Unamortized loss on reacquired debt	28	36	26	34
Preferred stock redemption	22	23	22	23
Recoverable REV demonstration project costs	21	20	19	18
Gate station upgrade project	19	17	19	17
Non-wire alternative projects	14	3	14	3
Workers’ compensation	3	5	3	5
O&R transition bond charges	—	2	—	—
Other	180	139	166	124
Regulatory assets – noncurrent	4,859	4,294	4,487	3,923
Deferred derivative losses	128	36	113	29
Recoverable energy costs	—	40	—	35
Regulatory assets – current	128	76	113	64
Total Regulatory Assets	$4,987	$4,370	$4,600	$3,987
Regulatory liabilities
Future income tax*	$2,426	$2,515	$2,275	$2,363
Allowance for cost of removal less salvage	989	928	843	790
TCJA net benefits	471	434	454	411
Net unbilled revenue deferrals	199	117	199	117
Net proceeds from sale of property	173	6	173	6
Energy efficiency portfolio standard unencumbered funds	122	127	118	122
Pension and other postretirement benefit deferrals	75	62	46	40
System benefit charge carrying charge	48	27	44	24
Property tax refunds	45	45	45	45
BQDM and REV Demo reconciliations	27	18	26	18
Earnings sharing - electric, gas and steam	22	36	15	27
Settlement of gas proceedings	10	15	10	15
Unrecognized other postretirement costs	9	7	—	7
Settlement of prudence proceeding	8	37	8	37
Property tax reconciliation	—	36	—	36
Other	203	231	171	200
Regulatory liabilities – noncurrent	4,827	4,641	4,427	4,258
Refundable energy costs	44	31	12	8
Deferred derivative gains	34	30	34	29
Revenue decoupling mechanism	24	53	17	36
Regulatory liabilities—current	102	114	63	73
Total Regulatory Liabilities	$4,929	$4,755	$4,490	$4,331

* See "Federal Income Tax" in Note A, "Other Regulatory Matters," above, and Note L.

Unrecognized pension and other postretirement costs represent the net regulatory asset associated with the accounting rules for retirement benefits. See Note A.

Revenue taxes represent the timing difference between taxes collected and paid by the Utilities to fund mass transportation.

Deferred storm costs represent response and restoration costs, other than capital expenditures, in connection with Superstorm Sandy and other major storms that were deferred by the O&R.

Electricity Purchase Agreements

The future capacity and other fixed payments under the electricity purchase agreements are estimated to be as follows:



(Millions of Dollars)	2020	2021	2022	2023	2024	All Years Thereafter
Con Edison	$172	$101	$62	$57	$55	$546
CECONY	169	99	62	57	55	546



	For the Years Ended December 31,
(Millions of Dollars)	2019		2018	2017
Indian Point (a)		$—	$6	$211
Linden Cogeneration (b)	—		—	114
Astoria Generating Company (c)	116		179	92
Brooklyn Navy Yard (d)	115		124	117
Cogen Technologies	—		9	18
Total	$231		$318	$552

(a) Contract term ended in 2018.

(b) Contract term ended in 2017.

(d) Contract for plant output, which started in 1996 and ends in 2036.

Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

In January 2019, the Companies adopted Accounting Standards Update (ASU) No. 2016-02, “Leases (Topic 842),” including the amendments thereto, using a modified retrospective transition method of adoption that required no prior period adjustments or charges to retained earnings for cumulative impact. The standard supersedes the lease requirements within ASC Topic 840, “Leases.”

The Companies lease land, office buildings, equipment and access rights to support electric transmission facilities. Upon adoption of Topic 842, the Companies recognized lease right-of-use assets and lease liabilities on their consolidated balance sheets for virtually all of their leases (other than leases that meet the definition of a short-term lease, the expense for which was immaterial). A lease right-of-use asset represents a right to use an identifiable underlying asset and obtain substantially all of the economic benefits from the use of that asset for the lease term. A lease liability represents an obligation to make lease payments arising from the lease. Leases are classified as either operating leases or finance leases. Operating leases are included in operating lease right-of-use asset and operating lease liabilities on the Companies’ consolidated balance sheets. Finance leases are included in other noncurrent assets, other current liabilities and other noncurrent liabilities. The Utilities, as regulated entities, are permitted to continue to recognize expense for operating leases using the timing that conforms to the regulatory rate treatment as rental payments are recovered from our customers and to account the same way for finance leases. Lessor accounting is similar to the previous model, but updated to align with ASC Topic 606 “Revenue from Contracts with Customers."

The Companies elected the following practical expedients: (1) a package of practical expedients that allows the Companies to not reassess: (a) whether expired or existing contracts contained leases; (b) the lease classification for expired or existing leases and (c) the initial direct costs for existing leases; (2) for all underlying asset classes, an expedient that allows the Companies to not apply the recognition requirements to short-term leases and an expedient that allows the Companies to account for lease and associated non-lease components as a single lease component; (3) an expedient that allows the use of hindsight to determine lease term; and (4) an expedient that allows the Companies to not evaluate under Topic 842 land easements that exist or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840.

The Companies, upon adoption of Topic 842 recognized, and for new operating leases at commencement date recognize, operating lease right-of-use assets and operating lease liabilities based on the present value of the future minimum lease payments over the lease term. As most of the Companies’ leases do not provide an implicit rate, the Companies used their collateralized incremental borrowing rate based on the information available at the commencement date to determine the present value of future payments. Most of the Companies’ leases have remaining lease terms of one year to 40 years, and may include options to renew or extend the leases for up to five years at the fair rental value. The Companies' lease terms include options to renew, extend or terminate the lease when it is reasonably certain that the Companies will exercise that option. There were no leases with material variable lease payments or residual value guarantees.

Operating lease cost and cash paid for amounts included in the measurement of lease liabilities for the twelve months ended December 31, 2019, were as follows:

As of December 31, 2019, assets recorded as finance leases were $1 million for Con Edison and an immaterial amount for CECONY, and the accumulated amortization associated with finance leases for Con Edison and CECONY were $5 million and $3 million, respectively. For the twelve months ended December 31, 2019, finance lease costs and cash flows for Con Edison and CECONY were immaterial.

Right-of-use assets obtained in exchange for lease obligations for Con Edison and CECONY were $39 million and $4 million, respectively, for the twelve months ended December 31, 2019.

Other information related to leases for Con Edison and CECONY at December 31, 2019 was as follows:



	Con Edison	CECONY
Weighted Average Remaining Lease Term:
Operating leases	19.8 years	14.0 years
Finance leases	12.2 years	2.4 years
Weighted Average Discount Rate:
Operating leases	4.3%	3.6%
Finance leases	3.5%	4.1%

Future minimum lease payments under non-cancellable leases at December 31, 2019 were as follows:



(Millions of Dollars)	Con Edison				CECONY
Year Ending December 31,	Operating Leases		Finance Leases		Operating Leases		Finance Leases
2020		$78		$—		$60		$—
2021	75		—		57		—
2022	73		—		55		—
2023	72		—		54		—
2024	72		—		55		—
All years thereafter	992		1		501		—
Total future minimum lease payments		$1,362		$1		$782		$—
Less: imputed interest	(488)		—		(177)		—
Total		$874		$1		$605		$—
Reported as of December 31, 2019
Operating lease liabilities (current)		$65		$—		$54		$—
Operating lease liabilities (noncurrent)	809		—		551		—
Other noncurrent liabilities	—		1		—		—
Total		$874		$1		$605		$—

At December 31, 2019, the Companies did not have material obligations under operating or finance leases that had not yet commenced.

Disclosures related to the twelve months ended December 31, 2019 are presented as required under Topic 842. Prior period disclosures for the year ended December 31, 2018 are presented under Topic 840. The Companies have elected to use a practical expedient provided by Topic 842 whereby comparative disclosures for prior periods are allowed to be presented under Topic 840. The disclosures presented under Topic 842 and Topic 840 will not be fully comparable in specific disclosure requirements.

The future minimum lease commitments at December 31, 2018, accounted for under Topic 840, for the Companies’ operating lease agreements that are not cancellable by the Companies were as follows:



(Millions of Dollars)	Con Edison	CECONY
2019	$72	$56
2020	72	56
2021	71	54
2022	68	53
2023	68	53
All years thereafter	890	592
Total	$1,241	$864

The Companies are lessors under certain leases whereby the Companies own real estate and distribution poles and lease portions of them to others. Revenue under such leases was immaterial for Con Edison and CECONY for the twelve months ended December 31, 2019.

Leases

Operating lease cost and cash paid for amounts included in the measurement of lease liabilities for the twelve months ended December 31, 2019, were as follows:

Right-of-use assets obtained in exchange for lease obligations for Con Edison and CECONY were $39 million and $4 million, respectively, for the twelve months ended December 31, 2019.

Other information related to leases for Con Edison and CECONY at December 31, 2019 was as follows:



	Con Edison	CECONY
Weighted Average Remaining Lease Term:
Operating leases	19.8 years	14.0 years
Finance leases	12.2 years	2.4 years
Weighted Average Discount Rate:
Operating leases	4.3%	3.6%
Finance leases	3.5%	4.1%

Future minimum lease payments under non-cancellable leases at December 31, 2019 were as follows:



(Millions of Dollars)	Con Edison				CECONY
Year Ending December 31,	Operating Leases		Finance Leases		Operating Leases		Finance Leases
2020		$78		$—		$60		$—
2021	75		—		57		—
2022	73		—		55		—
2023	72		—		54		—
2024	72		—		55		—
All years thereafter	992		1		501		—
Total future minimum lease payments		$1,362		$1		$782		$—
Less: imputed interest	(488)		—		(177)		—
Total		$874		$1		$605		$—
Reported as of December 31, 2019
Operating lease liabilities (current)		$65		$—		$54		$—
Operating lease liabilities (noncurrent)	809		—		551		—
Other noncurrent liabilities	—		1		—		—
Total		$874		$1		$605		$—

At December 31, 2019, the Companies did not have material obligations under operating or finance leases that had not yet commenced.

The future minimum lease commitments at December 31, 2018, accounted for under Topic 840, for the Companies’ operating lease agreements that are not cancellable by the Companies were as follows:



(Millions of Dollars)	Con Edison	CECONY
2019	$72	$56
2020	72	56
2021	71	54
2022	68	53
2023	68	53
All years thereafter	890	592
Total	$1,241	$864

Income Tax

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
State
Current	$(12)	$(10)	$(2)	$22	$6	$37
Deferred	96	107	103	68	82	75
Federal
Current	—	3	(11)	185	(34)	73
Deferred	219	310	391	63	275	504
Amortization of investment tax credits	(7)	(9)	(9)	(3)	(3)	(4)
Total income tax expense	$296	$401	$472	$335	$326	$685

The tax effects of temporary differences, which gave rise to deferred tax assets and liabilities, are as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Deferred tax liabilities:
Property basis differences	$7,699	$7,402	$6,640	$6,446
Regulatory assets:
Unrecognized pension and other postretirement costs	712	627	674	591
Environmental remediation costs	205	227	181	200
Deferred storm costs	22	21	—	—
Other regulatory assets	376	273	355	252
Operating lease right-of-use asset	231	—	169	—
Equity investments	104	102	—	—
Total deferred tax liabilities	$9,349	$8,652	$8,019	$7,489
Deferred tax assets:
Accrued pension and other postretirement costs	$291	$248	$222	$180
Regulatory liabilities:
Future income tax	678	702	638	662
Other regulatory liabilities	702	632	622	554
Superfund and other environmental costs	206	218	183	194
Asset retirement obligations	135	114	102	82
Operating lease liabilities	231	—	170	—
Loss carryforwards	108	229	—	—
Tax credits carryforward	896	817	—	—
Valuation allowance	(40)	(33)	—	—
Other	56	53	103	102
Total deferred tax assets	3,263	2,980	2,040	1,774
Net deferred tax liabilities	$6,086	$5,672	$5,979	$5,715
Unamortized investment tax credits	141	148	21	24
Net deferred tax liabilities and unamortized investment tax credits	$6,227	$5,820	$6,000	$5,739

Upon enactment of the TCJA in December 2017, the Companies re-measured their deferred tax assets and liabilities based upon the TCJA’s 21 percent corporate federal income tax rate. As a result, Con Edison, decreased its net deferred tax liabilities by $5,312 million (including $4,781 million for CECONY), recognized $259 million in net income, decreased its regulatory asset for future income tax by $1,250 million (including $1,182 million for CECONY), decreased the regulatory asset for revenue taxes by $90 million (including $86 million for CECONY), and accrued a regulatory liability for future income tax of $3,713 million (including $3,513 million for CECONY). Since the Companies were in a net regulatory liability position with respect to these income tax matters, the Companies netted the regulatory asset for future income tax against the regulatory liability for future income tax. Under the rate normalization requirements continued by the TCJA, $2,684 million of the net regulatory liability (including $2,542 million for CECONY) related to certain accelerated tax depreciation benefits is to be amortized over the remaining lives of the related assets. The remainder of the net regulatory liability is to be refunded (or credited) to customers as determined by the NYSPSC or NJBPU, as applicable. See “Other Regulatory Matters” in Note B. The amount recognized in net income included $269 million for the Clean Energy Businesses, $11 million for Con Edison Transmission and $(21) million for the parent company. The re-measurement had no impact on the Companies’ cash flows for 2017.

At December 31, 2017, the Companies recorded provisional income tax amounts in its accounting for certain effects of the provisions of the TCJA as allowed under SEC Staff Accounting Bulletin 118 (SAB 118). SAB 118 allowed a one year period for companies to finalize the provisional amounts recorded as of December 31, 2017. In August 2018, the Internal Revenue Service (IRS) and U.S. Department of Treasury issued proposed regulations (which were finalized in December 2019), that clarified provisions in the TCJA on the allowance for additional first-year depreciation for qualified property of regulated public utilities placed in service in the fourth quarter of 2017. Under this guidance, which Con Edison elected to adopt the Utilities deducted $477 million in additional depreciation in

Con Edison’s 2017 federal income tax return. The additional depreciation increased Con Edison’s 2017 federal net operating loss (NOL) carryover to $563 million (CECONY’s 2017 federal NOL carryover of $153 million was applied in full to CECONY's 2018 tax liability), which required a re-measurement of deferred tax assets and liabilities associated with the filing of its 2017 federal income tax return. As a result, Con Edison decreased its net deferred tax liabilities by $13 million (including $50 million for CECONY), recognized $42 million in income tax expense at the parent company related to re-measuring the 2017 federal NOL carryover to 2018, decreased the regulatory asset for revenue taxes by $1 million (entirely attributable to CECONY) and accrued a regulatory liability for future income tax of $54 million (including $49 million for CECONY). The Companies completed their assessment in the fourth quarter of 2018 and no further adjustments to the provisional amounts were recorded.

Reconciliation of the difference between income tax expense and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:



	Con Edison						CECONY
(% of Pre-tax income)	2019		2018		2017		2019		2018		2017
STATUTORY TAX RATE
Federal	21	%	21	%	35	%	21	%	21	%	35	%
Changes in computed taxes resulting from:
State income tax	4		4		4		5		5		4
Taxes attributable to noncontrolling interests	(1	)	—		—		—		—		—
Cost of removal	1		1		1		1		1		1
Other plant-related items	(1	)	(1	)	(1	)	(1	)	(1	)	(1	)
TCJA deferred tax re-measurement	—		2		(13	)	—		—		—
Amortization of excess deferred federal income taxes	(4	)	(3	)	—		(4	)	(3	)	—
Renewable energy credits	(2	)	(1	)	(1	)	—		—		—
Research and development credits	(1	)	—		—		(1	)	(1	)	—
Other	—		—		(2	)	—		(1	)	(1	)
Effective tax rate	17	%	23	%	23	%	21	%	21	%	38	%

CECONY and O&R deferred as regulatory liabilities their estimated net benefits under the TCJA for the year ended December 31, 2018. CECONY’s net benefits prior to January 1, 2019 for its electric service and amortization of excess deferred federal income taxes for its electric service continued to be deferred. RECO deferred as a regulatory liability its estimated net benefits under the TCJA for the three months ended March 31, 2018. The net benefits include the revenue requirement impact of the reduction in the corporate federal income tax rate to 21 percent, the elimination for utilities of bonus depreciation and the amortization of excess deferred federal income taxes the utilities collected from customers that will not be paid to the IRS under the TCJA. See “Other Regulatory Matters” in Note B.

At December 31, 2019, Con Edison had a federal net operating loss carryover of approximately $36 million from prior years, due primarily to accelerated depreciation (including bonus depreciation), comprised of its remaining 2017 federal net operating loss carryover of $13 million (which, will expire, if unused, in 2037) and its 2018 federal net operating loss carryover of $23 million (which can be carried forward indefinitely). Con Edison has $896 million in general business tax credit carryovers (primarily renewable energy tax credits), which if unused will begin to expire in 2032. A deferred tax asset for these tax attribute carryforwards was recorded, and no valuation allowance has been provided, as it is more likely than not that the deferred tax asset will be realized.

At December 31, 2019, Con Edison had a 2018 New York State net operating loss of approximately $272 million from 2018, primarily as a result of accelerated tax deductions on renewable energy projects. Con Edison will carry back approximately $100 million of its 2018 net operating loss to 2015 and 2016, which will result in recovery of $9 million of income tax. The remaining 2018 New York State net operating loss of $172 million will be carried forward to future years. At December 31, Con Edison had a 2019 New York State net operating loss of approximately $453 million, primarily as a result of accelerated tax deductions on renewable energy projects. This loss will be carried forward to future years. A deferred tax asset has been recognized for these New York State net operating loss carryforwards that will begin to expire, if unused, in 2038. A valuation allowance has not been provided; as it is more likely than not that the deferred tax asset will be realized. In addition, an $18 million valuation allowance for the entire amount of its New York City net operating loss carryforward and a $22 million valuation allowance for other

state net operating loss carryforwards has been provided; as it is not more likely than not that the deferred tax asset will be realized.

At December 31, 2019, Con Edison had charitable contributions carryforwards of $28 million ($5 million from 2015; $7 million from 2016; $5 million from 2017; $5 million from 2018 and $6 million from 2019), if unused will begin to expire in 2020. The tax effect of the carryforwards were recorded as a deferred tax asset, and no valuation allowance has been provided, as it is more likely than not that the deferred tax asset will be realized.

The Protecting Americans from Tax Hikes Act of 2015 extended bonus depreciation applying a 50 percent rate for property acquired and placed in service for years 2015 through 2017 with reduced rates of 40 percent and 30 percent for years 2018 and 2019, respectively. The TCJA does not allow bonus depreciation after December 31, 2017 (excluding certain transition rules) for Companies that qualify as a utility company for the consolidated group under the de minimis exception to Treasury regulations.

In December 2019, the Federal government issued final regulations providing guidance on provisions in the TCJA allowing for full expensing of qualified plant additions. These provisions, which Con Edison adopted under the proposed regulations of August 2018, allowed the Utilities a full expense tax deduction for plant additions in the fourth quarter of 2017, and the Utilities continue additional first year depreciation transition rules for plant additions placed in service in tax years beginning in 2018, under long-term construction contracts entered into before September 28, 2017. The impact on the Utilities of these regulations is discussed above.

In November 2018, the Federal government issued, and Con Edison adopted, proposed regulations providing guidance on the tax deductibility of interest expense under the TCJA. The TCJA generally provides for the continued deductibility of interest expense by regulated public utilities and may limit the deduction for interest expense by most non-utility businesses to 30 percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization).The regulations provide an annual safe harbor test that if at least 90 percent of consolidated plant assets consist of utility property, the entire consolidated group will be treated as a regulated public utility, and all of the consolidated group’s interest expense will be currently tax deductible. For 2018, Con Edison met the 90 percent safe harbor test and its deduction for interest expense was not limited. For 2019, Con Edison did not meet the 90 percent safe harbor test and its deduction for interest expense will be limited by an amount that is not material. Con Edison, as permitted, will carry over the portion of its 2019 interest expense that it will not be able to deduct for 2019 to future years when Con Edison expects it will be able to deduct such interest expense. Qualifying consolidated groups would not be entitled to the full expensing provisions in the TCJA noted above. The safe harbor rules do not apply to partnerships in which Con Edison and its subsidiaries are a partner.

Uncertain Tax Positions

Under the accounting rules for income taxes, the Companies are not permitted to recognize the tax benefit attributable to a tax position unless such position is more likely than not to be sustained upon examination by taxing authorities, including resolution of any related appeals and litigation processes, based solely on the technical merits of the position.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits for Con Edison and CECONY follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Balance at January 1,	$6	$12	$42	$4	$5	$21
Additions based on tax positions related to the current year	1	2	1	1	2	1
Additions based on tax positions of prior years	10	1	1	—	1	1
Reductions for tax positions of prior years	(2)	(2)	(24)	(1)	(1)	(18)
Reductions from expiration of statute of limitations	—	(4)	(2)	—	—	—
Settlements	(2)	(3)	(6)	(2)	(3)	—
Balance at December 31,	$13	$6	$12	$2	$4	$5

In 2019, Con Edison reached a settlement with the IRS on tax year 2017 and was denied state refund claims in New Jersey, which resulted in Con Edison reversing $4 million in uncertain tax positions. Of this amount, only an immaterial amount reduced Con Edison’s effective tax rate. The amount related to CECONY was $2 million, of which, only an immaterial amount reduced CECONY’s effective tax rate. Current and prior year additions in 2019 are for tax credits and a state combined reporting issue, which increased Con Edison's effective tax rate.

As of December 31, 2019, Con Edison reasonably expects to resolve within the next twelve months approximately $10 million of various federal and state uncertainties due to the expected completion of ongoing tax examinations, of which the entire amount, if recognized, would reduce Con Edison’s effective tax rate. The amount related to CECONY is approximately $1 million, of which the entire amount, if recognized, would reduce CECONY’s effective tax rate.

The Companies recognize interest on liabilities for uncertain tax positions in interest expense and would recognize penalties, if any, in operating expenses in the Companies’ consolidated income statements. In 2019, 2018 and 2017, the Companies recognized an immaterial amount of interest and no penalties for uncertain tax positions in their consolidated income statements. At December 31, 2019 and 2018, the Companies reflected an immaterial amount of interest and no penalties in their consolidated balance sheets.

At December 31, 2019, the total amount of unrecognized tax benefits that, if recognized, would reduce the Companies’ effective tax rate is $13 million ($12 million, net of federal taxes) with $2 million attributable to CECONY.

Con Edison's federal tax return for 2018 remains under examination. State income tax returns remain open for examination in New York for tax years 2010 through 2018 and in New Jersey for tax years 2008 through 2018.

Stock-Based Compensation

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Stock-Based Compensation

The Companies may compensate employees and directors with, among other things, stock options, stock units, restricted stock units and contributions to the stock purchase plan. The Long Term Incentive Plan, which was approved by Con Edison’s shareholders in 2003 (2003 LTIP), and the Long Term Incentive Plan, which was approved by Con Edison’s shareholders in 2013 (2013 LTIP), are collectively referred to herein as the LTIP. The LTIP provides for, among other things, awards to employees of restricted stock units and stock options and, to Con Edison’s non-employee directors, stock units. Existing awards under the 2003 LTIP continue in effect, however no new awards may be issued under the 2003 LTIP. The 2013 LTIP provides for awards for up to five million shares of common stock.

Shares of Con Edison common stock used to satisfy the Companies’ obligations with respect to stock-based compensation may be new (authorized, but unissued) shares, treasury shares or shares purchased in the open market. The shares used during the year ended December 31, 2019 were new shares. The Companies intend to use new shares to fulfill their stock-based compensation obligations for 2020.

The Companies recognized stock-based compensation expense using a fair value measurement method. The following table summarizes stock-based compensation expense recognized by the Companies in the years ended December 31, 2019, 2018 and 2017:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Performance-based restricted stock	$36	$3	$53	$30	$3	$45
Time-based restricted stock	2	2	2	2	1	2
Non-employee director deferred stock compensation	2	3	2	2	3	2
Stock purchase plan	7	6	6	6	6	6
Total	$47	$14	$63	$40	$13	$55
Income tax benefit	$13	$4	$25	$11	$4	$22

Restricted Stock and Stock Units

Restricted stock and stock unit awards under the LTIP have been made as follows: (i) awards that provide for adjustment of the number of units (performance-restricted stock units or Performance RSUs) to certain officers and employees; (ii) time-based awards to certain employees; and (iii) awards to non-employee directors. Restricted stock and stock units awarded represent the right to receive, upon vesting, shares of Con Edison common stock, or, except for units awarded under the directors’ plan, the cash value of shares or a combination thereof.

The number of units in each annual Performance RSU award is subject to adjustment as follows: (i) 50 percent of the units awarded will be multiplied by a factor that may range from 0 to 200 percent, based on Con Edison’s total shareholder return relative to a specified peer group during a specified performance period (the TSR portion); and (ii) 50 percent of the units awarded will be multiplied by factors that may range from 0 to 200 percent, based on determinations made in connection with the Companies’ annual incentive plans or, for certain executive officers, actual performance as compared to certain performance measures during a specified performance period (the non-TSR portion). Performance RSU awards generally vest upon completion of the performance period.

Performance against the established targets is recomputed each reporting period as of the earlier of the reporting date and the vesting date. The TSR portion applies a Monte Carlo simulation model, and the non-TSR portion is the product of the market price at the end of the period and the average non-TSR determination over the vesting period. Performance RSUs are “liability awards” because each Performance RSU represents the right to receive, upon vesting, one share of Con Edison common stock, the cash value of a share or a combination thereof. As such, changes in the fair value of the Performance RSUs are reflected in net income. The assumptions used to calculate the fair value of the awards were as follows:



	2019	2018	2017
Risk-free interest rate (a)	1.58% - 1.59%	2.48% - 2.63%	1.76% - 1.89%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	12.89% - 15.51%	14.76% - 17.71%	11.01% - 14.70%


(a)	The risk-free rate is based on the U.S. Treasury zero-coupon yield curve.


(b)	The expected term of the Performance RSUs equals the vesting period. The Companies do not expect significant forfeitures to occur.


(c)	Based on historical experience.

A summary of changes in the status of the Performance RSUs’ TSR and non-TSR portions during the year ended December 31, 2019 is as follows:



	Con Edison			CECONY
		Weighted Average Grant Date Fair Value (a)			Weighted Average Grant Date Fair Value (a)
	Units	TSR Portion (b)	Non-TSR Portion (c)	Units	TSR Portion (b)	Non-TSR Portion (c)
Non-vested at December 31, 2018	1,005,836	$74.81	$74.27	761,906	$74.47	$74.42
Granted	389,600	64.37	80.03	284,516	64.82	80.31
Vested	(357,325)	83.17	72.09	(275,376)	82.77	72.32
Forfeited	(46,873)	65.08	78.03	(30,186)	65.20	78.10
Transferred (d)	—	—	—	1,344	70.04	75.65
Non-vested at December 31, 2019	991,238	$68.15	$77.14	742,204	$68.06	$77.32


(a)	The TSR and non-TSR Portions each account for 50 percent of the awards’ value.


(b)	Fair value is determined using the Monte Carlo simulation described above. Weighted average grant date fair value does not reflect any accrual or payment of dividends prior to vesting.


(c)	Fair value is determined using the market price of one share of Con Edison common stock on the grant date. The market price has not been discounted to reflect that dividends do not accrue and are not payable on Performance RSUs until vesting.


(d)	Represents allocation to another Con Edison subsidiary of a portion of the Performance RSUs that had been awarded to a CECONY officer who transferred to another subsidiary.

The total expense to be recognized by Con Edison in future periods for unvested Performance RSUs outstanding at December 31, 2019 is $25 million, including $21 million for CECONY, and is expected to be recognized over a weighted average period of one year for both Con Edison and CECONY. Con Edison and CECONY paid cash of

$24 million and $22 million in 2019, $29 million and $28 million in 2018, and $22 million and $21 million in 2017, respectively, to settle vested Performance RSUs.

In accordance with the accounting rules for stock compensation, for time-based awards, the Companies are accruing a liability and recognizing compensation expense based on the market value of a common share throughout the vesting period. The vesting period for awards is three years and is based on the employee’s continuous service to Con Edison. Prior to vesting, the awards are subject to forfeiture in whole or in part under certain circumstances. The awards are “liability awards” because each restricted stock unit represents the right to receive, upon vesting, one share of Con Edison common stock, the cash value of a share or a combination thereof. As such, prior to vesting, changes in the fair value of the units are reflected in net income.

A summary of changes in the status of time-based awards during the year ended December 31, 2019 is as follows:



	Con Edison		CECONY
	Units	Weighted Average Grant Date Fair Value	Units	Weighted Average Grant Date Fair Value
Non-vested at December 31, 2018	65,180	$77.42	61,380	$77.42
Granted	24,850	84.81	23,350	84.81
Vested	(20,980)	76.62	(19,830)	76.62
Forfeited	(1,800)	79.12	(1,800)	79.12
Non-vested at December 31, 2019	67,250	$80.36	63,100	$80.36

The total expense to be recognized by Con Edison in future periods for unvested time-based awards outstanding at December 31, 2019 for Con Edison and CECONY was $3 million and $2 million, respectively, and is expected to be recognized over a weighted average period of one year. Con Edison and CECONY paid cash of $1 million in 2019, 2018 and 2017, to settle vested time-based awards.

Under the LTIP, each non-employee director receives stock units, which are deferred until the director’s separation from service or another date specified by the director. Each director may also elect to defer all or a portion of their cash compensation into additional stock units, which are deferred until the director’s termination of service or another date specified by the director. Non-employee directors’ stock units issued under the LTIP are considered “equity awards,” because they may only be settled in shares. Directors immediately vest in units issued to them. The fair value of the units is determined using the closing price of Con Edison’s common stock on the business day immediately preceding the date of issue. In the year ended December 31, 2019, approximately 27,100 units were issued at a weighted average grant date price of $87.57.

Stock Purchase Plan

The Stock Purchase Plan, which was approved by shareholders in 2004 and 2014, provides for the Companies to contribute up to $1 for each $9 invested by their directors, officers or employees to purchase Con Edison common stock under the plan. Eligible participants may invest up to $25,000 during any calendar year (subject to an additional limitation for officers and employees of not more than 20 percent of their pay). Dividends paid on shares held under the plan are reinvested in additional shares unless otherwise directed by the participant.

Participants in the plan immediately vest in shares purchased by them under the plan. The fair value of the shares of Con Edison common stock purchased under the plan was calculated using the average of the high and low composite sale prices at which shares were traded at the New York Stock Exchange on the trading day immediately preceding such purchase dates. During 2019, 2018 and 2017, 747,899, 786,385 and 719,125 shares were purchased under the Stock Purchase Plan at a weighted average price of $85.45, $78.27 and $79.57 per share, respectively.

Financial Information by Business Segment

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Financial Information by Business Segment

The business segments of each of the Companies, which are its operating segments, were determined based on management’s reporting and decision-making requirements in accordance with the accounting rules for segment reporting.

Con Edison’s principal business segments are CECONY’s regulated utility activities, O&R’s regulated utility activities, the Clean Energy Businesses and Con Edison Transmission. CECONY’s principal business segments are its regulated electric, gas and steam utility activities.

All revenues of these business segments are from customers located in the United States of America. Also, all assets of the business segments are located in the United States of America. The accounting policies of the segments are the same as those described in Note A.

Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided.

The financial data for the business segments are as follows:



As of and for the Year Ended December 31, 2019 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$8,062	$17		$1,053	$1,758	$(28)	$539	$239	$32,988	$1,851
Gas	2,132	7		231	528	(4)	147	99	11,090	1,078
Steam	627	70		89	62	(3)	42	4	2,479	91
Consolidation adjustments	—	(94)		—	—	—	—	—	—	—
Total CECONY	$10,821		$—	$1,373	$2,348	($35)	$728	$342	$46,557	$3,020
O&R
Electric	$634		$—	$60	$98	$(7)	$27	$15	$2,130	$142
Gas	259	—		24	41	(4)	14	6	876	61
Other	—	—		—	—	—	—	—	—	—
Total O&R	$893		$—	$84	$139	$(11)	$41	$21	$3,006	$203
Clean Energy Businesses	$857		$—	$226	$202	$5	$186	$(58)	$6,528	$248
Con Edison Transmission	4	—		1	(6)	104	25	1	1,618	205
Other (b)	(1)	—		—	(7)	(12)	11	(6)	370	—
Total Con Edison	$12,574		$—	$1,684	$2,676	$51	$991	$300	$58,079	$3,676



As of and for the Year Ended December 31, 2018 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$7,971	$16		$984	$1,799	$(110)	$519	$233	$31,012	$1,861
Gas	2,078	7		205	478	(23)	131	87	9,710	1,050
Steam	631	75		87	77	(10)	39	8	2,386	94
Consolidation adjustments	—	(98)		—	—	—	—	—	—	—
Total CECONY	$10,680		$—	$1,276	$2,354	$(143)	$689	$328	$43,108	$3,005
O&R
Electric	$642		$—	$56	$93	$(14)	$25	$14	$2,036	$138
Gas	249	—		21	39	(5)	14	7	856	67
Other	—	—		—	—	—	—	—	—	—
Total O&R	$891		$—	$77	$132	$(19)	$39	$21	$2,892	$205
Clean Energy Businesses	$763		$—	$85	$194	$33	$63	$19	$5,821	$1,791
Con Edison Transmission	4	—		1	(7)	91	20	(1)	1,425	248
Other (b)	(1)	—		(1)	(9)	(24)	8	39	674	—
Total Con Edison	$12,337		$—	$1,438	$2,664	$(62)	$819	$406	$53,920	$5,249



As of and for the Year Ended December 31, 2017 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$7,972	$16		$925	$1,974	$(105)	$472	$511	$29,661	$1,905
Gas	1,901	6		185	495	(23)	113	152	8,387	909
Steam	595	75		85	80	(9)	38	25	2,403	90
Consolidation adjustments	—	(97)		—	—	—	—	—	—	—
Total CECONY	$10,468		$—	$1,195	$2,549	$(137)	$623	$688	$40,451	$2,904
O&R
Electric	$642		$—	$51	$115	$(14)	$24	$30	$1,949	$128
Gas	232	—		20	46	(5)	12	12	824	61
Other	—	—		—	—	—	—	—	—	—
Total O&R	$874		$—	$71	$161	$(19)	$36	$42	$2,773	$189
Clean Energy Businesses	$694		$—	$74	$69	$33	$43	$(273)	$2,735	$447
Con Edison Transmission	2	—		1	(8)	80	16	(11)	1,222	66
Other (b)	(5)	—		—	3	(5)	11	13	930	—
Total Con Edison	$12,033		$—	$1,341	$2,774	$(48)	$729	$459	$48,111	$3,606

(a)

For Con Edison, the income tax expense/(benefit) on non-operating income was $(4) million, $(5) million and $13 million in 2019, 2018 and 2017, respectively. For CECONY, the income tax expense/(benefit) on non-operating income was $(7) million, $(2) million and $(3) million in 2019, 2018 and 2017, respectively. At December 31, 2017, Con Edison re-measured its deferred tax assets and liabilities based upon the 21 percent corporate income tax rate under the TCJA. As a result, Con Edison, decreased its federal income tax expense by $259 million ($269 million, $11 million and $(21) million, respectively, for the Clean Energy Businesses, Con Edison Transmission and the parent company). See Note L to the financial statements in Item 8.

(b)

Parent company and consolidation adjustments. Other does not represent a business segment.

Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Con Edison’s subsidiaries hedge market price fluctuations associated with physical purchases and sales of electricity, natural gas, steam and, to a lesser extent, refined fuels by using derivative instruments including futures, forwards, basis swaps, options, transmission congestion contracts and financial transmission rights contracts. These are economic hedges, for which the Utilities and the Clean Energy Business do not elect hedge accounting. The Clean Energy Businesses use interest rate swaps to manage the risks associated with interest rates related to outstanding and expected future debt issuances and borrowings. Derivatives are recognized on the consolidated balance sheet at fair value (see Note P), unless an exception is available under the accounting rules for derivatives and hedging. Qualifying derivative contracts that have been designated as normal purchases or normal sales contracts are not reported at fair value under the accounting rules.

In August 2017, the FASB issued amendments to the guidance for derivatives and hedging through ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update provide greater clarification on hedge accounting for risk components, presentation and disclosure of hedging instruments, and overall targeted improvements to simplify hedge accounting. The amendments were effective for reporting periods beginning after December 15, 2018. The application of the guidance did not have a material impact on the Companies’ financial position, results of operations and liquidity because the Companies do not elect hedge accounting for their derivative instruments and hedging activities.

The fair values of the Companies’ derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2019 and 2018 were:



(Millions of Dollars)	2019				2018
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$60	$(3)	$57	(b)	$43	$(14)	$29	(b)
Noncurrent	19	(13)	6	(c)	16	(7)	9	(d)
Total fair value of derivative assets	$79	$(16)	$63		$59	$(21)	$38
Fair value of derivative liabilities
Current	$(140)	$17	$(123)	(c)	$(61)	$11	$(50)
Noncurrent	(122)	16	(106)	(c)	(25)	9	(16)	(d)
Total fair value of derivative liabilities	$(262)	$33	$(229)		$(86)	$20	$(66)
Net fair value derivative assets/(liabilities)	$(183)	$17	$(166)		$(27)	$(1)	$(28)
CECONY
Fair value of derivative assets
Current	$39	$(6)	$33	(b)	$25	$(6)	$19	(b)
Noncurrent	17	(12)	5		11	(5)	6
Total fair value of derivative assets	$56	$(18)	$38		$36	$(11)	$25
Fair value of derivative liabilities
Current	$(100)	$19	$(81)		$(31)	$6	$(25)
Noncurrent	(80)	16	(64)		(12)	6	(6)
Total fair value of derivative liabilities	$(180)	$35	$(145)		$(43)	$12	$(31)
Net fair value derivative assets/(liabilities)	$(124)	$17	$(107)		$(7)	$1	$(6)

(a)

Derivative instruments and collateral were offset on the consolidated balance sheet as applicable under the accounting rules. The Companies enter into master agreements for their commodity derivatives. These agreements typically provide offset in the event of contract termination. In such case, generally the non-defaulting party’s payable will be offset by the defaulting party’s payable. The non-defaulting party will customarily notify the defaulting party within a specific time period and come to an agreement on the early termination amount.

(b)

At December 31, 2019 and 2018, margin deposits for Con Edison ($9 million and $7 million, respectively) and CECONY ($8 million and $6 million, respectively) were classified as derivative assets on the consolidated balance sheet, but not included in the table. Margin is collateral, typically cash, that the holder of a derivative instrument is required to deposit in order to transact on an exchange and to cover its potential losses with its broker or the exchange.


(c)	Includes amounts for interest rate swaps of $1 million in noncurrent assets, $(7) million in current liabilities and $(34) million in noncurrent liabilities. At December 31, 2019, the Clean Energy Businesses had interest rate swaps with notional amounts of $919 million. The expiration dates of the swaps range from 2024-2041.


(d)	Includes amounts for interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities. At December 31, 2018, the Clean Energy Businesses had interest rate swaps with notional amounts of $499 million. The expiration dates of the swaps range from 2024-2035.

The Utilities generally recover their prudently incurred fuel, purchased power and gas costs, including hedging gains and losses, in accordance with rate provisions approved by the applicable state utility regulators. See "Recoverable Energy Costs" in Note A. In accordance with the accounting rules for regulated operations, the Utilities record a regulatory asset or liability to defer recognition of unrealized gains and losses on their electric and gas derivatives. As gains and losses are realized in future periods, they will be recognized as purchased power, gas and fuel costs in the Companies’ consolidated income statements.

The Clean Energy Businesses record realized and unrealized gains and losses on their derivative contracts in purchased power, gas purchased for resale and non-utility revenue in the reporting period in which they occur. The Clean Energy Businesses record changes in the fair value of their interest rate swaps in other interest expense at the end of each reporting period. Management believes that these derivative instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices and interest rates.

The following table presents the realized and unrealized gains or losses on derivatives that have been deferred or recognized in earnings for the years ended December 31, 2019 and 2018:



		Con Edison		CECONY
(Millions of Dollars)	Balance Sheet Location	2019	2018	2019		2018
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$4	$(1)	$5		$1
Noncurrent	Deferred derivative gains	(3)	4	(1)		3
Total deferred gains/(losses)		$1	$3	$4		$4
Current	Deferred derivative losses	$(91)	$4	$(83)		$8
Current	Recoverable energy costs	(142)	(26)	(124)		(26)
Noncurrent	Deferred derivative losses	(67)	27	(65)		26
Total deferred gains/(losses)		$(300)	$5	$(272)		$8
Net deferred gains/(losses)		$(299)	$8	$(268)		$12
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Gas purchased for resale	$(2)	$(2)		$—		$—
	Non-utility revenue	25	4	—		—
	Other operations and maintenance expense	1	(2)	1		(2)
	Other interest expense	(36)	(4)	—		—
Total pre-tax gain/(loss) recognized in income		$(12)	$(4)	$1		$(2)

The following table presents the hedged volume of Con Edison’s and CECONY’s commodity derivative transactions at December 31, 2019:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison	24,868,670	28,916	277,827,601	5,712,000
CECONY	22,487,800	19,950	258,080,000	5,712,000


(a)	Volumes are reported net of long and short positions, except natural gas collars where the volumes of long positions are reported.


(b)	Excludes electric congestion and gas basis swap contracts which are associated with electric and gas contracts and hedged volumes.

The Companies are exposed to credit risk related to transactions entered into primarily for the various energy supply and hedging activities by the Utilities and the Clean Energy Businesses. Credit risk relates to the loss that may result from a counterparty’s nonperformance. The Companies use credit policies to manage this risk, including an established credit approval process, monitoring of counterparty limits, netting provisions within agreements, collateral or prepayment arrangements, credit insurance and credit default swaps. The Companies measure credit risk exposure as the replacement cost for open energy commodity and derivative positions plus amounts owed from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses where the Companies have a legally enforceable right to offset.

At December 31, 2019, Con Edison and CECONY had $128 million and $8 million of credit exposure in connection with open energy supply net receivables and hedging activities, net of collateral, respectively. Con Edison’s net credit exposure consisted of $62 million with independent system operators, $27 million with non-investment grade/non-rated counterparties, $24 million with investment-grade counterparties, and $15 million with commodity exchange brokers. CECONY’s net credit exposure consisted of $8 million with commodity exchange brokers.

The collateral requirements associated with, and settlement of, derivative transactions are included in net cash flows from operating activities in the Companies’ consolidated statement of cash flows. Most derivative instrument contracts contain provisions that may require a party to provide collateral on its derivative instruments that are in a net liability position. The amount of collateral to be provided will depend on the fair value of the derivative instruments and the party’s credit ratings.

The following table presents the aggregate fair value of the Companies’ derivative instruments with credit-risk-related contingent features that are in a net liability position, the collateral posted for such positions and the additional collateral that would have been required to be posted had the lowest applicable credit rating been reduced one level and to below investment grade at December 31, 2019:



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$163	$145
Collateral posted	25	25
Additional collateral (b) (downgrade one level from current ratings)	50	41
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	159	134

(a)

Non-derivative transactions for the purchase and sale of electricity and gas and qualifying derivative instruments, which have been designated as normal purchases or normal sales, are excluded from the table. These transactions primarily include purchases of electricity from independent system operators. In the event the Utilities and the Clean Energy Businesses were no longer extended unsecured credit for such purchases, the Companies would be required to post additional collateral of $1 million at December 31, 2019. For certain other such non-derivative transactions, the Companies could be required to post collateral under certain circumstances, including in the event counterparties had reasonable grounds for insecurity.

(b)

The Companies measure the collateral requirements by taking into consideration the fair value amounts of derivative instruments that contain credit-risk-related contingent features that are in a net liabilities position plus amounts owed to counterparties for settled transactions and amounts required by counterparties for minimum financial security. The fair value amounts represent unrealized losses, net of any unrealized gains where the Companies have a legally enforceable right to offset.

(c)

Derivative instruments that are net assets have been excluded from the table. At December 31, 2019, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $49 million.

Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

The accounting rules for fair value measurements and disclosures define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in a principal or most advantageous market. Fair value is a market-based measurement that is determined based on inputs, which refer broadly to assumptions that market participants use in pricing assets or liabilities. These inputs can be readily observable, market corroborated, or generally unobservable firm inputs. The Companies often make certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk, and the risks inherent in the inputs to valuation techniques. The Companies use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The accounting rules for fair value measurements and disclosures established a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value in three broad levels. The rules require that assets and liabilities be classified in their entirety based on the level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and their placement within the fair value hierarchy. The Companies classify fair value balances based on the fair value hierarchy defined by the accounting rules for fair value measurements and disclosures as follows:

•

Level 1 – Consists of assets or liabilities whose value is based on unadjusted quoted prices in active markets at the measurement date. An active market is one in which transactions for assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. This category includes contracts traded on active exchange markets valued using unadjusted prices quoted directly from the exchange.

•

Level 2 – Consists of assets or liabilities valued using industry standard models and based on prices, other than quoted prices within Level 1, that are either directly or indirectly observable as of the measurement date. The industry standard models consider observable assumptions including time value, volatility factors and current market and contractual prices for the underlying commodities, in addition to other economic measures. This category includes contracts traded on active exchanges or in over-the-counter markets priced with industry standard models.

•

Level 3 – Consists of assets or liabilities whose fair value is estimated based on internally developed models or methodologies using inputs that are generally less readily observable and supported by little, if any, market activity at the measurement date. Unobservable inputs are developed based on the best available information and subject to cost benefit constraints. This category includes contracts priced using models that are internally developed and contracts placed in illiquid markets. It also includes contracts that expire after

the period of time for which quoted prices are available and internal models are used to determine a significant portion of the value.

Assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2019 and 2018 are summarized below.



	2019						2018
(Millions of Dollars)	Level 1	Level 2	Level 3	Netting Adjustment (e)		Total	Level 1	Level 2	Level 3	Netting Adjustment (e)	Total
Con Edison
Derivative assets:
Commodity (a)(b)(c)	$4	$61	$2	$4		$71	$6	$36	$7	$(6)	$43
Interest rate swaps (a)(b)(c)(f)	—	1	—	—		1	—	2	—	—	2
Other (a)(b)(d)	353	125	—	—		478	287	114	—	—	401
Total assets	$357	$187	$2	$4		$550	$293	$152	$7	$(6)	$446
Derivative liabilities:
Commodity (a)(b)(c)	$18	$174	$18	$(22)		$188	$8	$43	$20	$(11)	$60
Interest rate swaps (a)(b)(c)(f)	—	41	—	—		41	—	6	—	—	6
Total liabilities	$18	$215	$18	$(22)		$229	$8	$49	$20	$(11)	$66
CECONY
Derivative assets:
Commodity (a)(b)(c)	$3	$42	$1		$—	$46	$3	$28	$1	$(1)	$31
Other (a)(b)(d)	333	119	—	—		452	267	109	—	—	376
Total assets	$336	$161	$1		$—	$498	$270	$137	$1	$(1)	$407
Derivative liabilities:
Commodity (a)(b)(c)	$15	$147	$7	$(24)		$145	$5	$30	3	$(6)	$32

(a)

The Companies’ policy is to review the fair value hierarchy and recognize transfers into and transfers out of the levels at the end of each reporting period. Con Edison and CECONY had $24 million and $22 million of commodity derivative liabilities transferred from level 3 to level 2 during the year ended December 31, 2019 because of availability of observable market data due to the decrease in the terms of certain contracts from beyond three years as of September 30, 2019 to less than three years as of December 31, 2019. Con Edison and CECONY had $2 million of commodity derivative liabilities transferred from level 3 to level 2 during the year ended December 31, 2018 because of availability of observable market data due to the decrease in the terms of certain contracts from beyond three years as of December 31, 2017 to less than three years as of December 31, 2018.

(b)

Level 2 assets and liabilities include investments held in the deferred compensation plan and/or non-qualified retirement plans, exchange-traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1, certain over-the-counter derivative instruments for electricity, refined products and natural gas. Derivative instruments classified as Level 2 are valued using industry standard models that incorporate corroborated observable inputs; such as pricing services or prices from similar instruments that trade in liquid markets, time value and volatility factors.

(c)

The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2019 and 2018, the Companies determined that nonperformance risk would have no material impact on their financial position or results of operations.


(d)	Other assets are comprised of assets such as life insurance contracts within the deferred compensation plan and non-qualified retirement plans.


(e)	Amounts represent the impact of legally-enforceable master netting agreements that allow the Companies to net gain and loss positions and cash collateral held or placed with the same counterparties.


(f)	See Note O.

The employees in the Companies’ risk management group develop and maintain the Companies’ valuation policies and procedures for, and verify pricing and fair value valuation of, commodity derivatives and interest rate swaps. Under the Companies’ policies and procedures, multiple independent sources of information are obtained for forward price curves used to value commodity derivatives and interest rate swaps. Fair value and changes in fair value of commodity derivatives and interest rate swaps are reported on a monthly basis to the Companies’ risk committees, comprised of officers and employees of the Companies that oversee energy hedging at the Utilities and the Clean Energy Businesses. The risk management group reports to the Companies’ Vice President and Treasurer.



	Fair Value of Level 3 at December 31, 2019
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(1)	Discounted Cash Flow	Forward energy prices (a)	$25.50-$34.10 per MWh
	(16)	Discounted Cash Flow	Forward capacity prices (a)	$0.09-$8.90 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$(3.69)-$7.37 per MWh
Total Con Edison — Commodity	$(16)
CECONY — Commodity
Electricity	$(7)	Discounted Cash Flow	Forward capacity prices (a)	$0.15-$8.90 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.36-$3.10 per MWh
Total CECONY — Commodity	$(6)


(a)	Generally, increases (decreases) in this input in isolation would result in a higher (lower) fair value measurement.


(b)	Generally, increases (decreases) in this input in isolation would result in a lower (higher) fair value measurement.

The table listed below provides a reconciliation of the beginning and ending net balances for assets and liabilities measured at fair value for the years ended December 31, 2019 and 2018 and classified as Level 3 in the fair value hierarchy:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Beginning balance as of January 1,	$(13)	$1	$(2)	$4
Included in earnings	(5)	4	—	4
Included in regulatory assets and liabilities	18	(10)	17	(4)
Settlements	8	(6)	1	(4)
Transfer out of level 3	(24)	(2)	(22)	(2)
Ending balance as of December 31,	$(16)	$(13)	$(6)	$(2)

For the Utilities, realized gains and losses on Level 3 commodity derivative assets and liabilities are reported as part of purchased power, gas and fuel costs. The Utilities generally recover these costs in accordance with rate provisions approved by the applicable state public utilities regulators. See Note A. Unrealized gains and losses for commodity derivatives are generally deferred on the consolidated balance sheet in accordance with the accounting rules for regulated operations.

For the Clean Energy Businesses, realized and unrealized gains and losses on Level 3 commodity derivative assets and liabilities are reported in non-utility revenues ($2 million gain and $3 million loss) and purchased power costs (immaterial) on the consolidated income statement for the years ended December 31, 2019 and 2018, respectively. The change in fair value relating to Level 3 commodity derivative assets and liabilities held at December 31, 2019 and 2018 is included in non-utility revenues ($2 million gain and $3 million loss) and purchased power costs (immaterial) on the consolidated income statement for the years ended December 31, 2019 and 2018, respectively.

Variable Interest Entities

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Variable Interest Entities

The accounting rules for consolidation address the consolidation of a variable interest entity (VIE) by a business enterprise that is the primary beneficiary. A VIE is an entity that does not have a sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary is the business enterprise that has the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and either absorbs a significant amount of the VIE’s losses or has the right to receive benefits that could be significant to the VIE.

The Companies enter into arrangements including leases, partnerships and electricity purchase agreements, with various entities. As a result of these arrangements, the Companies retain or may retain a variable interest in these entities.

CECONY

CECONY has an ongoing long-term electricity purchase agreement with Brooklyn Navy Yard Cogeneration Partners, LP, a potential VIE. In 2019, a request was made of this counterparty for information necessary to determine whether the entity was a VIE and whether CECONY is the primary beneficiary; however, the information was not made available. In April 2017, CECONY's long-term electricity purchase agreement with Cogen Technologies Linden Venture, LP (Linden Cogeneration), another potential VIE, expired. See Note I for information on these electricity purchase agreements, the payments pursuant to which constitute CECONY's maximum exposure to loss with respect to the potential VIEs.

Clean Energy Businesses

In September 2019, the Clean Energy Businesses, which previously owned an 80 percent membership interest in OCI Solar San Antonio 4 LLC (Texas Solar 4), acquired the remaining 20 percent interest. As a result of the acquisition, Texas Solar 4 is a consolidated entity. Prior to the acquisition, Con Edison had a variable interest in Texas Solar 4, as to which Con Edison was the primary beneficiary since the power to direct the activities that most significantly impact the economics of Texas Solar 4 was held by the Clean Energy Businesses. Texas Solar 4 owns a project company that developed a 40 MW (AC) solar electric production project. Electricity generated by the project is sold pursuant to a long-term power purchase agreement. Con Edison's earnings from Texas Solar 4 for the years ended December 31, 2019 and 2018 were immaterial.

In December 2018, the Clean Energy Businesses completed its acquisition of Sempra Solar Holdings, LLC. See Note U. Included in the acquisition were certain operating projects (Tax Equity Projects) with a noncontrolling tax equity investor to which a percentage of earnings, tax attributes and cash flows are allocated. The Tax Equity Projects are consolidated entities in which Con Edison has less than a 100 percent membership interest. Con Edison is the primary beneficiary since the power to direct the activities that most significantly impact the economics of the Tax Equity Projects is held by the Clean Energy Businesses. Electricity generated by the Tax Equity Projects is sold to utilities and municipalities pursuant to long-term power purchase agreements. For the year ended December 31, 2019, the hypothetical liquidation at book value (HLBV) method of accounting for the Tax Equity Projects resulted in $98 million of income ($74 million, after tax) for the tax equity investor and a $64 million loss ($48 million, after tax) for Con Edison, and earnings under the HLBV method for the year ended December 31, 2018 were immaterial.

Con Edison has determined that the use of HLBV accounting is reasonable and appropriate to attribute income and loss to the tax equity investors. Using the HLBV method, the company's earnings from the projects are adjusted to reflect the income or loss allocable to the tax equity investors calculated based on how the project would allocate and distribute its cash if it were to sell all of its assets for their carrying amounts and liquidate at a particular point in time. Under the HLBV method, the company calculates the liquidation value allocable to the tax equity investors at the beginning and end of each period based on the contractual liquidation waterfall and adjusts its income for the period to reflect the change in the liquidation value allocable to the tax equity investors.

At December 31, 2019 and 2018, Con Edison’s consolidated balance sheet included the following amounts associated with its VIEs:



	Tax Equity Projects
	Great Valley Solar (c)(d)				Copper Mountain - Mesquite Solar (c)(e)				Texas Solar 4 (c)(f)
(Millions of Dollars)	2019		2018		2019		2018		2018
Restricted cash		$—		$—		$—		$—	$4
Non-utility property, less accumulated depreciation (g)(h)	293		313		461		492		98
Other assets	40		18		128		97		9
Total assets (a)	$333		$331		$589		$589		$111
Long-term debt due within one year		$—		$—		$—		$—	$2
Other liabilities	17		17		18		33		26
Long-term debt	—		—		—		—		56
Total liabilities (b)	$17		$17		$18		$33		$84


(a)	The assets of the Tax Equity Projects represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.


(b)	The liabilities of the Tax Equity Projects represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.


(c)	Con Edison did not provide any financial or other support during the year that was not previously contractually required.


(d)	Great Valley Solar consists of the Great Valley Solar 1, Great Valley Solar 2, Great Valley Solar 3 and Great Valley Solar 4 projects, for which the noncontrolling interest of the tax equity investor was $62 million and $33 million at December 31, 2019 and 2018, respectively.


(e)	Copper Mountain - Mesquite Solar consists of the Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 projects for which the noncontrolling interest of the tax equity investor was $126 million and $71 million at December 31, 2019 and 2018, respectively.


(f)	Noncontrolling interest of the third party was $7 million at December 31, 2018.


(g)	Non-utility property is reduced by accumulated depreciation of $9 million for Great Valley Solar and $15 million for Copper Mountain - Mesquite Solar at December 31, 2019.


(h)	Non-utility property is reduced by accumulated depreciation of $1 million for Great Valley Solar, $1 million for Copper Mountain - Mesquite Solar and $15 million for Texas Solar 4 at December 31, 2018.

The following table summarizes the VIEs into which the Clean Energy Businesses have entered as of December 31, 2019:



Project Name	Generating Capacity (a) (MW AC)	Power Purchase Agreement Term in Years	Year of Investment	Location	Maximum Exposure to Loss (Millions of Dollars) (b)
Great Valley Solar (c)	200	15-20	2018	California	$254
Copper Mountain - Mesquite Solar (c)	344	20-25	2018	Nevada and Arizona	445


(a)	Represents ownership interest in the project.


(b)	Maximum exposure is equal to the net assets of the project on the consolidated balance sheet less any applicable noncontrolling interest ($62 million for Great Valley Solar and $126 million for Copper Mountain - Mesquite Solar). Con Edison did not provide any financial or other support during the year that was not previously contractually required.

(c)

For the projects comprising Great Valley Solar and Copper Mountain Mesquite Solar, refer to (d) and (e) in the table above.

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Companies recognize a liability at fair value for legal obligations associated with the retirement of long-lived assets in the period in which they are incurred, or when sufficient information becomes available to reasonably estimate the fair value of such legal obligations. When the liability is initially recorded, asset retirement costs are capitalized by increasing the carrying amount of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The fair value of the asset retirement obligation liability is measured using expected future cash flows discounted at credit-adjusted risk-free rates, historical information, and where available, quoted prices from outside contractors. The Companies evaluate these assumptions underlying the asset retirement obligation liability on an annual basis or as frequently as needed. The Companies recorded asset retirement obligations associated with the removal of asbestos and asbestos-containing material in their buildings (other than the structures enclosing generating stations and substations), electric equipment and steam and gas distribution systems. The Companies also recorded asset retirement obligations relating to gas and oil pipelines abandoned in place and municipal infrastructure support. The Companies did not record an asset retirement obligation for the removal of asbestos associated with the structures enclosing generating stations and substations. For these building structures, the Companies were unable to reasonably estimate their asset retirement obligations because the Companies were unable to estimate the undiscounted retirement costs or the retirement dates and settlement dates. The amount of the undiscounted retirement costs could vary considerably depending on the disposition method for the building structures, and the method has not been determined. The Companies anticipate continuing to use these building structures in their businesses for an indefinite period, and so the retirement dates and settlement dates are not determinable. Con Edison recorded asset retirement obligations for the removal of the Clean Energy Businesses’ solar and wind equipment related to projects located on property that is not owned by them and the term of the arrangement is finite including any renewal options. Con Edison did not record asset retirement obligations for the Clean Energy Businesses’ projects that are located on property that is owned by them because they expect that the equipment will continue to generate electricity at these facilities long past the manufacturer’s warranty at minimal operating expense. Therefore, Con Edison was unable to reasonably estimate the retirement date of this equipment. The Utilities include in depreciation rates the estimated removal costs, less salvage, for utility plant assets. The amounts related to removal costs that are associated with asset retirement obligations are classified as an asset retirement liability. Pursuant to accounting rules for regulated operations, future removal costs that do not represent legal asset retirement obligations are recorded as regulatory liabilities. Accretion and depreciation expenses related to removal costs that represent legal asset retirement obligations are applied against the Companies’ regulatory liabilities. Asset retirement costs that are recoverable from customers are recorded as regulatory liabilities to reflect the timing difference between costs recovered through the rate-making process and recognition of costs. At December 31, 2019, the liabilities for asset retirement obligations of Con Edison and CECONY were $425 million and $362 million, respectively. At December 31, 2018, the liabilities for asset retirement obligations of Con Edison and CECONY were $450 million and $292 million, respectively. The change in liabilities at December 31, 2019 was due to changes in estimated cash flows of $(1) million and $96 million for Con Edison and CECONY, respectively, and accretion expense of $14 million and $12 million for Con Edison and CECONY, respectively. The changes were offset by liabilities settled of $38 million for both Con Edison and CECONY. The change in liabilities at December 31, 2018 was due to changes in estimated cash flows of $168 million and $39 million for Con Edison and CECONY, respectively, and accretion expense of $13 million and $11 million for Con Edison and CECONY, respectively. The changes were offset by liabilities settled of $45 million for both Con Edison and CECONY. Con Edison and CECONY also recorded reductions of $44 million and $50 million during the years ended December 31, 2019 and 2018, respectively, to the regulatory liability associated with cost of removal to reflect depreciation and interest expense.

Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions

The NYSPSC generally requires that the Utilities and Con Edison’s other subsidiaries be operated as separate entities. The Utilities and the other subsidiaries are required to have separate operating employees and operating officers of the Utilities may not be operating officers of the other subsidiaries. The Utilities may provide administrative and other services to, and receive such services from, Con Edison and its other subsidiaries only pursuant to cost allocation procedures approved by the NYSPSC. Transfers of assets between the Utilities and Con Edison or its other subsidiaries may be made only as approved by the NYSPSC. The debt of the Utilities is to be raised directly by the Utilities and not derived from Con Edison. Without the prior permission of the NYSPSC, the Utilities may not make loans to, guarantee the obligations of, or pledge assets as security for the indebtedness of Con Edison or its other subsidiaries. The NYSPSC limits the dividends that the Utilities may pay Con Edison. See “Dividends” in Note C. As a result, substantially all of the net assets of CECONY and O&R ($14,147 million and $762 million, respectively), at December 31, 2019, are considered restricted net assets. The NYSPSC may impose additional measures to separate, or “ring fence,” the Utilities from Con Edison and its other subsidiaries. See “Rate Plans” in Note B.

The costs of administrative and other services provided by CECONY to, and received by it from, Con Edison and its other subsidiaries for the years ended December 31, 2019, 2018 and 2017 were as follows:



	CECONY
(Millions of Dollars)	2019	2018	2017
Cost of services provided	$121	$115	$111
Cost of services received	64	73	64

In addition, CECONY and O&R have joint gas supply arrangements, in connection with which CECONY sold to O&R $71 million, $83 million and $66 million of natural gas for the years ended December 31, 2019, 2018 and 2017, respectively. These amounts are net of the effect of related hedging transactions.

The Utilities perform work and incur expenses on behalf of NY Transco, a company in which CET Electric has a 45.7 percent equity interest. The Utilities bill NY Transco for such work and expenses in accordance with established policies. For the years ended December 31, 2019 and 2018, the amounts billed by the Utilities to NY Transco were immaterial. In May 2016, CECONY transferred certain electric transmission projects to NY Transco.

CECONY has storage and wheeling service contracts with Stagecoach Gas Services LLC (Stagecoach), a joint venture formed by a subsidiary of CET Gas and a subsidiary of Crestwood Equity Partners LP (Crestwood). In addition, CECONY is the replacement shipper on one of Crestwood’s firm transportation agreements with Tennessee Gas Pipeline Company LLC. CECONY incurred costs for storage and wheeling services from Stagecoach of $33 million, $28 million and $31 million for the years ended December 31, 2019, 2018 and 2017, respectively. In addition, the Clean Energy Businesses entered into two electricity sales agreements with Stagecoach under which the amounts received in 2019, 2018 and 2017 were immaterial.

CECONY has a 20-year transportation contract with Mountain Valley Pipeline, LLC (MVP) for 250,000 dekatherms per day of capacity. CET Gas holds a 12.5 percent equity interest in MVP (that is expected to be reduced by approximately 10 percent based on the current project estimate). In October 2017, the Environmental Defense Fund and the Natural Resource Defense Council requested the NYSPSC to prohibit CECONY from recovering costs under its MVP contract unless CECONY can demonstrate that the contract is in the public interest. CECONY advised the NYSPSC that it would respond to the request if the NYSPSC opened a proceeding to consider this request. For the years ended December 31, 2019 and 2018, CECONY incurred no costs under the contract.

FERC has authorized CECONY to lend funds to O&R for a period of not more than 12 months, in an amount not to exceed $250 million, at prevailing market rates. At December 31, 2019 and 2018 there were no outstanding loans to O&R.

The Clean Energy Businesses had financial electric capacity contracts with CECONY and O&R during 2019 and 2018. For the years ended December 31, 2019 and 2018, the Clean Energy Businesses realized $1 million loss under these contracts.

New Financial Accounting Standards	12 Months Ended
New Financial Accounting Standards	Dec. 31, 2019
Accounting Changes and Error Corrections [Abstract]
New Financial Accounting Standards	New Financial Accounting Standards In January 2020, the Companies adopted ASU 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The amendments replace the incurred loss impairment methodology which involved delayed recognition of credit losses. The amendments introduce an expected credit loss impairment model which requires immediate recognition of anticipated losses over the instrument’s life. A broader range of reasonable and supportable information must be considered in developing the credit loss estimates. The Companies' financial instruments subject to the amendments include their accounts receivable - customers and other receivables. The adoption of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity. The Companies will prepare additional disclosures as required by the amendments beginning in 2020. The Companies implemented additional internal controls related to the amendments, however the adoption of the amendments will not require a change that will materially affect the Companies’ internal control over financial reporting. In January 2020, the Companies adopted ASU 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The amendments in this update simplify goodwill impairment testing by eliminating Step 2 of the goodwill impairment test wherein an entity has to compute the implied fair value of goodwill by performing procedures to determine the fair value of its assets and liabilities. Under the new guidance, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value up to the total amount of goodwill allocated to that reporting unit. The adoption of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity. In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. The Companies are in the process of evaluating the potential impact of the new guidance on the Companies’ financial position, results of operations and liquidity.

Acquisitions, Investments and Dispositions

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions, Investments and Dispositions

Acquisitions and Investments

Mountain Valley Pipeline

In January 2016, CET Gas acquired a 12.5 percent equity interest in MVP, a company developing a proposed gas transmission project in West Virginia and Virginia. The company's initial contribution to MVP was $18 million. At December 31, 2019 and 2018, CET Gas' cash investment in MVP was $530 million and $337 million, respectively. In October 2019, the operator of MVP indicated that it expects a late 2020 full in-service date for the project at an overall project cost of $5,300 million to $5,500 million, excluding allowance for funds used during construction. MVP is currently defending certain agency actions and judicial challenges that must be resolved favorably before the pipeline can be completed. There are other proceedings that may affect MVP, including an investigation of potential criminal and/or civil violations of the Clean Water Act and other federal statutes as they relate to the construction of the pipeline. CET Gas, as it was permitted to do under the joint venture agreement, has limited its cash contributions to the joint venture to approximately $530 million, which will reduce its ownership interest in the joint venture to approximately 10 percent based on the current project cost estimate. Con Edison is accounting for its equity interest in MVP as an equity method investment.

Sempra Solar

In December 2018, the Clean Energy Businesses completed their acquisition of Sempra Solar Holdings, LLC, a Sempra Energy subsidiary, for $1,609 million, including working capital and other closing adjustments of $69 million. In 2019, Con Edison finalized the purchase price allocation and reclassified approximately $100 million which primarily decreased property, plant and equipment and asset retirement obligations, the impact of which was not material to earnings. The reclassification was recorded within the one year available to finalize the purchase price allocation.

The acquired company has ownership interests in 981 megawatts (AC) of operating renewable electric production projects, including its 379 megawatts (AC) share of projects in which its subsidiaries had a 50 percent ownership interest (Acquired JV Interests) and the Clean Energy Businesses had the remaining ownership interests (Previously-Owned JV Interests), and certain development rights with respect to solar electric production and energy storage projects.

At the acquisition date, the acquired company’s subsidiaries had $1,354 million of tangible assets consisting mostly of property, plant and equipment, $878 million of intangible assets mostly arising from power purchase agreements, $4 million of other noncurrent assets, $568 million of project debt (including, in each case, amounts associated with the Acquired JV Interests) and $28 million of asset retirement obligation liabilities. The weighted average amortization period for these intangible assets is 16 years. At the acquisition date, the fair value of the noncontrolling interest attributable to the tax equity investors (see below) was $100 million. The acquisition date valuation was performed using a discounted cash flow approach. The fair values of assets acquired and liabilities assumed were determined based on significant estimates and assumptions that are judgmental in nature, including projected amounts and timing of future cash flows, discount rates reflecting risk inherent in the future cash flows and future power prices.

Upon completion of the acquisition, the acquisition date fair value of the Previously-Owned JV Interests increased from $437 million to $568 million and Con Edison recognized a pre-tax gain of $131 million ($89 million or $0.28 per share net of taxes). Prior to the acquisition, Con Edison had been accounting for the Previously-Owned JV Interests under the equity method. Upon completion of the acquisition, Con Edison is accounting for Acquired JV Interests and the Previously-Owned JV Interests on a consolidated basis.

Certain projects acquired have tax equity investors to which a percentage of earnings, tax attributes and cash flows are allocated. See Note Q.

Con Edison's revenues and net income for the years ended December 31, 2018 and 2017 as reported and pro forma to account on a consolidated basis for the acquisition as if the acquisition had been completed on January 1, 2017 instead of December 13, 2018 are as follows:



	Years ended December 31,
(Millions of Dollars)	2018	2017
As Reported
Revenue	$12,337	$12,033
Net income	1,382	1,525

PRO FORMA SUPPLEMENTAL INFORMATION
If Acquired January 1, 2017 (a)(b)
Revenue	$12,655	$12,331
Net income	1,279	1,612

(a) Reflects the following material adjustments:


•	included additional interest expense of $37 million and $38 million in 2018 and 2017, respectively, that would have been incurred if $825 million that was borrowed in December 2018 under a variable rate term loan agreement to fund a portion of the purchase price for the acquisition had instead been borrowed for such purpose on January 1, 2017 at a fixed rate of 4.64% per annum; and

•

with respect to the Previously-Owned JV Interests: eliminated the $131 million purchase accounting gain (pre-tax) that Con Edison recognized upon the completion of the acquisition in 2018 and reflected the $131 million purchase accounting gain in 2017; recorded the corresponding increase to the book value of the related net utility plant and power purchase agreement intangible asset as of January 1, 2017 instead of December 13, 2018, and included the increased depreciation and amortization expense in 2018 and 2017; and eliminated $33 million and $32 million of other income that Con Edison had recorded in 2018 and 2017, respectively, under the equity method of accounting.

(b) Recalculating each investor’s claim on the investee’s assets under the contractual liquidation waterfall as if the acquisition had been completed on January 1, 2017 is impracticable. Accordingly, no HLBV adjustments were made.

Dispositions

Upton 2

In May 2017, the Clean Energy Businesses sold Upton 2, a development stage solar electric production project, for $11 million to Vistra Asset Co. and recorded a $1 million gain on sale ($0.7 million, net of taxes). In addition, the Clean Energy Businesses agreed to perform the engineering, procurement and construction for the 180 MW (AC) project, which was completed in 2018.

Schedule I - Condensed Financial Information

12 Months Ended

Dec. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Schedule I - Condensed Financial Information

Schedule I

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Statement of Income and Comprehensive Income

(Parent Company Only)



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts)	2019	2018	2017
Equity in earnings of subsidiaries	$1,354	$1,447	$1,544
Other income (deductions), net of taxes	76	(6)	31
Interest expense	(87)	(59)	(50)
Net Income	$1,343	$1,382	$1,525
Comprehensive Income	$1,340	$1,392	$1,526
Net Income Per Share – Basic	$4.09	$4.43	$4.97
Net Income Per Share – Diluted	$4.08	$4.42	$4.94
Dividends Declared Per Share	$2.96	$2.86	$2.76
Average Number Of Shares Outstanding—Basic (In Millions)	328.5	311.1	307.1
Average Number Of Shares Outstanding—Diluted (In Millions)	329.5	312.9	308.8


(a)	These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Statement of Cash Flows

(Parent Company Only)



	For the Years Ended December 31,
(Millions of Dollars)	2019		2018	2017
Net Income	1,343		1,382	1,525
Equity in earnings of subsidiaries	(1,354)		(1,447)	(1,544)
Dividends received from:
CECONY	912		846	796
O&R	47		46	44
Clean Energy Businesses	3		15	12
Con Edison Transmission	12		10	8
Change in Assets:
Special deposits	(3)		(8)	—
Income taxes receivable	25		2	34
Other – net	44		187	21
Net Cash Flows from Operating Activities	1,029		1,033	896
Investing Activities
Contributions to subsidiaries	(930)		(1,110)	(434)
Debt receivable from affiliated companies	450		(825)	—
Net Cash Flows Used in Investing Activities	(480)		(1,935)	(434)
Financing Activities
Net proceeds of short-term debt	(783)		164	(53)
Issuance of long-term debt	825		825	400
Retirement of long-term debt	(553)		(3)	(402)
Debt issuance costs	—		—	(2)
Issuance of common shares for stock plans, net of repurchases	54		53	51
Issuance of common shares - public offering	825		705	343
Common stock dividends	(924)		(842)	(803)
Net Cash Flows Used in Financing Activities	(556)		902	(466)
Net Change for the Period	(7	)	—	(4)
Balance at Beginning of Period	9		9	13
Balance at End of Period	$2		$9	$9


(a)	These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.

Condensed Financial Information of Consolidated Edison, Inc. (a)

Condensed Balance Sheet

(Parent Company Only)



	December 31,
(Millions of Dollars)	2019	2018
Assets
Current Assets
Cash and temporary cash investments	$2	$9
Income taxes receivable	18	43
Term loan receivable from affiliated companies	—	825
Accounts receivable from affiliated companies	870	536
Prepayments	32	33
Other current assets	12	12
Total Current Assets	934	1,458
Investments in subsidiaries and others	18,009	16,707
Goodwill	406	406
Deferred income tax	14	69
Long-term debt receivable from affiliated companies	1,275	900
Other noncurrent assets	—	2
Total Assets	$20,638	$19,542
Liabilities and Shareholders’ Equity
Current Liabilities
Long-term debt due within one year	$3	$3
Term loan	—	825
Notes payable	537	495
Accounts payable	—	9
Accounts payable to affiliated companies	595	274
Accrued taxes	2	2
Other current liabilities	10	13
Total Current Liabilities	1,147	1,621
Deferred income tax	—	—
Total Liabilities	1,147	1,621
Long-term debt	1,469	1,195
Shareholders’ Equity
Common stock, including additional paid-in capital	8,089	7,151
Retained earnings	9,933	9,575
Total Shareholders’ Equity	18,022	16,726
Total Liabilities and Shareholders’ Equity	$20,638	$19,542

(a)

These financial statements, in which Con Edison’s subsidiaries have been included using the equity method, should be read together with its consolidated financial statements and the notes thereto appearing above.

Summary of Significant Accounting Policies and Other Matters (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Principles of Consolidation

Accounting Policies

Revenue Recognition



	2019				2018
(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)	Total operating revenues	Revenues from contracts with customers		Other revenues (a)	Total operating revenues
CECONY
Electric	$7,913		$149	$8,062	$7,920		$51	$7,971
Gas	2,097		35	2,132	2,052		26	2,078
Steam	610		17	627	625		6	631
Total CECONY	$10,620		$201	$10,821	$10,597		$83	$10,680
O&R
Electric	627		7	634	647		(5)	642
Gas	247		12	259	256		(7)	249
Total O&R	$874		$19	$893	$903		$(12)	$891
Clean Energy Businesses
Renewables	575	(b)	—	575	329	(b)	—	329
Energy services	71		—	71	95		—	95
Other	—		211	211	—		339	339
Total Clean Energy Businesses	$646		$211	$857	$424		$339	$763
Con Edison Transmission	4		—	4	4		—	4
Other (c)	—		(1)	(1)	—		(1)	(1)
Total Con Edison	$12,144		$430	$12,574	$11,928		$409	$12,337



	2019			2018
(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)		Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1,	$29	$20		$58	$87
Additions (c)	86	1		144	38
Subtractions (c)	86	4	(d)	173	105	(d)
Ending balance as of December 31,	$29	$17		$29	$20

(a)


(b)	Unearned revenue represents a liability for billings to customers in excess of earned revenue, which are contract liabilities as defined in Topic 606.


(c)	Additions for unbilled contract revenue and subtractions for unearned revenue represent additional revenue earned. Additions for unearned revenue and subtractions for unbilled contract revenue represent billings. Activity also includes appropriate balance sheet classification for the period.


(d)	Of the subtractions from unearned revenue, $4 million and $50 million was included in the balance as of January 1, 2019 and 2018, respectively.

Other Receivables

Plant and Depreciation

Utility Plant

Non–Utility Plant

Goodwill

Long-Lived and Intangible Assets

Long–Lived and Intangible Assets

Recoverable Energy Costs/New York Independent System Operator (NYISO)

Recoverable Energy Costs

New York Independent System Operator (NYISO)

Temporary Cash Investments

Investments

Pension and Other Postretirement Benefits

between fair value and expected MRV of plan assets. This calculated value has the effect of stabilizing variability in assets to which the Companies apply the expected return.

Federal Income Tax/State Income Tax

Federal Income Tax

Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties and applied as a reduction to future federal income tax expense.

State Income Tax

Research and Development Costs

Research and development costs are charged to operating expenses as incurred.

Earnings Per Common Share

Estimates

New Financial Accounting Standards

In January 2020, the Companies adopted ASU 2016-13, “Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The amendments replace the incurred loss impairment methodology which involved delayed recognition of credit losses. The amendments introduce an expected credit loss impairment model which requires immediate recognition of anticipated losses over the instrument’s life. A broader range of reasonable and supportable information must be considered in developing the credit loss estimates. The Companies' financial instruments subject to the amendments include their accounts receivable - customers and other receivables. The adoption of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity. The Companies will prepare additional disclosures as required by the amendments beginning in 2020. The Companies implemented additional internal controls related to the amendments, however the adoption of the amendments will not require a change that will materially affect the Companies’ internal control over financial reporting.

In January 2020, the Companies adopted ASU 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” The amendments in this update simplify goodwill impairment testing by eliminating Step 2 of the goodwill impairment test wherein an entity has to compute the implied fair value of goodwill by performing procedures to determine the fair value of its assets and liabilities. Under the new guidance, an entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair

value up to the total amount of goodwill allocated to that reporting unit. The adoption of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity.

In December 2019, the FASB issued amendments to the guidance for income taxes through ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” The amendments in this update simplify the accounting for income taxes by removing certain exceptions such as: 1) the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, 2) the requirement to recognize a deferred tax liability for equity method investments when a foreign subsidiary becomes an equity method investment, 3) the ability not to recognize a deferred tax liability for a foreign subsidiary when a foreign equity method investment becomes a subsidiary, and 4) the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the anticipated loss for the year. For public entities, the amendments are effective for reporting periods beginning after December 15, 2020. Early adoption is permitted. The Companies are in the process of evaluating the potential impact of the new guidance on the Companies’ financial position, results of operations and liquidity.

Summary of Significant Accounting Policies and Other Matters (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Disaggregation of Revenue



	2019				2018
(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)	Total operating revenues	Revenues from contracts with customers		Other revenues (a)	Total operating revenues
CECONY
Electric	$7,913		$149	$8,062	$7,920		$51	$7,971
Gas	2,097		35	2,132	2,052		26	2,078
Steam	610		17	627	625		6	631
Total CECONY	$10,620		$201	$10,821	$10,597		$83	$10,680
O&R
Electric	627		7	634	647		(5)	642
Gas	247		12	259	256		(7)	249
Total O&R	$874		$19	$893	$903		$(12)	$891
Clean Energy Businesses
Renewables	575	(b)	—	575	329	(b)	—	329
Energy services	71		—	71	95		—	95
Other	—		211	211	—		339	339
Total Clean Energy Businesses	$646		$211	$857	$424		$339	$763
Con Edison Transmission	4		—	4	4		—	4
Other (c)	—		(1)	(1)	—		(1)	(1)
Total Con Edison	$12,144		$430	$12,574	$11,928		$409	$12,337

Change in Unbilled Contract and Unearned Revenues



	2019			2018
(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)		Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1,	$29	$20		$58	$87
Additions (c)	86	1		144	38
Subtractions (c)	86	4	(d)	173	105	(d)
Ending balance as of December 31,	$29	$17		$29	$20

(a)


(b)	Unearned revenue represents a liability for billings to customers in excess of earned revenue, which are contract liabilities as defined in Topic 606.


(c)	Additions for unbilled contract revenue and subtractions for unearned revenue represent additional revenue earned. Additions for unearned revenue and subtractions for unbilled contract revenue represent billings. Activity also includes appropriate balance sheet classification for the period.

(d)

Of the subtractions from unearned revenue, $4 million and $50 million was included in the balance as of January 1, 2019 and 2018, respectively.

Schedule of Total Excise Taxes Recorded in Operating Revenues

Total excise taxes (inclusive of gross receipts taxes) recorded in operating revenues were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$323	$330	$302
CECONY	312	318	292

Capitalized Cost of Utility Plant

At December 31, 2019 and 2018, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Electric
Generation	$591	$593	$591	$592
Transmission	3,634	3,333	3,380	3,106
Distribution	20,676	19,750	19,602	18,716
General	43	—	43	—
Gas (a)	8,617	7,714	7,961	7,107
Steam	1,813	1,830	1,813	1,830
General	2,365	2,306	2,143	2,102
Held for future use	75	76	67	67
Construction work in progress	1,937	1,978	1,812	1,850
Net Utility Plant	$39,751	$37,580	$37,412	$35,370

(a) Primarily distribution.

Schedule of Investment Assets

The following investment assets are included in the Companies' consolidated balance sheets at December 31, 2019 and 2018:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019		2018
CET Gas investment in Stagecoach Gas Services, LLC	$924	$948		$—		$—
CET Gas investment in Mountain Valley Pipeline, LLC (a)	602	363	—		—
Supplemental retirement income plan assets (b)	397	326	371		301
Deferred income plan assets	81	75	81		75
CET Electric investment in New York Transco, LLC	59	52	—		—
Other	2	2	9		9
Total investments	$2,065	$1,766	$461		$385


(a)	See Note U.

(b)

See Note E.

Research and Development Costs

Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$24	$24	$24
CECONY	23	23	23

Basic and Diluted EPS

Basic and diluted EPS for Con Edison are calculated as follows:



	For the Years Ended December 31,
(Millions of Dollars, except per share amounts/Shares in Millions)	2019	2018	2017
Net income for common stock	$1,343	$1,382	$1,525
Weighted average common shares outstanding – basic	328.5	311.7	307.1
Add: Incremental shares attributable to effect of potentially dilutive securities	1.0	1.2	1.7
Adjusted weighted average common shares outstanding – diluted	329.5	312.9	308.8
Net Income per common share – basic	$4.09	$4.43	$4.97
Net Income per common share – diluted	$4.08	$4.42	$4.94

Changes in Accumulated Other Comprehensive Income/(Loss)

Changes to accumulated other comprehensive income/(loss) (OCI) for Con Edison and CECONY are as follows:



(Millions of Dollars)	Con Edison	CECONY
Accumulated OCI, net of taxes, at December 31, 2016 (a)	$(27)	$(7)
OCI before reclassifications, net of tax of $3 and $1 for Con Edison and CECONY, respectively	(4)	—
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(3) and $(1) for Con Edison and CECONY, respectively (a)(b)	5	1
Total OCI, net of taxes, at December 31, 2017	1	1
Accumulated OCI, net of taxes, at December 31, 2017 (a)	$(26)	$(6)
OCI before reclassifications, net of tax of $3 for Con Edison	4	—
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(2) for Con Edison (a)(b)	6	1
Total OCI, net of taxes, at December 31, 2018	10	1
Accumulated OCI, net of taxes, at December 31, 2018 (a)	$(16)	$(5)
OCI before reclassifications, net of tax of $(6) and $(1) for Con Edison and CECONY, respectively	(10)	(3)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax of $(2) for Con Edison (a)(b)	7	2
Total OCI, net of taxes, at December 31, 2019	(3)	(1)
Accumulated OCI, net of taxes, at December 31, 2019 (a)	$(19)	$(6)

(a) Tax reclassified from accumulated OCI is reported in the income tax expense line item of the consolidated income statement.

Restrictions on Cash and Cash Equivalents

At December 31, 2019 and 2018, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Cash and temporary cash investments	$981	$895	$933	$818
Restricted cash (a)	236	111	—	—
Total cash, temporary cash investments and restricted cash	$1,217	$1,006	$933	$818

(a)

Schedule of Cash and Cash Equivalents

At December 31, 2019 and 2018, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Cash and temporary cash investments	$981	$895	$933	$818
Restricted cash (a)	236	111	—	—
Total cash, temporary cash investments and restricted cash	$1,217	$1,006	$933	$818

(a)

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Summary of Utilities Rate Plans

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	January 2017 – December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $195 million (b) Yr. 2 – $155 million (b) Yr. 3 – $155 million (b)	Yr. 1 – $113 million (c) Yr. 2 – $370 million (c) Yr. 3 – $326 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million	Yr. 1 – $267 million (d) Yr. 2 – $269 million (d) Yr. 3 – $272 million (d)
Other revenue sources	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 – $28 million Yr. 2 – $47 million Yr. 3 – $64 million In 2017, 2018 and 2019, the company recorded $13 million, $25 million and $43 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved $5 million of incentives for service terminations in 2017, 2018 and 2019 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded $3 million and $7 million of incentives for service terminations, respectively.	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $69 million Yr. 2 - $74 million Yr. 3 - $79 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017, 2018 and 2019, the company deferred for customer benefit $45 million, $(6) million and $169 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues.
Recoverable energy costs	Continuation of current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 – $376 million Yr. 2 – $341 million Yr. 3 – $352 million In 2017 and 2018, the company did not record any negative revenue adjustments. In 2019, the company recorded negative revenue adjustments of $15 million.	Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 - $450 million Yr. 2 - $461 million Yr. 3 - $476 million



Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (g). In 2017, 2018 and 2019, the company deferred $35 million, $189 million and $10 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 – $21,689 million Yr. 2 – $22,338 million Yr. 3 – $23,002 million AMI: Yr. 1 – $126 million Yr. 2 – $257 million Yr. 3 – $415 million The company deferred $0.4 million as a regulatory asset in 2017. In 2018 and 2019, $0.4 and $11.8 million was deferred as a regulatory liability, respectively.	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $24,491 million Yr. 2 - $25,092 million Yr. 3 - $25,708 million AMI: Yr. 1 - $572 million Yr. 2 - $740 million Yr. 3 - $806 million (h)
Average rate base	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million	Yr. 1 - $21,660 million Yr. 2 - $22,783 million Yr. 3 - $23,926 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent Yr. 3 – 8.82 percent
Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, the company had no earnings above the threshold but recorded a positive adjustment related to 2016 of $5.7 million in earnings. In 2018 and 2019, the company had no earnings sharing above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)

(b)

(c)

(d)


(e)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr 1 - 10.0 basis points; Yr 2 - 7.5 basis points; and Yr 3 - 5.0 basis points.

(f)

30 percent of the amount reflected in the January 2017-December 2019 rate plan and 15 percent of the amount reflected in the January 2020-December 2022 rate plan.


(g)	In addition, the NYSPSC staff has commenced a focused operations audit to investigate the income tax accounting of CECONY and other New York utilities. Any NYSPSC-ordered adjustment to CECONY’s income tax accounting will be refunded to or collected from customers, as determined by the NYSPSC. See "Other Regulatory Matters," below.


(h)	Reconciliation of net utility plant for AMI will be done on a combined basis for electric and gas.


(i)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



CECONY – Gas
Effective period	January 2017 - December 2019	January 2020 – December 2022 (a)
Base rate changes	Yr. 1 – $(5) million (b) Yr. 2 – $92 million Yr. 3 – $90 million	Yr. 1 – $84 million (c) Yr. 2 – $122 million (c) Yr. 3 – $167 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million	Yr. 1 – $45 million (d) Yr. 2 – $43 million (d) Yr. 3 – $10 million (d)
Other revenue sources	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential incentives if performance targets related to gas leak backlog, leak prone pipe and service terminations are met: Yr. 1 – $7 million Yr. 2 – $8 million Yr. 3 – $8 million In 2017, 2018 and 2019, the company achieved incentives of $7 million, $6 million and $7 million, respectively, that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded incentives of $5 million and $9 million, respectively, for gas leak backlog, leak prone pipe and service terminations.	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential earnings adjusted mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 - $20 million Yr. 2 - $22 million Yr. 3 - $25 million
Revenue decoupling mechanisms	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017, 2018 and 2019, the company deferred $3 million, $12 million and $10 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues, modified to be calculated based upon revenue per customer class instead of revenue per customer.
Recoverable energy costs	Continuation of current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 – $68 million Yr. 2 – $63 million Yr. 3 – $70 million In 2017 and 2018, the company recorded negative revenue adjustments of $5 million and $4 million, respectively. In 2019, the company did not record any negative revenue adjustments.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $81 million Yr. 2 - $88 million Yr. 3 - $96 million
Cost reconciliations	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g) In 2017, 2018 and 2019, the company deferred $2 million of net regulatory liabilities, $44 million of net regulatory assets and $18 million of net regulatory assets, respectively.	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
Net utility plant reconciliations	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 – $5,844 million Yr. 2 – $6,512 million Yr. 3 – $7,177 million AMI: Yr. 1 – $27 million Yr. 2 – $57 million Yr. 3 – $100 million In 2017 and 2018 the company deferred $2.2 million as regulatory liabilities. In 2019, the company deferred $1.7 million as a regulatory liability.	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 - $8,108 million Yr. 2 - $8,808 million Yr. 3 - $9,510 million AMI: Yr. 1 - $142 million Yr. 2 - $183 million Yr. 3 - $211 million (h)
Average rate base	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million	Yr. 1 - $7,171 million Yr. 2 - $7,911 million Yr. 3 - $8,622 million
Weighted average cost of capital (after-tax)	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent	6.61 percent
Authorized return on common equity	9.0 percent	8.80 percent
Actual return on common equity (i)	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent Yr. 3 – 8.72 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, 2018 and 2019, the company had no earnings above the threshold.	Most earnings above an annual earnings threshold of 9.3 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent	4.63 percent
Common equity ratio	48 percent	48 percent

(a)


(b)	The gas base rate decrease was offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.

(c)

(d)


(e)-(i)	See footnotes (e) - (i) to the table under “CECONY Electric,” above.



CECONY – Steam
Effective period		January 2014 – December 2016 (a)
Base rate changes		Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b) Yr. 4 – None Yr. 5 – None Yr. 6 – None
Amortizations to income of net regulatory (assets) and liabilities		$37 million over three years
Recoverable energy costs		Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments		Potential charges (up to $1 million annually) if certain steam performance targets are not met. In years 2014 through 2019, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016, 2017, 2018 and 2019, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, $1 million of net regulatory assets and $8 million of net regulatory liabilities, respectively.
Net utility plant reconciliations		Target levels reflected in rates were: Production: Yr. 1 – $1,752 million Yr. 2 – $1,732 million Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million Yr. 2 – $11 million Yr. 3 – $25 million The company reduced its regulatory liability by $0.1 million in 2014 and immaterial amounts in 2015 and 2016 and no deferrals were recorded in 2017, 2018 and 2019.
Average rate base		Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)		Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity		9.3 percent
Actual return on common equity (d)		Yr. 1 – 9.82 percent Yr. 2 – 10.88 percent Yr. 3 – 10.54 percent Yr. 4 – 9.51 percent Yr. 5 – 11.73 percent Yr. 6 – 10.45 percent
Earnings sharing		Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $11.5 million and $7.8 million above the threshold in 2015 and 2016, respectively. In 2017, actual earnings were $8.5 million above the threshold, offset in part by a positive adjustment related to 2016 of $4 million. In 2018, actual earnings were $16.5 million above the threshold, and an additional $1.1 million related to 2017 was recorded. In 2019 actual earnings were $5 million above the threshold, offset in part by an adjustment related to 2018 of $2.3 million.
Cost of long-term debt		Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio		48 percent


(a)	Rates determined pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.


(b)	The impact of these base rate changes was deferred which resulted in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.


(d)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Electric
Effective period	November 2015 - October 2017 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $9.3 million Yr. 2 – $8.8 million Yr. 3 – None	Yr. 1 – $13.4 million (e) Yr. 2 – $8.0 million (e) Yr. 3 – $5.8 million (e)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $(8.5) million (b) Yr. 2 – $(9.4) million (b) Yr. 3 – None	Yr. 1 – $(1.5) million (f) Yr. 2 – $(1.5) million (f) Yr. 3 – $(1.5) million (f)
Other revenue sources		Potential earnings adjustment mechanism incentives for peak reduction, energy efficiency, Distributed Energy Resources utilization and other potential incentives of up to: Yr. 1 - $3.6 million Yr. 2 - $4.0 million Yr. 3 - $4.2 million Potential incentive if performance target related to service terminations is met: $0.5 million annually. In 2019, the company recorded $2.6 million of earnings adjustment mechanism incentives for energy efficiency and $0.2 million of incentives for service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred for the customer’s benefit an immaterial amount, $6.3 million as regulatory liabilities, $11.2 million as regulatory asset and $0.5 million as regulatory asset, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2019 the company deferred $0.1 million as a regulatory asset.
Recoverable energy costs	Continuation of current rate recovery of purchased power costs.	Continuation of current rate recovery of purchased power costs.
Negative revenue adjustments	Potential charges (up to $4 million annually) if certain performance targets are not met. In 2015 the company recorded $1.25 million in negative revenue adjustments. In 2016, 2017 and 2018, the company did not record any negative revenue adjustments.	Potential charges if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million Yr. 2 - $4.4 million Yr. 3 - $4.5 million In 2019, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2015, 2016 and 2017, the company deferred $0.3 million, $7.4 million and $3.2 million as net decreases to regulatory assets, respectively. In 2018, the company deferred $5 million as a net regulatory asset.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), major storms, the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $4.3 million as a net regulatory asset.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $928 million (c) Yr. 2 – $970 million (c) The company increased/(reduced) its regulatory asset by $2.2 million, $(1.9) million, $(1.9) million and $1.4 million in 2015, 2016, 2017 and 2018, respectively.	Target levels reflected in rates were: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $1,008 million Yr. 2 - $1,032 million Yr. 3 - $1,083 million AMI (j): Yr. 1 - $48 million Yr. 2 - $58 million Yr. 3 - $61 million The company increased regulatory asset by an immaterial amount in 2019.
Average rate base	Yr. 1 – $763 million Yr. 2 – $805 million Yr. 3 – $805 million	Yr. 1 – $878 million Yr. 2 – $906 million Yr. 3 – $948 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 percent	Yr. 1 – 9.6 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $6.1 million, $0.3 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates determined pursuant to this rate plan continued in effect until the subsequent rate plan became effective.

(b)


(c)	Excludes electric AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.

(d)


(e)	The electric base rate increases shown above will be implemented with increases of: Yr. 1 - $8.6 million; Yr. 2 - $12.1 million; and Yr. 3 - $12.2 million.

(f)


(g)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr. 1 - 10.0 basis points; Yr. 2 - 7.5 basis points; and Yr. 3 - 5.0 basis points.


(h)	Energy efficiency costs are expensed as incurred. Such costs are subject to a downward-only reconciliation over the terms of the electric and gas rate plans. The company will defer for the benefit of customers any cumulative shortfall over the terms of the electric and gas rate plans between actual expenditures and the levels provided in rates.


(i)	In addition, amounts reflected in rates relating to income taxes and excess deferred federal income tax liability balances will be reconciled (i.e., refunded to or collected from customers) to any final, non-appealable NYSPSC-ordered findings in its investigation of O&R’s income tax accounting. See “Other Regulatory Matters,” in Note B.


(j)	Net plant reconciliation for AMI expenditures will be implemented for a single category of AMI capital expenditures that includes amounts allocated to both electric and gas customers.


(k)	Calculated in accordance with the earnings calculation method prescribed in the rate order.



O&R New York – Gas
Effective period	November 2015 – October 2018 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge	Yr. 1 – $(7.5) million (e) Yr. 2 – $3.6 million (e) Yr. 3 – $0.7 million (e)
Amortization to income of net regulatory (assets) and liabilities	Yr. 1 – $(1.7) million (b) Yr. 2 – $(2.1) million (b) Yr. 3 – $(2.5) million (b)	Yr. 1 – $1.8 million (f) Yr. 2 – $1.8 million (f) Yr. 3 – $1.8 million (f)
Other revenue sources		Continuation of retention of annual revenues from non-firm customers of up to $4.0 million, with variances to be shared 80 percent by customers and 20 percent by company. Potential earnings adjustment mechanism incentives of up to $0.3 million annually. Potential incentives if performance targets related to gas leak backlog, leak prone pipe, emergency response, damage prevention and service terminations are met: Yr. 1 - $1.2 million; Yr. 2 - $1.3 million; and Yr. 3 - $1.3 million. In 2019, the company recorded $0.3 million of earnings adjustment mechanism incentives for energy efficiency and $0.7 million of incentives for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred $0.8 million of regulatory assets, $6.2 million of regulatory liabilities, $1.7 million of regulatory liabilities and $6.3 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2019, the company deferred $0.8 million of regulatory assets.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential charges (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $4.9 million in Yr. 3) if certain performance targets are not met. In 2015, 2016 and 2017, the company did not record any negative revenue adjustments. In 2018, the company recorded a $0.1 million negative revenue adjustment.	Potential charges if performance targets relating to service, safety and other matters are not met: Yr. 1 - $5.5 million; Yr. 2 - $5.7 million; and Yr. 3 - $6.0 million. In 2019, the company recorded a $0.2 million negative revenue adjustment.
Cost reconciliations	In 2015 and 2016, the company deferred $4.5 million and $6.6 million as net regulatory liabilities and assets, respectively. In 2017 and 2018, the company deferred $3.5 million and $7.4 million as net regulatory liabilities, respectively.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), the impact of new laws and certain other costs to amounts reflected in rates.(i) In 2019, the company deferred $6 million as net regulatory liabilities.
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $492 million (c) Yr. 2 – $518 million (c) Yr. 3 – $546 million (c) No deferral was recorded for 2015 and immaterial amounts were recorded as regulatory liabilities in 2016 and 2017. In 2018, the company deferred $0.4 million as regulatory asset.	Target levels reflected in rates were: Gas average net plant target excluding AMI: Yr. 1 - $593 million Yr. 2 - $611 million Yr. 3 - $632 million AMI (j): Yr. 1 - $20 million Yr. 2 - $24 million Yr. 3 - $25 million In 2019, the company deferred an immaterial amount as regulatory asset.
Average rate base	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million	Yr. 1 – $454 million Yr. 2 – $476 million Yr. 3 – $498 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.0 percent
Actual return on common equity (k)	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 percent	Yr. 1 – 8.9 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $4 million, $0.2 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2019, earnings did not exceed the earnings threshold.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates pursuant to this rate plan continued in effect until the subsequent rate plan became effective.


(b)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes gas AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.

(d)


(e)	The gas base rate changes shown above will be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

(f)-(k) See footnotes (f) - (k) to the table under “O&R New York - Electric,” above.

In January 2020, the NJBPU approved an electric rate increase, effective February 1, 2020, of $12 million for RECO. The following table contains a summary of the terms of the distribution rate plans.



RECO
Effective period	March 2017 – January 2020	February 2020
Base rate changes	Yr. 1 – $1.7 million	Yr. 1 – $12 million
Amortization to income of net regulatory (assets) and liabilities	$0.2 million over three years and continuation of $(25.6) million of deferred storm costs over four years which expired on July 31, 2018 (a)	$4.8 million over four years.
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	Yr. 1 – $178.7 million	Yr. 1 – $229.9 million
Weighted average cost of capital (after-tax)	7.47 percent	7.11 percent
Authorized return on common equity	9.6 percent	9.5 percent
Actual return on common equity	Yr. 1 – 7.5 percent Yr. 2 – 5.7 percent
Cost of long-term debt	5.37 percent	4.88 percent
Common equity ratio	49.7 percent	48.32 percent


(a)	In January 2016, the NJBPU approved RECO’s plan to spend $15.7 million in capital over three years to harden its electric system against storms, the costs of which RECO, beginning in 2017, is collecting through a customer surcharge.

Schedule of Regulatory Assets

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2019 and 2018 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Regulatory assets
Unrecognized pension and other postretirement costs	$2,541	$2,238	$2,403	$2,111
Environmental remediation costs	732	810	647	716
Revenue taxes	321	291	308	278
MTA power reliability deferral	248	229	248	229
Property tax reconciliation	219	101	210	86
System peak reduction and energy efficiency programs	131	72	130	70
Deferred derivative losses	83	17	76	11
Municipal infrastructure support costs	75	67	75	67
Pension and other postretirement benefits deferrals	71	73	47	56
Deferred storm costs	77	76	—	—
Brooklyn Queens demand management program	39	39	39	39
Meadowlands heater odorization project	35	36	35	36
Unamortized loss on reacquired debt	28	36	26	34
Preferred stock redemption	22	23	22	23
Recoverable REV demonstration project costs	21	20	19	18
Gate station upgrade project	19	17	19	17
Non-wire alternative projects	14	3	14	3
Workers’ compensation	3	5	3	5
O&R transition bond charges	—	2	—	—
Other	180	139	166	124
Regulatory assets – noncurrent	4,859	4,294	4,487	3,923
Deferred derivative losses	128	36	113	29
Recoverable energy costs	—	40	—	35
Regulatory assets – current	128	76	113	64
Total Regulatory Assets	$4,987	$4,370	$4,600	$3,987
Regulatory liabilities
Future income tax*	$2,426	$2,515	$2,275	$2,363
Allowance for cost of removal less salvage	989	928	843	790
TCJA net benefits	471	434	454	411
Net unbilled revenue deferrals	199	117	199	117
Net proceeds from sale of property	173	6	173	6
Energy efficiency portfolio standard unencumbered funds	122	127	118	122
Pension and other postretirement benefit deferrals	75	62	46	40
System benefit charge carrying charge	48	27	44	24
Property tax refunds	45	45	45	45
BQDM and REV Demo reconciliations	27	18	26	18
Earnings sharing - electric, gas and steam	22	36	15	27
Settlement of gas proceedings	10	15	10	15
Unrecognized other postretirement costs	9	7	—	7
Settlement of prudence proceeding	8	37	8	37
Property tax reconciliation	—	36	—	36
Other	203	231	171	200
Regulatory liabilities – noncurrent	4,827	4,641	4,427	4,258
Refundable energy costs	44	31	12	8
Deferred derivative gains	34	30	34	29
Revenue decoupling mechanism	24	53	17	36
Regulatory liabilities—current	102	114	63	73
Total Regulatory Liabilities	$4,929	$4,755	$4,490	$4,331

* See "Federal Income Tax" in Note A, "Other Regulatory Matters," above, and Note L.

Schedule of Regulatory Liabilities

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2019 and 2018 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Regulatory assets
Unrecognized pension and other postretirement costs	$2,541	$2,238	$2,403	$2,111
Environmental remediation costs	732	810	647	716
Revenue taxes	321	291	308	278
MTA power reliability deferral	248	229	248	229
Property tax reconciliation	219	101	210	86
System peak reduction and energy efficiency programs	131	72	130	70
Deferred derivative losses	83	17	76	11
Municipal infrastructure support costs	75	67	75	67
Pension and other postretirement benefits deferrals	71	73	47	56
Deferred storm costs	77	76	—	—
Brooklyn Queens demand management program	39	39	39	39
Meadowlands heater odorization project	35	36	35	36
Unamortized loss on reacquired debt	28	36	26	34
Preferred stock redemption	22	23	22	23
Recoverable REV demonstration project costs	21	20	19	18
Gate station upgrade project	19	17	19	17
Non-wire alternative projects	14	3	14	3
Workers’ compensation	3	5	3	5
O&R transition bond charges	—	2	—	—
Other	180	139	166	124
Regulatory assets – noncurrent	4,859	4,294	4,487	3,923
Deferred derivative losses	128	36	113	29
Recoverable energy costs	—	40	—	35
Regulatory assets – current	128	76	113	64
Total Regulatory Assets	$4,987	$4,370	$4,600	$3,987
Regulatory liabilities
Future income tax*	$2,426	$2,515	$2,275	$2,363
Allowance for cost of removal less salvage	989	928	843	790
TCJA net benefits	471	434	454	411
Net unbilled revenue deferrals	199	117	199	117
Net proceeds from sale of property	173	6	173	6
Energy efficiency portfolio standard unencumbered funds	122	127	118	122
Pension and other postretirement benefit deferrals	75	62	46	40
System benefit charge carrying charge	48	27	44	24
Property tax refunds	45	45	45	45
BQDM and REV Demo reconciliations	27	18	26	18
Earnings sharing - electric, gas and steam	22	36	15	27
Settlement of gas proceedings	10	15	10	15
Unrecognized other postretirement costs	9	7	—	7
Settlement of prudence proceeding	8	37	8	37
Property tax reconciliation	—	36	—	36
Other	203	231	171	200
Regulatory liabilities – noncurrent	4,827	4,641	4,427	4,258
Refundable energy costs	44	31	12	8
Deferred derivative gains	34	30	34	29
Revenue decoupling mechanism	24	53	17	36
Regulatory liabilities—current	102	114	63	73
Total Regulatory Liabilities	$4,929	$4,755	$4,490	$4,331

* See "Federal Income Tax" in Note A, "Other Regulatory Matters," above, and Note L.

Capitalization (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Long-Term Debt Maturities

Long-term debt maturing in the period 2020-2024 is as follows:



(Millions of Dollars)	Con Edison		CECONY
2020	$518	(a)	$350
2021	1,967		640
2022	437		—
2023	316		—
2024	385		250

(a)

Carrying Amounts and Fair Values of Long-Term Debt

The carrying amounts and fair values of long-term debt at December 31, 2019 and 2018 are:



(Millions of Dollars)	2019		2018
Long-Term Debt (including current portion) (a)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$19,973	$22,738	$18,145	$18,740
CECONY	$14,964	$17,505	$14,151	$14,685

(a)

Amounts shown are net of unamortized debt expense and unamortized debt discount of $178 million and $151 million for Con Edison and CECONY, respectively, as of December 31, 2019 and $185 million and $139 million for Con Edison and CECONY, respectively, as of December 31, 2018.

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
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-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
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-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Pension Benefits (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Total Periodic Benefit Costs

The components of the Companies’ total periodic benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost – including administrative expenses	$250	$290	$263	$232	$272	$246
Interest cost on projected benefit obligation	601	561	591	564	525	554
Expected return on plan assets	(988)	(1,033)	(968)	(936)	(979)	(917)
Recognition of net actuarial loss	518	688	595	492	651	563
Recognition of prior service cost/(credit)	(17)	(17)	(17)	(19)	(19)	(19)
TOTAL PERIODIC BENEFIT COST	$364	$489	$464	$333	$450	$427
Cost capitalized	(108)	(127)	(181)	(102)	(119)	(169)
Reconciliation to rate level	(15)	(92)	(34)	(12)	(100)	(41)
Total expense recognized	$241	$270	$249	$219	$231	$217

The components of the Companies’ total periodic postretirement benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost	$18	$20	$20	$13	$14	$13
Interest cost on accumulated other postretirement benefit obligation	44	42	46	36	34	38
Expected return on plan assets	(66)	(73)	(69)	(54)	(63)	(61)
Recognition of net actuarial loss/(gain)	(9)	8	2	(10)	3	(3)
Recognition of prior service credit	(2)	(6)	(17)	(2)	(2)	(11)
TOTAL PERIODIC POSTRETIREMENT BENEFIT CREDIT	$(15)	$(9)	$(18)	$(17)	$(14)	$(24)
Cost capitalized	(7)	(8)	8	(5)	(6)	10
Reconciliation to rate level	12	8	(4)	7	9	(2)
Total credit recognized	$(10)	$(9)	($14)	$(15)	$(11)	($16)

Schedule of Funded Status

The funded status at December 31, 2019, 2018 and 2017 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
Service cost – excluding administrative expenses	245	286	259	228	267	241
Interest cost on projected benefit obligation	601	561	591	564	525	554
Net actuarial loss/(gain)	2,191	(1,219)	1,231	2,076	(1,159)	1,171
Plan amendments	15	—	6	—	—	—
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$16,792	$14,449	$15,536	$15,750	$13,542	$14,567
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
Actual return on plan assets	2,556	(536)	2,041	2,425	(507)	1,935
Employer contributions	350	473	450	318	434	412
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
Administrative expenses	(39)	(46)	(43)	(37)	(44)	(41)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$15,608	$13,450	$14,274	$14,790	$12,744	$13,519
FUNDED STATUS	$(1,184)	$(999)	$(1,262)	$(960)	$(798)	$(1,048)
Unrecognized net loss	$2,604	$2,464	$2,760	$2,466	$2,338	$2,624
Unrecognized prior service costs	(173)	(205)	(223)	(202)	(222)	(242)
Accumulated benefit obligation	15,015	13,030	13,897	14,010	12,161	12,972

The funded status of the programs at December 31, 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,114	$1,219	$1,198	$913	$985	$1,007
Service cost	18	20	20	13	14	13
Interest cost on accumulated postretirement benefit obligation	44	42	46	36	34	38
Amendments	(14)	—	—	—	—	—
Net actuarial loss/(gain)	264	(70)	53	252	(32)	16
Benefits paid and administrative expenses, net of subsidies	(110)	(135)	(134)	(100)	(125)	(124)
Participant contributions	41	38	36	40	37	35
BENEFIT OBLIGATION AT END OF YEAR	$1,357	$1,114	$1,219	$1,154	$913	$985
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$885	$1,039	$975	$759	$893	$851
Actual return on plan assets	198	(66)	150	165	(54)	130
Employer contributions	7	6	17	6	6	8
Employer group waiver plan subsidies	23	34	34	22	32	30
Participant contributions	40	37	35	40	37	35
Benefits paid	(127)	(165)	(172)	(120)	(155)	(161)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$1,026	$885	$1,039	$872	$759	$893
FUNDED STATUS	$(331)	$(229)	$(180)	$(282)	$(154)	$(92)
Unrecognized net loss/(gain)	$155	$14	$(47)	$149	$(2)	$(85)
Unrecognized prior service costs	(19)	(8)	(14)	(3)	(5)	(7)

Schedule of Assumptions

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	3.35	%	4.25	%	3.70	%
Rate of compensation increase
CECONY	3.80	%	4.25	%	4.25	%
O&R	3.20	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Expected return on plan assets	7.00	%	7.50	%	7.50	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	3.10	%	4.15	%	3.55	%
O&R	3.35	%	4.30	%	3.70	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Expected Return on Plan Assets	6.80	%	7.50	%	7.50	%

Schedule of Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$744	$756	$770	$788	$801	$4,181
CECONY	688	699	713	728	741	3,883

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years, net of receipt of governmental subsidies and participant contributions:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$96	$95	$93	$92	$91	$422
CECONY	87	85	83	82	80	368

Schedule of Plan Assets Allocations

The asset allocations for the pension plan at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	45% - 55%	51	%	51	%	58	%
Debt Securities	33% - 43%	38	%	39	%	33	%
Real Estate	10% - 14%	11	%	10	%	9	%
Total	100%	100	%	100	%	100	%

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	42%-80%	54	%	52	%	60	%
Debt Securities	20%-58%	46	%	48	%	40	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Value of Plan Assets

The fair values of the pension plan assets at December 31, 2019 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,652		$—	$3,652
International Equity (b)	3,354	—		3,354
U.S. Government Issued Debt (c)	—	1,496		1,496
Corporate Bonds Debt (d)	—	3,260		3,260
Structured Assets Debt (e)	—	173		173
Other Fixed Income Debt (f)	—	955		955
Cash and Cash Equivalents (g)	—	326		326
Futures (h)	—	—		—
Total investments within the fair value hierarchy	$7,006	$6,210		$13,216
Investments measured at NAV per share (n)
Private Equity (i)				555
Real Estate (j)				1,806
Hedge Funds (k)				270
Total investments valued using NAV per share				$2,631
Funds for retiree health benefits (l)	(110)	(98)		(208)
Funds for retiree health benefits measured at NAV per share (l)(n)				(42)
Total funds for retiree health benefits				$(250)
Investments (excluding funds for retiree health benefits)	$6,896	$6,112		$15,597
Pending activities (m)				11
Total fair value of plan net assets				$15,608


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	U.S. Government Issued Debt includes agency and treasury securities.


(d)	Corporate Bonds Debt consists of debt issued by various corporations.


(e)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(f)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(g)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(h)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(i)	Private Equity consists of global equity funds that are not exchange-traded.


(j)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.


(n)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

The fair values of the pension plan assets at December 31, 2018 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,515	$10	$3,525
International Equity (b)	2,896	—	2,896
U.S. Government Issued Debt (c)	—	1,886	1,886
Corporate Bonds Debt (d)	—	2,619	2,619
Structured Assets Debt (e)	—	6	6
Other Fixed Income Debt (f)	—	121	121
Cash and Cash Equivalents (g)	160	556	716
Futures (h)	568	—	568
Total investments within the fair value hierarchy	$7,139	$5,198	$12,337
Investments measured at NAV per share (n)
Private Equity (i)			440
Real Estate (j)			1,310
Hedge Funds (k)			255
Total investments valued using NAV per share			$2,005
Funds for retiree health benefits (l)	(118)	(86)	(204)
Funds for retiree health benefits measured at NAV per share (l)(n)			(33)
Total funds for retiree health benefits			$(237)
Investments (excluding funds for retiree health benefits)	$7,021	$5,112	$14,105
Pending activities (m)			(655)
Total fair value of plan net assets			$13,450

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2019 by asset category.

The fair values of the plans' assets at December 31, 2019 by asset category as defined by the accounting rules for fair value measurements (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$404	$404
Other Fixed Income Debt (b)	—		331	331
Cash and Cash Equivalents (c)	—		23	23
Total investments		$—	$758	$758
Funds for retiree health benefits (d)	110		98	208
Investments (including funds for retiree health benefits)		$110	$856	$966
Funds for retiree health benefits measured at net asset value (d)(e)				42
Pending activities (f)				18
Total fair value of plan net assets				$1,026


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Bloomberg Barclays U.S. Long Credit Index and an active separately managed fund indexed to the Bloomberg Barclays U.S. Long Credit Index.


(c)	Cash and Cash Equivalents include short-term investments and money markets.

(d)


(e)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.


(f)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year-end.

The fair values of the plans' assets at December 31, 2018 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$322	$322
Other Fixed Income Debt (b)	—		289	289
Cash and Cash Equivalents (c)	—		14	14
Total investments		$—	$625	$625
Funds for retiree health benefits (d)	118		86	204
Investments (including funds for retiree health benefits)		$118	$711	$829
Funds for retiree health benefits measured at net asset value (d)(e)				33
Pending activities (f)				23
Total fair value of plan net assets				$885

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2019 by asset category.

Schedule of Employer Contribution to Defined Savings Plan

The Companies also offer a defined contribution savings plan that covers substantially all employees and made contributions to the plan as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2019	2018	2017
Con Edison	$49	$45	$40
CECONY	42	39	35

Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Net Periodic Benefit Costs

The components of the Companies’ total periodic benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost – including administrative expenses	$250	$290	$263	$232	$272	$246
Interest cost on projected benefit obligation	601	561	591	564	525	554
Expected return on plan assets	(988)	(1,033)	(968)	(936)	(979)	(917)
Recognition of net actuarial loss	518	688	595	492	651	563
Recognition of prior service cost/(credit)	(17)	(17)	(17)	(19)	(19)	(19)
TOTAL PERIODIC BENEFIT COST	$364	$489	$464	$333	$450	$427
Cost capitalized	(108)	(127)	(181)	(102)	(119)	(169)
Reconciliation to rate level	(15)	(92)	(34)	(12)	(100)	(41)
Total expense recognized	$241	$270	$249	$219	$231	$217

The components of the Companies’ total periodic postretirement benefit costs for 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Service cost	$18	$20	$20	$13	$14	$13
Interest cost on accumulated other postretirement benefit obligation	44	42	46	36	34	38
Expected return on plan assets	(66)	(73)	(69)	(54)	(63)	(61)
Recognition of net actuarial loss/(gain)	(9)	8	2	(10)	3	(3)
Recognition of prior service credit	(2)	(6)	(17)	(2)	(2)	(11)
TOTAL PERIODIC POSTRETIREMENT BENEFIT CREDIT	$(15)	$(9)	$(18)	$(17)	$(14)	$(24)
Cost capitalized	(7)	(8)	8	(5)	(6)	10
Reconciliation to rate level	12	8	(4)	7	9	(2)
Total credit recognized	$(10)	$(9)	($14)	$(15)	$(11)	($16)

Schedule of Funded Status

The funded status at December 31, 2019, 2018 and 2017 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
Service cost – excluding administrative expenses	245	286	259	228	267	241
Interest cost on projected benefit obligation	601	561	591	564	525	554
Net actuarial loss/(gain)	2,191	(1,219)	1,231	2,076	(1,159)	1,171
Plan amendments	15	—	6	—	—	—
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$16,792	$14,449	$15,536	$15,750	$13,542	$14,567
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
Actual return on plan assets	2,556	(536)	2,041	2,425	(507)	1,935
Employer contributions	350	473	450	318	434	412
Benefits paid	(709)	(715)	(646)	(660)	(658)	(602)
Administrative expenses	(39)	(46)	(43)	(37)	(44)	(41)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$15,608	$13,450	$14,274	$14,790	$12,744	$13,519
FUNDED STATUS	$(1,184)	$(999)	$(1,262)	$(960)	$(798)	$(1,048)
Unrecognized net loss	$2,604	$2,464	$2,760	$2,466	$2,338	$2,624
Unrecognized prior service costs	(173)	(205)	(223)	(202)	(222)	(242)
Accumulated benefit obligation	15,015	13,030	13,897	14,010	12,161	12,972

The funded status of the programs at December 31, 2019, 2018 and 2017 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,114	$1,219	$1,198	$913	$985	$1,007
Service cost	18	20	20	13	14	13
Interest cost on accumulated postretirement benefit obligation	44	42	46	36	34	38
Amendments	(14)	—	—	—	—	—
Net actuarial loss/(gain)	264	(70)	53	252	(32)	16
Benefits paid and administrative expenses, net of subsidies	(110)	(135)	(134)	(100)	(125)	(124)
Participant contributions	41	38	36	40	37	35
BENEFIT OBLIGATION AT END OF YEAR	$1,357	$1,114	$1,219	$1,154	$913	$985
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$885	$1,039	$975	$759	$893	$851
Actual return on plan assets	198	(66)	150	165	(54)	130
Employer contributions	7	6	17	6	6	8
Employer group waiver plan subsidies	23	34	34	22	32	30
Participant contributions	40	37	35	40	37	35
Benefits paid	(127)	(165)	(172)	(120)	(155)	(161)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$1,026	$885	$1,039	$872	$759	$893
FUNDED STATUS	$(331)	$(229)	$(180)	$(282)	$(154)	$(92)
Unrecognized net loss/(gain)	$155	$14	$(47)	$149	$(2)	$(85)
Unrecognized prior service costs	(19)	(8)	(14)	(3)	(5)	(7)

Schedule of Actuarial Assumptions

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	3.35	%	4.25	%	3.70	%
Rate of compensation increase
CECONY	3.80	%	4.25	%	4.25	%
O&R	3.20	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Expected return on plan assets	7.00	%	7.50	%	7.50	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%

The actuarial assumptions were as follows:



	2019		2018		2017
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	3.10	%	4.15	%	3.55	%
O&R	3.35	%	4.30	%	3.70	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Expected Return on Plan Assets	6.80	%	7.50	%	7.50	%

Schedule of Change of Assumed Health Care Cost Trend Rate

A one-percentage point change in the assumed health care cost trend rate would have the following effects at December 31, 2019:



	Con Edison		CECONY
	One-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$60	$(17)	$33	$3
Effect on service cost and interest cost components for 2019	1	—	(1)	2

Schedule of Expected Benefit Payments

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$744	$756	$770	$788	$801	$4,181
CECONY	688	699	713	728	741	3,883

Based on current assumptions, the Companies expect to make the following benefit payments over the next ten years, net of receipt of governmental subsidies and participant contributions:



(Millions of Dollars)	2020	2021	2022	2023	2024	2025-2029
Con Edison	$96	$95	$93	$92	$91	$422
CECONY	87	85	83	82	80	368

Schedule of Plan Assets Allocations

The asset allocations for the pension plan at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	45% - 55%	51	%	51	%	58	%
Debt Securities	33% - 43%	38	%	39	%	33	%
Real Estate	10% - 14%	11	%	10	%	9	%
Total	100%	100	%	100	%	100	%

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2019, 2018 and 2017, and the target allocation for 2020 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2020	2019		2018		2017
Equity Securities	42%-80%	54	%	52	%	60	%
Debt Securities	20%-58%	46	%	48	%	40	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Value of Plan Assets

The fair values of the pension plan assets at December 31, 2019 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2		Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,652		$—	$3,652
International Equity (b)	3,354	—		3,354
U.S. Government Issued Debt (c)	—	1,496		1,496
Corporate Bonds Debt (d)	—	3,260		3,260
Structured Assets Debt (e)	—	173		173
Other Fixed Income Debt (f)	—	955		955
Cash and Cash Equivalents (g)	—	326		326
Futures (h)	—	—		—
Total investments within the fair value hierarchy	$7,006	$6,210		$13,216
Investments measured at NAV per share (n)
Private Equity (i)				555
Real Estate (j)				1,806
Hedge Funds (k)				270
Total investments valued using NAV per share				$2,631
Funds for retiree health benefits (l)	(110)	(98)		(208)
Funds for retiree health benefits measured at NAV per share (l)(n)				(42)
Total funds for retiree health benefits				$(250)
Investments (excluding funds for retiree health benefits)	$6,896	$6,112		$15,597
Pending activities (m)				11
Total fair value of plan net assets				$15,608


(a)	U.S. Equity includes both actively- and passively-managed assets with investments in domestic equity index funds and actively-managed small-capitalization equities.


(b)	International Equity includes international equity index funds and actively-managed international equities.


(c)	U.S. Government Issued Debt includes agency and treasury securities.


(d)	Corporate Bonds Debt consists of debt issued by various corporations.


(e)	Structured Assets Debt includes commercial-mortgage-backed securities and collateralized mortgage obligations.


(f)	Other Fixed Income Debt includes municipal bonds, sovereign debt and regional governments.


(g)	Cash and Cash Equivalents include short term investments, money markets, foreign currency and cash collateral.


(h)	Futures consist of exchange-traded financial contracts encompassing U.S. Equity, International Equity and U.S. Government indices.


(i)	Private Equity consists of global equity funds that are not exchange-traded.


(j)	Real Estate investments include real estate funds based on appraised values that are broadly diversified by geography and property type.


(k)	Hedge Funds are within a commingled structure which invests in various hedge fund managers who can invest in all financial instruments.

(l)


(m)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received and reflects adjustments for available estimates at year end.


(n)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

The fair values of the pension plan assets at December 31, 2018 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,515	$10	$3,525
International Equity (b)	2,896	—	2,896
U.S. Government Issued Debt (c)	—	1,886	1,886
Corporate Bonds Debt (d)	—	2,619	2,619
Structured Assets Debt (e)	—	6	6
Other Fixed Income Debt (f)	—	121	121
Cash and Cash Equivalents (g)	160	556	716
Futures (h)	568	—	568
Total investments within the fair value hierarchy	$7,139	$5,198	$12,337
Investments measured at NAV per share (n)
Private Equity (i)			440
Real Estate (j)			1,310
Hedge Funds (k)			255
Total investments valued using NAV per share			$2,005
Funds for retiree health benefits (l)	(118)	(86)	(204)
Funds for retiree health benefits measured at NAV per share (l)(n)			(33)
Total funds for retiree health benefits			$(237)
Investments (excluding funds for retiree health benefits)	$7,021	$5,112	$14,105
Pending activities (m)			(655)
Total fair value of plan net assets			$13,450

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2019 by asset category.

The fair values of the plans' assets at December 31, 2019 by asset category as defined by the accounting rules for fair value measurements (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$404	$404
Other Fixed Income Debt (b)	—		331	331
Cash and Cash Equivalents (c)	—		23	23
Total investments		$—	$758	$758
Funds for retiree health benefits (d)	110		98	208
Investments (including funds for retiree health benefits)		$110	$856	$966
Funds for retiree health benefits measured at net asset value (d)(e)				42
Pending activities (f)				18
Total fair value of plan net assets				$1,026


(a)	Equity includes a passively managed commingled index fund benchmarked to the MSCI All Country World Index.


(b)	Other Fixed Income Debt includes a passively managed commingled index fund benchmarked to the Bloomberg Barclays U.S. Long Credit Index and an active separately managed fund indexed to the Bloomberg Barclays U.S. Long Credit Index.


(c)	Cash and Cash Equivalents include short-term investments and money markets.

(d)


(e)	In accordance with ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its equivalent), certain investments that are measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.


(f)	Pending activities include security purchases and sales that have not settled, interest and dividends that have not been received, and reflects adjustments for available estimates at year-end.

The fair values of the plans' assets at December 31, 2018 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$322	$322
Other Fixed Income Debt (b)	—		289	289
Cash and Cash Equivalents (c)	—		14	14
Total investments		$—	$625	$625
Funds for retiree health benefits (d)	118		86	204
Investments (including funds for retiree health benefits)		$118	$711	$829
Funds for retiree health benefits measured at net asset value (d)(e)				33
Pending activities (f)				23
Total fair value of plan net assets				$885

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2019 by asset category.

Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease Costs, Cash Flows and Other Related Information

Other information related to leases for Con Edison and CECONY at December 31, 2019 was as follows:



	Con Edison	CECONY
Weighted Average Remaining Lease Term:
Operating leases	19.8 years	14.0 years
Finance leases	12.2 years	2.4 years
Weighted Average Discount Rate:
Operating leases	4.3%	3.6%
Finance leases	3.5%	4.1%

Operating lease cost and cash paid for amounts included in the measurement of lease liabilities for the twelve months ended December 31, 2019, were as follows:

Operating Leases, Future Minimum Lease Payments

Future minimum lease payments under non-cancellable leases at December 31, 2019 were as follows:



(Millions of Dollars)	Con Edison				CECONY
Year Ending December 31,	Operating Leases		Finance Leases		Operating Leases		Finance Leases
2020		$78		$—		$60		$—
2021	75		—		57		—
2022	73		—		55		—
2023	72		—		54		—
2024	72		—		55		—
All years thereafter	992		1		501		—
Total future minimum lease payments		$1,362		$1		$782		$—
Less: imputed interest	(488)		—		(177)		—
Total		$874		$1		$605		$—
Reported as of December 31, 2019
Operating lease liabilities (current)		$65		$—		$54		$—
Operating lease liabilities (noncurrent)	809		—		551		—
Other noncurrent liabilities	—		1		—		—
Total		$874		$1		$605		$—

Finance Leases, Future Minimum Lease Payments

Future minimum lease payments under non-cancellable leases at December 31, 2019 were as follows:



(Millions of Dollars)	Con Edison				CECONY
Year Ending December 31,	Operating Leases		Finance Leases		Operating Leases		Finance Leases
2020		$78		$—		$60		$—
2021	75		—		57		—
2022	73		—		55		—
2023	72		—		54		—
2024	72		—		55		—
All years thereafter	992		1		501		—
Total future minimum lease payments		$1,362		$1		$782		$—
Less: imputed interest	(488)		—		(177)		—
Total		$874		$1		$605		$—
Reported as of December 31, 2019
Operating lease liabilities (current)		$65		$—		$54		$—
Operating lease liabilities (noncurrent)	809		—		551		—
Other noncurrent liabilities	—		1		—		—
Total		$874		$1		$605		$—

Future Minimum Lease Commitments Accounted for Under Topic 840

The future minimum lease commitments at December 31, 2018, accounted for under Topic 840, for the Companies’ operating lease agreements that are not cancellable by the Companies were as follows:



(Millions of Dollars)	Con Edison	CECONY
2019	$72	$56
2020	72	56
2021	71	54
2022	68	53
2023	68	53
All years thereafter	890	592
Total	$1,241	$864

Income Tax (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
State
Current	$(12)	$(10)	$(2)	$22	$6	$37
Deferred	96	107	103	68	82	75
Federal
Current	—	3	(11)	185	(34)	73
Deferred	219	310	391	63	275	504
Amortization of investment tax credits	(7)	(9)	(9)	(3)	(3)	(4)
Total income tax expense	$296	$401	$472	$335	$326	$685

Schedule of Differences on Deferred Tax Assets and Liabilities

The tax effects of temporary differences, which gave rise to deferred tax assets and liabilities, are as follows:



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Deferred tax liabilities:
Property basis differences	$7,699	$7,402	$6,640	$6,446
Regulatory assets:
Unrecognized pension and other postretirement costs	712	627	674	591
Environmental remediation costs	205	227	181	200
Deferred storm costs	22	21	—	—
Other regulatory assets	376	273	355	252
Operating lease right-of-use asset	231	—	169	—
Equity investments	104	102	—	—
Total deferred tax liabilities	$9,349	$8,652	$8,019	$7,489
Deferred tax assets:
Accrued pension and other postretirement costs	$291	$248	$222	$180
Regulatory liabilities:
Future income tax	678	702	638	662
Other regulatory liabilities	702	632	622	554
Superfund and other environmental costs	206	218	183	194
Asset retirement obligations	135	114	102	82
Operating lease liabilities	231	—	170	—
Loss carryforwards	108	229	—	—
Tax credits carryforward	896	817	—	—
Valuation allowance	(40)	(33)	—	—
Other	56	53	103	102
Total deferred tax assets	3,263	2,980	2,040	1,774
Net deferred tax liabilities	$6,086	$5,672	$5,979	$5,715
Unamortized investment tax credits	141	148	21	24
Net deferred tax liabilities and unamortized investment tax credits	$6,227	$5,820	$6,000	$5,739

Schedule of Income Tax Reconciliation

Reconciliation of the difference between income tax expense and the amount computed by applying the prevailing statutory income tax rate to income before income taxes is as follows:



	Con Edison						CECONY
(% of Pre-tax income)	2019		2018		2017		2019		2018		2017
STATUTORY TAX RATE
Federal	21	%	21	%	35	%	21	%	21	%	35	%
Changes in computed taxes resulting from:
State income tax	4		4		4		5		5		4
Taxes attributable to noncontrolling interests	(1	)	—		—		—		—		—
Cost of removal	1		1		1		1		1		1
Other plant-related items	(1	)	(1	)	(1	)	(1	)	(1	)	(1	)
TCJA deferred tax re-measurement	—		2		(13	)	—		—		—
Amortization of excess deferred federal income taxes	(4	)	(3	)	—		(4	)	(3	)	—
Renewable energy credits	(2	)	(1	)	(1	)	—		—		—
Research and development credits	(1	)	—		—		(1	)	(1	)	—
Other	—		—		(2	)	—		(1	)	(1	)
Effective tax rate	17	%	23	%	23	%	21	%	21	%	38	%

Summary of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amounts of unrecognized tax benefits for Con Edison and CECONY follows:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Balance at January 1,	$6	$12	$42	$4	$5	$21
Additions based on tax positions related to the current year	1	2	1	1	2	1
Additions based on tax positions of prior years	10	1	1	—	1	1
Reductions for tax positions of prior years	(2)	(2)	(24)	(1)	(1)	(18)
Reductions from expiration of statute of limitations	—	(4)	(2)	—	—	—
Settlements	(2)	(3)	(6)	(2)	(3)	—
Balance at December 31,	$13	$6	$12	$2	$4	$5

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Summary of Stock-Based Compensation Expense

The following table summarizes stock-based compensation expense recognized by the Companies in the years ended December 31, 2019, 2018 and 2017:



	Con Edison			CECONY
(Millions of Dollars)	2019	2018	2017	2019	2018	2017
Performance-based restricted stock	$36	$3	$53	$30	$3	$45
Time-based restricted stock	2	2	2	2	1	2
Non-employee director deferred stock compensation	2	3	2	2	3	2
Stock purchase plan	7	6	6	6	6	6
Total	$47	$14	$63	$40	$13	$55
Income tax benefit	$13	$4	$25	$11	$4	$22

Assumptions Used to Calculate Fair Value of Awards

The assumptions used to calculate the fair value of the awards were as follows:



	2019	2018	2017
Risk-free interest rate (a)	1.58% - 1.59%	2.48% - 2.63%	1.76% - 1.89%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	12.89% - 15.51%	14.76% - 17.71%	11.01% - 14.70%


(a)	The risk-free rate is based on the U.S. Treasury zero-coupon yield curve.


(b)	The expected term of the Performance RSUs equals the vesting period. The Companies do not expect significant forfeitures to occur.


(c)	Based on historical experience.

Summary of Changes in Status of Performance RSUs

A summary of changes in the status of the Performance RSUs’ TSR and non-TSR portions during the year ended December 31, 2019 is as follows:



	Con Edison			CECONY
		Weighted Average Grant Date Fair Value (a)			Weighted Average Grant Date Fair Value (a)
	Units	TSR Portion (b)	Non-TSR Portion (c)	Units	TSR Portion (b)	Non-TSR Portion (c)
Non-vested at December 31, 2018	1,005,836	$74.81	$74.27	761,906	$74.47	$74.42
Granted	389,600	64.37	80.03	284,516	64.82	80.31
Vested	(357,325)	83.17	72.09	(275,376)	82.77	72.32
Forfeited	(46,873)	65.08	78.03	(30,186)	65.20	78.10
Transferred (d)	—	—	—	1,344	70.04	75.65
Non-vested at December 31, 2019	991,238	$68.15	$77.14	742,204	$68.06	$77.32


(a)	The TSR and non-TSR Portions each account for 50 percent of the awards’ value.


(b)	Fair value is determined using the Monte Carlo simulation described above. Weighted average grant date fair value does not reflect any accrual or payment of dividends prior to vesting.


(c)	Fair value is determined using the market price of one share of Con Edison common stock on the grant date. The market price has not been discounted to reflect that dividends do not accrue and are not payable on Performance RSUs until vesting.

(d)

Represents allocation to another Con Edison subsidiary of a portion of the Performance RSUs that had been awarded to a CECONY officer who transferred to another subsidiary.

Summary of Changes in Status of Time-Based Awards

A summary of changes in the status of time-based awards during the year ended December 31, 2019 is as follows:



	Con Edison		CECONY
	Units	Weighted Average Grant Date Fair Value	Units	Weighted Average Grant Date Fair Value
Non-vested at December 31, 2018	65,180	$77.42	61,380	$77.42
Granted	24,850	84.81	23,350	84.81
Vested	(20,980)	76.62	(19,830)	76.62
Forfeited	(1,800)	79.12	(1,800)	79.12
Non-vested at December 31, 2019	67,250	$80.36	63,100	$80.36

Financial Information by Business Segment (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Financial Data for Business Segments

The financial data for the business segments are as follows:



As of and for the Year Ended December 31, 2019 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$8,062	$17		$1,053	$1,758	$(28)	$539	$239	$32,988	$1,851
Gas	2,132	7		231	528	(4)	147	99	11,090	1,078
Steam	627	70		89	62	(3)	42	4	2,479	91
Consolidation adjustments	—	(94)		—	—	—	—	—	—	—
Total CECONY	$10,821		$—	$1,373	$2,348	($35)	$728	$342	$46,557	$3,020
O&R
Electric	$634		$—	$60	$98	$(7)	$27	$15	$2,130	$142
Gas	259	—		24	41	(4)	14	6	876	61
Other	—	—		—	—	—	—	—	—	—
Total O&R	$893		$—	$84	$139	$(11)	$41	$21	$3,006	$203
Clean Energy Businesses	$857		$—	$226	$202	$5	$186	$(58)	$6,528	$248
Con Edison Transmission	4	—		1	(6)	104	25	1	1,618	205
Other (b)	(1)	—		—	(7)	(12)	11	(6)	370	—
Total Con Edison	$12,574		$—	$1,684	$2,676	$51	$991	$300	$58,079	$3,676



As of and for the Year Ended December 31, 2018 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$7,971	$16		$984	$1,799	$(110)	$519	$233	$31,012	$1,861
Gas	2,078	7		205	478	(23)	131	87	9,710	1,050
Steam	631	75		87	77	(10)	39	8	2,386	94
Consolidation adjustments	—	(98)		—	—	—	—	—	—	—
Total CECONY	$10,680		$—	$1,276	$2,354	$(143)	$689	$328	$43,108	$3,005
O&R
Electric	$642		$—	$56	$93	$(14)	$25	$14	$2,036	$138
Gas	249	—		21	39	(5)	14	7	856	67
Other	—	—		—	—	—	—	—	—	—
Total O&R	$891		$—	$77	$132	$(19)	$39	$21	$2,892	$205
Clean Energy Businesses	$763		$—	$85	$194	$33	$63	$19	$5,821	$1,791
Con Edison Transmission	4	—		1	(7)	91	20	(1)	1,425	248
Other (b)	(1)	—		(1)	(9)	(24)	8	39	674	—
Total Con Edison	$12,337		$—	$1,438	$2,664	$(62)	$819	$406	$53,920	$5,249



As of and for the Year Ended December 31, 2017 (Millions of Dollars)	Operating revenues	Inter- segment revenues		Depreciation and amortization	Operating income	Other Income (deductions)	Interest charges	Income taxes on operating income (a)	Total assets	Capital expenditures
CECONY
Electric	$7,972	$16		$925	$1,974	$(105)	$472	$511	$29,661	$1,905
Gas	1,901	6		185	495	(23)	113	152	8,387	909
Steam	595	75		85	80	(9)	38	25	2,403	90
Consolidation adjustments	—	(97)		—	—	—	—	—	—	—
Total CECONY	$10,468		$—	$1,195	$2,549	$(137)	$623	$688	$40,451	$2,904
O&R
Electric	$642		$—	$51	$115	$(14)	$24	$30	$1,949	$128
Gas	232	—		20	46	(5)	12	12	824	61
Other	—	—		—	—	—	—	—	—	—
Total O&R	$874		$—	$71	$161	$(19)	$36	$42	$2,773	$189
Clean Energy Businesses	$694		$—	$74	$69	$33	$43	$(273)	$2,735	$447
Con Edison Transmission	2	—		1	(8)	80	16	(11)	1,222	66
Other (b)	(5)	—		—	3	(5)	11	13	930	—
Total Con Edison	$12,033		$—	$1,341	$2,774	$(48)	$729	$459	$48,111	$3,606

(a)

(b)

Parent company and consolidation adjustments. Other does not represent a business segment.

Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting of Assets

The fair values of the Companies’ derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2019 and 2018 were:



(Millions of Dollars)	2019				2018
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$60	$(3)	$57	(b)	$43	$(14)	$29	(b)
Noncurrent	19	(13)	6	(c)	16	(7)	9	(d)
Total fair value of derivative assets	$79	$(16)	$63		$59	$(21)	$38
Fair value of derivative liabilities
Current	$(140)	$17	$(123)	(c)	$(61)	$11	$(50)
Noncurrent	(122)	16	(106)	(c)	(25)	9	(16)	(d)
Total fair value of derivative liabilities	$(262)	$33	$(229)		$(86)	$20	$(66)
Net fair value derivative assets/(liabilities)	$(183)	$17	$(166)		$(27)	$(1)	$(28)
CECONY
Fair value of derivative assets
Current	$39	$(6)	$33	(b)	$25	$(6)	$19	(b)
Noncurrent	17	(12)	5		11	(5)	6
Total fair value of derivative assets	$56	$(18)	$38		$36	$(11)	$25
Fair value of derivative liabilities
Current	$(100)	$19	$(81)		$(31)	$6	$(25)
Noncurrent	(80)	16	(64)		(12)	6	(6)
Total fair value of derivative liabilities	$(180)	$35	$(145)		$(43)	$12	$(31)
Net fair value derivative assets/(liabilities)	$(124)	$17	$(107)		$(7)	$1	$(6)

(a)

(b)


(c)	Includes amounts for interest rate swaps of $1 million in noncurrent assets, $(7) million in current liabilities and $(34) million in noncurrent liabilities. At December 31, 2019, the Clean Energy Businesses had interest rate swaps with notional amounts of $919 million. The expiration dates of the swaps range from 2024-2041.


(d)	Includes amounts for interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities. At December 31, 2018, the Clean Energy Businesses had interest rate swaps with notional amounts of $499 million. The expiration dates of the swaps range from 2024-2035.

Offsetting of Liabilities

The fair values of the Companies’ derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2019 and 2018 were:



(Millions of Dollars)	2019				2018
Balance Sheet Location	Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)		Gross Amounts of Recognized Assets/ (Liabilities)	Gross Amounts Offset	Net Amounts of Assets/(Liabilities) (a)
Con Edison
Fair value of derivative assets
Current	$60	$(3)	$57	(b)	$43	$(14)	$29	(b)
Noncurrent	19	(13)	6	(c)	16	(7)	9	(d)
Total fair value of derivative assets	$79	$(16)	$63		$59	$(21)	$38
Fair value of derivative liabilities
Current	$(140)	$17	$(123)	(c)	$(61)	$11	$(50)
Noncurrent	(122)	16	(106)	(c)	(25)	9	(16)	(d)
Total fair value of derivative liabilities	$(262)	$33	$(229)		$(86)	$20	$(66)
Net fair value derivative assets/(liabilities)	$(183)	$17	$(166)		$(27)	$(1)	$(28)
CECONY
Fair value of derivative assets
Current	$39	$(6)	$33	(b)	$25	$(6)	$19	(b)
Noncurrent	17	(12)	5		11	(5)	6
Total fair value of derivative assets	$56	$(18)	$38		$36	$(11)	$25
Fair value of derivative liabilities
Current	$(100)	$19	$(81)		$(31)	$6	$(25)
Noncurrent	(80)	16	(64)		(12)	6	(6)
Total fair value of derivative liabilities	$(180)	$35	$(145)		$(43)	$12	$(31)
Net fair value derivative assets/(liabilities)	$(124)	$17	$(107)		$(7)	$1	$(6)

(a)

(b)


(c)	Includes amounts for interest rate swaps of $1 million in noncurrent assets, $(7) million in current liabilities and $(34) million in noncurrent liabilities. At December 31, 2019, the Clean Energy Businesses had interest rate swaps with notional amounts of $919 million. The expiration dates of the swaps range from 2024-2041.

(d)

Includes amounts for interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities. At December 31, 2018, the Clean Energy Businesses had interest rate swaps with notional amounts of $499 million. The expiration dates of the swaps range from 2024-2035.

Realized and Unrealized Gains or Losses on Commodity Derivatives

The following table presents the realized and unrealized gains or losses on derivatives that have been deferred or recognized in earnings for the years ended December 31, 2019 and 2018:



		Con Edison		CECONY
(Millions of Dollars)	Balance Sheet Location	2019	2018	2019		2018
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$4	$(1)	$5		$1
Noncurrent	Deferred derivative gains	(3)	4	(1)		3
Total deferred gains/(losses)		$1	$3	$4		$4
Current	Deferred derivative losses	$(91)	$4	$(83)		$8
Current	Recoverable energy costs	(142)	(26)	(124)		(26)
Noncurrent	Deferred derivative losses	(67)	27	(65)		26
Total deferred gains/(losses)		$(300)	$5	$(272)		$8
Net deferred gains/(losses)		$(299)	$8	$(268)		$12
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Gas purchased for resale	$(2)	$(2)		$—		$—
	Non-utility revenue	25	4	—		—
	Other operations and maintenance expense	1	(2)	1		(2)
	Other interest expense	(36)	(4)	—		—
Total pre-tax gain/(loss) recognized in income		$(12)	$(4)	$1		$(2)

Hedged Volume of Derivative Transactions

The following table presents the hedged volume of Con Edison’s and CECONY’s commodity derivative transactions at December 31, 2019:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison	24,868,670	28,916	277,827,601	5,712,000
CECONY	22,487,800	19,950	258,080,000	5,712,000


(a)	Volumes are reported net of long and short positions, except natural gas collars where the volumes of long positions are reported.


(b)	Excludes electric congestion and gas basis swap contracts which are associated with electric and gas contracts and hedged volumes.

Aggregate Fair Value of Companies' Derivative Instruments with Credit-Risk-Related Contingent Features



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$163	$145
Collateral posted	25	25
Additional collateral (b) (downgrade one level from current ratings)	50	41
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	159	134

(a)

(b)

(c)

- Definition

Tabular disclosure of credit derivatives which includes information by sellers of credit derivatives, about each credit derivative, or each group of similar credit derivatives, including (a) the nature of the credit derivative - its term, how it arose, the events or circumstances that would require the seller to perform under the credit derivative, and the current status of the payment/performance risk of the credit derivative; (b) the maximum potential amount of future payments (undiscounted) the seller could be required to make under the credit derivative; (c) the current fair value of the credit derivative; and (d) the nature of any recourse provisions under the credit derivative, and any assets held either as collateral or by third parties. A credit derivative is a derivative instrument (1) in which one or more of its underlyings are related to the credit risk of a specified entity (or a group of entities) or an index based on the credit risk of a group of entities and (2) that exposes the seller to potential loss from credit-risk-related events specified in the contract. Examples of credit derivatives within the scope of this paragraph include, but are not limited to, credit default swaps, credit spread options, and credit index products; also includes a hybrid instrument that has an embedded credit derivative (for example, but not limited to, a credit-linked note).

+ References + Details

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

Assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2019 and 2018 are summarized below.



	2019						2018
(Millions of Dollars)	Level 1	Level 2	Level 3	Netting Adjustment (e)		Total	Level 1	Level 2	Level 3	Netting Adjustment (e)	Total
Con Edison
Derivative assets:
Commodity (a)(b)(c)	$4	$61	$2	$4		$71	$6	$36	$7	$(6)	$43
Interest rate swaps (a)(b)(c)(f)	—	1	—	—		1	—	2	—	—	2
Other (a)(b)(d)	353	125	—	—		478	287	114	—	—	401
Total assets	$357	$187	$2	$4		$550	$293	$152	$7	$(6)	$446
Derivative liabilities:
Commodity (a)(b)(c)	$18	$174	$18	$(22)		$188	$8	$43	$20	$(11)	$60
Interest rate swaps (a)(b)(c)(f)	—	41	—	—		41	—	6	—	—	6
Total liabilities	$18	$215	$18	$(22)		$229	$8	$49	$20	$(11)	$66
CECONY
Derivative assets:
Commodity (a)(b)(c)	$3	$42	$1		$—	$46	$3	$28	$1	$(1)	$31
Other (a)(b)(d)	333	119	—	—		452	267	109	—	—	376
Total assets	$336	$161	$1		$—	$498	$270	$137	$1	$(1)	$407
Derivative liabilities:
Commodity (a)(b)(c)	$15	$147	$7	$(24)		$145	$5	$30	3	$(6)	$32

(a)

(b)

(c)


(d)	Other assets are comprised of assets such as life insurance contracts within the deferred compensation plan and non-qualified retirement plans.


(e)	Amounts represent the impact of legally-enforceable master netting agreements that allow the Companies to net gain and loss positions and cash collateral held or placed with the same counterparties.

(f)

See Note O.

Schedule of Commodity Derivatives



	Fair Value of Level 3 at December 31, 2019
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(1)	Discounted Cash Flow	Forward energy prices (a)	$25.50-$34.10 per MWh
	(16)	Discounted Cash Flow	Forward capacity prices (a)	$0.09-$8.90 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$(3.69)-$7.37 per MWh
Total Con Edison — Commodity	$(16)
CECONY — Commodity
Electricity	$(7)	Discounted Cash Flow	Forward capacity prices (a)	$0.15-$8.90 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.36-$3.10 per MWh
Total CECONY — Commodity	$(6)


(a)	Generally, increases (decreases) in this input in isolation would result in a higher (lower) fair value measurement.

(b)

Generally, increases (decreases) in this input in isolation would result in a lower (higher) fair value measurement.

Reconciliation of Beginning and Ending Net Balances for Assets and Liabilities Measured at Level 3 Fair Value



	Con Edison		CECONY
(Millions of Dollars)	2019	2018	2019	2018
Beginning balance as of January 1,	$(13)	$1	$(2)	$4
Included in earnings	(5)	4	—	4
Included in regulatory assets and liabilities	18	(10)	17	(4)
Settlements	8	(6)	1	(4)
Transfer out of level 3	(24)	(2)	(22)	(2)
Ending balance as of December 31,	$(16)	$(13)	$(6)	$(2)

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Business Acquisitions, by Acquisition

At December 31, 2019 and 2018, Con Edison’s consolidated balance sheet included the following amounts associated with its VIEs:



	Tax Equity Projects
	Great Valley Solar (c)(d)				Copper Mountain - Mesquite Solar (c)(e)				Texas Solar 4 (c)(f)
(Millions of Dollars)	2019		2018		2019		2018		2018
Restricted cash		$—		$—		$—		$—	$4
Non-utility property, less accumulated depreciation (g)(h)	293		313		461		492		98
Other assets	40		18		128		97		9
Total assets (a)	$333		$331		$589		$589		$111
Long-term debt due within one year		$—		$—		$—		$—	$2
Other liabilities	17		17		18		33		26
Long-term debt	—		—		—		—		56
Total liabilities (b)	$17		$17		$18		$33		$84


(a)	The assets of the Tax Equity Projects represent assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE.


(b)	The liabilities of the Tax Equity Projects represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.


(c)	Con Edison did not provide any financial or other support during the year that was not previously contractually required.


(d)	Great Valley Solar consists of the Great Valley Solar 1, Great Valley Solar 2, Great Valley Solar 3 and Great Valley Solar 4 projects, for which the noncontrolling interest of the tax equity investor was $62 million and $33 million at December 31, 2019 and 2018, respectively.


(e)	Copper Mountain - Mesquite Solar consists of the Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 projects for which the noncontrolling interest of the tax equity investor was $126 million and $71 million at December 31, 2019 and 2018, respectively.


(f)	Noncontrolling interest of the third party was $7 million at December 31, 2018.


(g)	Non-utility property is reduced by accumulated depreciation of $9 million for Great Valley Solar and $15 million for Copper Mountain - Mesquite Solar at December 31, 2019.

(h)

Non-utility property is reduced by accumulated depreciation of $1 million for Great Valley Solar, $1 million for Copper Mountain - Mesquite Solar and $15 million for Texas Solar 4 at December 31, 2018.

Summary of VIEs

The following table summarizes the VIEs into which the Clean Energy Businesses have entered as of December 31, 2019:



Project Name	Generating Capacity (a) (MW AC)	Power Purchase Agreement Term in Years	Year of Investment	Location	Maximum Exposure to Loss (Millions of Dollars) (b)
Great Valley Solar (c)	200	15-20	2018	California	$254
Copper Mountain - Mesquite Solar (c)	344	20-25	2018	Nevada and Arizona	445


(a)	Represents ownership interest in the project.


(b)	Maximum exposure is equal to the net assets of the project on the consolidated balance sheet less any applicable noncontrolling interest ($62 million for Great Valley Solar and $126 million for Copper Mountain - Mesquite Solar). Con Edison did not provide any financial or other support during the year that was not previously contractually required.

(c)

For the projects comprising Great Valley Solar and Copper Mountain Mesquite Solar, refer to (d) and (e) in the table above.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Summary of Significant Accounting Policies and Other Matters - Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 12,144	$ 11,928
Total revenues	12,574	12,337	$ 12,033
CECONY
Disaggregation of Revenue [Line Items]
Total revenues	10,821	10,680	10,468
Operating segment \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	646	424
Total revenues	857	763	694
Operating segment \| Con Edison Transmission
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4	4
Total revenues	4	4	2
Operating segment \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10,620	10,597
Total revenues	10,821	10,680	10,468
Operating segment \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	874	903
Total revenues	893	891	874
Operating segment \| Electric \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,913	7,920
Total revenues	8,062	7,971	7,972
Operating segment \| Electric \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	627	647
Total revenues	634	642	642
Operating segment \| Gas \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,097	2,052
Total revenues	2,132	2,078	1,901
Operating segment \| Gas \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	247	256
Total revenues	259	249	232
Operating segment \| Steam \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	610	625
Total revenues	627	631	595
Operating segment \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	575	329
Total revenues	575	329
Operating segment \| Energy services \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	71	95
Total revenues	71	95
Operating segment \| Other \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Total revenues	211	339
Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Total revenues	(1)	(1)	(5)
Other \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	0	0	$ 0
Other
Disaggregation of Revenue [Line Items]
Total revenues	430	409
Other \| Operating segment \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	211	339
Other \| Operating segment \| Con Edison Transmission
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Other \| Operating segment \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	201	83
Other \| Operating segment \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	19	(12)
Other \| Operating segment \| Electric \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	149	51
Other \| Operating segment \| Electric \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	7	(5)
Other \| Operating segment \| Gas \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	35	26
Other \| Operating segment \| Gas \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	12	(7)
Other \| Operating segment \| Steam \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	17	6
Other \| Operating segment \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Other \| Operating segment \| Energy services \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Other \| Operating segment \| Other \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	211	339
Other \| Other
Disaggregation of Revenue [Line Items]
Total revenues	(1)	(1)
Engineering, procurement and construction \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 14	$ 103

Summary of Significant Accounting Policies and Other Matters - Change in Unbilled Contract and Unearned Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Unbilled contract revenue
Beginning balance	$ 29	$ 58
Additions	86	144
Subtractions	86	173
Ending balance	29	29
Unearned revenue
Beginning balance	20	87
Additions	1	38
Subtractions	4	105
Ending balance	$ 17	$ 20
Contracts with customer, revenue recognized, amount outstanding end of last period			$ 4	$ 50

Summary of Significant Accounting Policies and Other Matters - Plant and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated amortization	$ 126	$ 29
Annual aggregate depreciation allowance	1,417
Software Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Gross asset	93	100
Estimated aggregate annual amortization expense	7
Accumulated amortization	$ 10	$ 3
Non-Utility Plant \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	10 years
CECONY
Public Utility, Property, Plant and Equipment [Line Items]
AFUDC rates (percent)	5.10%	5.40%	5.50%
Average depreciation rates (percent)	3.20%	3.10%	3.10%
Annual aggregate depreciation allowance	$ 1,332
CECONY \| Software Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Gross asset	88	$ 95
Estimated aggregate annual amortization expense	7
Accumulated amortization	$ 0	$ 3
CECONY \| Electric \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
CECONY \| Electric \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	95 years
CECONY \| Gas \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
CECONY \| Gas \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	90 years
CECONY \| Steam \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
CECONY \| Steam \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	80 years
CECONY \| General Plant \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
CECONY \| General Plant \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	55 years
O&R
Public Utility, Property, Plant and Equipment [Line Items]
AFUDC rates (percent)	5.30%	2.20%	2.50%
Average depreciation rates (percent)	3.00%	2.90%	2.90%
O&R \| Electric \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
O&R \| Electric \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	75 years
O&R \| Gas \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
O&R \| Gas \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	75 years
O&R \| General Plant \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	5 years
O&R \| General Plant \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)	50 years

Summary of Significant Accounting Policies and Other Matters - Capitalized Cost of Utility Plant (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 3,562	$ 3,331
Held for future use	75	76
Construction work in progress	1,937	1,978
NET UTILITY PLANT	39,751	37,580
Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	591	593
Electric Transmission
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	3,634	3,333
Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	20,676	19,750
General
Public Utility, Property, Plant and Equipment [Line Items]
General	43	0
Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	8,617	7,714
Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,813	1,830
General
Public Utility, Property, Plant and Equipment [Line Items]
General	2,365	2,306
CECONY
Public Utility, Property, Plant and Equipment [Line Items]
General	3,271	3,056
Held for future use	67	67
Construction work in progress	1,812	1,850
NET UTILITY PLANT	37,412	35,370
CECONY \| Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	591	592
CECONY \| Electric Transmission
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	3,380	3,106
CECONY \| Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	19,602	18,716
CECONY \| General
Public Utility, Property, Plant and Equipment [Line Items]
General	43	0
CECONY \| Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	7,961	7,107
CECONY \| Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,813	1,830
CECONY \| General
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 2,143	$ 2,102

Summary of Significant Accounting Policies and Other Matters - Long-Lived and Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Finite-Lived Intangible Assets [Line Items]
Accumulated amortization	$ 126,000,000	$ 29,000,000
Amortization of intangible assets	99,000,000	14,000,000	$ 9,000,000
Amortization expense, 2020	100,000,000
Amortization expense, 2021	105,000,000
Amortization expense, 2022	105,000,000
Amortization expense, 2023	105,000,000
Amortization expense, 2024	105,000,000
Asset impairment	2,000,000
Impairment charges on long-lived assets		0	0
Impairment charges on intangible assets		0	$ 0
Net non-utility plant	43,889,000,000	41,749,000,000
Intangible assets	1,557,000,000	1,654,000,000
Long-term debt	19,973,000,000	18,145,000,000
PG&E Project
Finite-Lived Intangible Assets [Line Items]
Net non-utility plant	819,000,000	885,000,000
Intangible assets	1,057,000,000	1,125,000,000
Long-term debt	$ 1,001,000,000	1,050,000,000
PG&E Project \| Con Edison Development
Finite-Lived Intangible Assets [Line Items]
Aggregate power to be sold (in MW) \| MW	680
PG&E Project \| Secured Related to Project Debt
Finite-Lived Intangible Assets [Line Items]
Net non-utility plant	$ 282,000,000	292,000,000
Other Intangible Assets
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	3,000,000
Accumulated amortization		7,000,000
Power Purchase Agreements
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	1,554,000,000	1,651,000,000
Accumulated amortization	$ 119,000,000	$ 22,000,000

Summary of Significant Accounting Policies and Other Matters - Investments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Supplemental retirement income plan assets	$ 397	$ 326
Deferred income plan assets	81	75
Other	2	2
Total investments	2,065	1,766
CET \| Stagecoach Gas Services, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	924	948
CET \| Mountain Valley Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	602	363
CET \| New York Transco, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	59	52
CECONY
Schedule of Equity Method Investments [Line Items]
Supplemental retirement income plan assets	371	301
Deferred income plan assets	81	75
Other	9	9
Total investments	461	385
CECONY \| CET \| Stagecoach Gas Services, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	0	0
CECONY \| CET \| Mountain Valley Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	0	0
CECONY \| CET \| New York Transco, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 0	$ 0

Summary of Significant Accounting Policies and Other Matters - Earnings Per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Net income	$ 1,343	$ 1,382	$ 1,525
Weighted average common shares outstanding – basic (in shares)	328.5	311.7	307.1
Add: Incremental shares attributable to effect of potentially dilutive securities (in shares)	1.0	1.2	1.7
Adjusted weighted average common shares outstanding – diluted (in shares)	329.5	312.9	308.8
Net income per common share — basic (in dollars per share)	$ 4.09	$ 4.43	$ 4.97
Net income per common share — diluted (in dollars per share)	$ 4.08	$ 4.42	$ 4.94

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

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-Name Accounting Standards Codification
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+ Details

- Definition

The amount of net income (loss) for the period available to each share of common stock or common unit outstanding during the reporting period and to each share or unit that would have been outstanding assuming the issuance of common shares or units for all dilutive potential common shares or units outstanding during the reporting period.

+ References

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Summary of Significant Accounting Policies and Other Matters - Changes in Accumulated Other Comprehensive Income/(Loss) by Component (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	$ 16,839	$ 15,425	$ 14,306
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(3)	10	1
BALANCE AS OF END OF PERIOD	18,213	16,839	15,425
Accumulated OCI
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	(16)	(26)	(27)
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(3)	10	1
BALANCE AS OF END OF PERIOD	(19)	(16)	(26)
Pension Plan Liabilities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
OCI before reclassifications, net of tax	(10)	4	(4)
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax	7	6	5
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(3)	10	1
OCI before reclassifications, tax	(6)	3	3
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax	(2)	(2)	(3)
CECONY
AOCI Attributable to Parent, Net of Tax [Roll Forward]
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(1)	1	1
CECONY \| Accumulated OCI
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	(5)	(6)	(7)
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(1)	1	1
BALANCE AS OF END OF PERIOD	(6)	(5)	(6)
CECONY \| Pension Plan Liabilities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
OCI before reclassifications, net of tax	(3)	0	0
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax	2	1	1
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	(1)	$ 1	1
OCI before reclassifications, tax	$ (1)		1
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax			$ (1)

Summary of Significant Accounting Policies and Other Matters - Reconciliation of Cash, Temporary Investments and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash and Cash Equivalents [Line Items]
Cash and temporary cash investments	$ 981	$ 895
Restricted cash	236	111
Total cash, temporary cash investments and restricted cash	1,217	1,006	$ 844	$ 830
CECONY
Cash and Cash Equivalents [Line Items]
Cash and temporary cash investments	933	818
Restricted cash	0	0
Total cash, temporary cash investments and restricted cash	933	818	$ 730	$ 704
Con Edison Development
Cash and Cash Equivalents [Line Items]
Restricted cash	$ 236	109
RECO \| Transition Bond
Cash and Cash Equivalents [Line Items]
Restricted cash		$ 2

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Electric) (Details) - USD ($)	1 Months Ended	12 Months Ended			36 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2022	Dec. 31, 2019	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Revenues		$ 12,574,000,000	$ 12,337,000,000	$ 12,033,000,000
Deferred revenues		17,000,000	20,000,000	87,000,000		$ 17,000,000
Deferred revenues		$ (599,000,000)	(514,000,000)			$ (599,000,000)
NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues		15.00%				15.00%
Maximum \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues		15.00%				15.00%
Percentage of debt to total consolidated debt		20.00%
CECONY
Public Utilities, General Disclosures [Line Items]
Revenues		$ 10,821,000,000	10,680,000,000	10,468,000,000
Deferred revenues		(477,000,000)	(392,000,000)			$ (477,000,000)
CECONY \| Electric
Public Utilities, General Disclosures [Line Items]
Retention of annual transmission congestion revenues						75,000,000
Actual earnings adjustment mechanism incentives		0	0	0
Other earnings incentives		0	0	0
Deferred revenues		69,000,000	(6,000,000)	45,000,000		69,000,000
Negative revenue adjustments		15,000,000	0	0
Cost reconciliation, deferred net regulatory liabilities		10,000,000	189,000,000	35,000,000		10,000,000
Deferred regulatory asset (liability)		(11,800,000)	(400,000)	400,000		$ (11,800,000)
Earnings sharing, threshold limit		$ 0	0
Earnings sharing, positive adjustment				$ 5,700,000
Common equity ratio (percent)						48.00%
Increase in gas base rate due to expiration of temporary credit under the prior rate plan	$ 48,000,000
Recovery or refund of energy costs, deferral period						10 years
Deferrals for property taxes limitation from rates (percent)							90.00%
Recovery deferral (percent)		80.00%				80.00%
Maximum deferral (percent)		30.00%				30.00%
CECONY \| Electric \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 199,000,000				$ 199,000,000
CECONY \| Electric \| Service Termination
Public Utilities, General Disclosures [Line Items]
Revenues		0	$ 0
CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Retention of annual transmission congestion revenues					$ 75,000,000
Authorized return on common equity (percent)					8.80%
Earnings sharing (percent)					9.30%
Common equity ratio (percent)					48.00%
Maximum deferral (percent)					15.00%
Income tax benefit to be credited to customers resulting from TCJA					$ 377,000,000
CECONY \| Electric \| Scenario, Forecast \| Deferred Project Costs
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities					238,000,000
CECONY \| Electric \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 195,000,000				195,000,000
Amortization to income of net regulatory (assets) and liabilities						84,000,000
Potential earnings adjustment mechanism incentives						0
Average rate base						$ 18,902,000,000
Weighted average cost of capital (after-tax) (percent)						6.82%
Authorized return on common equity (percent)						9.00%
Actual return on common equity (percent)						9.30%
Earnings sharing (percent)		9.50%				9.50%
Cost of long-term debt (percent)		4.93%				4.93%
Recovery of energy efficiency and savings program costs						$ 20,500,000
Deferral, annual maximum (not more than) (percent)							10.00%
CECONY \| Electric \| Year 1 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						21,689,000,000
CECONY \| Electric \| Year 1 \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						126,000,000
CECONY \| Electric \| Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						376,000,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					113,000,000
Amortization to income of net regulatory (assets) and liabilities					267,000,000
Potential earnings adjustment mechanism incentives					69,000,000
Potential penalties (annually)					450,000,000
Average rate base					$ 21,660,000,000
Weighted average cost of capital (after-tax) (percent)					6.82%
Cost of long-term debt (percent)					4.63%
Amount of cost recovery					$ 206,000,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					24,491,000,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					572,000,000
CECONY \| Electric \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 155,000,000				155,000,000
Amortization to income of net regulatory (assets) and liabilities						83,000,000
Potential earnings adjustment mechanism incentives						0
Average rate base						$ 19,530,000,000
Weighted average cost of capital (after-tax) (percent)						6.80%
Actual return on common equity (percent)						9.36%
Cost of long-term debt (percent)		4.88%				4.88%
Recovery of energy efficiency and savings program costs						$ 49,000,000
Deferral, annual maximum (not more than) (percent)							0.075%
CECONY \| Electric \| Year 2 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						22,338,000,000
CECONY \| Electric \| Year 2 \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						257,000,000
CECONY \| Electric \| Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						341,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					370,000,000
Amortization to income of net regulatory (assets) and liabilities					269,000,000
Potential earnings adjustment mechanism incentives					74,000,000
Potential penalties (annually)					461,000,000
Average rate base					22,783,000,000
Amount of cost recovery					245,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					25,092,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					740,000,000
CECONY \| Electric \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes		$ 155,000,000				155,000,000
Amortization to income of net regulatory (assets) and liabilities						69,000,000
Potential earnings adjustment mechanism incentives						0
Average rate base						$ 20,277,000,000
Weighted average cost of capital (after-tax) (percent)						6.73%
Actual return on common equity (percent)						8.82%
Cost of long-term debt (percent)		4.74%				4.74%
Recovery of energy efficiency and savings program costs						$ 107,500,000
Deferral, annual maximum (not more than) (percent)							0.05%
CECONY \| Electric \| Year 3 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						23,002,000,000
CECONY \| Electric \| Year 3 \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						415,000,000
CECONY \| Electric \| Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						$ 352,000,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					326,000,000
Amortization to income of net regulatory (assets) and liabilities					272,000,000
Potential earnings adjustment mechanism incentives					79,000,000
Potential penalties (annually)					476,000,000
Average rate base					23,926,000,000
Amount of cost recovery					251,000,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					25,708,000,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					806,000,000
Annually \| CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA					126,000,000
Annually \| CECONY \| Electric \| Scenario, Forecast \| Deferred Project Costs
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities					48,000,000
Protected Portion \| CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					(1,663,000,000)
Protected Portion \| CECONY \| Electric \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					(49,000,000)
Protected Portion \| CECONY \| Electric \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					(50,000,000)
Protected Portion \| CECONY \| Electric \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					(53,000,000)
Unprotected Portion \| CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					$ (784,000,000)
TCJA of 2017 regulatory liabilities, income tax benefit, amortization period					5 years
Unprotected Portion \| Annually \| CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					$ (157,000,000)

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Gas) (Details) - USD ($)	1 Months Ended	12 Months Ended			36 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2022	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Revenues		$ 12,574,000,000	$ 12,337,000,000	$ 12,033,000,000
Deferred revenues		17,000,000	20,000,000	87,000,000		$ 17,000,000
CECONY
Public Utilities, General Disclosures [Line Items]
Revenues		10,821,000,000	10,680,000,000	10,468,000,000
CECONY \| Gas
Public Utilities, General Disclosures [Line Items]
Percentage of revenue reserve						15.00%
Other earnings incentives		7,000,000	6,000,000	7,000,000
Deferred revenues		10,000,000	12,000,000	3,000,000		$ 10,000,000
Negative revenue adjustments		10,000,000	4,000,000	5,000,000
Cost reconciliation, deferred net regulatory liabilities		18,000,000	44,000,000	2,000,000		18,000,000
Deferred regulatory asset (liability)		$ (1,700,000)	(2,200,000)	(2,200,000)		$ (1,700,000)
Earnings sharing (percent)		9.50%				9.50%
Earnings sharing, threshold limit		$ 0	0	$ 0
Common equity ratio (percent)						48.00%
Increase in gas base rate due to expiration of temporary credit under the prior rate plan	$ 41,000,000
CECONY \| Gas \| Maximum
Public Utilities, General Disclosures [Line Items]
Amount of revenues retained		65,000,000				$ 65,000,000
CECONY \| Gas \| Gas Leak Backlog, Leak Prone Pipe and Service Terminations
Public Utilities, General Disclosures [Line Items]
Revenues		$ 9,000,000	$ 0
CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Percentage of revenue reserve					15.00%
Earnings sharing (percent)					9.30%
Common equity ratio (percent)					48.00%
Income tax benefit to be credited to customers resulting from TCJA					$ 63,000,000
CECONY \| Gas \| Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Amount of revenues retained					65,000,000
CECONY \| Gas \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes						(5,000,000)
Amortization to income of net regulatory (assets) and liabilities						39,000,000
Potential incentives if performance targets are met						7,000,000
Potential penalties (annually)						68,000,000
Average rate base						$ 4,841,000,000
Weighted average cost of capital (after-tax) (percent)						6.82%
Authorized return on common equity (percent)						9.00%
Actual return on common equity (percent)						9.22%
Cost of long-term debt (percent)		4.93%				4.93%
CECONY \| Gas \| Year 1 \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 5,844,000,000
CECONY \| Gas \| Year 1 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						27,000,000
CECONY \| Gas \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					84,000,000
Amortization to income of net regulatory (assets) and liabilities					39,000,000
Potential incentives if performance targets are met					20,000,000
Potential penalties (annually)					81,000,000
Average rate base					$ 7,171,000,000
Weighted average cost of capital (after-tax) (percent)					6.61%
Authorized return on common equity (percent)					8.80%
Cost of long-term debt (percent)					4.63%
CECONY \| Gas \| Year 1 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					$ 8,108,000,000
CECONY \| Gas \| Year 1 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					142,000,000
CECONY \| Gas \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes						92,000,000
Amortization to income of net regulatory (assets) and liabilities						37,000,000
Potential incentives if performance targets are met						8,000,000
Potential penalties (annually)						63,000,000
Average rate base						$ 5,395,000,000
Weighted average cost of capital (after-tax) (percent)						6.80%
Actual return on common equity (percent)						9.04%
Cost of long-term debt (percent)		4.88%				4.88%
CECONY \| Gas \| Year 2 \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 6,512,000,000
CECONY \| Gas \| Year 2 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						57,000,000
CECONY \| Gas \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					122,000,000
Amortization to income of net regulatory (assets) and liabilities					37,000,000
Potential incentives if performance targets are met					22,000,000
Potential penalties (annually)					88,000,000
Average rate base					7,911,000,000
CECONY \| Gas \| Year 2 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					8,808,000,000
CECONY \| Gas \| Year 2 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					183,000,000
CECONY \| Gas \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes						90,000,000
Amortization to income of net regulatory (assets) and liabilities						36,000,000
Potential incentives if performance targets are met						8,000,000
Potential penalties (annually)						70,000,000
Average rate base						$ 6,005,000,000
Weighted average cost of capital (after-tax) (percent)						6.73%
Actual return on common equity (percent)						8.72%
Cost of long-term debt (percent)		4.74%				4.74%
CECONY \| Gas \| Year 3 \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 7,177,000,000
CECONY \| Gas \| Year 3 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						$ 100,000,000
CECONY \| Gas \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes					167,000,000
Amortization to income of net regulatory (assets) and liabilities					36,000,000
Potential incentives if performance targets are met					25,000,000
Potential penalties (annually)					96,000,000
Average rate base					8,622,000,000
CECONY \| Gas \| Year 3 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					9,510,000,000
CECONY \| Gas \| Year 3 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations					211,000,000
NYSPSC \| CECONY \| Gas \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount					47,000,000
Amount of cost recovery					30,000,000
NYSPSC \| CECONY \| Gas \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount					176,000,000
Amount of cost recovery					37,000,000
NYSPSC \| CECONY \| Gas \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount					170,000,000
Amount of cost recovery					40,000,000
Annually \| CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA					32,000,000
Protected Portion \| CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					725,000,000
Protected Portion \| CECONY \| Gas \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					14,000,000
Protected Portion \| CECONY \| Gas \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					14,000,000
Protected Portion \| CECONY \| Gas \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					12,000,000
Unprotected Portion \| CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					$ 107,000,000
TCJA of 2017 regulatory liabilities, income tax benefit, amortization period					5 years
Unprotected Portion \| Annually \| CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA					$ 21,000,000

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Steam) (Details) - CECONY - Steam - USD ($)	12 Months Ended						36 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities							$ 37,000,000
Regulatory liabilities, amortization period							3 years
Negative revenue adjustments	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Cost reconciliation, deferred net regulatory liabilities			14,000,000	$ 8,000,000		42,000,000	$ 8,000,000
Cost reconciliation, deferred net regulatory assets	1,000,000	1,000,000			17,000,000
Increase (decrease) in regulatory liabilities	0	0	0			(100,000)
Authorized return on common equity (percent)							9.30%
Earnings sharing (percent)				9.90%			9.90%
Earnings sharing, threshold limit	$ 5,000,000	16,500,000	8,500,000	$ 7,800,000	$ 11,500,000	$ 0
Earnings sharing, positive adjustment		$ 2,300,000	$ 1,100,000	4,000,000
Common equity ratio (percent)							48.00%
Other regulatory liabilities				$ 8,000,000			$ 8,000,000
Difference in property taxes (percent)							90.00%
Deferral, annual maximum (not more than) (percent)							10.00%
Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ (22,400,000)
Average rate base							$ 1,511,000,000
Weighted average cost of capital (after-tax) (percent)							7.10%
Actual return on common equity (percent)							9.82%
Cost of long-term debt (percent)				5.17%			5.17%
Year 1 \| Production
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,752,000,000
Year 1 \| Distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							6,000,000
Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							1,000,000
Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes							19,800,000
Average rate base							$ 1,547,000,000
Weighted average cost of capital (after-tax) (percent)							7.13%
Actual return on common equity (percent)							10.88%
Cost of long-term debt (percent)				5.23%			5.23%
Year 2 \| Production
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,732,000,000
Year 2 \| Distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							11,000,000
Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							1,000,000
Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes							20,300,000
Average rate base							$ 1,604,000,000
Weighted average cost of capital (after-tax) (percent)							7.21%
Actual return on common equity (percent)							10.54%
Cost of long-term debt (percent)				5.39%			5.39%
Year 3 \| Production
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,720,000,000
Year 3 \| Distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							25,000,000
Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							1,000,000
Year 4
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 0
Actual return on common equity (percent)							9.51%
Year 5
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 0
Actual return on common equity (percent)							11.73%
Year 6
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 0
Actual return on common equity (percent)							10.45%

Regulatory Matters - Summary of Utilities Rate Plans (O&R New York-Electric) (Details) - USD ($)	12 Months Ended					24 Months Ended	36 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 31, 2017	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Deferred revenues	$ 17,000,000	$ 20,000,000	$ 87,000,000
Deferred revenues	$ 599,000,000	514,000,000
NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues	15.00%
Percentage of debt to total consolidated debt	20.00%
Maximum \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues	15.00%
O&R \| Electric
Public Utilities, General Disclosures [Line Items]
Deferred revenues				$ 6,300,000	$ 0
Deferred revenues		500,000	11,200,000
Negative revenue adjustments		0	0	0	1,250,000
Deferral of net increase (decrease) to regulatory assets		5,000,000	3,200,000	7,400,000	300,000
Net utility plant reconciliations		$ 1,400,000	(1,900,000)	(1,900,000)	$ 2,200,000
Authorized return on common equity (percent)						9.00%
Earnings sharing (percent)						9.60%
Earnings sharing, threshold limit			$ 300,000	$ 6,100,000
Common equity ratio (percent)						48.00%
Deferred storm and property reserve deficiency, noncurrent						$ 59,300,000
Deferred storm and property reserve deficiency, recovery period						5 years
Deferred storm and property reserve deficiency not recovered						$ 1,000,000
O&R \| Electric \| Property Tax and Interest Rate Reconciliations
Public Utilities, General Disclosures [Line Items]
Regulatory assets not recoverable						4,000,000
O&R \| Electric \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes						9,300,000
Amortization to income of net regulatory assets						(8,500,000)
Net utility plant reconciliations						928,000,000
Average rate base						$ 763,000,000
Weighted average cost of capital (after-tax) (percent)						7.10%
Actual return on common equity (percent)						10.80%
Cost of long-term debt (percent)						5.42%
Deferred storm and property reserve deficiency, noncurrent						$ 11,850,000
Rate exclusion amount with balance below regulatory threshold						1,000,000
O&R \| Electric \| Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						4,000,000
O&R \| Electric \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes						8,800,000
Amortization to income of net regulatory assets						(9,400,000)
Net utility plant reconciliations						970,000,000
Average rate base						$ 805,000,000
Weighted average cost of capital (after-tax) (percent)						7.06%
Actual return on common equity (percent)						9.70%
Cost of long-term debt (percent)						5.35%
Deferred storm and property reserve deficiency, noncurrent						$ 11,850,000
Rate exclusion amount with balance below regulatory threshold						9,000,000
O&R \| Electric \| Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						4,000,000
O&R \| Electric \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes						0
Amortization to income of net regulatory assets						0
Average rate base						$ 805,000,000
Weighted average cost of capital (after-tax) (percent)						7.06%
Actual return on common equity (percent)						7.20%
Cost of long-term debt (percent)						5.35%
O&R \| Electric \| Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						$ 4,000,000
O&R \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Authorized return on common equity (percent)							9.00%
Earnings sharing (percent)							9.60%
Common equity ratio (percent)							48.00%
Deferrals for property taxes limitation from rates (percent)							90.00%
O&R \| Electric \| Scenario, Forecast \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 13,400,000
Amortization to income of net regulatory assets							(1,500,000)
Potential earnings adjustment mechanism incentives							3,600,000
Potential incentive if target is met, related to service terminations							500,000
Average rate base							$ 878,000,000
Weighted average cost of capital (after-tax) (percent)							6.97%
Cost of long-term debt (percent)							5.17%
Requested rate increase (decrease), amount							$ 8,600,000
Deferral, annual maximum (not more than) (percent)							10.00%
O&R \| Electric \| Scenario, Forecast \| Year 1 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,008,000,000
O&R \| Electric \| Scenario, Forecast \| Year 1 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							48,000,000
O&R \| Electric \| Scenario, Forecast \| Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							4,400,000
O&R \| Electric \| Scenario, Forecast \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes							8,000,000
Amortization to income of net regulatory assets							(1,500,000)
Potential earnings adjustment mechanism incentives							4,000,000
Potential incentive if target is met, related to service terminations							500,000
Average rate base							$ 906,000,000
Weighted average cost of capital (after-tax) (percent)							6.96%
Cost of long-term debt (percent)							5.14%
Requested rate increase (decrease), amount							$ 12,100,000
Deferral, annual maximum (not more than) (percent)							7.50%
O&R \| Electric \| Scenario, Forecast \| Year 2 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,032,000,000
O&R \| Electric \| Scenario, Forecast \| Year 2 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							58,000,000
O&R \| Electric \| Scenario, Forecast \| Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							4,400,000
O&R \| Electric \| Scenario, Forecast \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes							5,800,000
Amortization to income of net regulatory assets							(1,500,000)
Potential earnings adjustment mechanism incentives							4,200,000
Potential incentive if target is met, related to service terminations							500,000
Average rate base							$ 948,000,000
Weighted average cost of capital (after-tax) (percent)							6.96%
Cost of long-term debt (percent)							5.14%
Requested rate increase (decrease), amount							$ 12,200,000
Deferral, annual maximum (not more than) (percent)							5.00%
O&R \| Electric \| Scenario, Forecast \| Year 3 \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 1,083,000,000
O&R \| Electric \| Scenario, Forecast \| Year 3 \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							61,000,000
O&R \| Electric \| Scenario, Forecast \| Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							$ 4,500,000
Energy Efficiency \| O&R \| Electric
Public Utilities, General Disclosures [Line Items]
Actual earnings adjustment mechanism incentives	$ 2,600,000
Service Termination \| O&R \| Electric
Public Utilities, General Disclosures [Line Items]
Actual earnings adjustment mechanism incentives	$ 200,000

Regulatory Matters - Summary of Utilities Rate Plans (O&R New York-Gas) (Details) - USD ($)	12 Months Ended					36 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2021	Oct. 31, 2018
Public Utilities, General Disclosures [Line Items]
Deferred revenues	$ 599,000,000	$ 514,000,000
Deferred revenues	$ 17,000,000	20,000,000	$ 87,000,000
NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues	15.00%
Percentage of debt to total consolidated debt	20.00%
Maximum \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues	15.00%
O&R \| Gas
Public Utilities, General Disclosures [Line Items]
Deferred revenues					$ 800,000
Deferred revenues		6,300,000	1,700,000	$ 6,200,000
Negative revenue adjustments	$ 200,000	100,000	0	0	0
Cost reconciliation, deferred net regulatory liabilities		7,400,000	3,500,000		4,500,000
Cost reconciliation, deferred net regulatory assets				6,600,000
Deferred regulatory asset (liability)		$ (400,000)			$ 0
Authorized return on common equity (percent)							9.00%
Earnings sharing (percent)							9.60%
Earnings sharing, threshold limit			$ 200,000	$ 4,000,000
Common equity ratio (percent)							48.00%
O&R \| Gas \| Property Tax and Interest Rate Reconciliations
Public Utilities, General Disclosures [Line Items]
Regulatory assets not recoverable							$ 14,000,000
O&R \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Amount of revenues retained						$ 4,000,000
Share in variances in annual revenue retained (percent)						20.00%
Potential earnings adjustment mechanism incentives						$ 300,000
Authorized return on common equity (percent)						9.00%
Earnings sharing (percent)						9.60%
Common equity ratio (percent)						48.00%
O&R \| Gas \| Scenario, Forecast \| Customers
Public Utilities, General Disclosures [Line Items]
Share in variances in annual revenue retained (percent)						80.00%
O&R \| Gas \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes							16,400,000
Amortization to income of net regulatory assets							1,700,000
Net utility plant reconciliations							492,000,000
Average rate base							$ 366,000,000
Weighted average cost of capital (after-tax) (percent)							7.10%
Actual return on common equity (percent)							11.20%
Cost of long-term debt (percent)							5.42%
Rate exclusion amount with balance below regulatory threshold							$ 500,000
O&R \| Gas \| Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							3,700,000
O&R \| Gas \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						$ (7,500,000)
Amortization to income of net regulatory assets						1,800,000
Potential earnings adjustment mechanism incentives						1,200,000
Net utility plant reconciliations						593,000,000
Average rate base						$ 454,000,000
Weighted average cost of capital (after-tax) (percent)						6.97%
Cost of long-term debt (percent)						5.17%
Requested rate increase (decrease), amount						$ (5,900,000)
O&R \| Gas \| Year 1 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						20,000,000
O&R \| Gas \| Year 1 \| Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						5,500,000
O&R \| Gas \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes							16,400,000
Amortization to income of net regulatory assets							2,100,000
Net utility plant reconciliations							518,000,000
Average rate base							$ 391,000,000
Weighted average cost of capital (after-tax) (percent)							7.06%
Actual return on common equity (percent)							9.70%
Cost of long-term debt (percent)							5.35%
Rate exclusion amount with balance below regulatory threshold							$ 4,200,000
O&R \| Gas \| Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							4,700,000
O&R \| Gas \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						3,600,000
Amortization to income of net regulatory assets						1,800,000
Potential earnings adjustment mechanism incentives						1,300,000
Net utility plant reconciliations						611,000,000
Average rate base						$ 476,000,000
Weighted average cost of capital (after-tax) (percent)						6.96%
Cost of long-term debt (percent)						5.14%
Requested rate increase (decrease), amount						$ 1,000,000.0
O&R \| Gas \| Year 2 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						24,000,000
O&R \| Gas \| Year 2 \| Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						5,700,000
O&R \| Gas \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes							5,800,000
Base rate change through surcharge							10,600,000
Amortization to income of net regulatory assets							2,500,000
Net utility plant reconciliations							546,000,000
Average rate base							$ 417,000,000
Weighted average cost of capital (after-tax) (percent)							7.06%
Actual return on common equity (percent)							8.00%
Cost of long-term debt (percent)							5.35%
Rate exclusion amount with balance below regulatory threshold							$ 7,200,000
O&R \| Gas \| Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)							$ 4,900,000
O&R \| Gas \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes						700,000
Amortization to income of net regulatory assets						1,800,000
Potential earnings adjustment mechanism incentives						1,300,000
Net utility plant reconciliations						632,000,000
Average rate base						$ 498,000,000
Weighted average cost of capital (after-tax) (percent)						6.96%
Cost of long-term debt (percent)						5.14%
Requested rate increase (decrease), amount						$ 1,000,000.0
O&R \| Gas \| Year 3 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations						25,000,000
O&R \| Gas \| Year 3 \| Scenario, Forecast \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)						$ 6,000,000
Energy Efficiency \| O&R \| Gas
Public Utilities, General Disclosures [Line Items]
Actual earnings adjustment mechanism incentives	300,000
Service Termination \| O&R \| Gas
Public Utilities, General Disclosures [Line Items]
Actual earnings adjustment mechanism incentives	$ 700,000

Regulatory Matters - Summary of Utilities Rate Plans (RECO) (Details) - RECO - USD ($) $ in Millions	1 Months Ended		35 Months Ended
	Feb. 29, 2020	Jan. 31, 2016	Jan. 31, 2020
Electric
Public Utilities, General Disclosures [Line Items]
Plan electric system storm hardening amount		$ 15.7
Plan period (years)		3 years
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities			$ 0.2
Regulatory liabilities, amortization period			3 years
Amortization to income of net regulatory assets	$ 4.8		$ 25.6
Regulatory assets, amortization period	4 years		4 years
Average rate base	$ 229.9		$ 178.7
Weighted average cost of capital (after-tax) (percent)	7.11%		7.47%
Authorized return on common equity (percent)	9.50%		9.60%
Cost of long-term debt (percent)	4.88%		5.37%
Common equity ratio (percent)	48.32%		49.70%
Scenario, Forecast \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ 12.0		$ 1.7
Actual return on common equity (percent)			7.50%
Scenario, Forecast \| Year 2
Public Utilities, General Disclosures [Line Items]
Actual return on common equity (percent)			5.70%

Regulatory Matters - Additional Information (Details) customer in Thousands, $ in Millions		1 Months Ended			3 Months Ended	9 Months Ended		12 Months Ended			36 Months Ended
	Jul. 13, 2019 USD ($) customer	Jan. 31, 2019	Mar. 31, 2018 customer	Apr. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2017	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2022 USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory assets								$ 4,987.0	$ 4,370.0
Regulatory liabilities								4,827.0	4,641.0
Future Income Tax
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA									54.0	$ 3,713.0
Regulatory liabilities								2,426.0	2,515.0
Net Unbilled Revenue Deferrals
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities								199.0	117.0
RECO \| Electric \| Hurricane
Public Utilities, General Disclosures [Line Items]
Number of customers affected with interrupted service \| customer			44
Restoration costs								17.0
RECO \| FERC
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount				$ 17.7	$ 11.8
Return on common equity (percent)							10.00%
CECONY
Public Utilities, General Disclosures [Line Items]
Regulatory assets								4,600.0	3,987.0
Regulatory liabilities								4,427.0	4,258.0
CECONY \| Future Income Tax
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA									49.0	$ 3,513.0
Regulatory liabilities								2,275.0	2,363.0
CECONY \| Net Unbilled Revenue Deferrals
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities								199.0	$ 117.0
CECONY \| Electric \| Hurricane
Public Utilities, General Disclosures [Line Items]
Number of customers affected with interrupted service \| customer			209
Restoration costs								134.0
Operation and maintenance expenses								15.0
Operation and maintenance expenses charged against a storm reserve								84.0
Capital expenditures								29.0
Removal costs								6.0
CECONY \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											3 years
Income tax benefit to be credited to customers resulting from TCJA											$ 377.0
CECONY \| Electric \| Scenario, Forecast \| Protected Portion
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA											$ 1,663.0
CECONY \| Electric \| Scenario, Forecast \| Unprotected Portion
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											5 years
Increase in regulatory liability resulting from TCJA											$ 784.0
CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											2 years
Income tax benefit to be credited to customers resulting from TCJA											$ 63.0
CECONY \| Gas \| Scenario, Forecast \| Protected Portion
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA											$ 725.0
CECONY \| Gas \| Scenario, Forecast \| Unprotected Portion
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											5 years
Increase in regulatory liability resulting from TCJA											$ 107.0
CECONY \| NYSPSC \| Steam
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period						3 years
Income tax benefit to be credited to customers resulting from TCJA						$ 15.0		185.0
CECONY \| NYSPSC \| Electric
Public Utilities, General Disclosures [Line Items]
Proposed EAM (percent)		1.00%
CECONY \| NYSPSC \| Gas
Public Utilities, General Disclosures [Line Items]
Proposed EAM (percent)		0.70%
O&R \| Electric \| Hurricane
Public Utilities, General Disclosures [Line Items]
Number of customers affected with interrupted service \| customer			93
Restoration costs								43.0
O&R \| Electric and Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											3 years
Income tax benefit to be credited to customers resulting from TCJA											$ 22.0
O&R \| Electric and Gas \| Scenario, Forecast \| Protected Portion
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA											$ 123.0
O&R \| Electric and Gas \| Scenario, Forecast \| Unprotected Portion
Public Utilities, General Disclosures [Line Items]
Tax Cuts And Jobs Act Of 2017, Net Benefit Amortization, Allocation Period											15 years
Increase in regulatory liability resulting from TCJA											$ 30.0
Manhattan \| CECONY \| Electric
Public Utilities, General Disclosures [Line Items]
Number of customers affected with interrupted service \| customer	72
Cumulative catch-up adjustment to revenue, modification of contract	$ (5.0)
Brooklyn \| CECONY \| Electric
Public Utilities, General Disclosures [Line Items]
Cumulative catch-up adjustment to revenue, modification of contract	$ (10.0)
Manhattan Steam Main Rupture \| CECONY \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Property damage, clean up and response costs								17.0
Capital and retirement costs								9.0
Violations Of Gas Operator Qualification, Performance, And Inspection Requirements \| CECONY \| NYSPSC \| Gas
Public Utilities, General Disclosures [Line Items]
Loss contingency accrual								$ 10.0

Regulatory Matters - Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	$ 4,859	$ 4,294
Regulatory assets – current	128	76
Total Regulatory Assets	4,987	4,370
Unrecognized pension and other postretirement costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	2,541	2,238
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	732	810
Revenue taxes
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	321	291
MTA power reliability deferral
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	248	229
Property tax reconciliation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	219	101
Deferred storm costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	77	76
Pension and other postretirement benefits deferrals
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	71	73
Municipal infrastructure support costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	75	67
System peak reduction and energy efficiency programs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	131	72
Brooklyn Queens demand management program
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	39	39
Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	28	36
Meadowlands heater odorization project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	35	36
Preferred stock redemption
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	22	23
Recoverable REV demonstration project costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	21	20
Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	83	17
Gate station upgrade project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	19	17
Non-wire alternative projects
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	14	3
Workers’ compensation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	3	5
Recoverable energy costs
Regulatory Assets [Line Items]
Regulatory assets – current	0	40
O&R transition bond charges
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	2
Other
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	180	139
Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – current	128	36
CECONY
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	4,487	3,923
Regulatory assets – current	113	64
Total Regulatory Assets	4,600	3,987
CECONY \| Unrecognized pension and other postretirement costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	2,403	2,111
CECONY \| Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	647	716
CECONY \| Revenue taxes
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	308	278
CECONY \| MTA power reliability deferral
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	248	229
CECONY \| Property tax reconciliation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	210	86
CECONY \| Deferred storm costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	0
CECONY \| Pension and other postretirement benefits deferrals
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	47	56
CECONY \| Municipal infrastructure support costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	75	67
CECONY \| System peak reduction and energy efficiency programs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	130	70
CECONY \| Brooklyn Queens demand management program
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	39	39
CECONY \| Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	26	34
CECONY \| Meadowlands heater odorization project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	35	36
CECONY \| Preferred stock redemption
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	22	23
CECONY \| Recoverable REV demonstration project costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	19	18
CECONY \| Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	76	11
CECONY \| Gate station upgrade project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	19	17
CECONY \| Non-wire alternative projects
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	14	3
CECONY \| Workers’ compensation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	3	5
CECONY \| Recoverable energy costs
Regulatory Assets [Line Items]
Regulatory assets – current	0	35
CECONY \| O&R transition bond charges
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	0
CECONY \| Other
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	166	124
CECONY \| Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – current	$ 113	$ 29

Regulatory Matters - Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	$ 4,827	$ 4,641
Regulatory liabilities—current	102	114
Total Regulatory Liabilities	4,929	4,755
Future income tax
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	2,426	2,515
Allowance for cost of removal less salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	989	928
TCJA net benefits
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	471	434
Energy efficiency portfolio standard unencumbered funds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	122	127
Net unbilled revenue deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	199	117
Net proceeds from sale of property
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	173	6
Pension and other postretirement benefit deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	75	62
Property tax refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	45	45
Settlement of prudence proceeding
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	8	37
Property tax reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	0	36
Earnings sharing - electric, gas and steam
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	22	36
System benefit charge carrying charge
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	48	27
BQDM and REV Demo reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	27	18
Settlement of gas proceedings
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	10	15
Unrecognized other postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	9	7
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	203	231
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	24	53
Refundable energy costs
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	44	31
Deferred derivative gains
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	34	30
CECONY
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	4,427	4,258
Regulatory liabilities—current	63	73
Total Regulatory Liabilities	4,490	4,331
CECONY \| Future income tax
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	2,275	2,363
CECONY \| Allowance for cost of removal less salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	843	790
CECONY \| TCJA net benefits
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	454	411
CECONY \| Energy efficiency portfolio standard unencumbered funds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	118	122
CECONY \| Net unbilled revenue deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	199	117
CECONY \| Net proceeds from sale of property
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	173	6
CECONY \| Pension and other postretirement benefit deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	46	40
CECONY \| Property tax refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	45	45
CECONY \| Settlement of prudence proceeding
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	8	37
CECONY \| Property tax reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	0	36
CECONY \| Earnings sharing - electric, gas and steam
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	15	27
CECONY \| System benefit charge carrying charge
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	44	24
CECONY \| BQDM and REV Demo reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	26	18
CECONY \| Settlement of gas proceedings
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	10	15
CECONY \| Unrecognized other postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	0	7
CECONY \| Other
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	171	200
CECONY \| Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	17	36
CECONY \| Refundable energy costs
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	12	8
CECONY \| Deferred derivative gains
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	$ 34	$ 29

Capitalization - Common Stock (Details) - USD ($) $ in Millions	1 Months Ended				12 Months Ended
	Jan. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 31, 2019	Nov. 30, 2018	Dec. 31, 2016
Schedule of Capitalization [Line Items]
Common stock, shares authorized (in shares)					500,000,000
Common stock, shares outstanding (in shares)				320,960,396	332,629,597	320,960,396
Treasury shares (in shares)					23,210,700
Shares issued (in shares)			5,649,369
Value of shares issued			$ 425		$ 825	$ 705	$ 343
Common Stock
Schedule of Capitalization [Line Items]
Common stock, shares outstanding (in shares)				321,000,000	333,000,000	321,000,000	310,000,000			305,000,000
Treasury shares (in shares)				23,210,700		23,210,700
Shares issued (in shares)				9,324,123	12,000,000	11,000,000	5,000,000
Value of shares issued				$ 705	$ 1		$ 1
Forward Contract
Schedule of Capitalization [Line Items]
Common stock, shares subject to forward sale agreements (in shares)					1,050,000			5,800,000	14,973,492
Forward Contract \| Common Stock
Schedule of Capitalization [Line Items]
Shares issued (in shares)		4,750,000
Value of shares issued		$ 400
CECONY
Schedule of Capitalization [Line Items]
Common stock, shares authorized (in shares)					340,000,000
Common stock, shares outstanding (in shares)					235,488,094
Treasury shares (in shares)					21,976,200
CECONY \| Common Stock
Schedule of Capitalization [Line Items]
Common stock, shares outstanding (in shares)				235,488,094	235,000,000	235,488,094	235,000,000			235,000,000
Subsequent Event \| Forward Contract \| Common Stock
Schedule of Capitalization [Line Items]
Shares issued (in shares)	1,050,000
Value of shares issued	$ 88

Capitalization - Schedule of Long-Term Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
2020	$ 518
2021	1,967
2022	437
2023	316
2024	385
Long-term debt	19,973	$ 18,145
Long-term debt due within one year	1,446	650
CECONY
Debt Instrument [Line Items]
2020	350
2021	640
2023	0
2024	250
Long-term debt	14,964	14,151
Long-term debt due within one year	350	475
PG&E Project
Debt Instrument [Line Items]
Long-term debt	1,001	$ 1,050
Long-term debt due within one year	928
PG&E Project Debt Maturing 2020 \| PG&E Project
Debt Instrument [Line Items]
Long-term debt	$ 73

Capitalization - Long-term Debt, Additional Information (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Non-recourse debt	$ 2,737,000,000	$ 2,076,000,000
Long-term debt	19,973,000,000	18,145,000,000
PG&E Project
Debt Instrument [Line Items]
Long-term debt	1,001,000,000	1,050,000,000
CECONY
Debt Instrument [Line Items]
Long-term debt	14,964,000,000	14,151,000,000
CECONY \| Tax-Exempt Debt
Debt Instrument [Line Items]
Debt instrument, face amount	450,000,000
Long-term debt	$ 450,000,000	$ 450,000,000

Capitalization - Carrying Amounts and Fair Values of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Unamortized debt expense	$ 178	$ 185
Carrying Amount
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	19,973	18,145
Fair Value
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	22,738	18,740
CECONY
Debt Instrument [Line Items]
Unamortized debt discount	151	139
CECONY \| Carrying Amount
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	14,964	14,151
CECONY \| Fair Value
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	$ 17,505	$ 14,685

Capitalization - Significant Debt Covenants (Details)	12 Months Ended
Capitalization - Significant Debt Covenants (Details)	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.51
CECONY
Debt Instrument [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.53
Term Loan
Debt Instrument [Line Items]
Debt instrument, face amount	$ 825,000,000
Debt term	2 years
Maximum ratio of consolidated debt to consolidated total capital	0.65
Covenant principal balance amount limit	$ 150,000,000
Term Loan \| CECONY
Debt Instrument [Line Items]
Covenant principal balance amount limit	$ 150,000,000
Notes
Debt Instrument [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.675
Covenant principal balance amount limit	$ 100,000,000
Notes \| CECONY
Debt Instrument [Line Items]
Covenant principal balance amount limit	100,000,000
Tax-Exempt Debt \| CECONY
Debt Instrument [Line Items]
Debt instrument, face amount	$ 450,000,000
Maximum ratio of consolidated debt to consolidated total capital	0.65

Short-Term Borrowing (Details)	12 Months Ended
Short-Term Borrowing (Details)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Short-term Debt [Line Items]
Commercial paper, outstanding	$ 1,692,000,000	$ 1,741,000,000
Weighted average interest rate	2.00%	3.00%
Loans outstanding under credit agreement	$ 0	$ 0
Maximum ratio of consolidated debt to consolidated total capital	0.51
Minimum percentage of liens on assets	5.00%
Failure to pay, maximum aggregate limit	$ 150,000,000
Maximum
Short-term Debt [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.65
Revolving Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 1,500,000,000
Current amount available	1,000,000,000
Letters of Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	1,200,000,000
CECONY
Short-term Debt [Line Items]
Commercial paper, outstanding	$ 1,137,000,000	$ 1,192,000,000
Weighted average interest rate	2.00%	3.00%
Maximum ratio of consolidated debt to consolidated total capital	0.53
Credit Availability Through December 2022 \| CECONY \| Revolving Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 2,250,000,000
Credit Availability Through December 2023 \| CECONY \| Revolving Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 2,200,000,000

Pension Benefits - Total Periodic Benefit Costs (Details) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	$ 250	$ 290	$ 263
Interest cost on projected benefit obligation	601	561	591
Expected return on plan assets	(988)	(1,033)	(968)
Recognition of net actuarial loss	518	688	595
Recognition of prior service cost/(credit)	(17)	(17)	(17)
TOTAL PERIODIC BENEFIT COST	364	489	464
Cost capitalized	(108)	(127)	(181)
Reconciliation to rate level	(15)	(92)	(34)
Total credit recognized	241	270	249
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	232	272	246
Interest cost on projected benefit obligation	564	525	554
Expected return on plan assets	(936)	(979)	(917)
Recognition of net actuarial loss	492	651	563
Recognition of prior service cost/(credit)	(19)	(19)	(19)
TOTAL PERIODIC BENEFIT COST	333	450	427
Cost capitalized	(102)	(119)	(169)
Reconciliation to rate level	(12)	(100)	(41)
Total credit recognized	$ 219	$ 231	$ 217

Pension Benefits - Schedule of Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$ 326
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	397	$ 326
Pension Benefits
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	14,449	15,536	$ 14,095
Service cost – excluding administrative expenses	245	286	259
Interest cost on projected benefit obligation	601	561	591
Net actuarial loss/(gain)	2,191	(1,219)	1,231
Plan amendments	15	0	6
Benefits paid	(709)	(715)	(646)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	16,792	14,449	15,536
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	13,450	14,274	12,472
Actual return on plan assets	2,556	(536)	2,041
Employer contributions	350	473	450
Benefits paid	(709)	(715)	(646)
Administrative expenses	(39)	(46)	(43)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	15,608	13,450	14,274
FUNDED STATUS	(1,184)	(999)	(1,262)
Unrecognized net loss	2,604	2,464	2,760
Unrecognized prior service costs	(173)	(205)	(223)
Accumulated benefit obligation	15,015	13,030	13,897
CECONY
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	301
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	371	301
CECONY \| Pension Benefits
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	13,542	14,567	13,203
Service cost – excluding administrative expenses	228	267	241
Interest cost on projected benefit obligation	564	525	554
Net actuarial loss/(gain)	2,076	(1,159)	1,171
Plan amendments	0	0	0
Benefits paid	(660)	(658)	(602)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	15,750	13,542	14,567
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	12,744	13,519	11,815
Actual return on plan assets	2,425	(507)	1,935
Employer contributions	318	434	412
Benefits paid	(660)	(658)	(602)
Administrative expenses	(37)	(44)	(41)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	14,790	12,744	13,519
FUNDED STATUS	(960)	(798)	(1,048)
Unrecognized net loss	2,466	2,338	2,624
Unrecognized prior service costs	(202)	(222)	(242)
Accumulated benefit obligation	$ 14,010	$ 12,161	$ 12,972

Pension Benefits - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Pension liability	$ 185,000,000
Investments value	397,000,000	$ 326,000,000
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets and liabilities for future income taxes, net	167,000,000
Charge to OCI	10,000,000
Net loss estimated to be amortized	701,000,000
Prior service cost estimated to be amortized	(16,000,000)
Investments value	15,608,000,000	13,450,000,000	$ 14,274,000,000	$ 12,472,000,000
Accumulated benefit obligation	15,015,000,000	13,030,000,000	13,897,000,000
Defined benefit plan, bond amount (excess of)	50,000,000
Estimated future employer contributions	472,000,000
Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	395,000,000	316,000,000
CECONY
Defined Benefit Plan Disclosure [Line Items]
Pension liability	162,000,000
Investments value	371,000,000	301,000,000
CECONY \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets and liabilities for future income taxes, net	147,000,000
Charge to OCI	2,000,000
Net loss estimated to be amortized	663,000,000
Prior service cost estimated to be amortized	(20,000,000)
Investments value	14,790,000,000	12,744,000,000	13,519,000,000	$ 11,815,000,000
Accumulated benefit obligation	14,010,000,000	12,161,000,000	$ 12,972,000,000
Estimated future employer contributions	433,000,000
CECONY \| Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 360,000,000	$ 285,000,000

Pension Benefits - Schedule of Assumptions (Details)	12 Months Ended
Pension Benefits - Schedule of Assumptions (Details)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CECONY
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.80%	4.25%	4.25%
Rate of compensation increase	4.25%	4.25%	4.25%
O&R
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.20%	4.00%	4.00%
Rate of compensation increase	4.00%	4.00%	4.00%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate, benefit obligations	3.35%	4.25%	3.70%
Discount rate, net periodic benefit cost	4.25%	3.70%	4.25%
Expected return on plan assets	7.00%	7.50%	7.50%

Pension Benefits - Schedule of Expected Benefit Payments (Details) - Pension Benefits $ in Millions	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2020	$ 744
2021	756
2022	770
2023	788
2024	801
2025-2029	4,181
CECONY
Defined Benefit Plan Disclosure [Line Items]
2020	688
2021	699
2022	713
2023	728
2024	741
2025-2029	$ 3,883

Pension Benefits - Schedule of Plan Assets Allocations (Details) - Pension Benefits	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	100.00%
Plan Assets Percentage	100.00%	100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets Percentage	51.00%	51.00%	58.00%
Equity Securities \| Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	45.00%
Equity Securities \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	55.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets Percentage	38.00%	39.00%	33.00%
Debt Securities \| Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	33.00%
Debt Securities \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	43.00%
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Plan Assets Percentage	11.00%	10.00%	9.00%
Real Estate \| Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	10.00%
Real Estate \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	14.00%

Pension Benefits - Schedule of Fair Value of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 397	$ 326
Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		440
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		1,310
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(208)	(204)
Funds for retiree health benefits measured at NAV per share	(42)	(33)
Total funds for retiree health benefits	(250)	(237)
Investments (excluding funds for retiree health benefits)	15,597	14,105
Pending activities	11	(655)
Total fair value of plan net assets	15,608	13,450	$ 14,274	$ 12,472
Pension Benefits \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,652	3,525
Pension Benefits \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,354	2,896
Pension Benefits \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,496	1,886
Pension Benefits \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,260	2,619
Pension Benefits \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	173	6
Pension Benefits \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	955	121
Pension Benefits \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	326	716
Pension Benefits \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		568
Pension Benefits \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	13,216	12,337
Pension Benefits \| Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	555
Pension Benefits \| Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,806
Pension Benefits \| Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	270	255
Pension Benefits \| Investments Valued Using NAV Per Share
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,631	2,005
Pension Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(110)	(118)
Investments (excluding funds for retiree health benefits)	6,896	7,021
Pension Benefits \| Level 1 \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,652	3,515
Pension Benefits \| Level 1 \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,354	2,896
Pension Benefits \| Level 1 \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Pension Benefits \| Level 1 \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Pension Benefits \| Level 1 \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Pension Benefits \| Level 1 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Pension Benefits \| Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		160
Pension Benefits \| Level 1 \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		568
Pension Benefits \| Level 1 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	7,006	7,139
Pension Benefits \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(98)	(86)
Investments (excluding funds for retiree health benefits)	6,112	5,112
Pension Benefits \| Level 2 \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	10
Pension Benefits \| Level 2 \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,496	1,886
Pension Benefits \| Level 2 \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,260	2,619
Pension Benefits \| Level 2 \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	173	6
Pension Benefits \| Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	955	121
Pension Benefits \| Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	326	556
Pension Benefits \| Level 2 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 6,210	$ 5,198

Other Postretirement Benefits - Net Periodic Postretirement Benefit Costs (Details) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 18	$ 20	$ 20
Interest cost on accumulated other postretirement benefit obligation	44	42	46
Expected return on plan assets	(66)	(73)	(69)
Recognition of net actuarial loss/(gain)	(9)	8	2
Recognition of prior service credit	(2)	(6)	(17)
TOTAL PERIODIC POSTRETIREMENT BENEFIT CREDIT	(15)	(9)	(18)
Cost capitalized	(7)	(8)	8
Reconciliation to rate level	12	8	(4)
Total credit recognized	(10)	(9)	(14)
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost	13	14	13
Interest cost on accumulated other postretirement benefit obligation	36	34	38
Expected return on plan assets	(54)	(63)	(61)
Recognition of net actuarial loss/(gain)	(10)	3	(3)
Recognition of prior service credit	(2)	(2)	(11)
TOTAL PERIODIC POSTRETIREMENT BENEFIT CREDIT	(17)	(14)	(24)
Cost capitalized	(5)	(6)	10
Reconciliation to rate level	7	9	(2)
Total credit recognized	$ (15)	$ (11)	$ (16)

Other Postretirement Benefits - Schedule of Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$ 326
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	397	$ 326
CECONY
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	301
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	371	301
Other Postretirement Benefits
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	1,114	1,219	$ 1,198
Service cost	18	20	20
Interest cost on accumulated other postretirement benefit obligation	44	42	46
Amendments	(14)	0	0
Net actuarial loss/(gain)	264	(70)	53
Benefits paid and administrative expenses, net of subsidies	(110)	(135)	(134)
Participant contributions	41	38	36
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	1,357	1,114	1,219
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	885	1,039	975
Actual return on plan assets	198	(66)	150
Employer contributions	7	6	17
Employer group waiver plan subsidies	23	34	34
Participant contributions	40	37	35
Benefits paid	(127)	(165)	(172)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	1,026	885	1,039
FUNDED STATUS	(331)	(229)	(180)
Unrecognized net loss/(gain)	155	14	(47)
Unrecognized prior service costs	(19)	(8)	(14)
Other Postretirement Benefits \| CECONY
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	913	985	1,007
Service cost	13	14	13
Interest cost on accumulated other postretirement benefit obligation	36	34	38
Amendments	0	0	0
Net actuarial loss/(gain)	252	(32)	16
Benefits paid and administrative expenses, net of subsidies	(100)	(125)	(124)
Participant contributions	40	37	35
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	1,154	913	985
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	759	893	851
Actual return on plan assets	165	(54)	130
Employer contributions	6	6	8
Employer group waiver plan subsidies	22	32	30
Participant contributions	40	37	35
Benefits paid	(120)	(155)	(161)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	872	759	893
FUNDED STATUS	(282)	(154)	(92)
Unrecognized net loss/(gain)	149	(2)	(85)
Unrecognized prior service costs	$ (3)	$ (5)	$ (7)

Other Postretirement Benefits - Additional Information (Details) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Increase in liability for other postretirement benefits	$ 102
Increase (decrease) in regulatory liabilities	134
Net losses unrecognized to be amortized	27
Prior service cost estimated to be amortized	$ (3)
Health care cost trend rate for net periodic benefit cost, current	5.40%	5.60%	5.80%
Health care cost trend rate for net periodic benefit cost	4.50%
Health care cost trend rate for benefit obligations, current	5.20%	5.40%	5.60%
Health care cost trend rate for benefit obligations	4.50%
Expected contributions	$ 6
Clean Energy Businesses, Con Edison Transmission and RECO
Defined Benefit Plan Disclosure [Line Items]
Credit to OCI (net of taxes) for unrecognized net losses	6
Debit to OCI (net of taxes) for unrecognized prior service costs	1
CECONY
Defined Benefit Plan Disclosure [Line Items]
Increase in liability for other postretirement benefits	128
Increase (decrease) in regulatory liabilities	153
Net losses unrecognized to be amortized	22
Prior service cost estimated to be amortized	$ (2)

Other Postretirement Benefits - Schedule of Actuarial Assumptions (Details) - Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected Return on Plan Assets	6.80%	7.50%	7.50%
CECONY
Defined Benefit Plan Disclosure [Line Items]
Discount Rate, Benefit Obligations	3.10%	4.15%	3.55%
Discount Rate, Net Periodic Benefit Cost	4.15%	3.55%	4.00%
O&R
Defined Benefit Plan Disclosure [Line Items]
Discount Rate, Benefit Obligations	3.35%	4.30%	3.70%
Discount Rate, Net Periodic Benefit Cost	4.30%	3.70%	4.20%

Other Postretirement Benefits - Schedule of Change of Assumed Health Care Cost Trend Rate (Details) - Other Postretirement Benefits $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Increase
Effect on accumulated other postretirement benefit obligation	$ 60
Effect on service cost and interest cost components for 2019	1
Decrease
Effect on accumulated other postretirement benefit obligation	(17)
Effect on service cost and interest cost components for 2019	0
CECONY
Increase
Effect on accumulated other postretirement benefit obligation	33
Effect on service cost and interest cost components for 2019	(1)
Decrease
Effect on accumulated other postretirement benefit obligation	3
Effect on service cost and interest cost components for 2019	$ 2

Other Postretirement Benefits - Schedule of Expected Benefit Payments (Details) - Other Postretirement Benefits $ in Millions	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2020	$ 96
2021	95
2022	93
2023	92
2024	91
2025-2029	422
CECONY
Defined Benefit Plan Disclosure [Line Items]
2020	87
2021	85
2022	83
2023	82
2024	80
2025-2029	$ 368

Other Postretirement Benefits - Schedule of Plan Assets Allocations (Details) - Other Postretirement Benefits - CECONY	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	100.00%
Plan Assets Percentage	100.00%	100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets Percentage	54.00%	52.00%	60.00%
Equity Securities \| Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	42.00%
Equity Securities \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	80.00%
Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan Assets Percentage	46.00%	48.00%	40.00%
Debt Securities \| Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	20.00%
Debt Securities \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Range	58.00%

Other Postretirement Benefits - Schedule of Fair Values of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 397	$ 326
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	208	204
Investments (including funds for retiree health benefits)	966	829
Funds for retiree health benefits measured at NAV per share	42	33
Pending activities	18	23
Total fair value of plan net assets	1,026	885	$ 1,039	$ 975
Other Postretirement Benefits \| Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	404	322
Other Postretirement Benefits \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	331	289
Other Postretirement Benefits \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	23	14
Other Postretirement Benefits \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	758	625
Other Postretirement Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	110	118
Investments (including funds for retiree health benefits)	110	118
Other Postretirement Benefits \| Level 1 \| Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Other Postretirement Benefits \| Level 1 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Other Postretirement Benefits \| Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Other Postretirement Benefits \| Level 1 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	0	0
Other Postretirement Benefits \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	98	86
Investments (including funds for retiree health benefits)	856	711
Other Postretirement Benefits \| Level 2 \| Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	404	322
Other Postretirement Benefits \| Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	331	289
Other Postretirement Benefits \| Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	23	14
Other Postretirement Benefits \| Level 2 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 758	$ 625

Environmental Matters - Accrued Liabilities and Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Site Contingency [Line Items]
Accrued Liabilities	$ 734	$ 779
Regulatory assets	4,987	4,370
Manufactured gas plant sites
Site Contingency [Line Items]
Accrued Liabilities	640	689
Other Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	94	90
Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	734	779
Regulatory assets	732	810
CECONY
Site Contingency [Line Items]
Accrued Liabilities	654	693
Regulatory assets	4,600	3,987
CECONY \| Manufactured gas plant sites
Site Contingency [Line Items]
Accrued Liabilities	561	603
CECONY \| Other Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	93	90
CECONY \| Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	654	693
Regulatory assets	$ 647	$ 716

Environmental Matters - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Asbestos Proceedings
Site Contingency [Line Items]
Estimated undiscounted asbestos liability (years)	15 years
CECONY \| Asbestos Proceedings
Site Contingency [Line Items]
Estimated undiscounted asbestos liability (years)	15 years
Superfund Sites
Site Contingency [Line Items]
Remediation cost estimate	$ 46
Superfund Sites \| Manufactured Gas Plant Sites \| Maximum
Site Contingency [Line Items]
Estimated aggregate undiscounted potential liability related environmental contaminants (up to)	2,800
Superfund Sites \| CECONY
Site Contingency [Line Items]
Remediation cost estimate	43
Superfund Sites \| CECONY \| Manufactured Gas Plant Sites \| Maximum
Site Contingency [Line Items]
Estimated aggregate undiscounted potential liability related environmental contaminants (up to)	$ 2,600

Other Material Contingencies - Manhattan Explosion and Fire (Details) $ in Millions		1 Months Ended
	Mar. 12, 2014 building people	Feb. 28, 2017 USD ($)	Dec. 31, 2019 USD ($) lawsuit	Dec. 31, 2018 USD ($)
Loss Contingencies [Line Items]
Accrued regulatory liability			$ 4,827	$ 4,641
Settlement of gas proceedings
Loss Contingencies [Line Items]
Accrued regulatory liability			$ 10	$ 15
Manhattan Explosion and Fire
Loss Contingencies [Line Items]
Number of buildings destroyed by fire \| building	2
Number of people died in explosion and fire incident \| people	8
Number of people injured in explosion and fire incident (more than) \| people	50
Amount of costs that will not recover from customers		$ 126
Number of pending lawsuits \| lawsuit			80
Manhattan Explosion and Fire \| Settlement of gas proceedings
Loss Contingencies [Line Items]
Accrued regulatory liability		$ 27

Other Material Contingencies - Total Guarantees (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 1,831	$ 2,439
Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	573
Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	679
Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	510
Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	69
0 – 3 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	945
0 – 3 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	387
0 – 3 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	419
0 – 3 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	70
0 – 3 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	69
4 – 10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	246
4 – 10 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	186
4 – 10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	51
4 – 10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	9
4 – 10 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	0
10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	640
10 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	0
10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	209
10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	431
10 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 0

Electricity Purchase Agreements - Summary of Estimated Capacity and Other Fixed Payments (Details) $ in Millions	Dec. 31, 2019 USD ($)
Long-term Contract for Purchase of Electric Power [Line Items]
2020	$ 172
2021	101
2022	62
2023	57
2024	55
All Years Thereafter	546
CECONY
Long-term Contract for Purchase of Electric Power [Line Items]
2020	169
2021	99
2022	62
2023	57
2024	55
All Years Thereafter	$ 546

Leases - Additional Information (Details) $ in Millions	12 Months Ended
Leases - Additional Information (Details) $ in Millions	Dec. 31, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Assets under finance leases	$ 1
Finance leases, accumulated amortization	5
Right-of-use asset obtained in exchange for operating lease liability	39
CECONY
Lessee, Lease, Description [Line Items]
Finance leases, accumulated amortization	3
Right-of-use asset obtained in exchange for operating lease liability	$ 4
Minimum
Lessee, Lease, Description [Line Items]
Lease, term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lease, term	40 years
Lease, renewal term	5 years

Leases - Other Related Information (Details)	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Weighted Average Remaining Lease Term, Operating leases	19 years 9 months 18 days
Weighted Average Remaining Lease Term, Finance leases	12 years 2 months 12 days
Weighted Average Discount Rate, Operating leases	4.30%
Weighted Average Discount Rate, Finance leases	3.50%
CECONY
Lessee, Lease, Description [Line Items]
Weighted Average Remaining Lease Term, Operating leases	14 years
Weighted Average Remaining Lease Term, Finance leases	2 years 4 months 24 days
Weighted Average Discount Rate, Operating leases	3.60%
Weighted Average Discount Rate, Finance leases	4.10%

Leases - Future Minimum Lease Payments (Details) $ in Millions	Dec. 31, 2019 USD ($)
Operating Leases
2020	$ 78
2021	75
2022	73
2023	72
2024	72
All years thereafter	992
Total future minimum lease payments	1,362
Less: imputed interest	(488)
Total	874
Operating lease liabilities (current)	65
Operating lease liabilities (noncurrent)	809
Total	874
Finance Leases
2020	0
2021	0
2022	0
2023	0
2024	0
All years thereafter	1
Total future minimum lease payments	1
Less: imputed interest	0
Total	1
Other noncurrent liabilities	1
Total	1
CECONY
Operating Leases
2020	60
2021	57
2022	55
2023	54
2024	55
All years thereafter	501
Total future minimum lease payments	782
Less: imputed interest	(177)
Total	605
Operating lease liabilities (current)	54
Operating lease liabilities (noncurrent)	551
Total	605
Finance Leases
2020	0
2021	0
2022	0
2023	0
2024	0
All years thereafter	0
Total future minimum lease payments	0
Less: imputed interest	0
Total	0
Other noncurrent liabilities	0
Total	$ 0

Leases - Future Minimum Rental Payments for Operating Leases (Details) $ in Millions	Dec. 31, 2019 USD ($)
Operating Leased Assets [Line Items]
2019	$ 72
2020	72
2021	71
2022	68
2023	68
All years thereafter	890
Total	1,241
CECONY
Operating Leased Assets [Line Items]
2019	56
2020	56
2021	54
2022	53
2023	53
All years thereafter	592
Total	$ 864

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 446	$ 440
CECONY
Goodwill [Line Items]
Goodwill	245	245
O&R
Goodwill [Line Items]
Goodwill	161	161
O&R Merger
Goodwill [Line Items]
Goodwill	406	406
Gas Storage Company \| CET Gas
Goodwill [Line Items]
Goodwill	8	8
Residential Solar Company \| Clean Energy Businesses
Goodwill [Line Items]
Goodwill	14	14
Battery Storage Company \| Clean Energy Businesses
Goodwill [Line Items]
Goodwill		$ 12
Goodwill, purchase accounting adjustments	$ 18

Income Tax - Schedule of Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
State
Current	$ (12)	$ (10)	$ (2)
Deferred	96	107	103
Federal
Current	0	3	(11)
Deferred	219	310	391
Amortization of investment tax credits	(7)	(9)	(9)
Total income tax expense	296	401	472
CECONY
State
Current	22	6	37
Deferred	68	82	75
Federal
Current	185	(34)	73
Deferred	63	275	504
Amortization of investment tax credits	(3)	(3)	(4)
Total income tax expense	$ 335	$ 326	$ 685

Income Tax - Schedule of Differences on Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Property basis differences	$ 7,699	$ 7,402
Regulatory assets:
Unrecognized pension and other postretirement costs	712	627
Environmental remediation costs	205	227
Deferred storm costs	22	21
Other regulatory assets	376	273
Operating lease right-of-use asset	231	0
Equity investments	104	102
Total deferred tax liabilities	9,349	8,652
Deferred tax assets:
Accrued pension and other postretirement costs	291	248
Future income tax	678	702
Other regulatory liabilities	702	632
Superfund and other environmental costs	206	218
Asset retirement obligations	135	114
Operating lease liabilities	231	0
Loss carryforwards	108	229
Tax credits carryforward	896	817
Valuation allowance	(40)	(33)
Other	56	53
Total deferred tax assets	3,263	2,980
Net deferred tax liabilities	6,086	5,672
Unamortized investment tax credits	141	148
Net deferred tax liabilities and unamortized investment tax credits	6,227	5,820
CECONY
Deferred tax liabilities:
Property basis differences	6,640	6,446
Regulatory assets:
Unrecognized pension and other postretirement costs	674	591
Environmental remediation costs	181	200
Deferred storm costs	0	0
Other regulatory assets	355	252
Operating lease right-of-use asset	169	0
Equity investments	0	0
Total deferred tax liabilities	8,019	7,489
Deferred tax assets:
Accrued pension and other postretirement costs	222	180
Future income tax	638	662
Other regulatory liabilities	622	554
Superfund and other environmental costs	183	194
Asset retirement obligations	102	82
Operating lease liabilities	170	0
Loss carryforwards	0	0
Tax credits carryforward	0	0
Valuation allowance	0	0
Other	103	102
Total deferred tax assets	2,040	1,774
Net deferred tax liabilities	5,979	5,715
Unamortized investment tax credits	21	24
Net deferred tax liabilities and unamortized investment tax credits	$ 6,000	$ 5,739

Income Tax - Additional Information (Details) - USD ($)	12 Months Ended
Income Tax - Additional Information (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Decrease in net deferred tax liabilities resulting from TCJA		$ 13,000,000	$ 5,312,000,000
Change in net income resulting from TCJA			259,000,000
Charitable contribution carryforwards	$ 28,000,000
Deferred tax asset, valuation allowance	40,000,000	33,000,000
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years	2,000,000	3,000,000	6,000,000
Effective income tax rate reconciliation, uncertainty of taxes	10,000,000
Penalties for uncertain tax positions	0	0
Amount of interest and penalties in their consolidated balance sheets	0	0
Unrecognized tax benefits that would have an impact on effective tax rate	13,000,000
Unrecognized tax benefits that would have an impact on effective tax rate, net of tax	12,000,000
General Business Tax Credit
Operating Loss Carryforwards [Line Items]
Tax credit carryovers	896,000,000
Operating loss carryforwards, valuation allowance	0
Tax Year 2015
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	5,000,000
Tax Year 2016
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	7,000,000
Tax Year 2017
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	5,000,000
Tax Year 2018
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	5,000,000
Tax Year 2019
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	6,000,000
Federal
Operating Loss Carryforwards [Line Items]
Additional depreciation deducted			477,000,000
Operating loss carryforwards	36,000,000		563,000,000
Operating loss carryover subject to expiration		13,000,000
Operating loss carryover not subject to expiration	23,000,000
State \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards		272,000,000
Operating loss carryforwards, valuation allowance	22,000,000
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years	4,000,000
State \| New York City
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, valuation allowance	18,000,000
State \| Carry Back to 2015 and 2016 \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	100,000,000
Income tax recovery resulting from operating loss carry back	9,000,000
State \| Carried Forward to Future Years \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	172,000,000
State \| Tax Year 2019 \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	453,000,000
Parent Company
Operating Loss Carryforwards [Line Items]
Change in net income resulting from TCJA		42,000,000	(21,000,000)
Clean Energy Businesses
Operating Loss Carryforwards [Line Items]
Change in net income resulting from TCJA			269,000,000
Con Edison Transmission
Operating Loss Carryforwards [Line Items]
Change in net income resulting from TCJA			11,000,000
Future Income Tax
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA		54,000,000	3,713,000,000
Accelerated Tax Depreciation Benefits
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA			2,684,000,000
Future Income Tax
Operating Loss Carryforwards [Line Items]
Decrease in regulatory asset resulting from TCJA			1,250,000,000
Revenue Taxes
Operating Loss Carryforwards [Line Items]
Decrease in regulatory asset resulting from TCJA			90,000,000
CECONY
Operating Loss Carryforwards [Line Items]
Decrease in net deferred tax liabilities resulting from TCJA		50,000,000	4,781,000,000
Deferred tax asset, valuation allowance	0	0
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years	2,000,000	3,000,000	0
Effective income tax rate reconciliation, uncertainty of taxes	1,000,000
Unrecognized tax benefits that would have an impact on effective tax rate	2,000,000
CECONY \| New York State
Operating Loss Carryforwards [Line Items]
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years	$ 2,000,000
CECONY \| Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards			153,000,000
CECONY \| Future Income Tax
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA		49,000,000	3,513,000,000
CECONY \| Accelerated Tax Depreciation Benefits
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA			2,542,000,000
CECONY \| Future Income Tax
Operating Loss Carryforwards [Line Items]
Decrease in regulatory asset resulting from TCJA			1,182,000,000
CECONY \| Revenue Taxes
Operating Loss Carryforwards [Line Items]
Decrease in regulatory asset resulting from TCJA		$ 1,000,000	$ 86,000,000

Income Tax - Schedule of Income Tax Reconciliation (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
STATUTORY TAX RATE
Federal	21.00%	21.00%	35.00%
Changes in computed taxes resulting from:
State income tax	4.00%	4.00%	4.00%
Taxes attributable to noncontrolling interests	(1.00%)	0.00%	0.00%
Cost of removal	1.00%	1.00%	1.00%
Other plant-related items	(1.00%)	(1.00%)	(1.00%)
TCJA deferred tax re-measurement	0	0.02	(0.13)
Amortization of excess deferred federal income taxes	(4.00%)	(3.00%)	0.00%
Renewable energy credits	(2.00%)	(1.00%)	(1.00%)
Research and development credits	(1.00%)	0.00%	0.00%
Other	0.00%	0.00%	(2.00%)
Effective tax rate	17.00%	23.00%	23.00%
CECONY
STATUTORY TAX RATE
Federal	21.00%	21.00%	35.00%
Changes in computed taxes resulting from:
State income tax	5.00%	5.00%	4.00%
Taxes attributable to noncontrolling interests	0.00%	0.00%	0.00%
Cost of removal	1.00%	1.00%	1.00%
Other plant-related items	(1.00%)	(1.00%)	(1.00%)
TCJA deferred tax re-measurement	0	0	0
Amortization of excess deferred federal income taxes	(4.00%)	(3.00%)	0.00%
Renewable energy credits	0.00%	0.00%	0.00%
Research and development credits	(1.00%)	(1.00%)	0.00%
Other	0.00%	(1.00%)	(1.00%)
Effective tax rate	21.00%	21.00%	38.00%

Income Tax - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 6	$ 12	$ 42
Additions based on tax positions related to the current year	1	2	1
Additions based on tax positions of prior years	10	1	1
Reductions for tax positions of prior years	(2)	(2)	(24)
Reductions from expiration of statute of limitations	0	(4)	(2)
Settlements	(2)	(3)	(6)
Balance at end of period	13	6	12
CECONY
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	4	5	21
Additions based on tax positions related to the current year	1	2	1
Additions based on tax positions of prior years	0	1	1
Reductions for tax positions of prior years	(1)	(1)	(18)
Reductions from expiration of statute of limitations	0	0	0
Settlements	(2)	(3)	0
Balance at end of period	$ 2	$ 4	$ 5

Stock-Based Compensation - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit realized from stock options exercised	$ 13,000,000	$ 4,000,000	$ 25,000,000
Compensation expense to be recognized	3,000,000
Maximum employer contribution match (up to)	1
Amount employee contribution for employer match	9
Maximum employee investment per year (up to)	$ 25,000
Maximum percentage allowed to invest (not more than)	20.00%
CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit realized from stock options exercised	$ 11,000,000	4,000,000	22,000,000
Compensation expense to be recognized	$ 2,000,000
Performance RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock received upon vesting (in shares)	1
Compensation expense to be recognized	$ 25,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 24,000,000	29,000,000	22,000,000
Performance RSUs \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense to be recognized	$ 21,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 22,000,000	28,000,000	21,000,000
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (years)	3 years
Time-based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 1,000,000	1,000,000	1,000,000
Weighted average grant date price per share (in dollars per share)	$ 84.81
Time-based Awards \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 1,000,000	$ 1,000,000	$ 1,000,000
Weighted average grant date price per share (in dollars per share)	$ 84.81
2013 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock that can be awarded under the plan	5,000,000
TSR Portion \| Performance RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustment percentage used for Performance awards	50.00%
Factor used for adjustment of Performance awards, low end (percent)	0.00%
Factor used for adjustment of Performance awards, high end (percent)	200.00%
Weighted average grant date price per share (in dollars per share)	$ 64.37
TSR Portion \| Performance RSUs \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date price per share (in dollars per share)	$ 64.82
Non-TSR Portion \| Performance RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustment percentage used for Performance awards	50.00%
Factor used for adjustment of Performance awards, low end (percent)	0.00%
Factor used for adjustment of Performance awards, high end (percent)	200.00%
Weighted average grant date price per share (in dollars per share)	$ 80.03
Non-TSR Portion \| Performance RSUs \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date price per share (in dollars per share)	$ 80.31
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units issued (in shares)	27,100
Weighted average grant date price per share (in dollars per share)	$ 87.57
Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares purchased on the open market	747,899	786,385	719,125
Weighted average share price per share, on shares purchased on open market (in dollars per share)	$ 85.45	$ 78.27	$ 79.57

Stock-Based Compensation - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 47	$ 14	$ 63
Income tax benefit	13	4	25
Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	36	3	53
Time-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	2	2
Non-employee director deferred stock compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	3	2
Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	7	6	6
CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	40	13	55
Income tax benefit	11	4	22
CECONY \| Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	30	3	45
CECONY \| Time-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	1	2
CECONY \| Non-employee director deferred stock compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	2	3	2
CECONY \| Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 6	$ 6	$ 6

Stock-Based Compensation - Assumptions Used to Calculate Fair Value (Details) - Performance RSUs	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate, minimum	1.58%	2.48%	1.76%
Risk-free interest rate, maximum	1.59%	2.46%	1.89%
Expected term (years)	3 years	3 years	3 years
Expected share price volatility, minimum (percent)	12.89%	14.76%	11.01%
Expected share price volatility, maximum (percent)	15.51%	17.71%	14.70%

Stock-Based Compensation - Summary of Changes in Status of Performance RSUs' (Details) - Performance RSUs	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Units
Non-vested at beginning of period (in shares) \| shares	1,005,836
Granted (in shares) \| shares	389,600
Vested (in shares) \| shares	(357,325)
Forfeited (in shares) \| shares	(46,873)
Transferred (in shares) \| shares	0
Non-vested at end of period (in shares) \| shares	991,238
CECONY
Units
Non-vested at beginning of period (in shares) \| shares	761,906
Granted (in shares) \| shares	284,516
Vested (in shares) \| shares	(275,376)
Forfeited (in shares) \| shares	(30,186)
Transferred (in shares) \| shares	1,344
Non-vested at end of period (in shares) \| shares	742,204
TSR Portion
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	$ 74.81
Granted (in dollars per share)	64.37
Vested (in dollars per share)	83.17
Forfeited (in dollars per share)	65.08
Transferred (in dollars per share)	0
Non-vested at end of period (in dollars per share)	$ 68.15
Adjustment percentage used for Performance awards	50.00%
TSR Portion \| CECONY
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	$ 74.47
Granted (in dollars per share)	64.82
Vested (in dollars per share)	82.77
Forfeited (in dollars per share)	65.20
Transferred (in dollars per share)	70.04
Non-vested at end of period (in dollars per share)	68.06
Non-TSR Portion
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	74.27
Granted (in dollars per share)	80.03
Vested (in dollars per share)	72.09
Forfeited (in dollars per share)	78.03
Transferred (in dollars per share)	0
Non-vested at end of period (in dollars per share)	$ 77.14
Adjustment percentage used for Performance awards	0.00%
Non-TSR Portion \| CECONY
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	$ 74.42
Granted (in dollars per share)	80.31
Vested (in dollars per share)	72.32
Forfeited (in dollars per share)	78.10
Transferred (in dollars per share)	75.65
Non-vested at end of period (in dollars per share)	$ 77.32

Stock-Based Compensation - Summary of Changes in Status of Time-Based Awards (Details) - Time-based Awards	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Units
Non-vested at beginning of period (in shares) \| shares	65,180
Granted (in shares) \| shares	24,850
Vested (in shares) \| shares	(20,980)
Forfeited (in shares) \| shares	(1,800)
Non-vested at end of period (in shares) \| shares	67,250
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share) \| $ / shares	$ 77.42
Granted (in dollars per share) \| $ / shares	84.81
Vested (in dollars per share) \| $ / shares	76.62
Forfeited (in dollars per share) \| $ / shares	79.12
Non-vested at end of period (in dollars per share) \| $ / shares	$ 80.36
CECONY
Units
Non-vested at beginning of period (in shares) \| shares	61,380
Granted (in shares) \| shares	23,350
Vested (in shares) \| shares	(19,830)
Forfeited (in shares) \| shares	(1,800)
Non-vested at end of period (in shares) \| shares	63,100
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share) \| $ / shares	$ 77.42
Granted (in dollars per share) \| $ / shares	84.81
Vested (in dollars per share) \| $ / shares	76.62
Forfeited (in dollars per share) \| $ / shares	79.12
Non-vested at end of period (in dollars per share) \| $ / shares	$ 80.36

Financial Information by Business Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 12,574	$ 12,337	$ 12,033
Depreciation and amortization	1,684	1,438	1,341
Operating income	2,676	2,664	2,774
Other Income (deductions)	51	(62)	(48)
Interest charges	991	819	729
Income taxes on operating income	300	406	459
Total assets	58,079	53,920	48,111
Capital expenditures	3,676	5,249	3,606
Income tax expense (benefit) on non-operating income	(4)	(5)	13
Federal income tax expense			259
Parent Company
Segment Reporting Information [Line Items]
Total assets	20,638	19,542
Federal income tax expense			(21)
Clean Energy Businesses
Segment Reporting Information [Line Items]
Federal income tax expense			269
Con Edison Transmission
Segment Reporting Information [Line Items]
Federal income tax expense			11
CECONY
Segment Reporting Information [Line Items]
Revenues	10,821	10,680	10,468
Depreciation and amortization	1,373	1,276	1,195
Operating income	2,348	2,354	2,549
Other Income (deductions)	(35)	(143)	(137)
Total assets	46,557	43,108
Income tax expense (benefit) on non-operating income	(7)	(2)	(3)
Operating segment \| Clean Energy Businesses
Segment Reporting Information [Line Items]
Revenues	857	763	694
Depreciation and amortization	226	85	74
Operating income	202	194	69
Other Income (deductions)	5	33	33
Interest charges	186	63	43
Income taxes on operating income	(58)	19	(273)
Total assets	6,528	5,821	2,735
Capital expenditures	248	1,791	447
Operating segment \| Con Edison Transmission
Segment Reporting Information [Line Items]
Revenues	4	4	2
Depreciation and amortization	1	1	1
Operating income	(6)	(7)	(8)
Other Income (deductions)	104	91	80
Interest charges	25	20	16
Income taxes on operating income	1	(1)	(11)
Total assets	1,618	1,425	1,222
Capital expenditures	205	248	66
Operating segment \| CECONY
Segment Reporting Information [Line Items]
Revenues	10,821	10,680	10,468
Depreciation and amortization	1,373	1,276	1,195
Operating income	2,348	2,354	2,549
Other Income (deductions)	(35)	(143)	(137)
Interest charges	728	689	623
Income taxes on operating income	342	328	688
Total assets	46,557	43,108	40,451
Capital expenditures	3,020	3,005	2,904
Operating segment \| CECONY \| Electric
Segment Reporting Information [Line Items]
Revenues	8,062	7,971	7,972
Depreciation and amortization	1,053	984	925
Operating income	1,758	1,799	1,974
Other Income (deductions)	(28)	(110)	(105)
Interest charges	539	519	472
Income taxes on operating income	239	233	511
Total assets	32,988	31,012	29,661
Capital expenditures	1,851	1,861	1,905
Operating segment \| CECONY \| Gas
Segment Reporting Information [Line Items]
Revenues	2,132	2,078	1,901
Depreciation and amortization	231	205	185
Operating income	528	478	495
Other Income (deductions)	(4)	(23)	(23)
Interest charges	147	131	113
Income taxes on operating income	99	87	152
Total assets	11,090	9,710	8,387
Capital expenditures	1,078	1,050	909
Operating segment \| CECONY \| Steam
Segment Reporting Information [Line Items]
Revenues	627	631	595
Depreciation and amortization	89	87	85
Operating income	62	77	80
Other Income (deductions)	(3)	(10)	(9)
Interest charges	42	39	38
Income taxes on operating income	4	8	25
Total assets	2,479	2,386	2,403
Capital expenditures	91	94	90
Operating segment \| O&R
Segment Reporting Information [Line Items]
Revenues	893	891	874
Depreciation and amortization	84	77	71
Operating income	139	132	161
Other Income (deductions)	(11)	(19)	(19)
Interest charges	41	39	36
Income taxes on operating income	21	21	42
Total assets	3,006	2,892	2,773
Capital expenditures	203	205	189
Operating segment \| O&R \| Electric
Segment Reporting Information [Line Items]
Revenues	634	642	642
Depreciation and amortization	60	56	51
Operating income	98	93	115
Other Income (deductions)	(7)	(14)	(14)
Interest charges	27	25	24
Income taxes on operating income	15	14	30
Total assets	2,130	2,036	1,949
Capital expenditures	142	138	128
Operating segment \| O&R \| Gas
Segment Reporting Information [Line Items]
Revenues	259	249	232
Depreciation and amortization	24	21	20
Operating income	41	39	46
Other Income (deductions)	(4)	(5)	(5)
Interest charges	14	14	12
Income taxes on operating income	6	7	12
Total assets	876	856	824
Capital expenditures	61	67	61
Other
Segment Reporting Information [Line Items]
Revenues	(1)	(1)	(5)
Depreciation and amortization	0	(1)	0
Operating income	(7)	(9)	3
Other Income (deductions)	(12)	(24)	(5)
Interest charges	11	8	11
Income taxes on operating income	(6)	39	13
Total assets	370	674	930
Capital expenditures	0	0	0
Other \| O&R
Segment Reporting Information [Line Items]
Revenues	0	0	0
Depreciation and amortization	0	0	0
Operating income	0	0	0
Other Income (deductions)	0	0	0
Interest charges	0	0	0
Income taxes on operating income	0	0	0
Total assets	0	0	0
Capital expenditures	0	0	0
Inter-segment
Segment Reporting Information [Line Items]
Revenues	0	0	0
Inter-segment \| Clean Energy Businesses
Segment Reporting Information [Line Items]
Revenues	0	0	0
Inter-segment \| CECONY
Segment Reporting Information [Line Items]
Revenues	(94)	(98)	(97)
Inter-segment \| CECONY \| Electric
Segment Reporting Information [Line Items]
Revenues	17	16	16
Inter-segment \| CECONY \| Gas
Segment Reporting Information [Line Items]
Revenues	7	7	6
Inter-segment \| CECONY \| Steam
Segment Reporting Information [Line Items]
Revenues	$ 70	$ 75	$ 75

Derivative Instruments and Hedging Activities - Fair Values of Commodity Derivatives Including Offsetting of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Net fair value derivative assets/(liabilities)
Gross Amounts of Recognized Assets/ (Liabilities)	$ (183)	$ (27)
Gross Amounts Offset	17	(1)
Net Amounts of Assets/ (Liabilities)	(166)	(28)
Margin deposits	9	7
CECONY
Net fair value derivative assets/(liabilities)
Gross Amounts of Recognized Assets/ (Liabilities)	(124)	(7)
Gross Amounts Offset	17	1
Net Amounts of Assets/ (Liabilities)	(107)	(6)
Margin deposits	8	6
Clean Energy Businesses \| Interest Rate Swap
Net fair value derivative assets/(liabilities)
Notional amount	919	499
Fair Value of Derivative Liabilities, Current
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(140)	(61)
Gross Amounts Offset	17	11
Net Amounts of Assets/ (Liabilities)	(123)	(50)
Fair Value of Derivative Liabilities, Current \| Interest Rate Swap
Fair value of derivative liabilities
Net Amounts of Assets/ (Liabilities)	(7)
Fair Value of Derivative Liabilities, Current \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(100)	(31)
Gross Amounts Offset	19	6
Net Amounts of Assets/ (Liabilities)	(81)	(25)
Fair Value of Derivative Liabilities, Non-current
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(122)	(25)
Gross Amounts Offset	16	9
Net Amounts of Assets/ (Liabilities)	(106)	(16)
Fair Value of Derivative Liabilities, Non-current \| Interest Rate Swap
Fair value of derivative liabilities
Net Amounts of Assets/ (Liabilities)	(34)	(6)
Fair Value of Derivative Liabilities, Non-current \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(80)	(12)
Gross Amounts Offset	16	6
Net Amounts of Assets/ (Liabilities)	(64)	(6)
Fair Value of Derivative Liabilities
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(262)	(86)
Gross Amounts Offset	33	20
Net Amounts of Assets/ (Liabilities)	(229)	(66)
Fair Value of Derivative Liabilities \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(180)	(43)
Gross Amounts Offset	35	12
Net Amounts of Assets/ (Liabilities)	(145)	(31)
Fair Value of Derivative Assets, Current
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	60	43
Gross Amounts Offset	(3)	(14)
Net Amounts of Assets/ (Liabilities)	57	29
Fair Value of Derivative Assets, Current \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	39	25
Gross Amounts Offset	(6)	(6)
Net Amounts of Assets/ (Liabilities)	33	19
Fair Value of Derivative Assets, Non-current
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	19	16
Gross Amounts Offset	(13)	(7)
Net Amounts of Assets/ (Liabilities)	6	9
Fair Value of Derivative Assets, Non-current \| Interest Rate Swap
Fair value of derivative assets
Net Amounts of Assets/ (Liabilities)	1	2
Fair Value of Derivative Assets, Non-current \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	17	11
Gross Amounts Offset	(12)	(5)
Net Amounts of Assets/ (Liabilities)	5	6
Fair Value of Derivative Assets
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	79	59
Gross Amounts Offset	(16)	(21)
Net Amounts of Assets/ (Liabilities)	63	38
Fair Value of Derivative Assets \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	56	36
Gross Amounts Offset	(18)	(11)
Net Amounts of Assets/ (Liabilities)	$ 38	$ 25

Derivative Instruments and Hedging Activities - Realized and Unrealized Gains or Losses on Commodity Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ 1	$ 3
Total deferred gains/(losses)	(300)	5
Net deferred gains/(losses)	(299)	8
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(12)	(4)
Gas purchased for resale
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(2)	(2)
Non-utility revenue
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	25	4
Other operations and maintenance expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	1	(2)
Other interest expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(36)	(4)
Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	4	(1)
Deferred Derivative Gains, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(3)	4
Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(91)	4
Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(142)	(26)
Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(67)	27
CECONY
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	4	4
Total deferred gains/(losses)	(272)	8
Net deferred gains/(losses)	(268)	12
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	1	(2)
CECONY \| Gas purchased for resale
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Non-utility revenue
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Other operations and maintenance expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	1	(2)
CECONY \| Other interest expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
CECONY \| Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	5	1
CECONY \| Deferred Derivative Gains, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(1)	3
CECONY \| Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(83)	8
CECONY \| Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(124)	(26)
CECONY \| Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ (65)	$ 26

Derivative Instruments and Hedging Activities - Aggregate Fair Value of Companies' Derivative Instruments with Credit-Risk-Related Contingent Features (Details) $ in Millions	Dec. 31, 2019 USD ($)
Derivatives, Fair Value [Line Items]
Aggregate fair value – net liabilities	$ 163
Collateral posted	25
Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	50
Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	159
Derivatives in net asset position additional collateral	49
Additional Collateral Required Due To Loss Of Unsecured Credit
Derivatives, Fair Value [Line Items]
Collateral posted	1
CECONY
Derivatives, Fair Value [Line Items]
Aggregate fair value – net liabilities	145
Collateral posted	25
CECONY \| Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	41
CECONY \| Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	$ 134

Fair Value Measurements - Schedule of Commodity Derivatives (Details) - Level 3 $ in Millions	Dec. 31, 2019 USD ($) $ / kW-month $ / MWh
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (16)
CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	(6)
Electricity \| Forward Energy Prices
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (1)
Electricity \| Forward Energy Prices \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	25.50
Electricity \| Forward Energy Prices \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	34.10
Electricity \| Forward Capacity Prices
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (16)
Electricity \| Forward Capacity Prices \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (7)
Electricity \| Forward Capacity Prices \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	0.09
Electricity \| Forward Capacity Prices \| Minimum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	0.15
Electricity \| Forward Capacity Prices \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	8.90
Electricity \| Forward Capacity Prices \| Maximum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	8.90
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ 1
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ 1
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	(3.69)
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves \| Minimum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	0.36
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	7.37
Transmission Congestion Contracts \| Inter-Zonal Forward Price Curves \| Maximum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	3.10

Fair Value Measurements - Reconciliation of Beginning and Ending Net Balances for Assets and Liabilities Measured at Level 3 Fair Value (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance		$ 1
Beginning Balance	$ (13)
Included in earnings	(5)	4
Included in regulatory assets and liabilities	18	(10)
Settlements	8	(6)
Transfer out of level 3	(24)	(2)
Ending Balance	(16)	(13)
CECONY
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance		4
Beginning Balance	(2)
Included in earnings	0	4
Included in regulatory assets and liabilities	17	(4)
Settlements	1	(4)
Transfer out of level 3	(22)	(2)
Ending Balance	$ (6)	$ (2)

Variable Interest Entities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) MW	Sep. 30, 2019
Variable Interest Entity [Line Items]
Noncontrolling interest	$ 191	$ 113
Texas Solar 4 \| Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Generating capacity (MW AC) \| MW		40
Texas Solar 4 \| Variable Interest Entity, Primary Beneficiary \| Con Edison Development
Variable Interest Entity [Line Items]
Percentage of variable interests (less than)		80.00%
Ownership percentage acquired			20.00%
Tax Equity Projects \| Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Income (loss)	(64)
Income (loss), after tax	$ (48)
Tax Equity Projects \| Variable Interest Entity, Primary Beneficiary \| Con Edison Development
Variable Interest Entity [Line Items]
Percentage of variable interests (less than)	100.00%
Tax Equity Projects \| Variable Interest Entity, Primary Beneficiary \| Tax Equity Investors
Variable Interest Entity [Line Items]
Income (loss)	$ 98
Income (loss), after tax	$ 74

Variable Interest Entities - Net Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Noncontrolling interest	$ 191	$ 113
Great Valley Solar
Business Acquisition [Line Items]
Restricted cash	0	0
Non-utility property, less accumulated depreciation	293	313
Other assets	40	18
Total assets	333	331
Long-term debt due within one year	0	0
Other liabilities	17	17
Long-term debt	0	0
Total liabilities	17	17
Accumulated depreciation	9	1
Copper Mountain Solar - Mesquite Solar
Business Acquisition [Line Items]
Restricted cash	0	0
Non-utility property, less accumulated depreciation	461	492
Other assets	128	97
Total assets	589	589
Long-term debt due within one year	0	0
Other liabilities	18	33
Long-term debt	0	0
Total liabilities	18	33
Accumulated depreciation	15	1
Texas Solar 4
Business Acquisition [Line Items]
Restricted cash		4
Non-utility property, less accumulated depreciation		98
Other assets		9
Total assets		111
Long-term debt due within one year		2
Other liabilities		26
Long-term debt		56
Total liabilities		84
Accumulated depreciation		15
Tax Equity Investors \| Great Valley Solar
Business Acquisition [Line Items]
Noncontrolling interest	62	33
Tax Equity Investors \| Copper Mountain Solar - Mesquite Solar
Business Acquisition [Line Items]
Noncontrolling interest	$ 126	71
Third Party \| Texas Solar 4
Business Acquisition [Line Items]
Noncontrolling interest		$ 7

Variable Interest Entities - Summary of VIEs (Details)	12 Months Ended
Variable Interest Entities - Summary of VIEs (Details)	Dec. 31, 2019 USD ($) MW
Variable Interest Entity, Not Primary Beneficiary \| Great Valley Solar
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW	200
Maximum Exposure to Loss	$ 254,000,000
Variable Interest Entity, Not Primary Beneficiary \| Great Valley Solar \| Minimum
Variable Interest Entity [Line Items]
Power Purchase Agreement Term in Years	15 years
Variable Interest Entity, Not Primary Beneficiary \| Great Valley Solar \| Maximum
Variable Interest Entity [Line Items]
Power Purchase Agreement Term in Years	20 years
Variable Interest Entity, Not Primary Beneficiary \| Copper Mountain Solar - Mesquite Solar
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW	344
Maximum Exposure to Loss	$ 445,000,000
Variable Interest Entity, Not Primary Beneficiary \| Copper Mountain Solar - Mesquite Solar \| Minimum
Variable Interest Entity [Line Items]
Power Purchase Agreement Term in Years	20 years
Variable Interest Entity, Not Primary Beneficiary \| Copper Mountain Solar - Mesquite Solar \| Maximum
Variable Interest Entity [Line Items]
Power Purchase Agreement Term in Years	25 years
Variable Interest Entity, Primary Beneficiary \| Great Valley Solar
Variable Interest Entity [Line Items]
Maximum exposure for consolidated investments	$ 62,000,000
Variable Interest Entity, Primary Beneficiary \| Copper Mountain Solar - Mesquite Solar
Variable Interest Entity [Line Items]
Maximum exposure for consolidated investments	$ 126,000,000

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	$ 425	$ 450
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	(1)	168
Asset retirement obligations, accretion expense	14	13
Asset retirement obligations, liabilities settled	38	45
Asset retirement obligations, reductions	44	50
CECONY
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	362	292
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	96	39
Asset retirement obligations, accretion expense	12	11
Asset retirement obligations, liabilities settled	38	45
Asset retirement obligations, reductions	$ 44	$ 50

Related Party Transactions - Additional Information (Details) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) MMBTU agreement	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jan. 31, 2016
Related Party Transaction [Line Items]
Net assets	$ 18,022,000,000	$ 16,726,000,000
CECONY
Related Party Transaction [Line Items]
Net assets	14,147,000,000	12,910,000,000	$ 12,439,000,000	$ 11,829,000,000
Sale of natural gas	71,000,000	83,000,000	66,000,000
Funding limit of CECONY to O&R (not to exceed)	$ 250,000,000
CECONY \| Related Party, Lending of Funds
Related Party Transaction [Line Items]
Lending period (not more than) (months)	12 months
CECONY \| Equity Method Investee \| Mountain Valley Pipeline
Related Party Transaction [Line Items]
Amount of transaction	$ 0	0
Contract term (years)	20 years
Generating capacity per day (in dekatherms) \| MMBTU	250
CECONY \| Equity Method Investee \| Stagecoach \| Purchased Power Costs
Related Party Transaction [Line Items]
Amount of transaction	$ 33,000,000	28,000,000	$ 31,000,000
CECONY \| Equity Method Investee \| Stagecoach \| Purchased Power Costs \| Clean Energy Businesses
Related Party Transaction [Line Items]
Number of electricity sales agreements entered into \| agreement	2
CECONY \| Affiliated Entity \| Financial Electric Capacity Contract \| Con Edison Energy
Related Party Transaction [Line Items]
Gain (loss) on financial electric capacity contracts	$ (1,000,000)	(1,000,000)
O&R
Related Party Transaction [Line Items]
Net assets	762,000,000
Outstanding loans	$ 0	$ 0
CET Electric \| NY Transco
Related Party Transaction [Line Items]
Ownership interest, percentage	45.70%
CET Gas \| Mountain Valley Pipeline
Related Party Transaction [Line Items]
Percentage of equity interest owned	12.50%				12.50%
Expected reduction in equity interest	10.00%

Acquisitions, Investments and Dispositions - Mountain Valley Pipeline (Details) - CET Gas - Mountain Valley Pipeline - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2016	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Percentage of equity interest acquired	12.50%	12.50%
Payments to acquire equity interest	$ 18
Equity method investment		$ 530	$ 337
Expected reduction in equity interest		10.00%
Minimum
Schedule of Equity Method Investments [Line Items]
Estimated project cost		$ 5,300
Maximum
Schedule of Equity Method Investments [Line Items]
Equity method investment		530
Estimated project cost		$ 5,500

Acquisitions, Investments and Dispositions - Sempra Solar (Details) $ / shares in Units, $ in Millions		11 Months Ended	12 Months Ended
	Dec. 13, 2018 USD ($) $ / shares MW	Dec. 12, 2018 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Business acquisition, pre-tax gain from interests in projects	$ 131			$ 131
Long-term debt			$ 19,973	$ 18,145
Sempra Solar
Business Acquisition [Line Items]
Ownership percentage	50.00%
Renewable Electric Production Projects \| Sempra Solar
Business Acquisition [Line Items]
Project generating capacity (MW AC) \| MW	379
Sempra Solar
Business Acquisition [Line Items]
Business acquisition, pre-tax gain from interests in projects	$ 131
Business acquisition, after-tax gain from interests in projects	$ 89
Business acquisition, after-tax gain from interests in projects, per share (in dollars per share) \| $ / shares	$ 0.28
Con Edison Development \| Sempra Solar
Business Acquisition [Line Items]
Purchase price	$ 1,609
Working capital and other closing adjustments	69
Reclassification adjustment to property, plant and equipment and asset retirement obligations			$ 100
Period available to finalize purchase price allocation			1 year
Acquisition-date fair value of ownership interest held	568	$ 437
Property, plant and equipment acquired	1,354
Intangible assets acquired	878
Noncurrent assets	$ 4
Weighted average amortization period for intangible assets	16 years
Fair value of noncontrolling interest attributable to tax equity investors	$ 100
Sempra Solar \| Renewable Electric Production Projects
Business Acquisition [Line Items]
Project generating capacity (MW AC) \| MW	981
Long-term debt	$ 568
Asset retirement obligation	$ 28

Acquisitions, Investments and Dispositions - Pro Forma Supplemental Information (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 13, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Combinations [Abstract]
Revenues		$ 12,574	$ 12,337	$ 12,033
Net income		1,343	1,382	1,525
If Acquired January 1, 2017 (a)(b)
Revenue			12,655	12,331
Net income			1,279	$ 1,612
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Interest expense		37	38
Business acquisition, pre-tax gain from interests in projects	$ 131		131
Pro Forma
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Income from equity method investment		33	$ 32
Term Loan
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Short-term borrowings		$ 825
Fixed interest rate		4.64%

Acquisitions, Investments and Dispositions - Upton 2 (Details) - Con Edison Development $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2017 USD ($)	Dec. 31, 2019 MW
Upton 2
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Generating capacity (MW AC) \| MW		180
Disposal Group, Disposed of by Sale, Not Discontinued Operations \| Upton 2
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Consideration the project is sold	$ 11.0
Gain on sale of project	1.0
Gain on sale of project, net of tax	$ 0.7

Schedule I - Condensed Financial Information - Income and Comprehensive Income (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Income Statements,Captions [Line Items]
Interest expense	$ (991)	$ (819)	$ (729)
NET INCOME FOR COMMON STOCK	1,343	1,382	1,525
Comprehensive Income	$ 1,340	$ 1,392	$ 1,526
Net Income Per Share – Basic (in dollars per share)	$ 4.09	$ 4.43	$ 4.97
Net Income Per Share – Diluted (in dollars per share)	$ 4.08	$ 4.42	$ 4.94
Average Number Of Shares Outstanding—Basic (in shares)	328.5	311.7	307.1
Average Number Of Shares Outstanding—Diluted (in shares)	329.5	312.9	308.8
Parent Company
Condensed Income Statements,Captions [Line Items]
Equity in earnings of subsidiaries	$ 1,354	$ 1,447	$ 1,544
Other income (deductions), net of taxes	76	(6)	31
Interest expense	(87)	(59)	(50)
NET INCOME FOR COMMON STOCK	1,343	1,382	1,525
Comprehensive Income	$ 1,340	$ 1,392	$ 1,526
Net Income Per Share – Basic (in dollars per share)	$ 4.09	$ 4.43	$ 4.97
Net Income Per Share – Diluted (in dollars per share)	4.08	4.42	4.94
Dividends Declared Per Share (in dollars per share)	$ 2.96	$ 2.86	$ 2.76
Average Number Of Shares Outstanding—Basic (in shares)	328.5	311.1	307.1
Average Number Of Shares Outstanding—Diluted (in shares)	329.5	312.9	308.8

Schedule I - Condensed Financial Information - Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	$ 1,343	$ 1,382	$ 1,525
Change in Assets:
Taxes receivable	29	27	15
Other – net	54	(62)	0
NET CASH FLOWS FROM OPERATING ACTIVITIES	3,134	2,695	3,367
INVESTING ACTIVITIES
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,782)	(5,471)	(3,710)
FINANCING ACTIVITIES
Net proceeds of short-term debt	(874)	1,989	(477)
Issuance of long-term debt	3,017	3,030	1,697
Retirement of long-term debt	(1,195)	(1,938)	(434)
Debt issuance costs	(32)	(61)	(19)
Issuance of common shares for stock plans	54	53	51
Issuance of common shares - public offering	825	705	343
Common stock dividends	(924)	(842)	(803)
NET CASH FLOWS FROM FINANCING ACTIVITIES	859	2,938	357
NET CHANGE FOR THE PERIOD	211	162	14
BALANCE AT BEGINNING OF PERIOD	1,006	844	830
BALANCE AT END OF PERIOD	1,217	1,006	844
CECONY
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,250	1,196	1,104
Change in Assets:
Other – net	54	(96)	23
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,502	2,204	2,866
INVESTING ACTIVITIES
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,124)	(3,306)	(3,080)
FINANCING ACTIVITIES
Net proceeds of short-term debt	(55)	1,042	(450)
Issuance of long-term debt	1,300	2,740	1,200
Retirement of long-term debt	(475)	(1,836)	0
Debt issuance costs	(21)	(30)	(15)
NET CASH FLOWS FROM FINANCING ACTIVITIES	737	1,190	240
NET CHANGE FOR THE PERIOD	115	88	26
BALANCE AT BEGINNING OF PERIOD	818	730	704
BALANCE AT END OF PERIOD	933	818	730
Parent Company
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,343	1,382	1,525
Equity in earnings of subsidiaries	(1,354)	(1,447)	(1,544)
Change in Assets:
Special deposits	(3)	(8)	0
Taxes receivable	25	2	34
Other – net	44	187	21
NET CASH FLOWS FROM OPERATING ACTIVITIES	1,029	1,033	896
INVESTING ACTIVITIES
Contributions to subsidiaries	(930)	(1,110)	(434)
Debt receivable from affiliated companies	450	(825)	0
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(480)	(1,935)	(434)
FINANCING ACTIVITIES
Net proceeds of short-term debt	(783)	164	(53)
Issuance of long-term debt	825	825	400
Retirement of long-term debt	(553)	(3)	(402)
Debt issuance costs	0	0	(2)
Issuance of common shares for stock plans	54	53	51
Issuance of common shares - public offering	825	705	343
Common stock dividends	(924)	(842)	(803)
NET CASH FLOWS FROM FINANCING ACTIVITIES	(556)	902	(466)
NET CHANGE FOR THE PERIOD	(7)	0	(4)
BALANCE AT BEGINNING OF PERIOD	9	9	13
BALANCE AT END OF PERIOD	2	9	9
Parent Company \| CECONY
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	912	846	796
Parent Company \| O&R
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	47	46	44
Parent Company \| Clean Energy Businesses
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	3	15	12
Parent Company \| Con Edison Transmission
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	$ 12	$ 10	$ 8

Schedule I - Condensed Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and temporary cash investments	$ 981	$ 895
Taxes receivable	20	49
Prepayments	260	187
Other current assets	200	122
TOTAL CURRENT ASSETS	4,272	3,864
Investments in subsidiaries and others	2,065	1,766
Goodwill	446	440
Other noncurrent assets	7,853	6,541
TOTAL ASSETS	58,079	53,920	$ 48,111
Current Liabilities
Long-term debt due within one year	1,446	650
Term Loan	0	825
Notes payable	1,692	1,741
Accounts payable	1,164	1,187
Accrued taxes	76	61
Other current liabilities	371	363
TOTAL CURRENT LIABILITIES	6,287	6,207
Long-term debt	18,527	17,495
Shareholders’ Equity
Equity	18,022	16,726
TOTAL LIABILITIES AND EQUITY	58,079	53,920
Parent Company
Current Assets
Cash and temporary cash investments	2	9
Taxes receivable	18	43
Term loan receivable from affiliated companies	0	825
Accounts receivable from affiliated companies	870	536
Prepayments	32	33
Other current assets	12	12
TOTAL CURRENT ASSETS	934	1,458
Investments in subsidiaries and others	18,009	16,707
Goodwill	406	406
Deferred income tax	14	69
Long-term debt receivable from affiliated companies	1,275	900
Other noncurrent assets	0	2
TOTAL ASSETS	20,638	19,542
Current Liabilities
Long-term debt due within one year	3	3
Term Loan	0	825
Notes payable	537	495
Accounts payable	0	9
Accounts payable to affiliated companies	595	274
Accrued taxes	2	2
Other current liabilities	10	13
TOTAL CURRENT LIABILITIES	1,147	1,621
Deferred income tax	0	0
Total Liabilities	1,147	1,621
Long-term debt	1,469	1,195
Shareholders’ Equity
Common stock, including additional paid-in capital	8,089	7,151
Retained earnings	9,933	9,575
Equity	18,022	16,726
TOTAL LIABILITIES AND EQUITY	$ 20,638	$ 19,542

Schedule II - Valuation and Qualifying Accounts (Details) - Allowance For Uncollectible Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 68	$ 70	$ 83
Charged To Costs And Expenses	77	62	64
Charged To Other Accounts	0	0	0
Deductions	(71)	(64)	(77)
Balance At End of Period	74	68	70
CECONY
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	61	65	78
Charged To Costs And Expenses	72	56	60
Charged To Other Accounts	0	0	0
Deductions	(65)	(60)	(73)
Balance At End of Period	$ 68	$ 61	$ 65

Goodwill	12 Months Ended
Goodwill	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill In 2019 and 2018, Con Edison elected to perform the optional qualitative assessment for goodwill related to the 1999 O&R merger and the acquisition of a gas storage company, and the first step of the quantitative test for the acquisition of a residential solar company. In 2019 and 2018, Con Edison completed impairment tests for its goodwill of $406 million related to the O&R merger, and determined that it was not impaired. For the impairment test, $245 million and $161 million of goodwill were allocated to CECONY and O&R, respectively. In 2019 and 2018, Con Edison completed impairment tests for goodwill of $8 million related to a gas storage company acquired by CET Gas from the Clean Energy Businesses and determined that it was not impaired. In 2019 and 2018, Con Edison determined that goodwill of $14 million related to the residential solar company acquired by the Clean Energy Businesses in 2016 was not impaired. In 2018, Con Edison recorded $12 million of goodwill related to a battery storage company acquired by the Clean Energy Businesses, and, in 2019, the amount was increased to $18 million, reflecting final purchase price adjustments. In 2019, Con Edison elected to perform the first step of the quantitative test for goodwill related to the battery storage company acquisition and determined that it was not impaired. Estimates of future cash flows, projected growth rates, and discount rates inherent in the cash flow estimates for Con Edison subsidiaries other than the Utilities may vary significantly from actual results, which could result in a future impairment of goodwill.

General (Details)	12 Months Ended
General (Details)	Dec. 31, 2019 subsidiary registrant
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of registrants \| registrant	2
Number of regulated subsidiaries \| subsidiary	2

Summary of Significant Accounting Policies and Other Matters - Revenue Recognition, Remaining Performance Obligation (Details) $ in Millions	Dec. 31, 2019 USD ($)
Accounting Policies [Abstract]
Remaining performance obligation	$ 82
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Accounting Policies [Abstract]
Remaining performance obligation	$ 46
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing of satisfaction	2 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Remaining performance obligation	$ 36
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected timing of satisfaction

Summary of Significant Accounting Policies and Other Matters - Schedule of Total Excise Taxes Recorded in Operating Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Excise Taxes [Line Items]
Excise taxes	$ 323	$ 330	$ 302
CECONY
Schedule of Excise Taxes [Line Items]
Excise taxes	$ 312	$ 318	$ 292

Summary of Significant Accounting Policies and Other Matters - Other Receivables (Details) $ in Millions	Dec. 31, 2019 USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables from third parties related with power restoration	$ 8

Summary of Significant Accounting Policies and Other Matters - Goodwill (Details)	12 Months Ended
	Dec. 31, 2019 USD ($)
Accounting Policies [Abstract]
Goodwill, impairment charge	$ 0

Summary of Significant Accounting Policies and Other Matters - Pension and Other Postretirement Benefits (Details)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Investment gains and losses recognized, time period (years)	15 years
Other actuarial gains and losses recognized, time period (years)	10 years
Difference between fair value and expected market related value of plan assets (percent)	20.00%

Capitalization - Dividends (Details)	12 Months Ended
Capitalization - Dividends (Details)	Dec. 31, 2019
Debt Disclosure [Abstract]
Percentage limitation for income available for dividends (not more than)	100.00%
Rolling average calculation of income available for dividends (years)	2 years

Environmental Matters - Environmental Remediation Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Environmental Exit Cost [Line Items]
Remediation costs incurred	$ 19	$ 25
CECONY
Environmental Exit Cost [Line Items]
Remediation costs incurred	$ 13	$ 18

Environmental Matters - Accrued Liability for Asbestos Suits and Workers' Compensation Proceedings (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Site Contingency [Line Items]
Regulatory assets	$ 4,987	$ 4,370
Asbestos Suits
Site Contingency [Line Items]
Accrued liability	8	8
Regulatory assets	8	8
Workers' Compensation
Site Contingency [Line Items]
Accrued liability	78	79
Regulatory assets	3	5
CECONY
Site Contingency [Line Items]
Regulatory assets	4,600	3,987
CECONY \| Asbestos Suits
Site Contingency [Line Items]
Accrued liability	7	7
Regulatory assets	7	7
CECONY \| Workers' Compensation
Site Contingency [Line Items]
Accrued liability	73	75
Regulatory assets	$ 3	$ 5

Other Material Contingencies - Guarantees (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Guarantee obligations maximum exposure	$ 1,831	$ 2,439

Leases - Lease Cost and Cash Flows (Details) $ in Millions	12 Months Ended
Leases - Lease Cost and Cash Flows (Details) $ in Millions	Dec. 31, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 83
Operating lease cash flows	75
CECONY
Lessee, Lease, Description [Line Items]
Operating lease cost	64
Operating lease cash flows	$ 60

Derivative Instruments and Hedging Activities - Hedged Volume of Derivative Transactions (Details)	Dec. 31, 2019 MW gal MMBTU MWh
Electric Energy
Derivatives, Fair Value [Line Items]
Notional amount \| MWh	24,868,670
Capacity
Derivatives, Fair Value [Line Items]
Notional amount \| MW	28,916
Natural Gas
Derivatives, Fair Value [Line Items]
Notional amount \| MMBTU	277,827,601
Refined Fuels
Derivatives, Fair Value [Line Items]
Notional amount \| gal	5,712,000
CECONY \| Electric Energy
Derivatives, Fair Value [Line Items]
Notional amount \| MWh	22,487,800
CECONY \| Capacity
Derivatives, Fair Value [Line Items]
Notional amount \| MW	19,950
CECONY \| Natural Gas
Derivatives, Fair Value [Line Items]
Notional amount \| MMBTU	258,080,000
CECONY \| Refined Fuels
Derivatives, Fair Value [Line Items]
Notional amount \| gal	5,712,000

Derivative Instruments and Hedging Activities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	$ 128
Makeup of net credit exposure with investment-grade counterparties	24
Makeup of net credit exposure independent system operators	62
Makeup of net credit exposure with commodity exchange brokers	15
Makeup of net credit exposure non-investment grade/non-rated counterparties	27
CECONY
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	8
Makeup of net credit exposure with commodity exchange brokers	$ 8

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer out of level 3	$ 24	$ 2
CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer out of level 3	22	2
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(16)
Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(6)
Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities transferred from Level 3 to Level 2	24
Transfer out of level 3		2
Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities transferred from Level 3 to Level 2	22	2
Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	550	446
Derivative liabilities	229	66
Recurring \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	498	407
Recurring \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4	(6)
Derivative liabilities	(22)	(11)
Recurring \| Netting Adjustment \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		(1)
Recurring \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	357	293
Derivative liabilities	18	8
Recurring \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	336	270
Recurring \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	187	152
Derivative liabilities	215	49
Recurring \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	161	137
Recurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	7
Derivative liabilities	18	20
Recurring \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	1
Recurring \| Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	71	43
Derivative liabilities	188	60
Recurring \| Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	46	31
Derivative liabilities	145	32
Recurring \| Commodity \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4	(6)
Derivative liabilities	(22)	(11)
Recurring \| Commodity \| Netting Adjustment \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		(1)
Derivative liabilities	(24)	(6)
Recurring \| Commodity \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4	6
Derivative liabilities	18	8
Recurring \| Commodity \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	3
Derivative liabilities	15	5
Recurring \| Commodity \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	61	36
Derivative liabilities	174	43
Recurring \| Commodity \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	42	28
Derivative liabilities	147	30
Recurring \| Commodity \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	7
Derivative liabilities	18	20
Recurring \| Commodity \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	1
Derivative liabilities	7	3
Recurring \| Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	2
Derivative liabilities	41	6
Recurring \| Interest Rate Swaps \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Recurring \| Interest Rate Swaps \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Recurring \| Interest Rate Swaps \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	2
Derivative liabilities	41	6
Recurring \| Interest Rate Swaps \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Recurring \| Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	478	401
Recurring \| Other \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	452	376
Recurring \| Other \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring \| Other \| Netting Adjustment \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring \| Other \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	353	287
Recurring \| Other \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	333	267
Recurring \| Other \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	125	114
Recurring \| Other \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	119	109
Recurring \| Other \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring \| Other \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 0

(Millions of Dollars)

Con Edison

Operating lease cost

Operating lease cash flows