Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	ED
Entity Registrant Name	CONSOLIDATED EDISON INC
Entity Central Index Key	0001047862
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		321,077,152
Entity Public Float			$ 24.3
CECONY
Document Information [Line Items]
Entity Registrant Name	CONSOLIDATED EDISON CO OF NEW YORK INC
Entity Central Index Key	0000023632
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false

Consolidated Income Statement - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING REVENUES
Total operating revenues	$ 12,337	$ 12,033	$ 12,075
OPERATING EXPENSES
Depreciation and amortization	1,438	1,341	1,216
Taxes, other than income taxes	2,266	2,155	2,031
TOTAL OPERATING EXPENSES	9,804	9,260	9,399
Gain on sale of solar electric production project in 2017 and retail electric supply business in 2016	0	1	104
Gain on acquisition of Sempra Solar Holdings, LLC	131	0	0
OPERATING INCOME	2,664	2,774	2,780
OTHER INCOME (DEDUCTIONS)
Investment income	119	111	75
Other income	17	15	16
Allowance for equity funds used during construction	12	11	10
Other deductions	(210)	(185)	(242)
TOTAL OTHER INCOME	(62)	(48)	(141)
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,602	2,726	2,639
INTEREST EXPENSE
Interest on long-term debt	780	726	678
Other interest	49	11	24
Allowance for borrowed funds used during construction	(10)	(8)	(6)
NET INTEREST EXPENSE	819	729	696
INCOME BEFORE INCOME TAX EXPENSE	1,783	1,997	1,943
INCOME TAX EXPENSE	401	472	698
NET INCOME	$ 1,382	$ 1,525	$ 1,245
Net income per common share — basic (in dollars per share)	$ 4.43	$ 4.97	$ 4.15
Net income per common share — diluted (in dollars per share)	$ 4.42	$ 4.94	$ 4.12
AVERAGE NUMBER OF SHARES OUTSTANDING — BASIC (in shares)	311.7	307.1	300.4
AVERAGE NUMBER OF SHARES OUTSTANDING — DILUTED (in shares)	312.9	308.8	301.9
CECONY
OPERATING REVENUES
Total operating revenues	$ 10,680	$ 10,468	$ 10,165
OPERATING EXPENSES
Depreciation and amortization	1,276	1,195	1,106
Taxes, other than income taxes	2,156	2,057	1,932
TOTAL OPERATING EXPENSES	8,326	7,919	7,714
OPERATING INCOME	2,354	2,549	2,451
OTHER INCOME (DEDUCTIONS)
Investment income	13	14	8
Allowance for equity funds used during construction	11	10	8
Other deductions	(167)	(161)	(205)
TOTAL OTHER INCOME	(143)	(137)	(189)
INCOME BEFORE INTEREST AND INCOME TAX EXPENSE	2,211	2,412	2,262
INTEREST EXPENSE
Interest on long-term debt	662	615	588
Other interest	36	14	19
Allowance for borrowed funds used during construction	(9)	(6)	(4)
NET INTEREST EXPENSE	689	623	603
INCOME BEFORE INCOME TAX EXPENSE	1,522	1,789	1,659
INCOME TAX EXPENSE	326	685	603
NET INCOME	1,196	1,104	1,056
Electric
OPERATING REVENUES
Total operating revenues	8,612	8,612	8,741
Electric \| CECONY
OPERATING REVENUES
Total operating revenues	7,971	7,972	8,106
Gas
OPERATING REVENUES
Total operating revenues	2,327	2,133	1,692
OPERATING EXPENSES
Operating costs	1,041	808	477
Gas \| CECONY
OPERATING REVENUES
Total operating revenues	2,078	1,901	1,508
OPERATING EXPENSES
Operating costs	643	510	319
Steam
OPERATING REVENUES
Total operating revenues	631	595	551
Steam \| CECONY
OPERATING REVENUES
Total operating revenues	631	595	551
Non-utility
OPERATING REVENUES
Total operating revenues	767	693	1,091
Power
OPERATING EXPENSES
Operating costs	1,644	1,601	2,439
Power \| CECONY
OPERATING EXPENSES
Operating costs	1,433	1,415	1,568
Fuel
OPERATING EXPENSES
Operating costs	263	216	172
Fuel \| CECONY
OPERATING EXPENSES
Operating costs	263	216	172
Other operations and maintenance
OPERATING EXPENSES
Operating costs	3,152	3,139	3,064
Other operations and maintenance \| CECONY
OPERATING EXPENSES
Operating costs	$ 2,555	$ 2,526	$ 2,617

Consolidated Statement of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
NET INCOME	$ 1,382	$ 1,525	$ 1,245
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	10	1	7
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	10	1	7
COMPREHENSIVE INCOME	1,392	1,526	1,252
CECONY
NET INCOME	1,196	1,104	1,056
OTHER COMPREHENSIVE INCOME, NET OF TAXES
Pension and other postretirement benefit plan liability adjustments, net of taxes	1	1	2
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	1	1	2
COMPREHENSIVE INCOME	$ 1,197	$ 1,105	$ 1,058

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

+ References + Details

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING ACTIVITIES
Net income	$ 1,382	$ 1,525	$ 1,245
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,438	1,341	1,216
Deferred income taxes	408	485	783
Rate case amortization and accruals	(117)	(124)	(210)
Common equity component of allowance for funds used during construction	(12)	(11)	(10)
Net derivative (gains)/losses	8	(4)	(6)
Unbilled revenue and net unbilled revenue deferrals	18	(113)	(71)
(Gain) on sale of retail electric supply business and solar electric production projects	0	(1)	(104)
(Gain) on acquisition of Sempra Solar Holdings, LLC	(131)	0	0
Other non-cash items, net	115	5	198
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	(140)	9	(69)
Materials and supplies, including fuel oil and gas in storage	(20)	5	13
Other receivables and other current assets	(62)	0	69
Taxes receivable	27	15	87
Prepayments	(7)	(19)	20
Accounts payable	(46)	95	29
Pensions and retiree benefits obligations, net	325	414	609
Pensions and retiree benefits contributions	(479)	(467)	(515)
Accrued taxes	(49)	44	2
Accrued interest	(35)	(7)	14
Superfund and environmental remediation costs, net	(19)	(14)	69
Distributions from equity investments	107	108	68
System benefit charge	92	101	244
Deferred charges, noncurrent assets and other regulatory assets	(393)	2,376	(97)
Deferred credits and other regulatory liabilities	436	(2,524)	(68)
Other current and noncurrent liabilities	(151)	128	(57)
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,695	3,367	3,459
INVESTING ACTIVITIES
Utility construction expenditures	(3,251)	(3,028)	(2,835)
Cost of removal less salvage	(258)	(248)	(206)
Non-utility construction expenditures	(246)	(415)	(845)
Acquisition of Sempra Solar Holdings, LLC, net of cash acquired	(1,488)	0	0
Proceeds from sale of assets	5	34	252
Proceeds from the transfer of assets to NY Transco	0	0	122
Other investing activities	34	37	31
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(5,471)	(3,710)	(4,950)
FINANCING ACTIVITIES
Net (payment)/issuance of short-term debt	1,989	(477)	(475)
Issuance of long-term debt	3,030	1,697	2,590
Retirement of long-term debt	(1,938)	(434)	(735)
Debt issuance costs	(61)	(19)	(24)
Common stock dividends	(842)	(803)	(763)
Issuance of common shares - public offering	705	343	702
Issuance of common shares for stock plans	53	51	51
Distribution to noncontrolling interest	2	(1)	(1)
NET CASH FLOWS FROM FINANCING ACTIVITIES	2,938	357	1,345
CASH, TEMPORARY CASH INVESTMENTS AND RESTRICTED CASH:
NET CHANGE FOR THE PERIOD	162	14	(146)
BALANCE AT BEGINNING OF PERIOD		826	972
BALANCE AT END OF PERIOD			826
LESS: CHANGE IN CASH BALANCES HELD FOR SALE			(4)
BALANCE AT BEGINNING OF PERIOD	844	830
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	1,006	844	830
Cash paid/(received) during the period for:
Interest	805	725	664
Income taxes	0	(29)	(180)
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	369	432	388
Issuance of common shares for dividend reinvestment	47	46	46
Debt assumed with business acquisitions	568	0	195
Software licenses acquired but unpaid as of end of period	100	0	0
Electric and Gas Transmission Projects
INVESTING ACTIVITIES
Investments in/acquisitions of projects	(248)	(45)	(1,076)
Renewable Electric Production Projects
INVESTING ACTIVITIES
Investments in/acquisitions of projects	(19)	(45)	(393)
CECONY
OPERATING ACTIVITIES
Net income	1,196	1,104	1,056
PRINCIPAL NON-CASH CHARGES/(CREDITS) TO INCOME
Depreciation and amortization	1,276	1,195	1,106
Deferred income taxes	354	575	545
Rate case amortization and accruals	(133)	(142)	(227)
Common equity component of allowance for funds used during construction	(11)	(10)	(8)
Unbilled revenue and net unbilled revenue deferrals	(4)	(17)	(36)
Other non-cash items, net	13	(59)	5
CHANGES IN ASSETS AND LIABILITIES
Accounts receivable - customers	(153)	15	(23)
Materials and supplies, including fuel oil and gas in storage	(17)	(17)	18
Other receivables and other current assets	(96)	23	(11)
Accounts receivables from affiliated companies	(150)	45	81
Prepayments	(9)	(8)	13
Accounts payable	(27)	125	20
Accounts payable to affiliated companies	7	0	(2)
Pensions and retiree benefits obligations, net	293	370	579
Pensions and retiree benefits contributions	(440)	(420)	(476)
Accrued taxes	(47)	52	1
Accrued taxes to affiliated companies	(72)	(47)	117
Accrued interest	(1)	2	(7)
Superfund and environmental remediation costs, net	(18)	(12)	79
System benefit charge	86	85	221
Deferred charges, noncurrent assets and other regulatory assets	(314)	2,212	(172)
Deferred credits and other regulatory liabilities	549	(2,242)	179
Other current and noncurrent liabilities	(78)	37	(20)
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,204	2,866	3,038
INVESTING ACTIVITIES
Utility construction expenditures	(3,051)	(2,840)	(2,672)
Cost of removal less salvage	(255)	(240)	(203)
Proceeds from the transfer of assets to NY Transco	0	0	122
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,306)	(3,080)	(2,753)
FINANCING ACTIVITIES
Net (payment)/issuance of short-term debt	1,042	(450)	(433)
Issuance of long-term debt	2,740	1,200	1,300
Retirement of long-term debt	(1,836)	0	(650)
Debt issuance costs	(30)	(15)	(13)
Capital contribution by parent	120	301	100
Dividend to parent	(846)	(796)	(744)
NET CASH FLOWS FROM FINANCING ACTIVITIES	1,190	240	(440)
CASH, TEMPORARY CASH INVESTMENTS AND RESTRICTED CASH:
NET CHANGE FOR THE PERIOD	88	26	(155)
BALANCE AT BEGINNING OF PERIOD	730	704	859
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	818	730	704
Cash paid/(received) during the period for:
Interest	662	602	581
Income taxes	195	108	(162)
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION
Construction expenditures in accounts payable	299	351	295
Software licenses acquired but unpaid as of end of period	$ 95	$ 0	$ 0

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and temporary cash investments	$ 895	$ 797
Accounts receivable - customers, less allowance for uncollectible accounts	1,267	1,103
Other receivables, less allowance for uncollectible accounts	285	160
Taxes receivable	49	76
Accrued unbilled revenue	514	598
Fuel oil, gas in storage, materials and supplies, at average cost	358	334
Prepayments	187	178
Regulatory assets	76	67
Restricted cash	111	47
Other current assets	122	177
TOTAL CURRENT ASSETS	3,864	3,537
INVESTMENTS	1,766	2,001
UTILITY PLANT, AT ORIGINAL COST
General	3,331	3,008
TOTAL	45,371	42,731
Less: Accumulated depreciation	9,769	9,063
Net	35,602	33,668
Construction work in progress	1,978	1,605
NET UTILITY PLANT	37,580	35,273
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	4,000	1,776
Construction work in progress	169	551
NET PLANT	41,749	37,600
OTHER NONCURRENT ASSETS
Goodwill	440	428
Intangible assets, less accumulated amortization of $29 and $15 in 2018 and 2017, respectively	1,654	131
Regulatory assets	4,294	4,266
Other deferred charges and noncurrent assets	153	148
TOTAL OTHER NONCURRENT ASSETS	6,541	4,973
TOTAL ASSETS	53,920	48,111
CURRENT LIABILITIES
Long-term debt due within one year	650	1,298
Term Loan	825	0
Notes payable	1,741	577
Accounts payable	1,187	1,286
Customer deposits	351	346
Accrued taxes	61	108
Accrued interest	129	143
Accrued wages	109	105
Fair value of derivative liabilities	50	17
Regulatory liabilities	114	101
System benefit charge	627	535
Other current liabilities	363	386
TOTAL CURRENT LIABILITIES	6,207	4,902
NONCURRENT LIABILITIES
Provision for injuries and damages	146	153
Pensions and retiree benefits	1,228	1,443
Superfund and other environmental costs	779	737
Asset retirement obligations	450	314
Fair value of derivative liabilities	16	38
Deferred income taxes and unamortized investment tax credits	5,820	5,495
Regulatory liabilities	4,641	4,577
Other deferred credits and noncurrent liabilities	299	296
TOTAL NONCURRENT LIABILITIES	13,379	13,053
LONG-TERM DEBT	17,495	14,731
EQUITY
Common shareholders’ equity	16,726	15,418
Noncontrolling interest	113	7
TOTAL EQUITY (See Statement of Equity)	16,839	15,425
TOTAL LIABILITIES AND EQUITY	53,920	48,111
Electric
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	30,378	28,994
Gas
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	9,100	8,256
Steam
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	2,562	2,473
CECONY
CURRENT ASSETS
Cash and temporary cash investments	818	730
Accounts receivable - customers, less allowance for uncollectible accounts	1,163	1,009
Other receivables, less allowance for uncollectible accounts	211	92
Taxes receivable	5	19
Accrued unbilled revenue	392	454
Accounts receivable from affiliated companies	214	64
Fuel oil, gas in storage, materials and supplies, at average cost	304	287
Prepayments	117	108
Regulatory assets	64	62
Other current assets	69	84
TOTAL CURRENT ASSETS	3,357	2,909
INVESTMENTS	385	383
UTILITY PLANT, AT ORIGINAL COST
General	3,056	2,753
TOTAL	42,508	40,024
Less: Accumulated depreciation	8,988	8,321
Net	33,520	31,703
Construction work in progress	1,850	1,502
NET UTILITY PLANT	35,370	33,205
NON-UTILITY PLANT
Non-utility property, less accumulated depreciation	4	4
NET PLANT	35,374	33,209
OTHER NONCURRENT ASSETS
Goodwill	245	245
Regulatory assets	3,923	3,863
Other deferred charges and noncurrent assets	69	87
TOTAL OTHER NONCURRENT ASSETS	3,992	3,950
TOTAL ASSETS	43,108	40,451
CURRENT LIABILITIES
Long-term debt due within one year	475	1,200
Notes payable	1,192	150
Accounts payable	977	1,057
Customer deposits	339	334
Accounts payable to affiliated companies	17	10
Accrued taxes	55	102
Accrued taxes to affiliated companies	0	72
Accrued interest	112	113
Accrued wages	99	95
Fair value of derivative liabilities	25	12
Regulatory liabilities	73	65
System benefit charge	569	483
Other current liabilities	267	245
TOTAL CURRENT LIABILITIES	4,200	3,938
NONCURRENT LIABILITIES
Provision for injuries and damages	141	147
Pensions and retiree benefits	952	1,140
Superfund and other environmental costs	693	637
Asset retirement obligations	292	287
Fair value of derivative liabilities	6	31
Deferred income taxes and unamortized investment tax credits	5,739	5,306
Regulatory liabilities	4,258	4,219
Other deferred credits and noncurrent liabilities	241	242
TOTAL NONCURRENT LIABILITIES	12,322	12,009
LONG-TERM DEBT	13,676	12,065
EQUITY
Common shareholders’ equity	12,910	12,439
TOTAL LIABILITIES AND EQUITY	43,108	40,451
CECONY \| Electric
CURRENT ASSETS
Accrued unbilled revenue	6
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	28,595	27,299
CECONY \| Gas
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	8,295	7,499
CECONY \| Steam
UTILITY PLANT, AT ORIGINAL COST
Utility plant, at original cost	$ 2,562	$ 2,473

Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts receivable - customers, allowance for uncollectible accounts	$ 62	$ 63
Other receivables, allowance for uncollectible accounts	5	8
Non-utility property, accumulated depreciation	275	201
Intangible assets, accumulated amortization	29	15
CECONY
Accounts receivable - customers, allowance for uncollectible accounts	57	58
Other receivables, allowance for uncollectible accounts	3	7
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, 2015		293,000,000								235,000,000
BALANCE AS OF BEGINNING OF PERIOD at Dec. 31, 2015	$ 13,061	$ 32	$ 5,030	$ 9,123	$ (1,038)	$ (61)	$ (34)	$ 9							$ (9)
BALANCE AS OF BEGINNING OF PERIOD at Dec. 31, 2015									$ 11,415	$ 589	$ 4,247	$ 7,611	$ (962)	$ (61)	(9)
TREASURY STOCK, BALANCE AS OF BEGINNING OF PERIOD (in shares) at Dec. 31, 2015					23,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,245			1,245					1,056			1,056
Common stock dividends	(809)			(809)					(744)			(744)
Issuance of common shares - public offering (in shares)		10,000,000
Issuance of common shares - public offering	702	$ 1	723			(22)
Issuance of common shares for stock plans (in shares)		2,000,000
Issuance of common shares for stock plans	101		101
Capital contribution by parent									100		100
Other comprehensive income	7						7		2						2
Noncontrolling interest	(1)							(1)
BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2016		305,000,000								235,000,000
BALANCE AS OF END OF PERIOD at Dec. 31, 2016	14,306	$ 33	5,854	9,559	$ (1,038)	(83)	(27)	8							(7)
BALANCE AS OF END OF PERIOD at Dec. 31, 2016									11,829	$ 589	4,347	7,923	(962)	(61)	(7)
TREASURY STOCK, BALANCE AS OF END OF PERIOD (in shares) at Dec. 31, 2016					23,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,525			1,525					1,104			1,104
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	15,418								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			1,382					1,196			1,196
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		321,000,000							21,976,200	235,000,000
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

Consolidated Statement of Capitalization - USD ($) shares in Millions, $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Capitalization, Equity [Line Items]
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS (in shares)	321	310
TOTAL EQUITY BEFORE ACCUMULATED OTHER COMPREHENSIVE LOSS	$ 16,742	$ 15,444
Pension plan liability adjustments, net of taxes	(12)	(23)
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	(4)	(3)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(16)	(26)
Equity	16,726	15,418
Noncontrolling interest	113	7
TOTAL EQUITY (See Statement of Equity)	$ 16,839	$ 15,425
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	$ 12,915	$ 12,445
Pension plan liability adjustments, net of taxes	0	(3)
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	(5)	(3)
TOTAL ACCUMULATED OTHER COMPREHENSIVE LOSS, NET OF TAXES	(5)	(6)
Equity	12,910	12,439
TOTAL SHAREHOLDER’S EQUITY (See Statement of Shareholder’s Equity)	$ 12,910	$ 12,439

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

Dec. 31, 2018

Dec. 31, 2017

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

Other long-term debt

$ 304

$ 310

Unamortized debt expense

(152)

(113)

Unamortized debt discount

(33)

(29)

TOTAL

18,145

16,029

Less: Long-term debt due within one year

650

1,298

TOTAL LONG-TERM DEBT

17,495

14,731

TOTAL CAPITALIZATION

34,221

30,149

CECONY

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

Unamortized debt expense

(107)

(94)

Unamortized debt discount

(32)

(27)

TOTAL

14,151

13,265

Less: Long-term debt due within one year

475

1,200

TOTAL LONG-TERM DEBT

13,676

12,065

TOTAL CAPITALIZATION

26,586

24,504

Copper Mountain Solar 2

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

TOTAL PROJECT DEBT

230

Coram

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

TOTAL PROJECT DEBT

$ 160

170

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]

TOTAL PROJECT DEBT

$ 298

Wind Holdings

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

Interest Rate

4.41%

TOTAL PROJECT DEBT

$ 137

Copper Mountain Solar 1

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

TOTAL PROJECT DEBT

Mesquite Solar 1

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

TOTAL PROJECT DEBT

$ 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%

Broken Bow II

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

Interest Rate

4.82%

TOTAL PROJECT DEBT

$ 69

Texas Solar 4

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

TOTAL PROJECT DEBT

$ 58

Texas Solar 4 | Minimum

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

Interest Rate

4.95%

Texas Solar 4 | Maximum

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

Interest Rate

5.25%

California Solar 2

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

Interest Rate

3.94%

TOTAL PROJECT DEBT

$ 103

110

California Solar 3

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

Interest Rate

4.07%

TOTAL PROJECT DEBT

$ 89

California Solar

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

Interest Rate

4.78%

TOTAL PROJECT DEBT

$ 190

Texas Solar 5

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

Interest Rate

4.53%

TOTAL PROJECT DEBT

$ 150

155

Texas Solar 7

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

Interest Rate

4.21%

TOTAL PROJECT DEBT

$ 206

214

Upton County Solar

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

Interest Rate

4.45%

TOTAL PROJECT DEBT

$ 94

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

2,076

915

Debentures

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

TOTAL

15,500

13,860

Debentures | CECONY

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

TOTAL

$ 13,840

12,300

Debentures | Debenture Series 2008A, 5.85% Due 2018

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

Interest Rate

5.85%

TOTAL

$ 0

600

Debentures | Debenture Series 2008A, 5.85% Due 2018 | CECONY

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

Interest Rate

5.85%

TOTAL

$ 0

600

Debentures | Debenture Series 2008A, 6.15% Due 2018

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

Interest Rate

6.15%

TOTAL

$ 0

Debentures | Debenture Series 2008C, 7.125% Due 2018

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

Interest Rate

7.125%

TOTAL

$ 0

600

Debentures | Debenture Series 2008C, 7.125% Due 2018 | CECONY

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

Interest Rate

7.125%

TOTAL

$ 0

600

Debentures | Debenture Series 2009A, 4.96% Due 2019

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

Interest Rate

4.96%

TOTAL

$ 60

Debentures | Debenture Series 2009B, 6.65% Due 2019

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

Interest Rate

6.65%

TOTAL

$ 475

475

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

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

Interest Rate

6.65%

TOTAL

$ 475

475

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 2017A, 2.00% Due 2020

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

Interest Rate

2.00%

TOTAL

$ 400

400

Debentures | Debenture Series 2018C, Variable Rate, Due 2021

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

TOTAL

640

Debentures | Debenture Series 2018C, Variable Rate, Due 2021 | CECONY

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

TOTAL

$ 640

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 Series 2014B, 3.30% Due 2024

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

Interest Rate

3.30%

TOTAL

$ 250

250

Debentures | Debenture Series 2014B, 3.30% 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

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

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

Interest Rate

3.80%

TOTAL

$ 300

Debentures | Debenture Series 2018D, 4.00% Due 2028

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

Interest Rate

4.00%

TOTAL

$ 500

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

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

Interest Rate

4.00%

TOTAL

$ 500

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 Series 2008B, 6.75% Due 2038

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

Interest Rate

6.75%

TOTAL

$ 600

600

Debentures | Debenture Series 2008B, 6.75% Due 2038 | CECONY

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

Interest Rate

6.75%

TOTAL

$ 600

600

Debentures | Debenture Series 2009B, 6.00% Due 2039

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

Interest Rate

6.00%

TOTAL

$ 60

Debentures | Debenture Series 2009C, 5.50% Due 2039

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

Interest Rate

5.50%

TOTAL

$ 600

600

Debentures | Debenture Series 2009C, 5.50% Due 2039 | CECONY

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

Interest Rate

5.50%

TOTAL

$ 600

600

Debentures | Debenture Series 2010B, 5.70% Due 2040

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

Interest Rate

5.70%

TOTAL

$ 350

350

Debentures | Debenture Series 2010B, 5.70% Due 2040 | CECONY

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

Interest Rate

5.70%

TOTAL

$ 350

350

Debentures | Debenture Series 2010B, 5.50% Due 2040

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

Interest Rate

5.50%

TOTAL

$ 115

115

Debentures | Debenture Series 2012A, 4.20% Due 2042

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

Interest Rate

4.20%

TOTAL

$ 400

400

Debentures | Debenture Series 2012A, 4.20% Due 2042 | CECONY

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

Interest Rate

4.20%

TOTAL

$ 400

400

Debentures | Debenture Series 2013A, 3.95% Due 2043

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

Interest Rate

3.95%

TOTAL

$ 700

700

Debentures | Debenture Series 2013A, 3.95% Due 2043 | CECONY

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

Interest Rate

3.95%

TOTAL

$ 700

700

Debentures | Debenture Series 2014A, 4.45% Due 2044

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

Interest Rate

4.45%

TOTAL

$ 850

850

Debentures | Debenture Series 2014A, 4.45% Due 2044 | CECONY

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

Interest Rate

4.45%

TOTAL

$ 850

850

Debentures | Debenture Series 2015A, 4.50% due 2045

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

Interest Rate

4.50%

TOTAL

$ 650

650

Debentures | Debenture Series 2015A, 4.50% due 2045 | CECONY

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

Interest Rate

4.50%

TOTAL

$ 650

650

Debentures | Debenture Series 2015A, 4.95% 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 Series 2016A, 3.85% Due 2046

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

Interest Rate

3.85%

TOTAL

$ 550

550

Debentures | Debenture Series 2016A, 3.85% 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

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

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

Interest Rate

4.65%

TOTAL

$ 600

Debentures | Debenture Series 2018A, 4.35% Due 2048

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

Interest Rate

4.35%

TOTAL

$ 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 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

400.00%

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

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

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

Interest Rate

4.50%

TOTAL

$ 700

Tax-Exempt Debt

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

TOTAL PROJECT DEBT

^[1]

450

1,086

Tax-Exempt Debt | CECONY

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

TOTAL

450

1,086

Tax-Exempt Debt | Tax Exempt Debt Series 2004B Series 1, 2.45% Due 2032

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

TOTAL PROJECT DEBT

^[1]

127

Tax-Exempt Debt | Tax Exempt Debt Series 2004B Series 1, 2.45% Due 2032 | CECONY

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

TOTAL

127

Tax-Exempt Debt | Tax Exempt Debt Series 1999A, 1.834% Due 2034

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

TOTAL PROJECT DEBT

^[1]

293

Tax-Exempt Debt | Tax Exempt Debt Series 1999A, 1.834% Due 2034 | CECONY

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

TOTAL

293

Tax-Exempt Debt | Tax Exempt Debt Series 2004B Series 2, 1.68% Due 2035

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

TOTAL PROJECT DEBT

^[1]

Tax-Exempt Debt | Tax Exempt Debt Series 2004B Series 2, 1.68% Due 2035 | CECONY

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

TOTAL

Tax-Exempt Debt | Tax Exempt Debt Series 2001B, 1.796% Due 2036

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

TOTAL PROJECT DEBT

^[1]

Tax-Exempt Debt | Tax Exempt Debt Series 2001B, 1.796% Due 2036 | CECONY

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

TOTAL

$ 0

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

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

Interest Rate

^[1]

1.74%

TOTAL PROJECT DEBT

^[1]

$ 225

225

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

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

Interest Rate

1.74%

TOTAL

$ 225

225

Tax-Exempt Debt | Tax Exempt Debt Series 2004A, 1.943% Due 2039

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

TOTAL PROJECT DEBT

^[1]

Tax-Exempt Debt | Tax Exempt Debt Series 2004A, 1.943% Due 2039 | CECONY

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

TOTAL

$ 0

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

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

Interest Rate

^[1]

1.75%

TOTAL PROJECT DEBT

^[1]

$ 99

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

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

Interest Rate

1.75%

TOTAL

$ 99

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

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

Interest Rate

^[1]

1.71%

TOTAL PROJECT DEBT

^[1]

$ 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

1.71%

TOTAL

$ 126

[1]	Rates are to be reset weekly; December 31, 2018 rates shown.

General	12 Months Ended
General	Dec. 31, 2018
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. has three subsidiaries: Consolidated Edison Development, Inc. (Con Edison Development), a company that develops, owns and operates renewable and energy infrastructure projects; Consolidated Edison Energy, Inc. (Con Edison Energy), a company that provides energy-related products and services to wholesale customers; and Consolidated Edison Solutions, Inc. (Con Edison Solutions), a company that provides energy-related products and services to retail customers. In December 2018, a Con Edison Development subsidiary 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, 2018

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 will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable state regulators.

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

Revenues

Adoption of New Standard

On January 1, 2018, the Companies adopted Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts that were not completed. No charge to retained earnings for cumulative impact was required as a result of the Companies’ adoption of Topic 606.

Revenue Recognition

The following table presents, for the year ended December 31, 2018, revenue from contracts with customers as defined in Topic 606, as well as additional revenue from sources other than contracts with customers, disaggregated by major source.



(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)		Total operating revenues
CECONY
Electric	$7,920		$51		$7,971
Gas	2,052		26		2,078
Steam	625		6		631
Total CECONY	$10,597		$83		$10,680
O&R
Electric	647		(5)		642
Gas	256		(7)		249
Total O&R	$903		$(12)		$891
Clean Energy Businesses
Renewables	329	(b)	—		329
Energy services	95		—		95
Other	—		339		339
Total Clean Energy Businesses	$424		$339		$763
Con Edison Transmission	4		—		4
Other (c)	—		(1	)	(1	)
Total Con Edison	$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 $103 million 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.

Con Edison Development recognizes revenue for the sale of energy from renewable electric production projects as energy is generated and billed to counterparties. Con Edison Development accrues revenues at the end of each month for energy generated but not yet billed to counterparties. Con Edison Energy recognizes 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. Con Edison Solutions recognizes revenue for providing energy-efficiency services to government and commercial customers, and Con Edison Development recognizes 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.



(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1, 2018	$58	$87
Additions (c)	144	38
Subtractions (c)	173	105	(d)
Ending balance as of December 31, 2018	$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 $105 million in subtractions from unearned revenue, $50 million was included in the balance as of December 31, 2017.

As of December 31, 2018, the aggregate amount of the remaining fixed performance obligations is $95 million, of which $59 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)	2018	2017	2016
Con Edison	$330	$302	$336
CECONY	318	292	316

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, 2018, Con Edison and CECONY other receivables' balances related to such costs were $104 million and $98 million, respectively.

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 5.4 percent, 5.5 percent and 4.7 percent for 2018, 2017 and 2016, respectively. The AFUDC rates for O&R were 2.2 percent, 2.5 percent and 3.5 percent for 2018, 2017 and 2016, 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 3.1 percent for 2018, 2017 and 2016. The average depreciation rates for O&R were 2.9 percent for 2018, 2017 and 2016.

The estimated lives for utility plant for CECONY range from 5 to 95 years for electric, 5 to 100 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, 2018 and 2017, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Electric
Generation	$593	$544	$592	$544
Transmission	3,333	3,210	3,106	2,990
Distribution	19,750	18,959	18,716	17,996
Gas (a)	7,714	6,976	7,107	6,403
Steam	1,830	1,798	1,830	1,798
General	2,306	2,105	2,102	1,905
Held for future use	76	76	67	67
Construction work in progress	1,978	1,605	1,850	1,502
Net Utility Plant	$37,580	$35,273	$35,370	$33,205

(a) Primarily distribution.

At December 31, 2018, general utility plant of Con Edison and CECONY included $100 million and $95 million, respectively, related to a May 2018 acquisition of software licenses. The software licenses asset is being amortized over a period of 15 years, and the estimated aggregate annual amortization expense for Con Edison and CECONY is $7 million. At December 31, 2018, the accumulated amortization for Con Edison and CECONY was $3 million.

Under the Utilities’ rate plans, the aggregate annual depreciation allowance for the period ended December 31, 2018 was $1,323 million, including $1,253 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 and gas storage. 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 range from 3 to 30 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 2018, Con Edison recorded no impairment charge on goodwill. See Note K.

Long–Lived and Intangible Assets

Con Edison evaluates the impairment of long-lived assets and intangible assets with definite lives, based on projections of undiscounted future cash flows, which projections may vary significantly from future projections or actual cash flows, whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event an evaluation indicates that such cash flows cannot be expected to be sufficient to fully recover the assets, the assets are 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 Con Edison Development in 2016 and 2018. At December 31, 2018 and 2017, intangible assets arising from power purchase agreements, including the PG&E PPAs (discussed below), were $1,712 million and $131 million, net of accumulated amortization of $22 million and $9 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 and an immaterial amount, net of accumulated amortization of $7 million and $6 million, at December 31, 2018 and 2017, respectively. CECONY’s other intangible assets were immaterial at December 31, 2018 and 2017. Con Edison recorded amortization expense related to its intangible assets of $14 million in 2018, $9 million in 2017 and $2 million in 2016. Con Edison expects amortization expense to be $105 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 2017 or 2016.

In January 2019, Pacific Gas and Electric Company (PG&E) filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The output of Con Edison Development renewable electric production projects with an aggregate of 680 MW (AC) of generating capacity (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 or, pursuant to a January 2019 FERC order (which PG&E is challenging), the bankruptcy court and FERC. 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 Con Edison Development will not be made during the pendency of the bankruptcy. At December 31, 2018, Con Edison’s consolidated balance sheet included $885 million of net non-utility plant relating to the PG&E Projects, $1,125 million of intangible assets relating to the PG&E PPAs, $292 million of net non-utility plant of additional projects that secure the related project debt and $1,050 million of non-recourse related project debt. 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 has 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 in the PG&E bankruptcy. 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 in the PG&E bankruptcy or any such rejection becomes likely, there will be an impairment of the related intangible asset 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 and the Clean Energy Businesses that are accounted for under the equity method, and the fair value of the Utilities’ supplemental retirement income plan and deferred income plan assets. The following investment assets are included in the Companies' consolidated balance sheets at December 31, 2018 and 2017:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018		2017
CET Gas investment in Stagecoach Gas Services, LLC	$948	$971		$—		$—
CET Gas investment in Mountain Valley Pipeline, LLC (a)	363	98	—		—
Supplemental retirement income plan assets (c)	326	330	301		301
Deferred income plan assets	75	73	75		73
CET Electric investment in New York Transco, LLC	52	53	—		—
Con Edison Development equity method investments (b)	—	467	—		—
Other	2	9	9		9
Total investments	$1,766	$2,001	$385		$383


(a)	See Note U.


(b)	Upon completion of the acquisition of Sempra Solar Holdings, LLC in December 2018, Con Edison is accounting on a consolidated basis for certain jointly-owned renewable electric production projects that previously were accounted for as equity method investments. See Note U.


(c)	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. Generally, O&R also defers such difference pursuant to its 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. 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)	2018	2017	2016
Con Edison	$24	$24	$24
CECONY	23	23	22

Reclassification

Certain prior year amounts have been reclassified to conform with the current year presentation.

Earnings Per Common Share

Con Edison presents basic and diluted earnings per share on the face of its consolidated income statement. Basic earnings per share (EPS) are calculated by dividing earnings available to common shareholders (“Net income” 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 certain 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)	2018	2017	2016
Net income	$1,382	$1,525	$1,245
Weighted average common shares outstanding – basic	311.7	307.1	300.4
Add: Incremental shares attributable to effect of potentially dilutive securities	1.2	1.7	1.5
Adjusted weighted average common shares outstanding – diluted	312.9	308.8	301.9
Net Income per common share – basic	$4.43	$4.97	$4.15
Net Income per common share – diluted	$4.42	$4.94	$4.12

The computation of diluted EPS for the year ended December 31, 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, 2015 (a)	$(34)	$(9)
OCI before reclassifications, net of tax of $(1) for Con Edison and CECONY	2	1
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, 2016	7	2
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)

(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

On January 1, 2018, the Companies adopted Accounting Standard Update (ASU) 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash," which they applied retrospectively for each prior period presented. Pursuant to ASU 2016-18, cash, temporary cash investments and restricted cash are presented on a combined basis in the Companies’ consolidated statements of cash flows. At December 31, 2018 and 2017, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Cash and temporary cash investments	$895	$797	$818	$730
Restricted cash (a)	111	47	—	—
Total cash, temporary cash investments and restricted cash	$1,006	$844	$818	$730

(a)

Restricted cash included cash of Con Edison Development renewable electric production project subsidiaries ($109 million and $46 million at December 31, 2018 and 2017, respectively) that, under the related project debt agreements, is 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. Also, during the pendency of the PG&E bankruptcy, restricted cash may also include additional cash that, unless the lenders for the related project debt agree, may not be distributed from the related projects to Con Edison Development. See "Long-Lived and Intangible Assets,” above. In addition, restricted cash includes O&R's New Jersey utility subsidiary, Rockland Electric Company transition bond charge collections, net of principal, interest, trustee and service fees ($2 million and $1 million at December 31, 2018 and 2017, respectively) that are restricted until the bonds mature in 2019.

Regulatory Matters

12 Months Ended

Dec. 31, 2018

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 New Jersey Board of Public Utilities (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. See "Other Regulatory Matters," below. 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 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 2014 – December 2016	January 2017 – December 2019 (b)
Base rate changes	Yr. 1 – $(76.2) million (a) Yr. 2 – $124.0 million (a) Yr. 3 – None	Yr. 1 – $195 million (c) Yr. 2 – $155 million (c) Yr. 3 – $155 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 and 2 – $(37) million (d) Yr. 3 – $123 million (d)	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million



Other revenue sources	Retention of $90 million of annual transmission congestion revenues.	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 and 2018, the company recorded $13 million and $25 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved other incentives of $5 million in 2017 and 2018 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $3 million for service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred for customer benefit $146 million, $98 million and $101 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017 and 2018, the company deferred for customer benefit $45 million and $(6) million of revenues, respectively.
Recoverable energy costs (e)	Current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $57 million, $26 million and $68 million of net regulatory liabilities, respectively (f).	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (f), municipal infrastructure support costs (g), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (h). In 2017 and 2018, the company deferred $35 million and $189 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred $6 million and $17 million as a regulatory liability in 2014 and 2015, respectively. In 2016, $9 million was deferred as a regulatory asset.	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, $0.4 was deferred as a regulatory liability.
Average rate base	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent	9.0 percent
Actual return on common equity	Yr. 1 – 9.04 percent Yr. 2 – 10.16 percent Yr. 3 – 9.66 percent	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 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 $44.4 million and $6.5 million above the threshold for 2015 and 2016, respectively.	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, the company had no earnings sharing above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred; this amount was amortized to $0 at December 31, 2016.

(b)

In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's electric rate plan for January 2017 through December 2019. 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, 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.

(c)

The electric base rate increases are 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 are being 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 ten-year period, including the overall pre-tax rate of return on such costs.

(d)

Amounts reflect annual amortization of $107 million of the regulatory asset for deferred Superstorm Sandy and other major storm costs. The costs recoverable from customers were reduced by $4 million. The costs are no longer subject to NYSPSC staff review and the recovery of the costs is no longer subject to refund. In 2016, an additional $123 million of net regulatory liabilities were amortized to income.

(e)

For transmission service provided pursuant to the open access transmission tariff of PJM Interconnection LLC (PJM), unless and until changed by the NYSPSC, the company will recover all charges incurred associated with the transmission service. In April 2017, the transmission service terminated because CECONY did not exercise its option to continue the service. See "Other Regulatory Matters," below.


(f)	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 (5.0, 7.5 or 10.0 basis points, depending on the year).

(g)

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 of 30 percent of the amount reflected in rates.

(h)

In addition, amounts reflected in rates relating to the regulatory asset for future income tax and the excess deferred federal income tax liability are subject to reconciliation. The NYSPSC staff is to audit the regulatory asset and the tax liability. Differences resulting from the NYSPSC staff review will be deferred for NYSPSC determination of any amounts to be refunded or collected from customers. See "Other Regulatory Matters," below.

In January 2019, CECONY filed a request with the NYSPSC for an electric rate increase of $485 million, effective January 2020. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 50 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate debt, storms, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. The company is also proposing full reconciliation of capital interference costs. In addition, the company is, among other things, proposing continuation of earnings opportunities from Earnings Adjustment Mechanisms (EAM) for meeting energy efficiency goals. The proposed EAM earnings opportunities are at 100 basis points of common equity annually. The filing also reflects continuation of the revenue decoupling mechanism and the provisions pursuant to which the company recovers its purchased power and fuel costs from customers. The requested rate increase was mitigated, in part, by the TCJA, including reduced tax rate, and amortization of excess deferred income taxes and 2018 tax savings. See "Other Regulatory Matters," below.

The filing includes supplemental information regarding electric rate plans for 2021 and 2022, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $352 million and $263 million effective January 2021 and 2022, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 50 percent.



CECONY – Gas
Effective period	January 2014 – December 2016	January 2017 - December 2019 (b)
Base rate changes	Yr. 1 – $(54.6) million (a) Yr. 2 – $38.6 million (a) Yr. 3 – $56.8 million (a)	Yr. 1 – $(5) million (b) Yr. 2 – $92 million (b) Yr. 3 – $90 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$4 million over three years	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million
Other revenue sources	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million, $66 million and $65 million of such revenues in 2014, 2015 and 2016, respectively.	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 and 2018, the company achieved incentives of $7 million and $6 million, respectively that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $5 million for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred $28 million, $54 million and $71 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017 and 2018, the company deferred $3 million and $12 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014, 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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 $5 million and $4 million of negative revenue adjustments, respectively.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $38 million, $11 million, and $32 million of net regulatory liabilities, respectively. (c)	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes, municipal infrastructure support costs, the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (d) In 2017 and 2018, the company deferred $2 million of net regulatory liabilities and $44 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million In 2015 $1 million was deferred as a regulatory liability. In 2014 and 2016 the company deferred an immaterial amount.	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.
Average rate base	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	9.3 percent	9.0 percent
Actual return on common equity	Yr. 1 – 8.02 percent Yr. 2 – 8.13 percent Yr. 3 – 7.83 percent	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent



Earnings sharing	Most 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, 2015 and 2016, the company had no earnings above the threshold.	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 and 2018, the company had no earnings above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred which resulted in a $32 million regulatory liability at December 31, 2016.


(b)	In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's gas rate plan for January 2017 through December 2019. The gas base rate decrease is offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.


(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)	See footnotes (e), (f), (g) and (h) to the table under "CECONY - Electric" above.

In January 2019, CECONY filed a request with the NYSPSC for a gas rate increase of $210 million, effective January 2020. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 50 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate debt, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. The company is also proposing full reconciliation of capital interference costs. In addition, the company is, among other things, proposing continuation of earnings opportunities from Earnings Adjustment Mechanisms (EAM) for meeting energy efficiency goals. The proposed EAM earnings opportunities are at 70 basis points of common equity annually. The filing also reflects continuation of the revenue decoupling mechanism (RDM) and provisions pursuant to which the company recovers its purchased gas costs from customers. Within the filing, the company is proposing to change the gas RDM from a revenue per customer methodology to a revenue per class methodology. The requested rate increase was mitigated, in part, by the TCJA, including reduced tax rate, and amortization of excess deferred income taxes and 2018 tax savings. See "Other Regulatory Matters," below.

The filing includes supplemental information regarding gas rate plans for 2021 and 2022, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $138 million and $155 million effective January 2021 and 2022, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 50 percent.



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
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 penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014, 2015, 2016 and 2017 and 2018, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016 2017 and 2018, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, and $1 million of net regulatory assets, 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 and 2018.
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		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
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 $14.2 million above the threshold, and an additional $1.1 million related to 2017 was recorded.
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.

In November 2018, O&R, the staff of the NYSPSC and other parties entered into a Joint Proposal for new electric and gas rate plans for the three-year period January 2019 through December 2021 (the Joint Proposal). The Joint Proposal is subject to NYSPSC approval. The following tables contain a summary of the current and proposed rate plans.



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; and Yr. 3 - $4.2 million. Potential incentive if performance target related to service terminations is met: $0.5 million annually.
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.
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 penalties (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 penalties if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million; Yr. 2 - $4.4 million; and Yr. 3 - $4.5 million.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.

(b)

$59.3 million of the regulatory asset for deferred storm costs is to be recovered from customers over a five 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 Joint Proposal recommends that these base rate changes may 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.



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.
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.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (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 penalties 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.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.


(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 Joint Proposal recommends that these base rate changes may be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

Footnotes (f) through (j) to this table are the same as footnotes (f) through (j) to the table under “O&R New York - Electric,” above.



RECO
Effective period	August 2014 – February 2017	March 2017 (a)
Base rate changes	Yr. 1 – $13.0 million	Yr. 1 – $1.7 million
Amortization to income of net regulatory (assets) and liabilities	$0.4 million over three years and $(25.6) million of deferred storm costs over four years	$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 (b)
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$172.2 million	Yr. 1 – $178.7 million
Weighted average cost of capital (after-tax)	7.83 percent	7.47 percent
Authorized return on common equity	9.75 percent	9.6 percent
Actual return on common equity	Yr. 1 – 9.2 percent Yr. 2 – 8.7 percent	Yr. 1 – 7.5 percent
Cost of long-term debt	5.89 percent	5.37 percent
Common equity ratio	50 percent	49.7 percent


(a)	Effective until a new rate plan approved by the NJBPU goes into effect.


(b)	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 and November 2017, the NYSPSC issued orders in its proceeding investigating an April 21, 2017 Metropolitan Transportation Authority (MTA) subway power outage. The orders indicated that the investigation determined that the outage was caused by a failure of CECONY’s electricity supply to a subway station, which led to a loss of the subway signals, and that one of the secondary services to the MTA facility had been improperly rerouted and was not properly documented by the company. The orders also indicated that the loss of power to the subway station affected multiple subway lines and caused widespread delays across the subway system. Pursuant to the orders, the company is required to take certain actions, including inspecting, repairing and installing certain electrical equipment that serves the subway system, analyzing power supply and power quality events affecting the MTA’s signaling services, and filing monthly reports with the NYSPSC on all of the company's activities related to the subway system. The company completed the required actions in 2018. Through December 31, 2018, the company incurred costs related to this matter of $260 million. Included in this amount is $31 million in capital and operating and maintenance costs reflected in the company's electric rate plan and $229 million deferred as a regulatory asset pursuant to the rate plan.

In December 2017, the NYSPSC issued an order initiating a proceeding to study the potential effects of the federal Tax Cuts and Jobs Act of 2017 (TCJA) on income tax expense and liabilities of New York State utilities and the regulatory treatment to preserve the resulting benefits for customers. Upon enactment of the TCJA in December 2017, CECONY and O&R re-measured their deferred tax assets and liabilities and accrued net regulatory liabilities for future income taxes of $3,513 million and $161 million, respectively. In 2018, CECONY and O&R accrued additional net regulatory liabilities for future income tax of $49 million and $2 million, respectively (see Note L). Under the rate normalization requirements continued by the TCJA, the "protected" portion of their net regulatory liabilities related to certain accelerated tax depreciation benefits ($2,593 million and $128 million, respectively) is to be amortized over the remaining lives of the related assets. The remainder of the net regulatory liabilities, or "unprotected" portion, ($969 million and $35 million, respectively) is to be amortized as determined by the NYSPSC.

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 TCJA as measured based on amounts reflected in its rate plans prior to the enactment of the TCJA. 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 estimates that its credit of net benefits of the TCJA to its electric, gas and steam customers in 2019 will amount to $259 million, $113 million and $25 million, respectively. CECONY's credit of net benefits to its steam customers in the fourth quarter of 2018 was $6 million. CECONY’s net benefits prior to January 1, 2019 allocable to the company’s electric customers ($307 million) are to be deferred and addressed in its next electric rate proceeding. CECONY’s net benefits prior to January 1, 2019 allocable to the company’s gas customers ($90 million) and net benefits prior to October 1, 2018 allocable to the company’s steam customers ($15 million) are to be 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 electric customers ($2,516 million) is to continue to be deferred until its next electric rate proceeding and the amounts allocable to its gas and steam customers ($841 million and $193 million, respectively) are to be amortized over the remaining lives of the related assets (with the amortization period for the unprotected portion subject to review in its next gas and steam rate proceedings). O&R, under its November 2018 joint proposal for new electric and gas rate plans (which is subject to NYSPSC approval), is to reflect its TCJA net benefits in its electric and gas rates beginning as of January 1, 2019, to amortize its net benefits prior to January 1, 2019 ($22 million) over a three-year period and to amortize the protected portion of its net regulatory liability for future income taxes over the remaining lives of the related assets and the unprotected portion over a fifteen-year period. See "Rate Plans," above.

In 2018, the Utilities deferred as regulatory liabilities estimated net benefits of the TCJA of $434 million.

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.

In January 2018, the NJBPU issued an order initiating a proceeding to consider the TCJA. In June 2018, the NJBPU made permanent its previously approved $2.9 million interim decrease in Rockland Electric Company's (RECO) electric base rates, effective April 1, 2018, and ordered RECO to pay to its customers in July 2018 its approximately $1 million of net benefits of the TCJA for the three-month period ended March 31, 2018 and to begin in July 2018 to refund to its customers the unprotected portion of its net regulatory liability for future income taxes over a three-year period. Also in November 2018, the Federal Energy Regulatory Commission (FERC) issued an order directing RECO to refund $0.6 million to its transmission customers and reducing its annual transmission revenue requirement by an immaterial amount to reflect the TCJA. RECO’s net regulatory liability for future income taxes resulting from its re-measurement of its deferred tax asset and liabilities is $28 million (including $16 million subject to the normalization requirements continued by the TCJA).

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. Through December 31, 2018, CECONY's costs related to March 2018 storms, including Riley and Quinn, amounted to $133 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 ($83 million), capital expenditures ($29 million) and removal costs ($6 million). O&R and RECO had storm-related costs of $43 million and $17 million, respectively, most of which were deferred as regulatory assets pursuant to their electric rate plans. Recovery of CECONY and O&R storm-related costs is subject to review by the NYSPSC, and recovery of RECO storm-related costs is subject to review by the NJBPU. The NYSPSC is investigating 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, and may penalize them. In July 2018, the NJBPU adopted NJBPU staff's recommendations to increase requirements for New Jersey utilities, including RECO, relating to pre-storm preparations, restoration of service and communications and outreach. The Companies are unable to estimate the amount or range of their possible loss in connection with the storms.

In May 2018, FERC denied a complaint the NJBPU filed with FERC seeking the re-allocation to CECONY of certain PJM Interconnection LLC (PJM) transmission costs that had been allocated to the company prior to April 2017 when transmission service provided to the company pursuant to the PJM open access transmission tariff terminated. The transmission service terminated because the company did not exercise its option to continue the service following a series of requests PJM had submitted to FERC that substantially increased the charges for the transmission service. CECONY challenged each of these requests. FERC rejected all but one of CECONY’s protests. In June 2015 and May 2016, CECONY filed appeals of certain FERC decisions with the U.S. Court of Appeals. In July 2018, FERC established a settlement proceeding relating to the allocation of PJM transmission costs. Under CECONY’s electric rate plan, unless and until changed by the NYSPSC, the company will recover all charges incurred associated with the transmission service.

In July 2018, the NYSPSC commenced an investigation into the rupture of a CECONY steam main (see Note H).

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2018 and 2017 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Regulatory assets
Unrecognized pension and other postretirement costs	$2,238	$2,526	$2,111	$2,376
Environmental remediation costs	810	793	716	677
Revenue taxes	291	260	278	248
MTA power reliability deferral	229	50	229	50
Property tax reconciliation	101	51	86	25
Deferred storm costs	76	38	—	—
Pension and other postretirement benefits deferrals	73	79	56	58
Municipal infrastructure support costs	67	56	67	56
System peak reduction and energy efficiency programs	72	14	70	14
Brooklyn Queens demand management program	39	37	39	37
Unamortized loss on reacquired debt	36	37	34	35
Meadowlands heater odorization project	36	18	36	18
Preferred stock redemption	23	24	23	24
Recoverable REV demonstration project costs	20	19	18	17
Deferred derivative losses	17	44	11	37
Gate station upgrade project	17	13	17	13
Indian Point Energy Center program costs	13	29	13	29
Workers’ compensation	5	10	5	10
Recoverable energy costs	3	60	—	52
O&R transition bond charges	2	9	—	—
Surcharge for New York State assessment	—	2	—	2
Other	126	97	114	85
Regulatory assets – noncurrent	4,294	4,266	3,923	3,863
Recoverable energy costs	40	27	35	25
Deferred derivative losses	36	40	29	37
Regulatory assets – current	76	67	64	62
Total Regulatory Assets	$4,370	$4,333	$3,987	$3,925
Regulatory liabilities
Future income tax*	$2,515	$2,545	$2,363	$2,390
Allowance for cost of removal less salvage	928	846	790	719
TCJA net benefits	434	—	411	—
Energy efficiency portfolio standard unencumbered funds	127	127	122	122
Net unbilled revenue deferrals	117	183	117	183
Pension and other postretirement benefit deferrals	62	207	40	181
Property tax refunds	45	44	45	44
Settlement of prudence proceeding	37	66	37	66
Property tax reconciliation	36	107	36	107
Earnings sharing - electric, gas and steam	36	29	27	19
System benefit charge carrying charge	27	12	24	11
Carrying charges on repair allowance and bonus depreciation	21	43	21	42
BQDM and REV Demo reconciliations	18	9	18	9
New York State income tax rate change	17	36	17	35
Settlement of gas proceedings	15	27	15	27
Base rate change deferrals	10	21	10	21
Unrecognized other postretirement costs	7	92	7	92
Net utility plant reconciliations	3	12	1	8
Variable-rate tax-exempt debt - cost rate reconciliation	1	30	1	26
Other	185	141	156	117
Regulatory liabilities – noncurrent	4,641	4,577	4,258	4,219
Revenue decoupling mechanism	53	29	36	21
Refundable energy costs	31	41	8	16
Deferred derivative gains	30	31	29	28
Regulatory liabilities—current	114	101	73	65
Total Regulatory Liabilities	$4,755	$4,678	$4,331	$4,284

* 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 Utilities.

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 $117 million and $183 million at December 31, 2018 and 2017, 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)	2019	2020	2021	2022	2023	All Years Thereafter
Con Edison	$206	$117	$65	$54	$55	$601
CECONY	202	113	64	54	55	601

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 2018, 2017 and 2016 were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2018	2017	2016
Indian Point (a)	$6	$211	$203
Linden Cogeneration (b)	—	114	304
Astoria Energy (c)	—	—	50
Astoria Generating Company (d)	179	92	16
Brooklyn Navy Yard (e)	124	117	119
Cogen Technologies	9	18	—
Total	$318	$552	$692

(a) Contract term ended in 2018.

(b) Contract term ended in 2017.

(d) Capacity purchase agreements with terms ending in 2019, 2020 and 2021.

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

Capitalization

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Capitalization

Common Stock

At December 31, 2018 and 2017, Con Edison owned all of the issued and outstanding shares of common stock of the Utilities, the Clean Energy Businesses and Con Edison Transmission. CECONY owns 21,976,200 shares of Con Edison stock, which it 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, to fund, in part, payment of the purchase price for the acquisition by a Con Edison Development subsidiary of Sempra Solar Holdings LLC. See Note U. At December 31, 2018, 5,649,369 shares remain subject to the forward sale agreements. The company expects the remaining shares under the forward sale agreements to settle by December 27, 2019. The company or the forward purchasers may accelerate the forward sale agreements upon the occurrence of certain events. On a settlement date, if the company decides to physically settle, it will issue shares to the forward purchasers at the then-applicable forward sale price. The forward sale price is equal to $75.537 per share subject to adjustment on a daily basis based on a floating interest rate factor less a spread and will be subject to decrease by amounts related to expected dividends. The remaining shares under the forward sale agreements will be physically settled, unless the company elects cash or net share settlement (which it has the right to do, subject to certain conditions, other than in limited circumstances). In the event the company elects to cash settle or net share settle, the settlement amount will be generally related to (1)(a) the market value of the common stock during the unwind period under the forward sale agreement minus (b) the applicable forward sale price; multiplied by (2) the number of shares subject to such cash settlement or net share settlement. If this settlement amount is a negative number, the forward purchasers will pay the company the absolute value of that amount or deliver to the company a number of share having a value equal to the absolute value of such amount. If this settlement amount is a positive number, the company will pay the forward purchasers that amount or deliver to the forward purchasers a number of shares having a value equal to such amount.

Capitalization of Con Edison

The outstanding capitalization for each of the Companies is shown on its Consolidated Statement of Capitalization, and for Con Edison includes outstanding 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. 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 2019-2023 is as follows:



(Millions of Dollars)	Con Edison	CECONY
2019	$650	$475
2020	866	350
2021	1,260	640
2022	413	—
2023	293	—

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, 2018 and 2017 are:



(Millions of Dollars)	2018		2017
Long-Term Debt (including current portion) (a)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$18,145	$18,740	$16,029	$18,147
CECONY	$14,151	$14,685	$13,625	$15,163


(a)	Amounts shown are net of unamortized debt expense and unamortized debt discount of $185 million and $139 million for Con Edison and CECONY, respectively, as of December 31, 2018 and $142 million and $121 million for Con Edison and CECONY, respectively, as of December 31, 2017.

The fair values of the Companies' long-term debt have been estimated primarily using available market information and at December 31, 2018 are classified as Level 2 (see Note P).

At December 31, 2018 and 2017, long–term debt of Con Edison included $2,076 million and $915 million, respectively, of non-recourse debt secured by the pledge of the applicable renewable energy production projects of the Clean Energy Businesses. As a result of the January 2019 PG&E bankruptcy (see "Long-Lived and Intangible Assets" in Note A), the company may be required to reclassify up to $1,050 million of such project debt to a current liability during the first quarter of 2019. The lenders for the $1,050 million of project debt may, upon written notice, declare principal and interest on the 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 lenders pursuant to which the lenders would defer exercising these remedies.

At December 31, 2018 and 2017, long-term debt of Con Edison included $2 million and $7 million, respectively, of Transition Bonds issued in 2004 by O&R’s New Jersey utility subsidiary through a special purpose entity.

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, 2018.

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, 2018
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 expires in December 2022. There is a maximum of $2,250 million of credit available. 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, 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, 2017, Con Edison had $577 million of commercial paper outstanding of which $150 million was outstanding under CECONY’s program. The weighted average interest rate at December 31, 2017 was 1.8 percent for both Con Edison and CECONY. At December 31, 2018 and 2017, 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, 2018 and 2017. 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, 2018 this ratio was 0.53 to 1 for Con Edison and 0.54 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, 2018. In December 2018, Con Edison borrowed $825 million under a 6-month variable-rate term loan to fund, in part, payment of the purchase price for the acquisition by a Con Edison Development subsidiary of Sempra Solar Holdings, LLC. See Note U. The company repaid the 6-month loan in February 2019 with borrowings under a two-year term loan agreement. See Note C. See Note S for information about short-term borrowing between related parties.

Pension Benefits

12 Months Ended

Dec. 31, 2018

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 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost – including administrative expenses	$290	$263	$275	$272	$246	$258
Interest cost on projected benefit obligation	561	591	596	525	554	559
Expected return on plan assets	(1,033)	(968)	(947)	(979)	(917)	(898)
Recognition of net actuarial loss	688	595	596	651	563	565
Recognition of prior service cost/(credit)	(17)	(17)	4	(19)	(19)	2
TOTAL PERIODIC BENEFIT COST	$489	$464	$524	$450	$427	$486
Cost capitalized	(127)	(181)	(214)	(119)	(169)	(203)
Reconciliation to rate level	(92)	(34)	54	(100)	(41)	58
Total expense recognized	$270	$249	$364	$231	$217	$341

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, 2018, 2017 and 2016 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,536	$14,095	$14,377	$14,567	$13,203	$13,482
Service cost – excluding administrative expenses	286	259	271	267	241	254
Interest cost on projected benefit obligation	561	591	596	525	554	559
Net actuarial loss/(gain)	(1,219)	1,231	(302)	(1,159)	1,171	(282)
Plan amendments	—	6	(256)	—	—	(259)
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$14,274	$12,472	$11,759	$13,519	$11,815	$11,141
Actual return on plan assets	(536)	2,041	829	(507)	1,935	787
Employer contributions	473	450	508	434	412	469
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
Administrative expenses	(46)	(43)	(33)	(44)	(41)	(31)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
FUNDED STATUS	$(999)	$(1,262)	$(1,623)	$(798)	$(1,048)	$(1,388)
Unrecognized net loss	$2,464	$2,760	$3,157	$2,338	$2,624	$2,995
Unrecognized prior service costs	(205)	(223)	(244)	(222)	(242)	(258)
Accumulated benefit obligation	13,030	13,897	12,655	12,161	12,972	11,806

The decrease in the pension liability at Con Edison and CECONY of $263 million and $250 million, respectively, compared with December 31, 2017, was primarily due to a decrease in the plan’s projected benefit obligation as a result of an increase in the discount rate, partially offset by a decrease in plan assets as a result of the actual return on plan assets. For Con Edison, this decrease in pension liability corresponds with a decrease to regulatory assets of $273 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 $7 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 decrease in pension liability corresponds with a decrease to regulatory assets of $265 million for unrecognized net losses and unrecognized prior service costs consistent with the accounting rules for regulated operations, and also a credit to OCI of $1 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 $512 million and $(17) 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 $486 million and $(19) million, respectively, for CECONY.

At December 31, 2018 and 2017, Con Edison’s investments include $326 million and $330 million, respectively, held in external trust accounts for benefit payments pursuant to the supplemental retirement plans. Included in these amounts for CECONY were $301 million. See Note P. The accumulated benefit obligations for the supplemental retirement plans for Con Edison and CECONY were $316 million and $285 million as of December 31, 2018 and $331 million and $297 million as of December 31, 2017, respectively.

Assumptions

The actuarial assumptions were as follows:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.70	%	4.25	%	4.25	%
Expected return on plan assets	7.50	%	7.50	%	7.80	%
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)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$707	$726	$740	$755	$772	$4,072
CECONY	658	676	689	703	718	3,795

Expected Contributions

Based on estimates as of December 31, 2018, the Companies expect to make contributions to the pension plans during 2019 of $332 million (of which $301 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 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	45% - 55%	51	%	58	%	58	%
Debt Securities	33% - 43%	39	%	33	%	33	%
Real Estate	10% -14%	10	%	9	%	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 2019 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, 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)	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, 2017 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,872	$28	$3,900
International Equity (b)	4,132	—	4,132
U.S. Government Issued Debt (c)	—	1,786	1,786
Corporate Bonds Debt (d)	—	2,450	2,450
Structured Assets Debt (e)	—	3	3
Other Fixed Income Debt (f)	—	125	125
Cash and Cash Equivalents (g)	124	352	476
Futures (h)	308	—	308
Total investments within the fair value hierarchy	$8,436	$4,744	$13,180
Investments measured at NAV per share (n)
Private Equity (i)			336
Real Estate (j)			1,214
Hedge Funds (k)			251
Total investments valued using NAV per share			$1,801
Funds for retiree health benefits (l)	(168)	(94)	(262)
Funds for retiree health benefits measured at NAV per share (l)(n)			(36)
Total funds for retiree health benefits			$(298)
Investments (excluding funds for retiree health benefits)	$8,268	$4,650	$14,683
Pending activities (m)			(409)
Total fair value of plan net assets			$14,274

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2018 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)	2018	2017	2016
Con Edison	$45	$40	$36
CECONY	39	35	32

Other Postretirement Benefits

12 Months Ended

Dec. 31, 2018

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 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost	$20	$20	$18	$14	$13	$13
Interest cost on accumulated other postretirement benefit obligation	42	46	48	34	38	40
Expected return on plan assets	(73)	(69)	(77)	(63)	(61)	(67)
Recognition of net actuarial loss/(gain)	8	2	5	3	(3)	3
Recognition of prior service cost/(credit)	(6)	(17)	(20)	(2)	(11)	(14)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST/(CREDIT)	$(9)	$(18)	$(26)	$(14)	$(24)	$(25)
Cost capitalized	(8)	8	11	(6)	10	10
Reconciliation to rate level	8	(4)	22	9	(2)	22
Total expense/(credit) recognized	$(9)	$(14)	$7	$(11)	$(16)	$7

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, 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,219	$1,198	$1,287	$985	$1,007	$1,093
Service cost	20	20	18	14	13	13
Interest cost on accumulated postretirement benefit obligation	42	46	48	34	38	40
Net actuarial loss/(gain)	(70)	53	(57)	(32)	16	(52)
Benefits paid and administrative expenses, net of subsidies	(135)	(134)	(134)	(125)	(124)	(122)
Participant contributions	38	36	36	37	35	35
BENEFIT OBLIGATION AT END OF YEAR	$1,114	$1,219	$1,198	$913	$985	$1,007
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$1,039	$975	$994	$893	$851	$870
Actual return on plan assets	(66)	150	60	(54)	130	52
Employer contributions	6	17	7	6	8	7
Employer group waiver plan subsidies	34	34	35	32	30	33
Participant contributions	37	35	36	37	35	35
Benefits paid	(165)	(172)	(157)	(155)	(161)	(146)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$885	$1,039	$975	$759	$893	$851
FUNDED STATUS	$(229)	$(180)	$(223)	$(154)	$(92)	$(156)
Unrecognized net loss/(gain)	$14	$(47)	$(24)	$(2)	$(85)	$(42)
Unrecognized prior service costs	(8)	(14)	(31)	(5)	(7)	(18)

The increase in the other postretirement benefits liability at Con Edison and CECONY of $49 million and $62 million, respectively, compared with December 31, 2017, was primarily due to a decrease in plan assets as a result of the actual return on plan assets, partially offset by a decrease in the plans' projected benefit obligation as a result of an increase in the discount rate. For Con Edison, this increased liability corresponds with a decrease to regulatory liabilities of $70 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 $4 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 a decrease to regulatory liabilities of $85 million for unrecognized net losses and unrecognized prior service costs associated with the company consistent with the accounting rules for regulated operations, and also a credit to OCI of $1 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 certain 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 $(7) million and $(2) million, respectively, will be recognized from accumulated OCI and the regulatory liability into net periodic benefit cost over the next year for Con Edison. Included in these amounts are $(10) million and $(2) million, respectively, for CECONY.

Assumptions

The actuarial assumptions were as follows:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	3.55	%	4.00	%	4.05	%
O&R	3.70	%	4.20	%	4.20	%
Expected Return on Plan Assets	7.50	%	7.50	%	7.00	%

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 year ended December 31, 2018 was 5.60 percent, 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, 2018 was 5.40 percent, 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, 2018:



	Con Edison		CECONY
	1-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$9	$11	$(18)	$31
Effect on service cost and interest cost components for 2018	2	(1)	(1)	1

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:



(Millions of Dollars)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$80	$78	$76	$75	$74	$359
CECONY	70	67	65	64	63	302

Expected Contributions

Based on estimates as of December 31, 2018, Con Edison and CECONY expect to make a contribution of $10 million (of which $8 million is to be made by CECONY) to the other postretirement benefit plans in 2019. 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 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	42%-80%	52	%	60	%	60	%
Debt Securities	20%-58%	48	%	40	%	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, 2018 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)		$—	$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)	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, 2017 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$420	$420
Other Fixed Income Debt (b)	—		286	286
Cash and Cash Equivalents (c)	—		16	16
Total investments		$—	$722	$722
Funds for retiree health benefits (d)	168		94	262
Investments (including funds for retiree health benefits)		$168	$816	$984
Funds for retiree health benefits measured at net asset value (d)(e)				36
Pending activities (f)				19
Total fair value of plan net assets				$1,039

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2018 by asset category.

Environmental Matters

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Accrued Liabilities:
Manufactured gas plant sites	$689	$651	$603	$551
Other Superfund Sites	90	86	90	86
Total	$779	$737	$693	$637
Regulatory assets	$810	$793	$716	$677

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, 2018 and 2017 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Remediation costs incurred	$25	$24	$18	$19

Insurance and other third party recoveries received by Con Edison or CECONY were immaterial in 2018 and 2017.

Con Edison and CECONY estimate that in 2019 they will incur costs for remediation of approximately $28 million and $21 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 2018, 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, 2018, 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, 2018 and 2017 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$79	$84	$75	$80
Regulatory assets – workers’ compensation	$5	$10	$5	$10

Other Material Contingencies

12 Months Ended

Dec. 31, 2018

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, 2018, the company had not accrued a liability for damages related to the incident.

Manhattan Steam Main Rupture

In July 2018, a CECONY steam main located on Fifth Avenue and 21^st Street in Manhattan ruptured. 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, 2018, with respect to the incident, the company incurred estimated operating costs of $14 million for property damage, clean-up and other response costs and invested $8 million in capital and retirement costs. The company has notified its insurers of the incident and believes that the policies currently in force 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 to others in connection with the incident. The company is unable to estimate the amount or range of its possible loss related to the incident. At December 31, 2018, the company had not accrued a liability 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 $2,439 million and $2,073 million at December 31, 2018 and 2017, respectively.

A summary, by type and term, of Con Edison’s total guarantees under these other agreements at December 31, 2018 is as follows:



Guarantee Type	0 – 3 years	4 – 10 years	> 10 years		Total
	(Millions of Dollars)
Con Edison Transmission	$742	$404		$—	$1,146
Energy transactions	462	20	201		683
Renewable electric production projects	137	—	403		540
Other	70	—	—		70
Total	$1,411	$424	$604		$2,439

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 acquired a 45.7 percent interest in NY Transco when it was formed in 2014. In May 2016, the transmission owners transferred certain projects to NY Transco, for which CET Electric made its required contributions. NY Transco has proposed other transmission projects in the New York Independent System Operator's competitive bidding process. These other projects are subject to certain authorizations from the NYSPSC, the FERC and, as applicable, other federal, state and local agencies. Guarantee amount shown is for the maximum possible required amount of CET Electric's contributions for these other projects as calculated based on the assumptions that the projects are completed at 175 percent of their estimated costs and NY Transco does not use any debt financing for the projects. Guarantee term shown is assumed as the selection of the projects and resulting timing of the contributions is not certain. Also included within the table above are guarantees for $124 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, Con Edison Development and Con Edison Solutions 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 Con Edison Development and Con Edison Solutions, respectively.

Electricity Purchase Agreements

12 Months Ended

Dec. 31, 2018

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 2014 – December 2016	January 2017 – December 2019 (b)
Base rate changes	Yr. 1 – $(76.2) million (a) Yr. 2 – $124.0 million (a) Yr. 3 – None	Yr. 1 – $195 million (c) Yr. 2 – $155 million (c) Yr. 3 – $155 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 and 2 – $(37) million (d) Yr. 3 – $123 million (d)	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million



Other revenue sources	Retention of $90 million of annual transmission congestion revenues.	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 and 2018, the company recorded $13 million and $25 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved other incentives of $5 million in 2017 and 2018 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $3 million for service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred for customer benefit $146 million, $98 million and $101 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017 and 2018, the company deferred for customer benefit $45 million and $(6) million of revenues, respectively.
Recoverable energy costs (e)	Current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $57 million, $26 million and $68 million of net regulatory liabilities, respectively (f).	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (f), municipal infrastructure support costs (g), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (h). In 2017 and 2018, the company deferred $35 million and $189 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred $6 million and $17 million as a regulatory liability in 2014 and 2015, respectively. In 2016, $9 million was deferred as a regulatory asset.	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, $0.4 was deferred as a regulatory liability.
Average rate base	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent	9.0 percent
Actual return on common equity	Yr. 1 – 9.04 percent Yr. 2 – 10.16 percent Yr. 3 – 9.66 percent	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 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 $44.4 million and $6.5 million above the threshold for 2015 and 2016, respectively.	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, the company had no earnings sharing above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred; this amount was amortized to $0 at December 31, 2016.

(b)

(c)

(d)

(e)


(f)	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 (5.0, 7.5 or 10.0 basis points, depending on the year).

(g)

(h)



CECONY – Gas
Effective period	January 2014 – December 2016	January 2017 - December 2019 (b)
Base rate changes	Yr. 1 – $(54.6) million (a) Yr. 2 – $38.6 million (a) Yr. 3 – $56.8 million (a)	Yr. 1 – $(5) million (b) Yr. 2 – $92 million (b) Yr. 3 – $90 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$4 million over three years	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million
Other revenue sources	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million, $66 million and $65 million of such revenues in 2014, 2015 and 2016, respectively.	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 and 2018, the company achieved incentives of $7 million and $6 million, respectively that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $5 million for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred $28 million, $54 million and $71 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017 and 2018, the company deferred $3 million and $12 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014, 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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 $5 million and $4 million of negative revenue adjustments, respectively.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $38 million, $11 million, and $32 million of net regulatory liabilities, respectively. (c)	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes, municipal infrastructure support costs, the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (d) In 2017 and 2018, the company deferred $2 million of net regulatory liabilities and $44 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million In 2015 $1 million was deferred as a regulatory liability. In 2014 and 2016 the company deferred an immaterial amount.	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.
Average rate base	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	9.3 percent	9.0 percent
Actual return on common equity	Yr. 1 – 8.02 percent Yr. 2 – 8.13 percent Yr. 3 – 7.83 percent	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent



Earnings sharing	Most 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, 2015 and 2016, the company had no earnings above the threshold.	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 and 2018, the company had no earnings above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred which resulted in a $32 million regulatory liability at December 31, 2016.


(b)	In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's gas rate plan for January 2017 through December 2019. The gas base rate decrease is offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.


(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)	See footnotes (e), (f), (g) and (h) 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
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 penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014, 2015, 2016 and 2017 and 2018, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016 2017 and 2018, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, and $1 million of net regulatory assets, 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 and 2018.
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		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
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 $14.2 million above the threshold, and an additional $1.1 million related to 2017 was recorded.
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.



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; and Yr. 3 - $4.2 million. Potential incentive if performance target related to service terminations is met: $0.5 million annually.
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.
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 penalties (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 penalties if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million; Yr. 2 - $4.4 million; and Yr. 3 - $4.5 million.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.

(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 Joint Proposal recommends that these base rate changes may 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.



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.
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.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (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 penalties 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.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.


(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 Joint Proposal recommends that these base rate changes may be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

Footnotes (f) through (j) to this table are the same as footnotes (f) through (j) to the table under “O&R New York - Electric,” above.



RECO
Effective period	August 2014 – February 2017	March 2017 (a)
Base rate changes	Yr. 1 – $13.0 million	Yr. 1 – $1.7 million
Amortization to income of net regulatory (assets) and liabilities	$0.4 million over three years and $(25.6) million of deferred storm costs over four years	$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 (b)
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$172.2 million	Yr. 1 – $178.7 million
Weighted average cost of capital (after-tax)	7.83 percent	7.47 percent
Authorized return on common equity	9.75 percent	9.6 percent
Actual return on common equity	Yr. 1 – 9.2 percent Yr. 2 – 8.7 percent	Yr. 1 – 7.5 percent
Cost of long-term debt	5.89 percent	5.37 percent
Common equity ratio	50 percent	49.7 percent


(a)	Effective until a new rate plan approved by the NJBPU goes into effect.


(b)	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

In 2018, the Utilities deferred as regulatory liabilities estimated net benefits of the TCJA of $434 million.

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.

In July 2018, the NYSPSC commenced an investigation into the rupture of a CECONY steam main (see Note H).

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2018 and 2017 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Regulatory assets
Unrecognized pension and other postretirement costs	$2,238	$2,526	$2,111	$2,376
Environmental remediation costs	810	793	716	677
Revenue taxes	291	260	278	248
MTA power reliability deferral	229	50	229	50
Property tax reconciliation	101	51	86	25
Deferred storm costs	76	38	—	—
Pension and other postretirement benefits deferrals	73	79	56	58
Municipal infrastructure support costs	67	56	67	56
System peak reduction and energy efficiency programs	72	14	70	14
Brooklyn Queens demand management program	39	37	39	37
Unamortized loss on reacquired debt	36	37	34	35
Meadowlands heater odorization project	36	18	36	18
Preferred stock redemption	23	24	23	24
Recoverable REV demonstration project costs	20	19	18	17
Deferred derivative losses	17	44	11	37
Gate station upgrade project	17	13	17	13
Indian Point Energy Center program costs	13	29	13	29
Workers’ compensation	5	10	5	10
Recoverable energy costs	3	60	—	52
O&R transition bond charges	2	9	—	—
Surcharge for New York State assessment	—	2	—	2
Other	126	97	114	85
Regulatory assets – noncurrent	4,294	4,266	3,923	3,863
Recoverable energy costs	40	27	35	25
Deferred derivative losses	36	40	29	37
Regulatory assets – current	76	67	64	62
Total Regulatory Assets	$4,370	$4,333	$3,987	$3,925
Regulatory liabilities
Future income tax*	$2,515	$2,545	$2,363	$2,390
Allowance for cost of removal less salvage	928	846	790	719
TCJA net benefits	434	—	411	—
Energy efficiency portfolio standard unencumbered funds	127	127	122	122
Net unbilled revenue deferrals	117	183	117	183
Pension and other postretirement benefit deferrals	62	207	40	181
Property tax refunds	45	44	45	44
Settlement of prudence proceeding	37	66	37	66
Property tax reconciliation	36	107	36	107
Earnings sharing - electric, gas and steam	36	29	27	19
System benefit charge carrying charge	27	12	24	11
Carrying charges on repair allowance and bonus depreciation	21	43	21	42
BQDM and REV Demo reconciliations	18	9	18	9
New York State income tax rate change	17	36	17	35
Settlement of gas proceedings	15	27	15	27
Base rate change deferrals	10	21	10	21
Unrecognized other postretirement costs	7	92	7	92
Net utility plant reconciliations	3	12	1	8
Variable-rate tax-exempt debt - cost rate reconciliation	1	30	1	26
Other	185	141	156	117
Regulatory liabilities – noncurrent	4,641	4,577	4,258	4,219
Revenue decoupling mechanism	53	29	36	21
Refundable energy costs	31	41	8	16
Deferred derivative gains	30	31	29	28
Regulatory liabilities—current	114	101	73	65
Total Regulatory Liabilities	$4,755	$4,678	$4,331	$4,284

* 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 Utilities.

Electricity Purchase Agreements

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



(Millions of Dollars)	2019	2020	2021	2022	2023	All Years Thereafter
Con Edison	$206	$117	$65	$54	$55	$601
CECONY	202	113	64	54	55	601



	For the Years Ended December 31,
(Millions of Dollars)	2018	2017	2016
Indian Point (a)	$6	$211	$203
Linden Cogeneration (b)	—	114	304
Astoria Energy (c)	—	—	50
Astoria Generating Company (d)	179	92	16
Brooklyn Navy Yard (e)	124	117	119
Cogen Technologies	9	18	—
Total	$318	$552	$692

(a) Contract term ended in 2018.

(b) Contract term ended in 2017.

(d) Capacity purchase agreements with terms ending in 2019, 2020 and 2021.

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

Leases

12 Months Ended

Dec. 31, 2018

Leases [Abstract]

Leases

Con Edison’s subsidiaries lease electric transmission facilities, gas distribution facilities, land, office buildings and equipment. In accordance with the accounting rules for leases, these leases are classified as either capital leases or operating leases. Most of the operating leases provide the option to renew at the fair rental value for future periods.

Capital leases: For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. The following assets under capital leases are included in the Companies’ consolidated balance sheets at December 31, 2018 and 2017:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
UTILITY PLANT
Common	$1	$2	$1	$1

The accumulated amortization of the capital leases for Con Edison and CECONY was $4 million and $2 million, respectively, at December 31, 2018, and $3 million and $2 million, respectively, at December 31, 2017.

Operating leases: The future minimum lease commitments under the Companies’ operating lease agreements that are not cancellable by the Companies are 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

Substantially all of the amounts shown in the above table for CECONY are estimated amounts payable under CECONY’s revocable consent agreement with New York City for the use of streets and public places for installation and operation of transformers and associated vaults and equipment. Under the agreement, payments by CECONY increase 2.18 percent annually and are subject to decrease if CECONY’s transformer installations decrease by ½ of 1 percent or more from the prior year.

For information about changes to the accounting rules for leases adopted by the Companies in January 2019, see Note T.

Goodwill	12 Months Ended
Goodwill	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill In 2018 and 2017, Con Edison elected to perform the optional qualitative assessment for goodwill related to the 1999 O&R merger and the gas storage company, and the first step of the quantitative test for the residential solar company. In 2018 and 2017, 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 2018 and 2017, Con Edison completed impairment tests for goodwill of $8 million related to a gas storage company acquired by CET Gas from Con Edison Development and determined that it was not impaired. In 2016, Con Edison completed impairment tests for goodwill of $15 million related to two energy services companies owned by the Clean Energy Businesses and determined that goodwill was impaired and, upon calculating the implied fair value of goodwill using fair values based primarily on discounted cash flows, recorded a corresponding impairment charge of $15 million ($12 million, net of tax). In 2018 and 2017, 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 the Clean Energy Businesses acquired a battery storage company and recorded $12 million of goodwill as part of the purchase price allocation. 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.

Income Tax

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
State
Current	$(10)	$(2)	$(42)	$6	$37	$(1)
Deferred	107	103	188	82	75	114
Federal
Current	3	(11)	(43)	(34)	73	59
Deferred	310	391	604	275	504	435
Amortization of investment tax credits	(9)	(9)	(9)	(3)	(4)	(4)
Total income tax expense	$401	$472	$698	$326	$685	$603

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



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Deferred tax liabilities:
Property basis differences	$7,402	$6,555	$6,446	$5,968
Regulatory assets:
Unrecognized pension and other postretirement costs	627	697	591	656
Environmental remediation costs	227	219	200	187
Deferred storm costs	21	11	—	—
Other regulatory assets	273	269	252	241
Equity investments	102	263	—	—
Total deferred tax liabilities	$8,652	$8,014	$7,489	$7,052
Deferred tax assets:
Accrued pension and other postretirement costs	$248	$264	$180	$187
Regulatory liabilities:
Future income tax	702	698	662	660
Other regulatory liabilities	632	593	554	524
Superfund and other environmental costs	218	203	194	176
Asset retirement obligations	114	86	82	79
Loss carryforwards	229	95	—	—
Tax credits carryforward	817	658	—	—
Valuation allowance	(33)	(33)	—	—
Other	53	112	102	148
Total deferred tax assets	2,980	2,676	1,774	1,774
Net deferred tax liabilities	$5,672	$5,338	$5,715	$5,278
Unamortized investment tax credits	148	157	24	28
Net deferred tax liabilities and unamortized investment tax credits	$5,820	$5,495	$5,739	$5,306

The TCJA includes significant changes affecting the taxation of regulated public utilities, such as CECONY and O&R, and Con Edison’s other businesses. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA reduced the corporate federal income tax rate from 35 percent to 21 percent. The TCJA provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, do not allow for full expensing of certain property acquired after September 27, 2017, and continue certain rate normalization requirements for the tax benefit of accelerated depreciation. For most non-utility businesses, TCJA provides for full expensing of property acquired after September 27, 2017 and limits a deduction for interest expense to 30 percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization or “EBITDA”).

In accordance with the accounting rules for income taxes (see “Federal Income Tax” in Note A), 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 CECONY and O&R, 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. See “Rate Plans” in Note B. 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.

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 are 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 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)	2018		2017		2016		2018		2017		2016
STATUTORY TAX RATE
Federal	21	%	35	%	35	%	21	%	35	%	35	%
Changes in computed taxes resulting from:
State income tax	4		4		4		5		4		4
Cost of removal	1		1		(1	)	1		1		(1	)
Other plant-related items	(1	)	(1	)	—		(1	)	(1	)	(1	)
TCJA deferred tax re-measurement	2		(13	)	—		—		—		—
Amortization of excess deferred federal income taxes	(3	)	—		—		(3	)	—		—
Renewable energy credits	(1	)	(1	)	(1	)	—		—		—
Research and development credits	—		—		(1	)	(1	)	—		(1	)
Other	—		(2	)	—		(1	)	(1	)	—
Effective tax rate	23	%	23	%	36	%	21	%	38	%	36	%

CECONY and O&R deferred as regulatory liabilities their estimated net benefits under the TCJA for the year ended December 31, 2018. 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.

Con Edison has a federal net operating loss carryover of approximately $711 million, due primarily to accelerated depreciation (including bonus depreciation). The 2017 federal net operating loss carryover of $520 million will expire, if unused, in 2037 and the 2018 federal net operating loss carryover of $191 million can be carried forward indefinitely. Con Edison has $817 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.

For New York State income tax purposes, Con Edison had a net operating loss of $97 million from 2017, primarily as a result of accelerated tax deductions on renewable energy projects. This loss was carried back to 2015 and will result in recovery of $9 million of income tax. In 2018, Con Edison had a New York State net operating loss of approximately $398 million, primarily as a result of accelerated tax deductions on renewable energy projects. Con Edison expects to carry back approximately $99 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 $299 million will be carried forward to future years. A deferred tax asset has been recognized for this New York State net operating loss that will 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.

Charitable contributions carryforward of $5 million, $5 million, $7 million and $5 million for 2015, 2016, 2017 and 2018, respectively, will expire in 2020, 2021, 2022 and 2023, respectively. 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. In addition, a $12 million valuation allowance for New York City net operating loss carryforward and a $21 million valuation allowance for state net operating losses carryforward has been provided; as it is not more likely than not that the deferred tax asset will be realized.

The Protecting Americans from Tax Hikes Act of 2015 extended bonus depreciation for property acquired and placed in service during 2015 through 2019. The bonus depreciation percentage is 50 percent for property placed in service during 2015, 2016 and 2017 and phases down to 40 percent in 2018, and 30 percent in 2019. Since Con Edison meets the de minimis exception set forth in the proposed Treasury regulations to qualify as a utility company for the consolidated group, the TCJA does not allow bonus depreciation for property acquired and placed in service by the Companies after December 31, 2017 (excluding the transition rules for incurred property costs prior to September 28, 2017 and subsequently placed in service in 2018 or 2019).

In August 2018, the Federal government issued proposed regulations providing guidance on provisions in the TCJA allowing for full expensing of qualified plant additions. These proposed regulations, which Con Edison adopted, allows Con Edison’s 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 proposed regulations provide guidance on the treatment of consolidated interest expense. The regulations provide a safe harbor test that if at least 90% 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. Qualifying consolidated groups would not be entitled to the full expensing provisions in the TCJA noted above. This safe harbor test must be met for each year in order to achieve a current tax deduction for consolidated interest expense. The safe harbor rules do not apply to partnerships in which Con Edison and its subsidiaries are a partner. Con Edison qualified for the safe harbor treatment in 2018.

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)	2018	2017	2016	2018	2017	2016
Balance at January 1,	$12	$42	$34	$5	$21	$2
Additions based on tax positions related to the current year	2	1	2	2	1	2
Additions based on tax positions of prior years	1	1	19	1	1	19
Reductions for tax positions of prior years	(2)	(24)	(13)	(1)	(18)	(2)
Reductions from expiration of statute of limitations	(4)	(2)	—	—	—	—
Settlements	(3)	(6)	—	(3)	—	—
Balance at December 31,	$6	$12	$42	$4	$5	$21

In 2018, Con Edison reached a settlement with the IRS on tax years 2012 through 2016 and certain state statute of limitations expired which resulted in Con Edison reversing $9 million in uncertain tax positions. Of this amount, $6 million reduced Con Edison’s effective tax rate. The amount related to CECONY was $4 million, of which $1 million reduced CECONY’s effective tax rate. Current and prior year additions in 2018 are for tax credits.

As of December 31, 2018, Con Edison reasonably expects to resolve within the next twelve months approximately $4 million of various federal and state uncertainties due to the expected completion of ongoing tax examinations and resolution of state refund claims, of which the entire amount, if recognized, would reduce Con Edison’s effective tax rate. The amount related to CECONY is approximately $2 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 2018, 2017 and 2016, the Companies recognized an immaterial amount of interest and no penalties for uncertain tax positions in their consolidated income statements. At December 31, 2018 and 2017, the Companies reflected an immaterial amount of interest and no penalties in their consolidated balance sheets.

At December 31, 2018, the total amount of unrecognized tax benefits that, if recognized, would reduce the Companies’ effective tax rate is $6 million with $4 million attributable to CECONY.

Federal tax returns for 2017 remain under examination. State income tax returns remain open for examination in New York for tax years 2010 through 2017 and in New Jersey for tax years 2008 through 2017.

Stock-Based Compensation

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [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, 2018 were new shares. The Companies intend to use new shares to fulfill their stock-based compensation obligations for 2019.

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, 2018, 2017 and 2016:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Performance-based restricted stock	$3	$53	$42	$3	$45	$36
Time-based restricted stock	2	2	2	1	2	2
Non-employee director deferred stock compensation	3	2	2	3	2	2
Stock purchase plan	6	6	4	6	6	4
Total	$14	$63	$50	$13	$55	$44
Income tax benefit	$4	$25	$20	$4	$22	$18

Stock Options

The Companies last granted stock options in 2006. The stock options generally vested over a three-year period and had a term of 10 years. Options were granted at an exercise price equal to the fair market value of a common share when the option was granted. The Companies generally recognized compensation expense (based on the fair value of stock option awards) over the vesting period. At December 31, 2018 and 2017, there were no outstanding options and no options were exercised.

The income tax benefit Con Edison realized from stock options exercised in the year ended December 31, 2016 was $1 million.

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 represents 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:



	2018	2017	2016
Risk-free interest rate (a)	2.48% - 2.63%	1.76% - 1.89%	0.85% - 1.20%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	14.76% - 17.71%	11.01% - 14.70%	17.72% - 18.22%


(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, 2018 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, 2017	1,028,932	$71.74	$70.11	784,166	$71.06	$70.08
Granted	328,850	67.26	76.37	247,532	66.79	76.48
Vested	(327,069)	57.77	63.27	(261,167)	57.37	63.18
Forfeited	(24,877)	72.22	74.97	(20,877)	71.76	75.14
Transferred (d)	—	—	—	12,252	78.47	72.71
Non-vested at December 31, 2018	1,005,836	$74.81	$74.27	761,906	$74.47	$74.42


(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, 2018 is $21 million, including $18 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 $29 million and $28 million in 2018, $22 million and $21 million in 2017, and $21 million and $20 million in 2016, 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, 2018 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, 2017	64,870	$71.93	61,420	$71.93
Granted	23,000	77.94	21,400	77.94
Vested	(20,523)	61.03	(19,473)	61.03
Forfeited	(2,167)	73.93	(1,967)	73.97
Non-vested at December 31, 2018	65,180	$77.42	61,380	$77.42

The total expense to be recognized by Con Edison in future periods for unvested time-based awards outstanding at December 31, 2018 for Con Edison and CECONY was $2 million and is expected to be recognized over a weighted average period of one year. Con Edison and CECONY paid cash of $1 million in 2018, 2017 and 2016, 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, 2018, approximately 33,100 units were issued at a weighted average grant date price of $76.08.

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 2018, 2017 and 2016, 786,385, 719,125 and 720,268 shares were purchased under the Stock Purchase Plan at a weighted average price of $78.27, $79.57 and $72.67 per share, respectively.

Financial Information by Business Segment

12 Months Ended

Dec. 31, 2018

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, 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



As of and for the Year Ended December 31, 2016 (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	$8,106	$17		$865	$1,996	$(147)	$459	$495	$30,708	$1,819
Gas	1,508	6		159	387	(31)	105	92	7,553	811
Steam	551	88		82	68	(11)	39	30	2,595	126
Consolidation adjustments	—	(111)		—	—	—	—	—	—	—
Total CECONY	$10,165		$—	$1,106	$2,451	$(189)	$603	$617	$40,856	$2,756
O&R
Electric	$637		$—	$49	$107	$(11)	$24	$30	$1,949	$114
Gas	184	—		18	39	(4)	12	10	809	52
Other	—	—		—	—	—	—	—	—	—
Total O&R	$821		$—	$67	$146	$(15)	$36	$40	$2,758	$166
Clean Energy Businesses	$1,091	$7		$42	$183	$21	$34	$53	$2,551	$1,235
Con Edison Transmission	—	—		—	(3)	43	6	—	1,150	1,078
Other (b)	(2)	(7)		1	3	(1)	17	4	940	—
Total Con Edison	$12,075		$—	$1,216	$2,780	$(141)	$696	$714	$48,255	$5,235

(a)

For Con Edison, the income tax expense/(benefit) on non-operating income was $(5) million, $13 million and $(16) million in 2018, 2017 and 2016, respectively. For CECONY, the income tax expense/(benefit) on non-operating income was $(2) million, $(3) million and $(14) million in 2018, 2017 and 2016, 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 “Other Regulatory Matters” in Note B and 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, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Commodity Derivatives

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. 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.

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2018 and 2017 were:



(Millions of Dollars)	2018				2017
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	$43	$(14)	$29	(b)	$83	$(51)		$32	(b)
Noncurrent	14	(7)	7	(c)	10	(4)		6
Total fair value of derivative assets	$57	$(21)	$36	(b)(c)	$93	$(55)		$38
Fair value of derivative liabilities
Current	$(61)	$11	$(50)		$(67)	$50		$(17)
Noncurrent	(19)	9	(10)	(c)	(43)	5		(38)
Total fair value of derivative liabilities	$(80)	$20	$(60)		$(110)	$55		$(55)
Net fair value derivative assets/(liabilities)	$(23)	$(1)	$(24)	(b)(c)	$(17)		$—	$(17)	(b)
CECONY
Fair value of derivative assets
Current	$25	$(6)	$19	(b)	$39	$(15)		$24	(b)
Noncurrent	11	(5)	6		9	(4)		5
Total fair value of derivative assets	$36	$(11)	$25		$48	$(19)		$29
Fair value of derivative liabilities
Current	$(31)	$6	$(25)		$(26)	$14		$(12)
Noncurrent	(12)	6	(6)		(36)	4		(32)
Total fair value of derivative liabilities	$(43)	$12	$(31)		$(62)	$18		$(44)
Net fair value derivative assets/(liabilities)	$(7)	$1	$(6)	(b)	$(14)	$(1)		$(15)	(b)

(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, 2018 and 2017, margin deposits for Con Edison ($7 million and $12 million, respectively) and CECONY ($6 million and $11 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)	Does not include interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities (see below).

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. Management believes that these derivative instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices.

The following table presents the realized and unrealized gains or losses on commodity derivatives that have been deferred or recognized in earnings for the years ended December 31, 2018 and 2017:



		Con Edison						CECONY
(Millions of Dollars)	Balance Sheet Location	2018			2017			2018		2017
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$(1)			$3			$1		$4
Noncurrent	Deferred derivative gains	4			—			3		—
Total deferred gains/(losses)		$3			$3			$4		$4
Current	Deferred derivative losses	$4			$51			$8		$49
Current	Recoverable energy costs	(26)			(154)			(26)		(144)
Noncurrent	Deferred derivative losses	27			4			26		5
Total deferred gains/(losses)		$5			$(99)			$8		$(90)
Net deferred gains/(losses)		$8			$(96)			$12		$(86)
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Purchased power expense		$—			$—			$—		$—
	Gas purchased for resale	(2)			3			—		—
	Non-utility revenue	4		(a)	5		(b)	—		—
	Other operations and maintenance expense	(2)		(c)	—			(2)		—
Total pre-tax gain/(loss) recognized in income			$—		$8			$(2)			$—


(a)	For the year ended December 31, 2018, Con Edison recorded unrealized pre-tax losses in non-utility operating revenue ($5 million).


(b)	For the year ended December 31, 2017, Con Edison recorded an immaterial unrealized pre-tax gain in non-utility operating revenue.


(c)	For the year ended December 31, 2018, Con Edison recorded unrealized pre-tax losses in other operations and maintenance expense ($2 million).

The following table presents the hedged volume of Con Edison’s and CECONY’s derivative transactions at December 31, 2018:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison	28,303,678	18,519	164,668,697	3,780,000
CECONY	25,458,600	10,350	151,280,000	3,780,000


(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, 2018, Con Edison and CECONY had $106 million and $13 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 $31 million with independent system operators, $28 million with investment-grade counterparties, $28 million with non-investment grade/non-rated counterparties, and $19 million with commodity exchange brokers. CECONY’s net credit exposure consisted of $7 million with investment-grade counterparties and $6 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, 2018:



(Millions of Dollars)	Con Edison (a)	CECONY (a)
Aggregate fair value – net liabilities	$36	$24
Collateral posted	6	—
Additional collateral (b) (downgrade one level from current ratings)	6	2
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	66	37

(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, 2018. 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, 2018, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $20 million.

Interest Rate Swaps

In December 2018, the Clean Energy Businesses acquired Sempra Solar Holding, LLC, which holds interest rate swaps that terminate in 2025, 2028 and 2035. The fair value of these interest rate swaps were a net liability of $5 million as of December 31, 2018 on Con Edison’s consolidated balance sheet.

In December 2016, the Clean Energy Businesses acquired Coram Wind which holds an interest rate swap that terminates in June 2024, pursuant to which it pays a fixed-rate of 2.0855 percent and receives a LIBOR-based variable rate. The fair value of this interest rate swap was an asset of $1 million as of December 31, 2018 and immaterial as of December 31, 2017 on Con Edison’s consolidated balance sheet.

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 are summarized below.



	2018					2017
(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)	$6	$36	$7	$(6)	$43	$5	$77	$7		$(39)	$50
Interest Rate Swaps (a)(b)(c)(f)	—	2	—	—	2	—	—	—		—	—
Other (a)(b)(d)	287	114	—	—	401	283	120	—		—	403
Total assets	$293	$152	$7	$(6)	$446	$288	$197	$7		$(39)	$453
Derivative liabilities:
Commodity (a)(b)(c)	$8	$43	$20	$(11)	$60	$8	$93	$6		$(52)	$55
Interest Rate Swaps (a)(b)(c)(f)	—	6	—	—	6	—	—	—		—	—
Total liabilities	$8	$49	$20	$(11)	$66	$8	$93	$6		$(52)	$55
CECONY
Derivative assets:
Commodity (a)(b)(c)	$3	$28	$1	$(1)	$31	$3	$40	$4		$(7)	$40
Other (a)(b)(d)	267	109	—	—	376	260	114	—		—	374
Total assets	$270	$137	$1	$(1)	$407	$263	$154	$4		$(7)	$414
Derivative liabilities:
Commodity (a)(b)(c)	$5	$30	$3	$(6)	$32	$5	$57		$—	$(18)	$44

(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 $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. Con Edison and CECONY had $11 million and $10 million, respectively, of commodity derivative liabilities transferred from level 3 to level 2 during the year ended December 31, 2017 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, 2017 to less than three years as of December 31, 2017.

(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, 2018 and 2017, 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. Under the Companies’ policies and procedures, multiple independent sources of information are obtained for forward price curves used to value commodity derivatives. Fair value and changes in fair value of commodity derivatives 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, 2018
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(12)	Discounted Cash Flow	Forward energy prices (a)	$21.34-$64.45 per MWh
		Discounted Cash Flow	Forward capacity prices (a)	$1.00-$6.30 per kW-month
Natural Gas	(2)	Discounted Cash Flow	Forward natural gas prices (a)	$0.92-$6.62 per Dt
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.29-$8.03 per MWh
Total Con Edison — Commodity	$(13)
CECONY — Commodity
Electricity	$(3)	Discounted Cash Flow	Forward capacity prices (a)	$1.00-$6.30 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.49-$2.60 per MWh
Total CECONY — Commodity	$(2)


(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, 2018 and 2017 and classified as Level 3 in the fair value hierarchy:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Beginning balance as of January 1,	$1	$1	$4	$1
Included in earnings	4	8	4	2
Included in regulatory assets and liabilities	(10)	(13)	(4)	(7)
Purchases	—	2	—	1
Settlements	(6)	(8)	(4)	(3)
Transfer out of level 3	(2)	11	(2)	10
Ending balance as of December 31,	$(13)	$1	$(2)	$4

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 ($3 million loss and $2 million gain) and purchased power costs (immaterial) on the consolidated income statement for the years ended December 31, 2018 and 2017, respectively. The change in fair value relating to Level 3 commodity derivative assets and liabilities held at December 31, 2018 and 2017 is included in non-utility revenues ($3 million loss and $2 million gain) and purchased power costs (immaterial) on the consolidated income statement for the years ended December 31, 2018 and 2017, respectively.

Variable Interest Entities

12 Months Ended

Dec. 31, 2018

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 2018, 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.

Con Edison Development

Con Edison has a variable interest in OCI Solar San Antonio 4 LLC (Texas Solar 4), which is a consolidated entity in which Con Edison Development has an 80 percent membership interest. Con Edison is the primary beneficiary since the power to direct the activities that most significantly impact the economics of Texas Solar 4 is held by a Con Edison Development subsidiary. 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. At December 31, 2018 and 2017, Con Edison’s consolidated balance sheet includes $27 million and $26 million in net assets (as detailed in the table below) respectively and the noncontrolling interest of the third party of $7 million related to Texas Solar 4. Con Edison's earnings from Texas Solar 4 for the years ended December 31, 2018 and 2017 were immaterial.

In December 2018, a Con Edison Development subsidiary completed its acquisition of Sempra Solar Holdings, LLC. See Note U. Included in the acquisition were certain operating projects (Tax Equity Projects) with noncontrolling tax equity investors 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 Con Edison Development subsidiaries. Electricity generated by the Tax Equity Projects is sold to utilities and municipalities pursuant to long-term power purchase agreements. At December 31, 2018, Con Edison’s consolidated balance sheet includes $870 million in net assets (as detailed in the table below) related to these Tax Equity Projects and the noncontrolling interest of the tax equity investors of $104 million. Con Edison's earnings from the Tax Equity Projects, accounted for under the hypothetical liquidation at book value (HLBV) method of accounting, for the year ended December 31, 2018 were immaterial.

At December 31, 2018 and 2017, Con Edison’s consolidated balance sheet included the following amounts associated with its VIEs:



	Tax Equity Projects
	Great Valley Solar		Copper Mountain - Mesquite Solar		Texas Solar 4
(Millions of Dollars)	2018		2018		2018	2017
Restricted cash		$—		$—	$4	$5
Non-utility property, less accumulated depreciation of $1 for each of the Tax Equity Projects and $15 and $12, for Texas Solar 4 in 2018 and 2017, respectively	313		492		98	101
Other assets	18		97		9	8
Total assets (a)	$331		$589		$111	$114
Long-term debt due within one year		$—		$—	$2	$2
Other liabilities	17		33		26	28
Long-term debt	—		—		56	58
Total liabilities (b)	$17		$33		$84	$88


(a)	The assets of the Tax Equity Projects and Texas Solar 4 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 and Texas Solar 4 represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

The following table summarizes the VIEs into which Con Edison Development has entered as of December 31, 2018:



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	$281
Copper Mountain - Mesquite Solar (d)	344	20-25	2018	Nevada and Arizona	485
Texas Solar 4	32	25	2014	Texas	20


(a)	Represents Con Edison Development’s 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 ($33 million for Great Valley Solar, $71 million for Copper Mountain - Mesquite Solar and $7 million for Texas Solar 4). Con Edison did not provide any financial or other support during the year that was not previously contractually required.


(c)	Great Valley Solar consists of the Great Valley Solar 1, Great Valley Solar 2, Great Valley Solar 3 and Great Valley Solar 4 projects.


(d)	Copper Mountain - Mesquite Solar consists of the Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 projects.

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2018
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, 2018, the liabilities for asset retirement obligations of Con Edison and CECONY were $450 million and $292 million, respectively. At December 31, 2017, the liabilities for asset retirement obligations of Con Edison and CECONY were $314 million and $287 million, respectively. 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 $50 million and $36 million during the years ended December 31, 2018 and 2017, respectively, to the regulatory liability associated with cost of removal to reflect depreciation and interest expense.

Related Party Transactions

12 Months Ended

Dec. 31, 2018

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 ($12,910 million and $712 million), respectively, at December 31, 2018 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, 2018, 2017 and 2016 were as follows:



	CECONY
(Millions of Dollars)	2018	2017	2016
Cost of services provided	$115	$111	$108
Cost of services received	73	64	64

In addition, CECONY and O&R have joint gas supply arrangements, in connection with which CECONY sold to O&R $83 million, $66 million and $47 million of natural gas for the years ended December 31, 2018, 2017 and 2016, 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 year ended December 31, 2018 and 2017, 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 $28 million, $31 million and $18 million for the years ended December 31, 2018, 2017 and 2016, respectively. In addition, the Clean Energy Businesses entered into two electricity sales agreements with Stagecoach under which the amounts received in 2018, 2017 and 2016 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. 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, 2018 and 2017, CECONY incurred no costs under the contract.

FERC has authorized CECONY through 2019 to lend funds to O&R from time to time, for periods of not more than 12 months, in amounts not to exceed $250 million outstanding at any time, at prevailing market rates. There were no outstanding loans to O&R at December 31, 2018 and 2017.

Con Edison Energy had financial electric capacity contracts with CECONY and O&R during 2018 and a contract with CECONY during 2017. For the years ended December 31, 2018 and 2017, Con Edison Energy realized a $1 million loss and a $3 million gain, respectively, under these contracts.

New Financial Accounting Standards	12 Months Ended
New Financial Accounting Standards	Dec. 31, 2018
Accounting Changes and Error Corrections [Abstract]
New Financial Accounting Standards	New Financial Accounting Standards In January 2019, the Companies adopted Accounting Standards Update (ASU) No. 2016-02, “Leases (Topic 842),” including the amendments thereto (the New Standard), using a modified retrospective transition method of adoption. The New Standard supersedes the lease requirements within Accounting Standard Codification (ASC) Topic 840, “Leases.” The New Standard requires lessees to recognize assets and liabilities on the balance sheet and disclose key information about leasing arrangements. Under the New Standard, lessees will need to recognize a right-of-use asset and a lease liability for virtually all of their leases (other than leases that meet the definition of a short-term lease). The Utilities, as regulated entities, are permitted to continue to recognize expense using the timing that conforms to the regulatory rate treatment. Lessor accounting is similar to the previous model, but updated to align with “Revenue from Contracts with Customers (Topic 606)." Upon adoption of the New Standard, the Companies elected the following practical expedients: (1) for leases commenced prior to adoption date, the following three transition expedients that will allow the Companies to not reassess: (a) whether expired contracts contain leases; (b) the lease classification for expired leases and (c) the initial direct costs for existing leases; (2) for an underlying asset class, an expedient that allows the Companies to not apply the recognition requirements to short-term leases and an expedient that will allow 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. For leases previously classified as operating leases, upon adoption of the New Standard, the Companies recognized on their balance sheets right-of-use assets and corresponding lease liabilities of approximately $875 million and $635 million for Con Edison and CECONY, respectively, as of January 1, 2019. The adoption of the New Standard will not have a material effect on the Companies’ liquidity or results of operations. The Companies will prepare additional disclosures as required by the New Standard beginning in 2019. The Companies implemented additional internal controls related to the New Standard, however the adoption of the New Standard is not expected to require a change that will materially affect the Companies’ internal control over financial reporting. In January 2017, the FASB issued amendments to the guidance for the subsequent measurement of goodwill through 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 should 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. For public entities, the amendments are effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity. In March 2017, the FASB issued amendments to the guidance for debt securities through ASU 2017-08, “Receivables-Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities.” The amendments in this update shorten the amortization period for certain callable debt securities held at a premium. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity. For public entities, the amendments are effective for reporting periods beginning after December 15, 2018. Early adoption is permitted. The application of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity. 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. For public entities, the amendments are effective, and the Companies plan to adopt the amendments, for reporting periods beginning after December 15, 2018. The application of the guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity. In February 2018, the FASB issued amendments to the guidance for reporting comprehensive income through ASU 2018-02, “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The amendments allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. For public entities, the amendments are effective for reporting periods beginning after December 15, 2018, with early adoption permitted. The Companies adopted the amendments in the fourth quarter of 2018. The impact of adoption on the Companies’ financial position, results of operations and liquidity was immaterial. In August 2018, the FASB issued amendments to the guidance for internal use software through ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” The amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. For public entities, the amendments are effective for reporting periods beginning after December 15, 2019, with early adoption permitted. The Companies elected to adopt the amendments in the third quarter of 2018, prospectively for all in-scope implementation costs incurred after the date of adoption. The impact of adoption on the Companies’ financial position, results of operations and liquidity was immaterial.

Acquisitions, Investments and Dispositions

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017, CET Gas' investment in MVP was $363 million and $98 million, respectively. MVP has indicated that the project has an estimated total cost of $4,600 million and is targeted to be fully in-service during the fourth quarter of 2019. Con Edison is accounting for its equity interest in MVP as an equity method investment.

Pilesgrove

In June 2016, Con Edison Development recorded an $8 million ($5 million, net of taxes) impairment charge on its 50 percent equity interest in Pilesgrove Solar, LLC (Pilesgrove), which owns an 18 MW (AC) solar electric production project in New Jersey. In August 2016, Con Edison Development acquired the remaining 50 percent equity interest in Pilesgrove for a purchase price of approximately $16 million and recorded a bargain purchase gain of $8 million ($5 million, net of taxes); $45 million was recorded as non-utility property and the remaining $3 million was recorded as current assets. The impairment charge and bargain purchase gain are included in Investment and other income on Con Edison’s consolidated income statement. At December 31, 2018 and 2017, net assets of the project were approximately $45 million. Con Edison's equity interest in Pilesgrove is consolidated in the financial statements.

Sempra Solar

On December 13, 2018, a Con Edison Development subsidiary completed its acquisition of Sempra Solar Holdings, LLC, a Sempra Energy subsidiary, for $1,609 million, including working capital and other closing adjustments of $69 million. Under the accounting rules for acquisitions, Con Edison has one year to finalize the purchase price allocation, including working capital adjustments and other closing adjustments. 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 other Con Edison Development subsidiaries 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 $1,454 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 $128 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. See "Investments" in Note A. 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 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.

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

Con Edison Solutions' Retail Electric Supply Business

In July 2016, Con Edison Solutions entered into an agreement to sell the assets of its retail electric supply business (including retail contracts, related derivative instruments, information systems, and accounts receivable) to a subsidiary of Exelon Corporation (Exelon). In September 2016, the sale was completed for cash consideration of $235 million, subject to working capital adjustments. The sale resulted in a gain of $104 million ($56 million, net of taxes), inclusive of a $65 million ($42 million, net of taxes) gain on derivative instruments. The tax effect of the sale included $16 million ($10 million, net of federal tax) of state taxes related to a change in the apportionment of state income taxes. Con Edison Solutions provided transition services to the Exelon subsidiary for operations and customer support through January 2018 during a portion of which period certain guarantees or other credit support provided by Con Edison in connection with the retail electric supply business continued in effect.

Upton 2

In May 2017, Con Edison Development 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, Con Edison Development agreed to perform the engineering, procurement and construction for the 180 MW (AC) project, which was substantially completed in the third quarter of 2018.

Schedule I - Condensed Financial Information

12 Months Ended

Dec. 31, 2018

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)	2018	2017	2016
Equity in earnings of subsidiaries	$1,447	$1,544	$1,254
Other income (deductions), net of taxes	(6)	31	32
Interest expense	(59)	(50)	(41)
Net Income	$1,382	$1,525	$1,245
Comprehensive Income	$1,392	$1,526	$1,252
Net Income Per Share – Basic	$4.43	$4.97	$4.15
Net Income Per Share – Diluted	$4.42	$4.94	$4.12
Dividends Declared Per Share	$2.86	$2.76	$2.68
Average Number Of Shares Outstanding—Basic (In Millions)	311.7	307.1	300.4
Average Number Of Shares Outstanding—Diluted (In Millions)	312.9	308.8	301.9


(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 Statement of Cash Flows

(Parent Company Only)



	For the Years Ended December 31,
(Millions of Dollars)	2018	2017	2016
Net Income	1,382	1,525	1,245
Equity in earnings of subsidiaries	(1,447)	(1,544)	(1,254)
Dividends received from:
CECONY	846	796	744
O&R	46	44	43
Clean Energy Businesses	15	12	10
Con Edison Transmission	10	8	—
Change in Assets:
Special deposits	(8)	—	—
Income taxes receivable	2	34	87
Other – net	187	21	(152)
Net Cash Flows from Operating Activities	1,033	896	723
Investing Activities
Contributions to subsidiaries	(1,110)	(434)	(691)
Debt receivable from affiliated companies	(825)	—	(900)
Net Cash Flows Used in Investing Activities	(1,935)	(434)	(1,591)
Financing Activities
Net proceeds of short-term debt	164	(53)	(53)
Issuance of long-term debt	825	400	900
Retirement of long-term debt	(3)	(402)	(2)
Debt issuance costs	—	(2)	(5)
Issuance of common shares for stock plans, net of repurchases	53	51	51
Issuance of common shares - public offering	705	343	702
Common stock dividends	(842)	(803)	(763)
Net Cash Flows Used in Financing Activities	902	(466)	830
Net Change for the Period	—	(4)	(38)
Balance at Beginning of Period	9	13	51
Balance at End of Period	$9	$9	$13


(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)	2018	2017
Assets
Current Assets
Cash and temporary cash investments	$9	$9
Income taxes receivable	43	45
Term loan receivable from affiliated companies	825	—
Accounts receivable from affiliated companies	536	687
Prepayments	33	36
Other current assets	12	18
Total Current Assets	1,458	795
Investments in subsidiaries	16,707	15,110
Goodwill	406	406
Deferred income tax	69	18
Long-term debt receivable from affiliated companies	900	900
Other noncurrent assets	2	2
Total Assets	$19,542	$17,231
Liabilities and Shareholders’ Equity
Current Liabilities
Long-term debt due within one year	$3	$2
Term loan	825	—
Notes payable	495	331
Accounts payable	9	—
Accounts payable to affiliated companies	274	274
Accrued taxes	2	—
Other current liabilities	13	10
Total Current Liabilities	1,621	617
Total Liabilities	1,621	617
Long-term debt	1,195	1,195
Shareholders’ Equity
Common stock, including additional paid-in capital	7,151	6,331
Retained earnings	9,575	9,088
Total Shareholders’ Equity	16,726	15,419
Total Liabilities and Shareholders’ Equity	$19,542	$17,231


(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, 2018

Accounting Policies [Abstract]

Principles of Consolidation

Accounting Policies

Revenues

Adoption of New Standard

Revenue Recognition



(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)		Total operating revenues
CECONY
Electric	$7,920		$51		$7,971
Gas	2,052		26		2,078
Steam	625		6		631
Total CECONY	$10,597		$83		$10,680
O&R
Electric	647		(5)		642
Gas	256		(7)		249
Total O&R	$903		$(12)		$891
Clean Energy Businesses
Renewables	329	(b)	—		329
Energy services	95		—		95
Other	—		339		339
Total Clean Energy Businesses	$424		$339		$763
Con Edison Transmission	4		—		4
Other (c)	—		(1	)	(1	)
Total Con Edison	$11,928		$409		$12,337

(b) Included within the total for Renewables revenue at the Clean Energy Businesses is $103 million of revenue related to engineering, procurement and construction services.



(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1, 2018	$58	$87
Additions (c)	144	38
Subtractions (c)	173	105	(d)
Ending balance as of December 31, 2018	$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 $105 million in subtractions from unearned revenue, $50 million was included in the balance as of December 31, 2017.

Plant and Depreciation

Non–Utility Plant

Plant and Depreciation

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

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.

Reclassification

Certain prior year amounts have been reclassified to conform with the current year presentation.

Earnings Per Common Share

Estimates

New Financial Accounting Standards

In January 2019, the Companies adopted Accounting Standards Update (ASU) No. 2016-02, “Leases (Topic 842),” including the amendments thereto (the New Standard), using a modified retrospective transition method of adoption. The New Standard supersedes the lease requirements within Accounting Standard Codification (ASC) Topic 840, “Leases.” The New Standard requires lessees to recognize assets and liabilities on the balance sheet and disclose key information about leasing arrangements. Under the New Standard, lessees will need to recognize a right-of-use asset and a lease liability for virtually all of their leases (other than leases that meet the definition of a short-term lease). The Utilities, as regulated entities, are permitted to continue to recognize expense using the timing that conforms to the regulatory rate treatment. Lessor accounting is similar to the previous model, but updated to align with “Revenue from Contracts with Customers (Topic 606)."

Upon adoption of the New Standard, the Companies elected the following practical expedients: (1) for leases commenced prior to adoption date, the following three transition expedients that will allow the Companies to not reassess: (a) whether expired contracts contain leases; (b) the lease classification for expired leases and (c) the initial direct costs for existing leases; (2) for an underlying asset class, an expedient that allows the Companies to not apply the recognition requirements to short-term leases and an expedient that will allow 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. For leases previously classified as operating leases, upon adoption of the New Standard, the Companies recognized on their balance sheets right-of-use assets and corresponding lease liabilities of approximately $875 million and $635 million for Con Edison and CECONY, respectively, as of January 1, 2019.

The adoption of the New Standard will not have a material effect on the Companies’ liquidity or results of operations. The Companies will prepare additional disclosures as required by the New Standard beginning in 2019. The Companies implemented additional internal controls related to the New Standard, however the adoption of the New Standard is not expected to require a change that will materially affect the Companies’ internal control over financial reporting.

In January 2017, the FASB issued amendments to the guidance for the subsequent measurement of goodwill through 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 should 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. For public entities, the amendments are effective for reporting periods beginning after December 15, 2019. Early adoption is permitted. The application of this guidance is not expected to have a material impact on the Companies’ financial position, results of operations and liquidity.

In March 2017, the FASB issued amendments to the guidance for debt securities through ASU 2017-08, “Receivables-Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities.” The amendments in this update shorten the amortization period for certain callable debt securities held at a premium. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity. For public entities, the amendments are effective for reporting periods beginning after December 15, 2018. Early adoption is permitted. The application of this guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity.

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. For public entities, the amendments are effective, and the Companies plan to adopt the amendments, for reporting periods beginning after December 15, 2018. The application of the guidance will not have a material impact on the Companies’ financial position, results of operations and liquidity.

In February 2018, the FASB issued amendments to the guidance for reporting comprehensive income through ASU 2018-02, “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The amendments allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. For public entities, the amendments are effective for reporting periods beginning after December 15, 2018, with early adoption permitted. The Companies adopted the amendments in the fourth quarter of 2018. The impact of adoption on the Companies’ financial position, results of operations and liquidity was immaterial.

In August 2018, the FASB issued amendments to the guidance for internal use software through ASU 2018-15, “Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” The amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. For public entities, the amendments are effective for reporting periods beginning after December 15, 2019, with early adoption permitted. The Companies elected to adopt the amendments in the third quarter of 2018, prospectively for all in-scope implementation costs incurred after the date of adoption. The impact of adoption on the Companies’ financial position, results of operations and liquidity was immaterial.

Summary of Significant Accounting Policies and Other Matters (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Disaggregation of Revenue



(Millions of Dollars)	Revenues from contracts with customers		Other revenues (a)		Total operating revenues
CECONY
Electric	$7,920		$51		$7,971
Gas	2,052		26		2,078
Steam	625		6		631
Total CECONY	$10,597		$83		$10,680
O&R
Electric	647		(5)		642
Gas	256		(7)		249
Total O&R	$903		$(12)		$891
Clean Energy Businesses
Renewables	329	(b)	—		329
Energy services	95		—		95
Other	—		339		339
Total Clean Energy Businesses	$424		$339		$763
Con Edison Transmission	4		—		4
Other (c)	—		(1	)	(1	)
Total Con Edison	$11,928		$409		$12,337

(b) Included within the total for Renewables revenue at the Clean Energy Businesses is $103 million of revenue related to engineering, procurement and construction services.

Change in Unbilled Contract and Unearned Revenues



(Millions of Dollars)	Unbilled contract revenue (a)	Unearned revenue (b)
Beginning balance as of January 1, 2018	$58	$87
Additions (c)	144	38
Subtractions (c)	173	105	(d)
Ending balance as of December 31, 2018	$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 $105 million in subtractions from unearned revenue, $50 million was included in the balance as of December 31, 2017.

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)	2018	2017	2016
Con Edison	$330	$302	$336
CECONY	318	292	316

Capitalized Cost of Utility Plant

At December 31, 2018 and 2017, the capitalized cost of the Companies’ utility plant, net of accumulated depreciation, was as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Electric
Generation	$593	$544	$592	$544
Transmission	3,333	3,210	3,106	2,990
Distribution	19,750	18,959	18,716	17,996
Gas (a)	7,714	6,976	7,107	6,403
Steam	1,830	1,798	1,830	1,798
General	2,306	2,105	2,102	1,905
Held for future use	76	76	67	67
Construction work in progress	1,978	1,605	1,850	1,502
Net Utility Plant	$37,580	$35,273	$35,370	$33,205

(a) Primarily distribution.

Schedule of Investment Assets

The following investment assets are included in the Companies' consolidated balance sheets at December 31, 2018 and 2017:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018		2017
CET Gas investment in Stagecoach Gas Services, LLC	$948	$971		$—		$—
CET Gas investment in Mountain Valley Pipeline, LLC (a)	363	98	—		—
Supplemental retirement income plan assets (c)	326	330	301		301
Deferred income plan assets	75	73	75		73
CET Electric investment in New York Transco, LLC	52	53	—		—
Con Edison Development equity method investments (b)	—	467	—		—
Other	2	9	9		9
Total investments	$1,766	$2,001	$385		$383


(a)	See Note U.


(b)	Upon completion of the acquisition of Sempra Solar Holdings, LLC in December 2018, Con Edison is accounting on a consolidated basis for certain jointly-owned renewable electric production projects that previously were accounted for as equity method investments. See Note U.


(c)	See Note E.

Research and Development Costs

Research and development costs were as follows:



	For the Years Ended December 31,
(Millions of Dollars)	2018	2017	2016
Con Edison	$24	$24	$24
CECONY	23	23	22

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)	2018	2017	2016
Net income	$1,382	$1,525	$1,245
Weighted average common shares outstanding – basic	311.7	307.1	300.4
Add: Incremental shares attributable to effect of potentially dilutive securities	1.2	1.7	1.5
Adjusted weighted average common shares outstanding – diluted	312.9	308.8	301.9
Net Income per common share – basic	$4.43	$4.97	$4.15
Net Income per common share – diluted	$4.42	$4.94	$4.12

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, 2015 (a)	$(34)	$(9)
OCI before reclassifications, net of tax of $(1) for Con Edison and CECONY	2	1
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, 2016	7	2
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)

(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, 2018 and 2017, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Cash and temporary cash investments	$895	$797	$818	$730
Restricted cash (a)	111	47	—	—
Total cash, temporary cash investments and restricted cash	$1,006	$844	$818	$730

(a)

Schedule of Cash and Cash Equivalents

At December 31, 2018 and 2017, cash, temporary cash investments and restricted cash for Con Edison and CECONY were as follows:



	At December 31,
	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Cash and temporary cash investments	$895	$797	$818	$730
Restricted cash (a)	111	47	—	—
Total cash, temporary cash investments and restricted cash	$1,006	$844	$818	$730

(a)

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Summary of Utilities Rate Plans

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



CECONY – Electric
Effective period	January 2014 – December 2016	January 2017 – December 2019 (b)
Base rate changes	Yr. 1 – $(76.2) million (a) Yr. 2 – $124.0 million (a) Yr. 3 – None	Yr. 1 – $195 million (c) Yr. 2 – $155 million (c) Yr. 3 – $155 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 and 2 – $(37) million (d) Yr. 3 – $123 million (d)	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million



Other revenue sources	Retention of $90 million of annual transmission congestion revenues.	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 and 2018, the company recorded $13 million and $25 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved other incentives of $5 million in 2017 and 2018 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $3 million for service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred for customer benefit $146 million, $98 million and $101 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017 and 2018, the company deferred for customer benefit $45 million and $(6) million of revenues, respectively.
Recoverable energy costs (e)	Current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $57 million, $26 million and $68 million of net regulatory liabilities, respectively (f).	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (f), municipal infrastructure support costs (g), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (h). In 2017 and 2018, the company deferred $35 million and $189 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred $6 million and $17 million as a regulatory liability in 2014 and 2015, respectively. In 2016, $9 million was deferred as a regulatory asset.	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, $0.4 was deferred as a regulatory liability.
Average rate base	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent	9.0 percent
Actual return on common equity	Yr. 1 – 9.04 percent Yr. 2 – 10.16 percent Yr. 3 – 9.66 percent	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 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 $44.4 million and $6.5 million above the threshold for 2015 and 2016, respectively.	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, the company had no earnings sharing above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred; this amount was amortized to $0 at December 31, 2016.

(b)

(c)

(d)

(e)


(f)	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 (5.0, 7.5 or 10.0 basis points, depending on the year).

(g)

(h)



CECONY – Gas
Effective period	January 2014 – December 2016	January 2017 - December 2019 (b)
Base rate changes	Yr. 1 – $(54.6) million (a) Yr. 2 – $38.6 million (a) Yr. 3 – $56.8 million (a)	Yr. 1 – $(5) million (b) Yr. 2 – $92 million (b) Yr. 3 – $90 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$4 million over three years	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million
Other revenue sources	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million, $66 million and $65 million of such revenues in 2014, 2015 and 2016, respectively.	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 and 2018, the company achieved incentives of $7 million and $6 million, respectively that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $5 million for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred $28 million, $54 million and $71 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017 and 2018, the company deferred $3 million and $12 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014, 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties 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 $5 million and $4 million of negative revenue adjustments, respectively.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $38 million, $11 million, and $32 million of net regulatory liabilities, respectively. (c)	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes, municipal infrastructure support costs, the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (d) In 2017 and 2018, the company deferred $2 million of net regulatory liabilities and $44 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million In 2015 $1 million was deferred as a regulatory liability. In 2014 and 2016 the company deferred an immaterial amount.	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.
Average rate base	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	9.3 percent	9.0 percent
Actual return on common equity	Yr. 1 – 8.02 percent Yr. 2 – 8.13 percent Yr. 3 – 7.83 percent	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent



Earnings sharing	Most 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, 2015 and 2016, the company had no earnings above the threshold.	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 and 2018, the company had no earnings above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred which resulted in a $32 million regulatory liability at December 31, 2016.


(b)	In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's gas rate plan for January 2017 through December 2019. The gas base rate decrease is offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.


(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)	See footnotes (e), (f), (g) and (h) 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
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 penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014, 2015, 2016 and 2017 and 2018, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016 2017 and 2018, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, and $1 million of net regulatory assets, 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 and 2018.
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		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
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 $14.2 million above the threshold, and an additional $1.1 million related to 2017 was recorded.
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.



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; and Yr. 3 - $4.2 million. Potential incentive if performance target related to service terminations is met: $0.5 million annually.
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.
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 penalties (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 penalties if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million; Yr. 2 - $4.4 million; and Yr. 3 - $4.5 million.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.

(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 Joint Proposal recommends that these base rate changes may 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.



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.
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.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (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 penalties 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.
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)
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
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	9.00 percent
Actual return on common equity	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 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.
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 continue in effect until a new rate plan is approved by the NYSPSC.


(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 Joint Proposal recommends that these base rate changes may be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

Footnotes (f) through (j) to this table are the same as footnotes (f) through (j) to the table under “O&R New York - Electric,” above.



RECO
Effective period	August 2014 – February 2017	March 2017 (a)
Base rate changes	Yr. 1 – $13.0 million	Yr. 1 – $1.7 million
Amortization to income of net regulatory (assets) and liabilities	$0.4 million over three years and $(25.6) million of deferred storm costs over four years	$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 (b)
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$172.2 million	Yr. 1 – $178.7 million
Weighted average cost of capital (after-tax)	7.83 percent	7.47 percent
Authorized return on common equity	9.75 percent	9.6 percent
Actual return on common equity	Yr. 1 – 9.2 percent Yr. 2 – 8.7 percent	Yr. 1 – 7.5 percent
Cost of long-term debt	5.89 percent	5.37 percent
Common equity ratio	50 percent	49.7 percent


(a)	Effective until a new rate plan approved by the NJBPU goes into effect.


(b)	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 custome

Schedule of Regulatory Assets

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2018 and 2017 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Regulatory assets
Unrecognized pension and other postretirement costs	$2,238	$2,526	$2,111	$2,376
Environmental remediation costs	810	793	716	677
Revenue taxes	291	260	278	248
MTA power reliability deferral	229	50	229	50
Property tax reconciliation	101	51	86	25
Deferred storm costs	76	38	—	—
Pension and other postretirement benefits deferrals	73	79	56	58
Municipal infrastructure support costs	67	56	67	56
System peak reduction and energy efficiency programs	72	14	70	14
Brooklyn Queens demand management program	39	37	39	37
Unamortized loss on reacquired debt	36	37	34	35
Meadowlands heater odorization project	36	18	36	18
Preferred stock redemption	23	24	23	24
Recoverable REV demonstration project costs	20	19	18	17
Deferred derivative losses	17	44	11	37
Gate station upgrade project	17	13	17	13
Indian Point Energy Center program costs	13	29	13	29
Workers’ compensation	5	10	5	10
Recoverable energy costs	3	60	—	52
O&R transition bond charges	2	9	—	—
Surcharge for New York State assessment	—	2	—	2
Other	126	97	114	85
Regulatory assets – noncurrent	4,294	4,266	3,923	3,863
Recoverable energy costs	40	27	35	25
Deferred derivative losses	36	40	29	37
Regulatory assets – current	76	67	64	62
Total Regulatory Assets	$4,370	$4,333	$3,987	$3,925
Regulatory liabilities
Future income tax*	$2,515	$2,545	$2,363	$2,390
Allowance for cost of removal less salvage	928	846	790	719
TCJA net benefits	434	—	411	—
Energy efficiency portfolio standard unencumbered funds	127	127	122	122
Net unbilled revenue deferrals	117	183	117	183
Pension and other postretirement benefit deferrals	62	207	40	181
Property tax refunds	45	44	45	44
Settlement of prudence proceeding	37	66	37	66
Property tax reconciliation	36	107	36	107
Earnings sharing - electric, gas and steam	36	29	27	19
System benefit charge carrying charge	27	12	24	11
Carrying charges on repair allowance and bonus depreciation	21	43	21	42
BQDM and REV Demo reconciliations	18	9	18	9
New York State income tax rate change	17	36	17	35
Settlement of gas proceedings	15	27	15	27
Base rate change deferrals	10	21	10	21
Unrecognized other postretirement costs	7	92	7	92
Net utility plant reconciliations	3	12	1	8
Variable-rate tax-exempt debt - cost rate reconciliation	1	30	1	26
Other	185	141	156	117
Regulatory liabilities – noncurrent	4,641	4,577	4,258	4,219
Revenue decoupling mechanism	53	29	36	21
Refundable energy costs	31	41	8	16
Deferred derivative gains	30	31	29	28
Regulatory liabilities—current	114	101	73	65
Total Regulatory Liabilities	$4,755	$4,678	$4,331	$4,284

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

Schedule of Regulatory Liabilities

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2018 and 2017 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Regulatory assets
Unrecognized pension and other postretirement costs	$2,238	$2,526	$2,111	$2,376
Environmental remediation costs	810	793	716	677
Revenue taxes	291	260	278	248
MTA power reliability deferral	229	50	229	50
Property tax reconciliation	101	51	86	25
Deferred storm costs	76	38	—	—
Pension and other postretirement benefits deferrals	73	79	56	58
Municipal infrastructure support costs	67	56	67	56
System peak reduction and energy efficiency programs	72	14	70	14
Brooklyn Queens demand management program	39	37	39	37
Unamortized loss on reacquired debt	36	37	34	35
Meadowlands heater odorization project	36	18	36	18
Preferred stock redemption	23	24	23	24
Recoverable REV demonstration project costs	20	19	18	17
Deferred derivative losses	17	44	11	37
Gate station upgrade project	17	13	17	13
Indian Point Energy Center program costs	13	29	13	29
Workers’ compensation	5	10	5	10
Recoverable energy costs	3	60	—	52
O&R transition bond charges	2	9	—	—
Surcharge for New York State assessment	—	2	—	2
Other	126	97	114	85
Regulatory assets – noncurrent	4,294	4,266	3,923	3,863
Recoverable energy costs	40	27	35	25
Deferred derivative losses	36	40	29	37
Regulatory assets – current	76	67	64	62
Total Regulatory Assets	$4,370	$4,333	$3,987	$3,925
Regulatory liabilities
Future income tax*	$2,515	$2,545	$2,363	$2,390
Allowance for cost of removal less salvage	928	846	790	719
TCJA net benefits	434	—	411	—
Energy efficiency portfolio standard unencumbered funds	127	127	122	122
Net unbilled revenue deferrals	117	183	117	183
Pension and other postretirement benefit deferrals	62	207	40	181
Property tax refunds	45	44	45	44
Settlement of prudence proceeding	37	66	37	66
Property tax reconciliation	36	107	36	107
Earnings sharing - electric, gas and steam	36	29	27	19
System benefit charge carrying charge	27	12	24	11
Carrying charges on repair allowance and bonus depreciation	21	43	21	42
BQDM and REV Demo reconciliations	18	9	18	9
New York State income tax rate change	17	36	17	35
Settlement of gas proceedings	15	27	15	27
Base rate change deferrals	10	21	10	21
Unrecognized other postretirement costs	7	92	7	92
Net utility plant reconciliations	3	12	1	8
Variable-rate tax-exempt debt - cost rate reconciliation	1	30	1	26
Other	185	141	156	117
Regulatory liabilities – noncurrent	4,641	4,577	4,258	4,219
Revenue decoupling mechanism	53	29	36	21
Refundable energy costs	31	41	8	16
Deferred derivative gains	30	31	29	28
Regulatory liabilities—current	114	101	73	65
Total Regulatory Liabilities	$4,755	$4,678	$4,331	$4,284

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

Capitalization (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of Long-Term Debt Maturities

Long-term debt maturing in the period 2019-2023 is as follows:



(Millions of Dollars)	Con Edison	CECONY
2019	$650	$475
2020	866	350
2021	1,260	640
2022	413	—
2023	293	—

Carrying Amounts and Fair Values of Long-Term Debt

The carrying amounts and fair values of long-term debt at December 31, 2018 and 2017 are:



(Millions of Dollars)	2018		2017
Long-Term Debt (including current portion) (a)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Con Edison	$18,145	$18,740	$16,029	$18,147
CECONY	$14,151	$14,685	$13,625	$15,163


(a)	Amounts shown are net of unamortized debt expense and unamortized debt discount of $185 million and $139 million for Con Edison and CECONY, respectively, as of December 31, 2018 and $142 million and $121 million for Con Edison and CECONY, respectively, as of December 31, 2017.

- 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)
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Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
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Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
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-Name Accounting Standards Codification
-Topic 505
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-Section 50
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Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
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-Subparagraph (SX 210.4-08.(e),(f))
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Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
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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
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Pension Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Total Periodic Benefit Costs

The components of the Companies’ total periodic benefit costs for 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost – including administrative expenses	$290	$263	$275	$272	$246	$258
Interest cost on projected benefit obligation	561	591	596	525	554	559
Expected return on plan assets	(1,033)	(968)	(947)	(979)	(917)	(898)
Recognition of net actuarial loss	688	595	596	651	563	565
Recognition of prior service cost/(credit)	(17)	(17)	4	(19)	(19)	2
TOTAL PERIODIC BENEFIT COST	$489	$464	$524	$450	$427	$486
Cost capitalized	(127)	(181)	(214)	(119)	(169)	(203)
Reconciliation to rate level	(92)	(34)	54	(100)	(41)	58
Total expense recognized	$270	$249	$364	$231	$217	$341

The components of the Companies’ total periodic postretirement benefit costs for 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost	$20	$20	$18	$14	$13	$13
Interest cost on accumulated other postretirement benefit obligation	42	46	48	34	38	40
Expected return on plan assets	(73)	(69)	(77)	(63)	(61)	(67)
Recognition of net actuarial loss/(gain)	8	2	5	3	(3)	3
Recognition of prior service cost/(credit)	(6)	(17)	(20)	(2)	(11)	(14)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST/(CREDIT)	$(9)	$(18)	$(26)	$(14)	$(24)	$(25)
Cost capitalized	(8)	8	11	(6)	10	10
Reconciliation to rate level	8	(4)	22	9	(2)	22
Total expense/(credit) recognized	$(9)	$(14)	$7	$(11)	$(16)	$7

Schedule of Funded Status

The funded status at December 31, 2018, 2017 and 2016 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,536	$14,095	$14,377	$14,567	$13,203	$13,482
Service cost – excluding administrative expenses	286	259	271	267	241	254
Interest cost on projected benefit obligation	561	591	596	525	554	559
Net actuarial loss/(gain)	(1,219)	1,231	(302)	(1,159)	1,171	(282)
Plan amendments	—	6	(256)	—	—	(259)
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$14,274	$12,472	$11,759	$13,519	$11,815	$11,141
Actual return on plan assets	(536)	2,041	829	(507)	1,935	787
Employer contributions	473	450	508	434	412	469
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
Administrative expenses	(46)	(43)	(33)	(44)	(41)	(31)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
FUNDED STATUS	$(999)	$(1,262)	$(1,623)	$(798)	$(1,048)	$(1,388)
Unrecognized net loss	$2,464	$2,760	$3,157	$2,338	$2,624	$2,995
Unrecognized prior service costs	(205)	(223)	(244)	(222)	(242)	(258)
Accumulated benefit obligation	13,030	13,897	12,655	12,161	12,972	11,806

The funded status of the programs at December 31, 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,219	$1,198	$1,287	$985	$1,007	$1,093
Service cost	20	20	18	14	13	13
Interest cost on accumulated postretirement benefit obligation	42	46	48	34	38	40
Net actuarial loss/(gain)	(70)	53	(57)	(32)	16	(52)
Benefits paid and administrative expenses, net of subsidies	(135)	(134)	(134)	(125)	(124)	(122)
Participant contributions	38	36	36	37	35	35
BENEFIT OBLIGATION AT END OF YEAR	$1,114	$1,219	$1,198	$913	$985	$1,007
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$1,039	$975	$994	$893	$851	$870
Actual return on plan assets	(66)	150	60	(54)	130	52
Employer contributions	6	17	7	6	8	7
Employer group waiver plan subsidies	34	34	35	32	30	33
Participant contributions	37	35	36	37	35	35
Benefits paid	(165)	(172)	(157)	(155)	(161)	(146)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$885	$1,039	$975	$759	$893	$851
FUNDED STATUS	$(229)	$(180)	$(223)	$(154)	$(92)	$(156)
Unrecognized net loss/(gain)	$14	$(47)	$(24)	$(2)	$(85)	$(42)
Unrecognized prior service costs	(8)	(14)	(31)	(5)	(7)	(18)

Schedule of Assumptions

The actuarial assumptions were as follows:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.70	%	4.25	%	4.25	%
Expected return on plan assets	7.50	%	7.50	%	7.80	%
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:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	3.55	%	4.00	%	4.05	%
O&R	3.70	%	4.20	%	4.20	%
Expected Return on Plan Assets	7.50	%	7.50	%	7.00	%

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)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$707	$726	$740	$755	$772	$4,072
CECONY	658	676	689	703	718	3,795

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



(Millions of Dollars)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$80	$78	$76	$75	$74	$359
CECONY	70	67	65	64	63	302

Schedule of Plan Assets Allocations

The asset allocations for the pension plan at the end of 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	45% - 55%	51	%	58	%	58	%
Debt Securities	33% - 43%	39	%	33	%	33	%
Real Estate	10% -14%	10	%	9	%	9	%
Total	100%	100	%	100	%	100	%

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	42%-80%	52	%	60	%	60	%
Debt Securities	20%-58%	48	%	40	%	40	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Value of Plan Assets

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)	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, 2017 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,872	$28	$3,900
International Equity (b)	4,132	—	4,132
U.S. Government Issued Debt (c)	—	1,786	1,786
Corporate Bonds Debt (d)	—	2,450	2,450
Structured Assets Debt (e)	—	3	3
Other Fixed Income Debt (f)	—	125	125
Cash and Cash Equivalents (g)	124	352	476
Futures (h)	308	—	308
Total investments within the fair value hierarchy	$8,436	$4,744	$13,180
Investments measured at NAV per share (n)
Private Equity (i)			336
Real Estate (j)			1,214
Hedge Funds (k)			251
Total investments valued using NAV per share			$1,801
Funds for retiree health benefits (l)	(168)	(94)	(262)
Funds for retiree health benefits measured at NAV per share (l)(n)			(36)
Total funds for retiree health benefits			$(298)
Investments (excluding funds for retiree health benefits)	$8,268	$4,650	$14,683
Pending activities (m)			(409)
Total fair value of plan net assets			$14,274

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2018 by asset category.

The fair values of the plans' assets at December 31, 2018 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)		$—	$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)	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, 2017 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$420	$420
Other Fixed Income Debt (b)	—		286	286
Cash and Cash Equivalents (c)	—		16	16
Total investments		$—	$722	$722
Funds for retiree health benefits (d)	168		94	262
Investments (including funds for retiree health benefits)		$168	$816	$984
Funds for retiree health benefits measured at net asset value (d)(e)				36
Pending activities (f)				19
Total fair value of plan net assets				$1,039

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2018 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)	2018	2017	2016
Con Edison	$45	$40	$36
CECONY	39	35	32

Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Net Periodic Benefit Costs

The components of the Companies’ total periodic benefit costs for 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost – including administrative expenses	$290	$263	$275	$272	$246	$258
Interest cost on projected benefit obligation	561	591	596	525	554	559
Expected return on plan assets	(1,033)	(968)	(947)	(979)	(917)	(898)
Recognition of net actuarial loss	688	595	596	651	563	565
Recognition of prior service cost/(credit)	(17)	(17)	4	(19)	(19)	2
TOTAL PERIODIC BENEFIT COST	$489	$464	$524	$450	$427	$486
Cost capitalized	(127)	(181)	(214)	(119)	(169)	(203)
Reconciliation to rate level	(92)	(34)	54	(100)	(41)	58
Total expense recognized	$270	$249	$364	$231	$217	$341

The components of the Companies’ total periodic postretirement benefit costs for 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Service cost	$20	$20	$18	$14	$13	$13
Interest cost on accumulated other postretirement benefit obligation	42	46	48	34	38	40
Expected return on plan assets	(73)	(69)	(77)	(63)	(61)	(67)
Recognition of net actuarial loss/(gain)	8	2	5	3	(3)	3
Recognition of prior service cost/(credit)	(6)	(17)	(20)	(2)	(11)	(14)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST/(CREDIT)	$(9)	$(18)	$(26)	$(14)	$(24)	$(25)
Cost capitalized	(8)	8	11	(6)	10	10
Reconciliation to rate level	8	(4)	22	9	(2)	22
Total expense/(credit) recognized	$(9)	$(14)	$7	$(11)	$(16)	$7

Schedule of Funded Status

The funded status at December 31, 2018, 2017 and 2016 was as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	$15,536	$14,095	$14,377	$14,567	$13,203	$13,482
Service cost – excluding administrative expenses	286	259	271	267	241	254
Interest cost on projected benefit obligation	561	591	596	525	554	559
Net actuarial loss/(gain)	(1,219)	1,231	(302)	(1,159)	1,171	(282)
Plan amendments	—	6	(256)	—	—	(259)
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	$14,449	$15,536	$14,095	$13,542	$14,567	$13,203
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$14,274	$12,472	$11,759	$13,519	$11,815	$11,141
Actual return on plan assets	(536)	2,041	829	(507)	1,935	787
Employer contributions	473	450	508	434	412	469
Benefits paid	(715)	(646)	(591)	(658)	(602)	(551)
Administrative expenses	(46)	(43)	(33)	(44)	(41)	(31)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$13,450	$14,274	$12,472	$12,744	$13,519	$11,815
FUNDED STATUS	$(999)	$(1,262)	$(1,623)	$(798)	$(1,048)	$(1,388)
Unrecognized net loss	$2,464	$2,760	$3,157	$2,338	$2,624	$2,995
Unrecognized prior service costs	(205)	(223)	(244)	(222)	(242)	(258)
Accumulated benefit obligation	13,030	13,897	12,655	12,161	12,972	11,806

The funded status of the programs at December 31, 2018, 2017 and 2016 were as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year	$1,219	$1,198	$1,287	$985	$1,007	$1,093
Service cost	20	20	18	14	13	13
Interest cost on accumulated postretirement benefit obligation	42	46	48	34	38	40
Net actuarial loss/(gain)	(70)	53	(57)	(32)	16	(52)
Benefits paid and administrative expenses, net of subsidies	(135)	(134)	(134)	(125)	(124)	(122)
Participant contributions	38	36	36	37	35	35
BENEFIT OBLIGATION AT END OF YEAR	$1,114	$1,219	$1,198	$913	$985	$1,007
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$1,039	$975	$994	$893	$851	$870
Actual return on plan assets	(66)	150	60	(54)	130	52
Employer contributions	6	17	7	6	8	7
Employer group waiver plan subsidies	34	34	35	32	30	33
Participant contributions	37	35	36	37	35	35
Benefits paid	(165)	(172)	(157)	(155)	(161)	(146)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	$885	$1,039	$975	$759	$893	$851
FUNDED STATUS	$(229)	$(180)	$(223)	$(154)	$(92)	$(156)
Unrecognized net loss/(gain)	$14	$(47)	$(24)	$(2)	$(85)	$(42)
Unrecognized prior service costs	(8)	(14)	(31)	(5)	(7)	(18)

Schedule of Actuarial Assumptions

The actuarial assumptions were as follows:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	4.25	%	3.70	%	4.25	%
Rate of compensation increase
CECONY	4.25	%	4.25	%	4.25	%
O&R	4.00	%	4.00	%	4.00	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate	3.70	%	4.25	%	4.25	%
Expected return on plan assets	7.50	%	7.50	%	7.80	%
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:



	2018		2017		2016
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount Rate
CECONY	4.15	%	3.55	%	4.00	%
O&R	4.30	%	3.70	%	4.20	%
Weighted-average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount Rate
CECONY	3.55	%	4.00	%	4.05	%
O&R	3.70	%	4.20	%	4.20	%
Expected Return on Plan Assets	7.50	%	7.50	%	7.00	%

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, 2018:



	Con Edison		CECONY
	1-Percentage-Point
(Millions of Dollars)	Increase	Decrease	Increase	Decrease
Effect on accumulated other postretirement benefit obligation	$9	$11	$(18)	$31
Effect on service cost and interest cost components for 2018	2	(1)	(1)	1

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)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$707	$726	$740	$755	$772	$4,072
CECONY	658	676	689	703	718	3,795

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



(Millions of Dollars)	2019	2020	2021	2022	2023	2024-2028
Con Edison	$80	$78	$76	$75	$74	$359
CECONY	70	67	65	64	63	302

Schedule of Plan Assets Allocations

The asset allocations for the pension plan at the end of 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	45% - 55%	51	%	58	%	58	%
Debt Securities	33% - 43%	39	%	33	%	33	%
Real Estate	10% -14%	10	%	9	%	9	%
Total	100%	100	%	100	%	100	%

The asset allocations for CECONY’s other postretirement benefit plans at the end of 2018, 2017 and 2016, and the target allocation for 2019 are as follows:



	Target Allocation Range	Plan Assets at December 31,
Asset Category	2019	2018		2017		2016
Equity Securities	42%-80%	52	%	60	%	60	%
Debt Securities	20%-58%	48	%	40	%	40	%
Total	100%	100	%	100	%	100	%

Schedule of Fair Value of Plan Assets

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)	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, 2017 by asset category are as follows:



(Millions of Dollars)	Level 1	Level 2	Total
Investments within the fair value hierarchy
U.S. Equity (a)	$3,872	$28	$3,900
International Equity (b)	4,132	—	4,132
U.S. Government Issued Debt (c)	—	1,786	1,786
Corporate Bonds Debt (d)	—	2,450	2,450
Structured Assets Debt (e)	—	3	3
Other Fixed Income Debt (f)	—	125	125
Cash and Cash Equivalents (g)	124	352	476
Futures (h)	308	—	308
Total investments within the fair value hierarchy	$8,436	$4,744	$13,180
Investments measured at NAV per share (n)
Private Equity (i)			336
Real Estate (j)			1,214
Hedge Funds (k)			251
Total investments valued using NAV per share			$1,801
Funds for retiree health benefits (l)	(168)	(94)	(262)
Funds for retiree health benefits measured at NAV per share (l)(n)			(36)
Total funds for retiree health benefits			$(298)
Investments (excluding funds for retiree health benefits)	$8,268	$4,650	$14,683
Pending activities (m)			(409)
Total fair value of plan net assets			$14,274

(a) - (n) Reference is made to footnotes (a) through (n) in the above table of pension plan assets at December 31, 2018 by asset category.

The fair values of the plans' assets at December 31, 2018 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)		$—	$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)	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, 2017 by asset category (see Note P) are as follows:



(Millions of Dollars)	Level 1		Level 2	Total
Equity (a)		$—	$420	$420
Other Fixed Income Debt (b)	—		286	286
Cash and Cash Equivalents (c)	—		16	16
Total investments		$—	$722	$722
Funds for retiree health benefits (d)	168		94	262
Investments (including funds for retiree health benefits)		$168	$816	$984
Funds for retiree health benefits measured at net asset value (d)(e)				36
Pending activities (f)				19
Total fair value of plan net assets				$1,039

(a) - (f) Reference is made to footnotes (a) through (f) in the above table of other postretirement benefit plan assets at December 31, 2018 by asset category.

Environmental Matters (Tables)

12 Months Ended

Dec. 31, 2018

Environmental Remediation Obligations [Abstract]

Accrued Liabilities and Regulatory Assets

The accrued liabilities and regulatory assets related to Superfund Sites at December 31, 2018 and 2017 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Accrued Liabilities:
Manufactured gas plant sites	$689	$651	$603	$551
Other Superfund Sites	90	86	90	86
Total	$779	$737	$693	$637
Regulatory assets	$810	$793	$716	$677

Environmental Remediation Costs

Environmental remediation costs incurred related to Superfund Sites at December 31, 2018 and 2017 were as follows:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Remediation costs incurred	$25	$24	$18	$19

Accrued Liability for Asbestos Suits and Workers' Compensation Proceedings



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Accrued liability – asbestos suits	$8	$8	$7	$7
Regulatory assets – asbestos suits	$8	$8	$7	$7
Accrued liability – workers’ compensation	$79	$84	$75	$80
Regulatory assets – workers’ compensation	$5	$10	$5	$10

Leases (Tables)

12 Months Ended

Dec. 31, 2018

Leases [Abstract]

Schedule of Capital Leases

The following assets under capital leases are included in the Companies’ consolidated balance sheets at December 31, 2018 and 2017:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
UTILITY PLANT
Common	$1	$2	$1	$1

Future Minimum Rental Payments for Operating Leases

The future minimum lease commitments under the Companies’ operating lease agreements that are not cancellable by the Companies are 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, 2018

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax

The components of income tax are as follows:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
State
Current	$(10)	$(2)	$(42)	$6	$37	$(1)
Deferred	107	103	188	82	75	114
Federal
Current	3	(11)	(43)	(34)	73	59
Deferred	310	391	604	275	504	435
Amortization of investment tax credits	(9)	(9)	(9)	(3)	(4)	(4)
Total income tax expense	$401	$472	$698	$326	$685	$603

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)	2018	2017	2018	2017
Deferred tax liabilities:
Property basis differences	$7,402	$6,555	$6,446	$5,968
Regulatory assets:
Unrecognized pension and other postretirement costs	627	697	591	656
Environmental remediation costs	227	219	200	187
Deferred storm costs	21	11	—	—
Other regulatory assets	273	269	252	241
Equity investments	102	263	—	—
Total deferred tax liabilities	$8,652	$8,014	$7,489	$7,052
Deferred tax assets:
Accrued pension and other postretirement costs	$248	$264	$180	$187
Regulatory liabilities:
Future income tax	702	698	662	660
Other regulatory liabilities	632	593	554	524
Superfund and other environmental costs	218	203	194	176
Asset retirement obligations	114	86	82	79
Loss carryforwards	229	95	—	—
Tax credits carryforward	817	658	—	—
Valuation allowance	(33)	(33)	—	—
Other	53	112	102	148
Total deferred tax assets	2,980	2,676	1,774	1,774
Net deferred tax liabilities	$5,672	$5,338	$5,715	$5,278
Unamortized investment tax credits	148	157	24	28
Net deferred tax liabilities and unamortized investment tax credits	$5,820	$5,495	$5,739	$5,306

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)	2018		2017		2016		2018		2017		2016
STATUTORY TAX RATE
Federal	21	%	35	%	35	%	21	%	35	%	35	%
Changes in computed taxes resulting from:
State income tax	4		4		4		5		4		4
Cost of removal	1		1		(1	)	1		1		(1	)
Other plant-related items	(1	)	(1	)	—		(1	)	(1	)	(1	)
TCJA deferred tax re-measurement	2		(13	)	—		—		—		—
Amortization of excess deferred federal income taxes	(3	)	—		—		(3	)	—		—
Renewable energy credits	(1	)	(1	)	(1	)	—		—		—
Research and development credits	—		—		(1	)	(1	)	—		(1	)
Other	—		(2	)	—		(1	)	(1	)	—
Effective tax rate	23	%	23	%	36	%	21	%	38	%	36	%

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)	2018	2017	2016	2018	2017	2016
Balance at January 1,	$12	$42	$34	$5	$21	$2
Additions based on tax positions related to the current year	2	1	2	2	1	2
Additions based on tax positions of prior years	1	1	19	1	1	19
Reductions for tax positions of prior years	(2)	(24)	(13)	(1)	(18)	(2)
Reductions from expiration of statute of limitations	(4)	(2)	—	—	—	—
Settlements	(3)	(6)	—	(3)	—	—
Balance at December 31,	$6	$12	$42	$4	$5	$21

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [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, 2018, 2017 and 2016:



	Con Edison			CECONY
(Millions of Dollars)	2018	2017	2016	2018	2017	2016
Performance-based restricted stock	$3	$53	$42	$3	$45	$36
Time-based restricted stock	2	2	2	1	2	2
Non-employee director deferred stock compensation	3	2	2	3	2	2
Stock purchase plan	6	6	4	6	6	4
Total	$14	$63	$50	$13	$55	$44
Income tax benefit	$4	$25	$20	$4	$22	$18

Assumptions Used to Calculate Fair Value of Awards

The assumptions used to calculate the fair value of the awards were as follows:



	2018	2017	2016
Risk-free interest rate (a)	2.48% - 2.63%	1.76% - 1.89%	0.85% - 1.20%
Expected term (b)	3 years	3 years	3 years
Expected share price volatility (c)	14.76% - 17.71%	11.01% - 14.70%	17.72% - 18.22%


(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, 2018 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, 2017	1,028,932	$71.74	$70.11	784,166	$71.06	$70.08
Granted	328,850	67.26	76.37	247,532	66.79	76.48
Vested	(327,069)	57.77	63.27	(261,167)	57.37	63.18
Forfeited	(24,877)	72.22	74.97	(20,877)	71.76	75.14
Transferred (d)	—	—	—	12,252	78.47	72.71
Non-vested at December 31, 2018	1,005,836	$74.81	$74.27	761,906	$74.47	$74.42


(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, 2018 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, 2017	64,870	$71.93	61,420	$71.93
Granted	23,000	77.94	21,400	77.94
Vested	(20,523)	61.03	(19,473)	61.03
Forfeited	(2,167)	73.93	(1,967)	73.97
Non-vested at December 31, 2018	65,180	$77.42	61,380	$77.42

Financial Information by Business Segment (Tables)

12 Months Ended

Dec. 31, 2018

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, 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



As of and for the Year Ended December 31, 2016 (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	$8,106	$17		$865	$1,996	$(147)	$459	$495	$30,708	$1,819
Gas	1,508	6		159	387	(31)	105	92	7,553	811
Steam	551	88		82	68	(11)	39	30	2,595	126
Consolidation adjustments	—	(111)		—	—	—	—	—	—	—
Total CECONY	$10,165		$—	$1,106	$2,451	$(189)	$603	$617	$40,856	$2,756
O&R
Electric	$637		$—	$49	$107	$(11)	$24	$30	$1,949	$114
Gas	184	—		18	39	(4)	12	10	809	52
Other	—	—		—	—	—	—	—	—	—
Total O&R	$821		$—	$67	$146	$(15)	$36	$40	$2,758	$166
Clean Energy Businesses	$1,091	$7		$42	$183	$21	$34	$53	$2,551	$1,235
Con Edison Transmission	—	—		—	(3)	43	6	—	1,150	1,078
Other (b)	(2)	(7)		1	3	(1)	17	4	940	—
Total Con Edison	$12,075		$—	$1,216	$2,780	$(141)	$696	$714	$48,255	$5,235

(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, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting of Assets

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2018 and 2017 were:



(Millions of Dollars)	2018				2017
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	$43	$(14)	$29	(b)	$83	$(51)		$32	(b)
Noncurrent	14	(7)	7	(c)	10	(4)		6
Total fair value of derivative assets	$57	$(21)	$36	(b)(c)	$93	$(55)		$38
Fair value of derivative liabilities
Current	$(61)	$11	$(50)		$(67)	$50		$(17)
Noncurrent	(19)	9	(10)	(c)	(43)	5		(38)
Total fair value of derivative liabilities	$(80)	$20	$(60)		$(110)	$55		$(55)
Net fair value derivative assets/(liabilities)	$(23)	$(1)	$(24)	(b)(c)	$(17)		$—	$(17)	(b)
CECONY
Fair value of derivative assets
Current	$25	$(6)	$19	(b)	$39	$(15)		$24	(b)
Noncurrent	11	(5)	6		9	(4)		5
Total fair value of derivative assets	$36	$(11)	$25		$48	$(19)		$29
Fair value of derivative liabilities
Current	$(31)	$6	$(25)		$(26)	$14		$(12)
Noncurrent	(12)	6	(6)		(36)	4		(32)
Total fair value of derivative liabilities	$(43)	$12	$(31)		$(62)	$18		$(44)
Net fair value derivative assets/(liabilities)	$(7)	$1	$(6)	(b)	$(14)	$(1)		$(15)	(b)

(a)

(b)


(c)	Does not include interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities (see below).

Offsetting of Liabilities

The fair values of the Companies’ commodity derivatives including the offsetting of assets and liabilities on the consolidated balance sheet at December 31, 2018 and 2017 were:



(Millions of Dollars)	2018				2017
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	$43	$(14)	$29	(b)	$83	$(51)		$32	(b)
Noncurrent	14	(7)	7	(c)	10	(4)		6
Total fair value of derivative assets	$57	$(21)	$36	(b)(c)	$93	$(55)		$38
Fair value of derivative liabilities
Current	$(61)	$11	$(50)		$(67)	$50		$(17)
Noncurrent	(19)	9	(10)	(c)	(43)	5		(38)
Total fair value of derivative liabilities	$(80)	$20	$(60)		$(110)	$55		$(55)
Net fair value derivative assets/(liabilities)	$(23)	$(1)	$(24)	(b)(c)	$(17)		$—	$(17)	(b)
CECONY
Fair value of derivative assets
Current	$25	$(6)	$19	(b)	$39	$(15)		$24	(b)
Noncurrent	11	(5)	6		9	(4)		5
Total fair value of derivative assets	$36	$(11)	$25		$48	$(19)		$29
Fair value of derivative liabilities
Current	$(31)	$6	$(25)		$(26)	$14		$(12)
Noncurrent	(12)	6	(6)		(36)	4		(32)
Total fair value of derivative liabilities	$(43)	$12	$(31)		$(62)	$18		$(44)
Net fair value derivative assets/(liabilities)	$(7)	$1	$(6)	(b)	$(14)	$(1)		$(15)	(b)

(a)

(b)


(c)	Does not include interest rate swaps of $2 million in noncurrent assets and $(6) million in noncurrent liabilities (see below).

Realized and Unrealized Gains or Losses on Commodity Derivatives

The following table presents the realized and unrealized gains or losses on commodity derivatives that have been deferred or recognized in earnings for the years ended December 31, 2018 and 2017:



		Con Edison						CECONY
(Millions of Dollars)	Balance Sheet Location	2018			2017			2018		2017
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Current	Deferred derivative gains	$(1)			$3			$1		$4
Noncurrent	Deferred derivative gains	4			—			3		—
Total deferred gains/(losses)		$3			$3			$4		$4
Current	Deferred derivative losses	$4			$51			$8		$49
Current	Recoverable energy costs	(26)			(154)			(26)		(144)
Noncurrent	Deferred derivative losses	27			4			26		5
Total deferred gains/(losses)		$5			$(99)			$8		$(90)
Net deferred gains/(losses)		$8			$(96)			$12		$(86)
	Income Statement Location
Pre-tax gain/(loss) recognized in income
	Purchased power expense		$—			$—			$—		$—
	Gas purchased for resale	(2)			3			—		—
	Non-utility revenue	4		(a)	5		(b)	—		—
	Other operations and maintenance expense	(2)		(c)	—			(2)		—
Total pre-tax gain/(loss) recognized in income			$—		$8			$(2)			$—


(a)	For the year ended December 31, 2018, Con Edison recorded unrealized pre-tax losses in non-utility operating revenue ($5 million).


(b)	For the year ended December 31, 2017, Con Edison recorded an immaterial unrealized pre-tax gain in non-utility operating revenue.


(c)	For the year ended December 31, 2018, Con Edison recorded unrealized pre-tax losses in other operations and maintenance expense ($2 million).

Hedged Volume of Derivative Transactions

The following table presents the hedged volume of Con Edison’s and CECONY’s derivative transactions at December 31, 2018:



	Electric Energy (MWh) (a)(b)	Capacity (MW) (a)	Natural Gas (Dt) (a)(b)	Refined Fuels (gallons)
Con Edison	28,303,678	18,519	164,668,697	3,780,000
CECONY	25,458,600	10,350	151,280,000	3,780,000


(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	$36	$24
Collateral posted	6	—
Additional collateral (b) (downgrade one level from current ratings)	6	2
Additional collateral (b)(c) (downgrade to below investment grade from current ratings)	66	37

(a)

(b)


(c)	Derivative instruments that are net assets have been excluded from the table. At December 31, 2018, if Con Edison had been downgraded to below investment grade, it would have been required to post additional collateral for such derivative instruments of $20 million.

- 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

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=109980867&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017 are summarized below.



	2018					2017
(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)	$6	$36	$7	$(6)	$43	$5	$77	$7		$(39)	$50
Interest Rate Swaps (a)(b)(c)(f)	—	2	—	—	2	—	—	—		—	—
Other (a)(b)(d)	287	114	—	—	401	283	120	—		—	403
Total assets	$293	$152	$7	$(6)	$446	$288	$197	$7		$(39)	$453
Derivative liabilities:
Commodity (a)(b)(c)	$8	$43	$20	$(11)	$60	$8	$93	$6		$(52)	$55
Interest Rate Swaps (a)(b)(c)(f)	—	6	—	—	6	—	—	—		—	—
Total liabilities	$8	$49	$20	$(11)	$66	$8	$93	$6		$(52)	$55
CECONY
Derivative assets:
Commodity (a)(b)(c)	$3	$28	$1	$(1)	$31	$3	$40	$4		$(7)	$40
Other (a)(b)(d)	267	109	—	—	376	260	114	—		—	374
Total assets	$270	$137	$1	$(1)	$407	$263	$154	$4		$(7)	$414
Derivative liabilities:
Commodity (a)(b)(c)	$5	$30	$3	$(6)	$32	$5	$57		$—	$(18)	$44

(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, 2018
	(Millions of Dollars)	Valuation Techniques	Unobservable Inputs	Range
Con Edison — Commodity
Electricity	$(12)	Discounted Cash Flow	Forward energy prices (a)	$21.34-$64.45 per MWh
		Discounted Cash Flow	Forward capacity prices (a)	$1.00-$6.30 per kW-month
Natural Gas	(2)	Discounted Cash Flow	Forward natural gas prices (a)	$0.92-$6.62 per Dt
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.29-$8.03 per MWh
Total Con Edison — Commodity	$(13)
CECONY — Commodity
Electricity	$(3)	Discounted Cash Flow	Forward capacity prices (a)	$1.00-$6.30 per kW-month
Transmission Congestion Contracts	1	Discounted Cash Flow	Inter-zonal forward price curves adjusted for historical zonal losses (b)	$0.49-$2.60 per MWh
Total CECONY — Commodity	$(2)


(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)	2018	2017	2018	2017
Beginning balance as of January 1,	$1	$1	$4	$1
Included in earnings	4	8	4	2
Included in regulatory assets and liabilities	(10)	(13)	(4)	(7)
Purchases	—	2	—	1
Settlements	(6)	(8)	(4)	(3)
Transfer out of level 3	(2)	11	(2)	10
Ending balance as of December 31,	$(13)	$1	$(2)	$4

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2018

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Business Acquisitions, by Acquisition

At December 31, 2018 and 2017, Con Edison’s consolidated balance sheet included the following amounts associated with its VIEs:



	Tax Equity Projects
	Great Valley Solar		Copper Mountain - Mesquite Solar		Texas Solar 4
(Millions of Dollars)	2018		2018		2018	2017
Restricted cash		$—		$—	$4	$5
Non-utility property, less accumulated depreciation of $1 for each of the Tax Equity Projects and $15 and $12, for Texas Solar 4 in 2018 and 2017, respectively	313		492		98	101
Other assets	18		97		9	8
Total assets (a)	$331		$589		$111	$114
Long-term debt due within one year		$—		$—	$2	$2
Other liabilities	17		33		26	28
Long-term debt	—		—		56	58
Total liabilities (b)	$17		$33		$84	$88


(a)	The assets of the Tax Equity Projects and Texas Solar 4 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 and Texas Solar 4 represent liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

Summary of VIEs

The following table summarizes the VIEs into which Con Edison Development has entered as of December 31, 2018:



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	$281
Copper Mountain - Mesquite Solar (d)	344	20-25	2018	Nevada and Arizona	485
Texas Solar 4	32	25	2014	Texas	20


(a)	Represents Con Edison Development’s 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 ($33 million for Great Valley Solar, $71 million for Copper Mountain - Mesquite Solar and $7 million for Texas Solar 4). Con Edison did not provide any financial or other support during the year that was not previously contractually required.


(c)	Great Valley Solar consists of the Great Valley Solar 1, Great Valley Solar 2, Great Valley Solar 3 and Great Valley Solar 4 projects.


(d)	Copper Mountain - Mesquite Solar consists of the Copper Mountain Solar 4, Mesquite Solar 2 and Mesquite Solar 3 projects.

- 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

Acquisitions, Investments and Dispositions (Tables)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Pro Forma Supplemental Information



	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

•

Summary of Significant Accounting Policies and Other Matters - Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 11,928
Total revenues	12,337	$ 12,033	$ 12,075
CECONY
Disaggregation of Revenue [Line Items]
Total revenues	10,680	10,468	10,165
Operating segment \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	424
Total revenues	763	694	1,091
Operating segment \| Con Edison Transmission
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4
Total revenues	4	2	0
Operating segment \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10,597
Total revenues	10,680	10,468	10,165
Operating segment \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	903
Total revenues	891	874	821
Operating segment \| Electric \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7,920
Total revenues	7,971	7,972	8,106
Operating segment \| Electric \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	647
Total revenues	642	642	637
Operating segment \| Gas \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,052
Total revenues	2,078	1,901	1,508
Operating segment \| Gas \| O&R
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	256
Total revenues	249	232	184
Operating segment \| Steam \| CECONY
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	625
Total revenues	631	595	551
Operating segment \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	329
Total revenues	329
Operating segment \| Energy services \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	95
Total revenues	95
Operating segment \| Other \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Total revenues	339
Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0
Total revenues	(1)	(5)	(2)
Other \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	0	$ 0	$ 0
Other
Disaggregation of Revenue [Line Items]
Total revenues	409
Other \| Operating segment \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	339
Other \| Operating segment \| Con Edison Transmission
Disaggregation of Revenue [Line Items]
Total revenues	0
Other \| Operating segment \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	83
Other \| Operating segment \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	(12)
Other \| Operating segment \| Electric \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	51
Other \| Operating segment \| Electric \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	(5)
Other \| Operating segment \| Gas \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	26
Other \| Operating segment \| Gas \| O&R
Disaggregation of Revenue [Line Items]
Total revenues	(7)
Other \| Operating segment \| Steam \| CECONY
Disaggregation of Revenue [Line Items]
Total revenues	6
Other \| Operating segment \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	0
Other \| Operating segment \| Energy services \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	0
Other \| Operating segment \| Other \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Total revenues	339
Other \| Other
Disaggregation of Revenue [Line Items]
Total revenues	(1)
Engineering, procurement and construction \| Renewables \| Clean Energy Businesses
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 103

Summary of Significant Accounting Policies and Other Matters - Change in Unbilled Contract and Unearned Revenues (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Unbilled contract revenue
Beginning balance	$ 58
Additions	144
Subtractions	173
Ending balance	29
Unearned revenue
Beginning balance	87
Additions	38
Subtractions	105
Ending balance	20
Contracts with customer, revenue recognized, amount outstanding end of last period	$ 50

Summary of Significant Accounting Policies and Other Matters - Revenue Recognition, Remaining Performance Obligation (Details) $ in Millions	Dec. 31, 2018 USD ($)
Accounting Policies [Abstract]
Remaining performance obligation	$ 95
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Accounting Policies [Abstract]
Remaining performance obligation	$ 59
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]: 2021-01-01
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 - Plant and Depreciation (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated amortization		$ 29	$ 15
Annual aggregate depreciation allowance		1,323
Software Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Gross asset		100
Amortization period	15 years
Estimated aggregate annual amortization expense	$ 7
Accumulated amortization		$ 3
Non-Utility Plant \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)		3 years
Non-Utility Plant \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives (years)		30 years
CECONY
Public Utility, Property, Plant and Equipment [Line Items]
AFUDC rates (percent)		5.40%	5.50%	4.70%
Average depreciation rates (percent)		3.10%	3.10%	3.10%
Annual aggregate depreciation allowance		$ 1,253
CECONY \| Software Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Gross asset		$ 95
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)		100 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)		2.20%	2.50%	3.50%
Average depreciation rates (percent)		2.90%	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, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 3,331	$ 3,008
Held for future use	76	76
Construction work in progress	1,978	1,605
NET UTILITY PLANT	37,580	35,273
Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	593	544
Electric Transmission
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	3,333	3,210
Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	19,750	18,959
Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	7,714	6,976
Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,830	1,798
General
Public Utility, Property, Plant and Equipment [Line Items]
General	2,306	2,105
CECONY
Public Utility, Property, Plant and Equipment [Line Items]
General	3,056	2,753
Held for future use	67	67
Construction work in progress	1,850	1,502
NET UTILITY PLANT	35,370	33,205
CECONY \| Electric Generation
Public Utility, Property, Plant and Equipment [Line Items]
Generation	592	544
CECONY \| Electric Transmission
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	3,106	2,990
CECONY \| Electric Distribution
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	18,716	17,996
CECONY \| Gas
Public Utility, Property, Plant and Equipment [Line Items]
Gas	7,107	6,403
CECONY \| Steam
Public Utility, Property, Plant and Equipment [Line Items]
Steam	1,830	1,798
CECONY \| General
Public Utility, Property, Plant and Equipment [Line Items]
General	$ 2,102	$ 1,905

Summary of Significant Accounting Policies and Other Matters - Long-Lived and Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Finite-Lived Intangible Assets [Line Items]
Accumulated amortization	$ 29,000,000	$ 15,000,000
Amortization of intangible assets	14,000,000	9,000,000	$ 2,000,000
Amortization expense, 2019	105,000,000
Amortization expense, 2020	105,000,000
Amortization expense, 2021	105,000,000
Amortization expense, 2022	105,000,000
Amortization expense, 2023	105,000,000
Asset impairment	2,000,000
Impairment charges on long-lived assets		0	0
Impairment charges on intangible assets		0	$ 0
Long-term debt	18,145,000,000	16,029,000,000
Net non-utility plant	41,749,000,000	37,600,000,000
Intangible assets	1,654,000,000	131,000,000
PG&E Project
Finite-Lived Intangible Assets [Line Items]
Long-term debt	1,050,000,000
Net non-utility plant	885,000,000
Intangible assets	$ 1,125,000,000
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	$ 292,000,000
Other Intangible Assets
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	3,000,000
Accumulated amortization	7,000,000	6,000,000
Power Purchase Agreements
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	1,712,000,000	131,000,000
Accumulated amortization	$ 22,000,000	$ 9,000,000

Summary of Significant Accounting Policies and Other Matters - Investments (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 0	$ 467
Supplemental retirement income plan assets	326	330
Deferred income plan assets	75	73
Other	2	9
Total investments	1,766	2,001
CET \| Stagecoach Gas Services, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	948	971
CET \| Mountain Valley Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	363	98
CET \| New York Transco, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	52	53
CECONY
Schedule of Equity Method Investments [Line Items]
Equity method investments	0	0
Supplemental retirement income plan assets	301	301
Deferred income plan assets	75	73
Other	9	9
Total investments	385	383
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 - Research and Development Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Research and Development Expenses [Line Items]
Research and development costs	$ 24	$ 24	$ 24
CECONY
Research and Development Expenses [Line Items]
Research and development costs	$ 23	$ 23	$ 22

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Net income	$ 1,382	$ 1,525	$ 1,245
Weighted average common shares outstanding – basic (in shares)	311.7	307.1	300.4
Add: Incremental shares attributable to effect of potentially dilutive securities (in shares)	1.2	1.7	1.5
Adjusted weighted average common shares outstanding – diluted (in shares)	312.9	308.8	301.9
Net income per common share — basic (in dollars per share)	$ 4.43	$ 4.97	$ 4.15
Net income per common share — diluted (in dollars per share)	$ 4.42	$ 4.94	$ 4.12

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
-URI http://asc.fasb.org/extlink&oid=114873790&loc=SL114874131-224263

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109260490&loc=d3e1337-109256

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 55
-Paragraph 52
-URI http://asc.fasb.org/extlink&oid=109256448&loc=d3e4984-109258

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
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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, 2018	Dec. 31, 2017	Dec. 31, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	$ 15,425	$ 14,306	$ 13,061
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	10	1	7
BALANCE AS OF END OF PERIOD	16,839	15,425	14,306
Accumulated OCI
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	(26)	(27)	(34)
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	10	1	7
BALANCE AS OF END OF PERIOD	(16)	(26)	(27)
Pension Plan Liabilities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
OCI before reclassifications, net of tax	4	(4)	2
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax	6	5	5
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	10	1	7
OCI before reclassifications, tax	3	3	(1)
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax	(2)	(3)	(3)
CECONY
AOCI Attributable to Parent, Net of Tax [Roll Forward]
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	1	1	2
CECONY \| Accumulated OCI
AOCI Attributable to Parent, Net of Tax [Roll Forward]
BALANCE AS OF BEGINNING OF PERIOD	(6)	(7)	(9)
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	1	1	2
BALANCE AS OF END OF PERIOD	(5)	(6)	(7)
CECONY \| Pension Plan Liabilities
AOCI Attributable to Parent, Net of Tax [Roll Forward]
OCI before reclassifications, net of tax	0	0	1
Amounts reclassified from accumulated OCI related to pension plan liabilities, net of tax	1	1	1
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAXES	$ 1	1	2
OCI before reclassifications, tax		(1)	1
Amounts reclassified from accumulated OCI related to pension plan liabilities, tax		$ (1)	$ (1)

Summary of Significant Accounting Policies and Other Matters - Reconciliation of Cash, Temporary Investments and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash and Cash Equivalents [Line Items]
Cash and temporary cash investments	$ 895	$ 797
Restricted cash	111	47
Total cash, temporary cash investments and restricted cash	1,006	844	$ 830
CECONY
Cash and Cash Equivalents [Line Items]
Cash and temporary cash investments	818	730
Restricted cash	0	0
Total cash, temporary cash investments and restricted cash	818	730	$ 704	$ 859
Con Edison Development
Cash and Cash Equivalents [Line Items]
Restricted cash	109	46
RECO \| Transition Bond
Cash and Cash Equivalents [Line Items]
Restricted cash	$ 2	$ 1

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2019	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Revenues		$ 12,337,000,000	$ 12,033,000,000	$ 12,075,000,000
Deferred revenues		20,000,000	87,000,000
Deferred revenues		$ (514,000,000)	(598,000,000)
NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues		15.00%
Maximum \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Percentage of total consolidated revenues		15.00%
Percentage of debt to total consolidated debt		20.00%
CECONY
Public Utilities, General Disclosures [Line Items]
Revenues		$ 10,680,000,000	10,468,000,000	10,165,000,000
Deferred revenues		(392,000,000)	(454,000,000)
CECONY \| Electric
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities				123,000,000
Retention of annual transmission congestion revenues								$ 90,000,000
Actual earnings adjustment mechanism incentives		25,000,000	13,000,000
Other earnings incentives		5,000,000	5,000,000
Deferred revenues	$ 101,000,000		45,000,000	101,000,000	$ 98,000,000	$ 146,000,000		101,000,000
Deferred revenues		(6,000,000)
Negative revenue adjustments		0	0	0	0	5,000,000
Cost reconciliation, deferred net regulatory liabilities	68,000,000			68,000,000	26,000,000	57,000,000		$ 68,000,000
Cost reconciliation, deferred net regulatory assets		189,000,000	35,000,000
Net utility plant reconciliations		(400,000)	400,000	9,000,000	(17,000,000)	(6,000,000)
Earnings sharing, threshold limit		$ 0	$ 0	6,500,000	$ 44,400,000	$ 0
Earnings sharing, positive adjustment				5,700,000
Common equity ratio (percent)								48.00%
Base rate change deferral regulatory liability impact	0			0				$ 0
Increase in gas base rate due to expiration of temporary credit under the prior rate plan	48,000,000
Deferrals for property taxes limitation from rates (percent)								90.00%
Recovery deferral (percent)		80.00%
Maximum deferral (percent)		30.00%
CECONY \| Electric \| Deferred storm costs
Public Utilities, General Disclosures [Line Items]
Amortization of regulatory asset								$ 107,000,000
Decrease in recoverable property damage costs								4,000,000
CECONY \| Electric \| Service Termination
Public Utilities, General Disclosures [Line Items]
Revenues		$ 3,000,000
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)							9.00%
Earnings sharing (percent)							9.50%
Common equity ratio (percent)							48.00%
Recovery or refund of energy costs, deferral period							10 years
CECONY \| Electric \| Scenario, Forecast \| NYSPSC
Public Utilities, General Disclosures [Line Items]
Base rate changes							$ 199,000,000
CECONY \| Electric \| Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ (76,200,000)			$ (76,200,000)				(76,200,000)
Amortization to income of net regulatory (assets) and liabilities								(37,000,000)
Average rate base								$ 17,323,000,000
Weighted average cost of capital (after-tax) (percent)								7.05%
Authorized return on common equity (percent)								9.20%
Actual return on common equity (percent)								9.04%
Earnings sharing (percent)	9.80%			9.80%				9.80%
Cost of long-term debt (percent)	5.17%			5.17%				5.17%
Deferral, annual maximum (not more than) (percent)								5.00%
CECONY \| Electric \| Year 1 \| Transmission and distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 16,869,000,000
CECONY \| Electric \| Year 1 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								89,000,000
CECONY \| Electric \| Year 1 \| Other
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								2,034,000,000
CECONY \| Electric \| Year 1 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)								400,000,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes							195,000,000
Amortization to income of net regulatory (assets) and liabilities							84,000,000
Potential earnings adjustment mechanism incentives							28,000,000
Potential penalties (annually)							376,000,000
Average rate base							$ 18,902,000,000
Weighted average cost of capital (after-tax) (percent)							6.82%
Actual return on common equity (percent)							9.30%
Cost of long-term debt (percent)							4.93%
Recovery of energy efficiency and savings program costs							$ 20,500,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							21,689,000,000
CECONY \| Electric \| Year 1 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							126,000,000
CECONY \| Electric \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ 124,000,000			$ 124,000,000				124,000,000
Amortization to income of net regulatory (assets) and liabilities								(37,000,000)
Average rate base								$ 18,113,000,000
Weighted average cost of capital (after-tax) (percent)								7.08%
Authorized return on common equity (percent)								9.20%
Actual return on common equity (percent)								10.16%
Earnings sharing (percent)	9.80%			9.80%				9.80%
Cost of long-term debt (percent)	5.23%			5.23%				5.23%
Deferral, annual maximum (not more than) (percent)								7.50%
CECONY \| Electric \| Year 2 \| Transmission and distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 17,401,000,000
CECONY \| Electric \| Year 2 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								177,000,000
CECONY \| Electric \| Year 2 \| Other
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								2,102,000,000
CECONY \| Electric \| Year 2 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)								400,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes							155,000,000
Amortization to income of net regulatory (assets) and liabilities							83,000,000
Potential earnings adjustment mechanism incentives							47,000,000
Potential penalties (annually)							341,000,000
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%
Recovery of energy efficiency and savings program costs							$ 49,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							22,338,000,000
CECONY \| Electric \| Year 2 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							257,000,000
CECONY \| Electric \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ 0			$ 0				0
Amortization to income of net regulatory (assets) and liabilities								123,000,000
Average rate base								$ 18,282,000,000
Weighted average cost of capital (after-tax) (percent)								6.91%
Authorized return on common equity (percent)								9.00%
Actual return on common equity (percent)								9.66%
Earnings sharing (percent)	9.60%			9.60%				9.60%
Cost of long-term debt (percent)	5.09%			5.09%				5.09%
Deferral, annual maximum (not more than) (percent)								10.00%
CECONY \| Electric \| Year 3 \| Transmission and distribution
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 17,929,000,000
CECONY \| Electric \| Year 3 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								268,000,000
CECONY \| Electric \| Year 3 \| Other
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								2,069,000,000
CECONY \| Electric \| Year 3 \| Maximum
Public Utilities, General Disclosures [Line Items]
Potential penalties (annually)								$ 400,000,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Base rate changes							155,000,000
Amortization to income of net regulatory (assets) and liabilities							69,000,000
Potential earnings adjustment mechanism incentives							64,000,000
Potential penalties (annually)							352,000,000
Average rate base							$ 20,277,000,000
Weighted average cost of capital (after-tax) (percent)							6.73%
Cost of long-term debt (percent)							4.74%
Recovery of energy efficiency and savings program costs							$ 107,500,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast \| Electric average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							23,002,000,000
CECONY \| Electric \| Year 3 \| Scenario, Forecast \| Advanced metering infrastructure (AMI)
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 415,000,000

Regulatory Matters - Additional Information (Details) customer in Thousands, $ in Millions		1 Months Ended								3 Months Ended			9 Months Ended			12 Months Ended			13 Months Ended
	Apr. 01, 2018 USD ($)	Jan. 31, 2022 USD ($)	Jan. 31, 2021 USD ($)	Jan. 31, 2019 USD ($)	Nov. 30, 2018 USD ($)	Aug. 31, 2018 USD ($)	Mar. 31, 2018 USD ($) customer	Dec. 31, 2017 USD ($)	Apr. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 31, 2022
Public Utilities, General Disclosures [Line Items]
Regulatory assets								$ 4,333.0		$ 4,370.0			$ 4,370.0		$ 4,333.0		$ 4,370.0	$ 4,333.0
Net benefit of the TCJA																		(259.0)
Regulatory liabilities								4,577.0		4,641.0			4,641.0		4,577.0		4,641.0	4,577.0
Utilities
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	434.0
Future Income Tax
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	54.0	3,713.0
Regulatory liabilities								2,545.0		2,515.0			2,515.0		2,545.0		2,515.0	2,545.0
Accelerated Tax Depreciation Benefits
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																		2,684.0
Net Unbilled Revenue Deferrals
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities								183.0		117.0			117.0		$ 183.0		117.0	183.0
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%
Increase in regulatory liability resulting from TCJA							$ 28.0
Amount of customer refund to reflect TCJA					$ 0.6
Impact in regulatory liability resulting from TCJA, subject to normalization requirements							$ 16.0
RECO \| NJBPU \| Electric
Public Utilities, General Disclosures [Line Items]
Approved interim rate decrease	$ 2.9
Net benefit of the TCJA											$ 1.0
CECONY
Public Utilities, General Disclosures [Line Items]
Regulatory assets								3,925.0		3,987.0			3,987.0		$ 3,925.0		3,987.0	3,925.0
Regulatory liabilities								4,219.0		4,258.0			4,258.0		4,219.0		4,258.0	4,219.0
CECONY \| Future Income Tax
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA								3,513.0									49.0	3,513.0
Regulatory liabilities								2,390.0		2,363.0			2,363.0		2,390.0		2,363.0	2,390.0
CECONY \| Accelerated Tax Depreciation Benefits
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	2,593.0	2,542.0
CECONY \| Deferred Income Tax Charge, Amortized Over Remaining Life of Asset
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	969.0
CECONY \| Net Unbilled Revenue Deferrals
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities								183.0		117.0			117.0		$ 183.0		117.0	$ 183.0
CECONY \| Electric \| Hurricane
Public Utilities, General Disclosures [Line Items]
Number of customers affected with interrupted service \| customer							209
Restoration costs													133.0
Operation and maintenance expenses													15.0
Operation and maintenance expenses charged against a storm reserve													83.0
Capital expenditures										29.0			29.0				29.0
Removal costs													6.0
CECONY \| NYSPSC \| Electric
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA						$ 2,516.0
Income tax benefit to be credited to customers resulting from TCJA										307.0
CECONY \| NYSPSC \| Gas
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	841.0
Income tax benefit to be credited to customers resulting from TCJA										90.0
CECONY \| NYSPSC \| Steam
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	$ 193.0
Income tax benefit to be credited to customers resulting from TCJA										6.0				$ 15.0
Tax credit, amortization period, protected portion																	3 years
CECONY \| NYSPSC \| MTA Subway Power Outage
Public Utilities, General Disclosures [Line Items]
Regulatory costs										260.0			260.0				$ 260.0
Regulatory assets										229.0			229.0				229.0
CECONY \| NYSPSC \| Scenario, Forecast \| Electric
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA																$ 259.0
CECONY \| NYSPSC \| Scenario, Forecast \| Gas
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA																113.0
CECONY \| NYSPSC \| Scenario, Forecast \| Steam
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA																$ 25.0
CECONY \| NYSPSC \| Electric \| MTA Subway Power Outage
Public Utilities, General Disclosures [Line Items]
Regulatory costs										31.0			31.0				31.0
CECONY \| NYSPSC \| Electric \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount		$ 263.0	$ 352.0
Return on common equity (percent)																			9.75%
Common equity ratio (percent)																			50.00%
CECONY \| NYSPSC \| Electric \| Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount				$ 485.0
Return on common equity (percent)				9.75%
Common equity ratio (percent)				50.00%
Proposed EAM (percent)				1.00%
CECONY \| NYSPSC \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount		$ 155.0	$ 138.0
Return on common equity (percent)																			9.75%
Common equity ratio (percent)																			50.00%
CECONY \| NYSPSC \| Gas \| Subsequent Event
Public Utilities, General Disclosures [Line Items]
Requested rate increase (decrease), amount				$ 210.0
Return on common equity (percent)				9.75%
Common equity ratio (percent)				50.00%
Proposed EAM (percent)				0.70%
O&R \| Future Income Tax
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA								$ 161.0									2.0
O&R \| Accelerated Tax Depreciation Benefits
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	128.0
O&R \| Deferred Income Tax Charge, Amortized Over Remaining Life of Asset
Public Utilities, General Disclosures [Line Items]
Increase in regulatory liability resulting from TCJA																	$ 35.0
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 \| NYSPSC \| Electricity and Gas
Public Utilities, General Disclosures [Line Items]
Income tax benefit to be credited to customers resulting from TCJA										$ 22.0
Tax credit, amortization period, protected portion										3 years
Tax credit, amortization period, unprotected portion										15 years

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2019	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Revenues		$ 12,337,000,000	$ 12,033,000,000	$ 12,075,000,000
Deferred revenues		20,000,000	87,000,000
CECONY
Public Utilities, General Disclosures [Line Items]
Revenues		10,680,000,000	10,468,000,000	10,165,000,000
CECONY \| Gas
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities								$ 4,000,000
Regulatory liabilities, amortization period								3 years
Amount of revenues retained	$ 65,000,000			65,000,000	$ 66,000,000	$ 70,000,000		$ 65,000,000
Percentage of revenue reserve								15.00%
Other earnings incentives		6,000,000	7,000,000
Deferred revenues	71,000,000	12,000,000	3,000,000	71,000,000	54,000,000	28,000,000		$ 71,000,000
Negative revenue adjustments		0	5,000,000	0	0	0
Cost reconciliation, deferred net regulatory liabilities	$ 32,000,000		2,000,000	$ 32,000,000	11,000,000	38,000,000		$ 32,000,000
Cost reconciliation, deferred net regulatory assets		44,000,000
Net utility plant reconciliations		2,200,000	2,200,000		1,000,000
Earnings sharing (percent)	9.90%			9.90%				9.90%
Earnings sharing, threshold limit		0	$ 0	$ 0	0	0
Common equity ratio (percent)								48.00%
Base rate change deferral regulatory liability impact	$ 32,000,000			32,000,000				$ 32,000,000
Increase in gas base rate due to expiration of temporary credit under the prior rate plan	41,000,000
Difference in property taxes (percent)								90.00%
CECONY \| Gas \| Maximum
Public Utilities, General Disclosures [Line Items]
Amount of revenues retained	$ 65,000,000			65,000,000				$ 65,000,000
Potential penalties (annually)				$ 56,000,000	$ 44,000,000	$ 33,000,000
CECONY \| Gas \| Gas Leak Backlog, Leak Prone Pipe and Service Terminations
Public Utilities, General Disclosures [Line Items]
Revenues		$ 5,000,000
CECONY \| Gas \| Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Percentage of revenue reserve							15.00%
Earnings sharing (percent)							9.50%
Common equity ratio (percent)							48.00%
Deferral, annual maximum (not more than) (percent)							10.00%
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								(54,600,000)
Average rate base								$ 3,521,000,000
Weighted average cost of capital (after-tax) (percent)								7.10%
Authorized return on common equity (percent)								9.30%
Actual return on common equity (percent)								8.02%
Cost of long-term debt (percent)	5.17%			5.17%				5.17%
CECONY \| Gas \| Year 1 \| Gas delivery
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 3,899,000,000
CECONY \| Gas \| Year 1 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								3,000,000
CECONY \| Gas \| Year 1 \| Scenario, Forecast
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%
CECONY \| Gas \| Year 1 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 5,844,000,000
CECONY \| Gas \| Year 1 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							27,000,000
CECONY \| Gas \| Year 2
Public Utilities, General Disclosures [Line Items]
Base rate changes								38,600,000
Average rate base								$ 3,863,000,000
Weighted average cost of capital (after-tax) (percent)								7.13%
Actual return on common equity (percent)								8.13%
Cost of long-term debt (percent)	5.23%			5.23%				5.23%
CECONY \| Gas \| Year 2 \| Gas delivery
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 4,258,000,000
CECONY \| Gas \| Year 2 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								8,000,000
CECONY \| Gas \| Year 2 \| Scenario, Forecast
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%
CECONY \| Gas \| Year 2 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 6,512,000,000
CECONY \| Gas \| Year 2 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							57,000,000
CECONY \| Gas \| Year 3
Public Utilities, General Disclosures [Line Items]
Base rate changes								56,800,000
Average rate base								$ 4,236,000,000
Weighted average cost of capital (after-tax) (percent)								7.21%
Actual return on common equity (percent)								7.83%
Cost of long-term debt (percent)	5.39%			5.39%				5.39%
CECONY \| Gas \| Year 3 \| Gas delivery
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 4,698,000,000
CECONY \| Gas \| Year 3 \| Storm hardening
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations								$ 30,000,000
CECONY \| Gas \| Year 3 \| Scenario, Forecast
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%
Cost of long-term debt (percent)							4.74%
CECONY \| Gas \| Year 3 \| Scenario, Forecast \| Gas average excluding AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 7,177,000,000
CECONY \| Gas \| Year 3 \| Scenario, Forecast \| AMI
Public Utilities, General Disclosures [Line Items]
Net utility plant reconciliations							$ 100,000,000

Regulatory Matters - Summary of Utilities Rate Plans (CECONY-Steam) (Details) - CECONY - Steam - USD ($)	12 Months Ended					36 Months Ended
	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
Cost reconciliation, deferred net regulatory liabilities	(1,000,000)	14,000,000	$ 8,000,000		42,000,000	$ 8,000,000
Cost reconciliation, deferred net regulatory assets				17,000,000
Net utility plant reconciliations	0	0			100,000
Authorized return on common equity (percent)						9.30%
Earnings sharing (percent)			9.90%			9.90%
Earnings sharing, threshold limit	$ 14,200,000	8,500,000	$ 7,800,000	$ 11,500,000	$ 0
Earnings sharing, positive adjustment		$ 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%

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 31, 2017	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Deferred revenues	$ 20,000,000	$ 87,000,000
Deferred revenues	$ 514,000,000	598,000,000
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)						0.10%
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)						4,000,000
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)						0.075%
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)						4,000,000
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)						0.05%
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)						$ 5,000,000

Regulatory Matters - Summary of Utilities Rate Plans (O&R New York-Gas) (Details) - USD ($)	12 Months Ended				36 Months Ended
	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	$ 514,000,000	$ 598,000,000
Deferred revenues	$ 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	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
Net utility plant reconciliations	$ 400,000	0	0	$ 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
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
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

Regulatory Matters - Summary of Utilities Rate Plans (RECO) (Details) - RECO - USD ($) $ in Millions	1 Months Ended	31 Months Ended
	Mar. 31, 2017	Feb. 28, 2017
Public Utilities, General Disclosures [Line Items]
Amortization to income of net regulatory (assets) and liabilities	$ 0.2	$ 0.4
Regulatory liabilities, amortization period	3 years	3 years
Amortization to income of net regulatory assets	$ (25.6)	$ (25.6)
Regulatory assets, amortization period	4 years	4 years
Average rate base	$ 178.7	$ 172.2
Weighted average cost of capital (after-tax) (percent)	7.47%	7.83%
Authorized return on common equity (percent)	9.60%	9.75%
Cost of long-term debt (percent)	5.37%	5.89%
Common equity ratio (percent)	49.70%	50.00%
Electric
Public Utilities, General Disclosures [Line Items]
Plan electric system storm hardening amount	$ 15.7
Plan period (years)	3 years
Year 1
Public Utilities, General Disclosures [Line Items]
Base rate changes	$ 1.7	$ 13.0
Actual return on common equity (percent)	7.50%	9.20%
Year 2
Public Utilities, General Disclosures [Line Items]
Actual return on common equity (percent)		8.70%

Regulatory Matters - Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	$ 4,294	$ 4,266
Regulatory assets – current	76	67
Total Regulatory Assets	4,370	4,333
Unrecognized pension and other postretirement costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	2,238	2,526
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	810	793
Revenue taxes
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	291	260
MTA power reliability deferral
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	229	50
Property tax reconciliation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	101	51
Deferred storm costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	76	38
Pension and other postretirement benefits deferrals
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	73	79
Municipal infrastructure support costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	67	56
System peak reduction and energy efficiency programs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	72	14
Brooklyn Queens demand management program
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	39	37
Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	36	37
Meadowlands heater odorization project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	36	18
Preferred stock redemption
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	23	24
Recoverable REV demonstration project costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	20	19
Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	17	44
Gate Station Upgrade Project [Member]
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	17	13
Indian Point Energy Center program costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	13	29
Workers’ compensation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	5	10
Recoverable energy costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	3	60
Regulatory assets – current	40	27
O&R transition bond charges
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	2	9
Surcharge for New York State assessment
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	2
Other
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	126	97
Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – current	36	40
CECONY
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	3,923	3,863
Regulatory assets – current	64	62
Total Regulatory Assets	3,987	3,925
CECONY \| Unrecognized pension and other postretirement costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	2,111	2,376
CECONY \| Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	716	677
CECONY \| Revenue taxes
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	278	248
CECONY \| MTA power reliability deferral
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	229	50
CECONY \| Property tax reconciliation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	86	25
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	56	58
CECONY \| Municipal infrastructure support costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	67	56
CECONY \| System peak reduction and energy efficiency programs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	70	14
CECONY \| Brooklyn Queens demand management program
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	39	37
CECONY \| Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	34	35
CECONY \| Meadowlands heater odorization project
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	36	18
CECONY \| Preferred stock redemption
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	23	24
CECONY \| Recoverable REV demonstration project costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	18	17
CECONY \| Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	11	37
CECONY \| Gate Station Upgrade Project [Member]
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	17	13
CECONY \| Indian Point Energy Center program costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	13	29
CECONY \| Workers’ compensation
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	5	10
CECONY \| Recoverable energy costs
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	52
Regulatory assets – current	35	25
CECONY \| O&R transition bond charges
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	0
CECONY \| Surcharge for New York State assessment
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	0	2
CECONY \| Other
Regulatory Assets [Line Items]
Regulatory assets – noncurrent	114	85
CECONY \| Deferred derivative losses
Regulatory Assets [Line Items]
Regulatory assets – current	$ 29	$ 37

Regulatory Matters - Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory assets	$ 4,294	$ 4,266
Regulatory liabilities – noncurrent	4,641	4,577
Regulatory liabilities—current	114	101
Total Regulatory Liabilities	4,755	4,678
Future income tax
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	2,515	2,545
Allowance for cost of removal less salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	928	846
TCJA net benefits
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	434	0
Energy efficiency portfolio standard unencumbered funds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	127	127
Net unbilled revenue deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	117	183
Pension and other postretirement benefit deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	62	207
Property tax refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	45	44
Settlement of prudence proceeding
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	37	66
Property tax reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	36	107
Earnings sharing - electric, gas and steam
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	36	29
System benefit charge carrying charge
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	27	12
Carrying charges on repair allowance and bonus depreciation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	21	43
BQDM and REV Demo reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	18	9
New York State income tax rate change
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	17	36
Settlement of gas proceedings
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	15	27
Base rate change deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	10	21
Unrecognized other postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	7	92
Net utility plant reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	3	12
Variable-rate tax-exempt debt - cost rate reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	1	30
Other
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	185	141
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	53	29
Refundable energy costs
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	31	41
Deferred derivative gains
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	30	31
CECONY
Regulatory Liabilities [Line Items]
Regulatory assets	3,923	3,863
Regulatory liabilities – noncurrent	4,258	4,219
Regulatory liabilities—current	73	65
Total Regulatory Liabilities	4,331	4,284
CECONY \| Future income tax
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	2,363	2,390
CECONY \| Allowance for cost of removal less salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	790	719
CECONY \| TCJA net benefits
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	411	0
CECONY \| Energy efficiency portfolio standard unencumbered funds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	122	122
CECONY \| Net unbilled revenue deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	117	183
CECONY \| Pension and other postretirement benefit deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	40	181
CECONY \| Property tax refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	45	44
CECONY \| Settlement of prudence proceeding
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	37	66
CECONY \| Property tax reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	36	107
CECONY \| Earnings sharing - electric, gas and steam
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	27	19
CECONY \| System benefit charge carrying charge
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	24	11
CECONY \| Carrying charges on repair allowance and bonus depreciation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	21	42
CECONY \| BQDM and REV Demo reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	18	9
CECONY \| New York State income tax rate change
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	17	35
CECONY \| Settlement of gas proceedings
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	15	27
CECONY \| Base rate change deferrals
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	10	21
CECONY \| Unrecognized other postretirement costs
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	7	92
CECONY \| Net utility plant reconciliations
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	1	8
CECONY \| Variable-rate tax-exempt debt - cost rate reconciliation
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	1	26
CECONY \| Other
Regulatory Liabilities [Line Items]
Regulatory liabilities – noncurrent	156	117
CECONY \| Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	36	21
CECONY \| Refundable energy costs
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	8	16
CECONY \| Deferred derivative gains
Regulatory Liabilities [Line Items]
Regulatory liabilities—current	$ 29	$ 28

Capitalization - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 30, 2018	Dec. 31, 2015
Schedule of Capitalization [Line Items]
Value of shares issued		$ 705	$ 343	$ 702
Common Stock
Schedule of Capitalization [Line Items]
Common stock, shares outstanding (in shares)	321,000,000	321,000,000	310,000,000	305,000,000		293,000,000
Shares issued (in shares)		11,000,000	5,000,000	10,000,000
Value of shares issued			$ 1	$ 1
Forward Contract
Schedule of Capitalization [Line Items]
Common stock, shares subject to forward sale agreements (in shares)	5,649,369	5,649,369			14,973,492
Share price (in dollars per share)					$ 75.537
Forward Contract \| Common Stock
Schedule of Capitalization [Line Items]
Shares issued (in shares)	9,324,123
Value of shares issued	$ 705
CECONY
Schedule of Capitalization [Line Items]
Common stock, shares outstanding (in shares)	21,976,200	21,976,200
CECONY \| Common Stock
Schedule of Capitalization [Line Items]
Common stock, shares outstanding (in shares)	235,000,000	235,000,000	235,000,000	235,000,000		235,000,000

Capitalization - Schedule of Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
2019	$ 650
2020	866
2021	1,260
2022	413
2023	293
CECONY
Debt Instrument [Line Items]
2019	475
2020	350
2021	640
2022	0
2023	$ 0

Capitalization - Long-term Debt, Additional Information (Details) - USD ($)	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Non-recourse debt		$ 2,076,000,000	$ 915,000,000
Short-term debt		825,000,000	0
Long-term debt		18,145,000,000	16,029,000,000
Transition Bonds Issued in 2004
Debt Instrument [Line Items]
Long-term debt		2,000,000	7,000,000
PG&E Project
Debt Instrument [Line Items]
Long-term debt		1,050,000,000
PG&E Project \| Scenario, Forecast
Debt Instrument [Line Items]
Short-term debt	$ 1,050,000,000
CECONY
Debt Instrument [Line Items]
Long-term debt		14,151,000,000	13,265,000,000
CECONY \| Tax-Exempt Debt
Debt Instrument [Line Items]
Debt instrument, face amount		450,000,000
Long-term debt		$ 450,000,000	$ 1,086,000,000

Capitalization - Carrying Amounts and Fair Values of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Unamortized debt expense	$ 185	$ 142
Carrying Amount
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	18,145	16,029
Fair Value
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	18,740	18,147
CECONY
Debt Instrument [Line Items]
Unamortized debt discount	139	121
CECONY \| Carrying Amount
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	14,151	13,625
CECONY \| Fair Value
Debt Instrument [Line Items]
Long-Term Debt (including current portion)	$ 14,685	$ 15,163

Capitalization - Significant Debt Covenants (Details)	12 Months Ended
Capitalization - Significant Debt Covenants (Details)	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.53
CECONY
Debt Instrument [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.54
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) - USD ($)	1 Months Ended	12 Months Ended
Short-Term Borrowing (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Commercial paper, outstanding	$ 1,741,000,000	$ 1,741,000,000	$ 577,000,000
Weighted average interest rate		3.00%	1.80%
Loans outstanding under credit agreement	0	$ 0	$ 0
Letters of credit outstanding	$ 0	$ 0
Maximum ratio of consolidated debt to consolidated total capital	0.53	0.53
Minimum percentage of liens on assets	5.00%	5.00%
Failure to pay, maximum aggregate limit	$ 150,000,000	$ 150,000,000
Term Loan
Short-term Debt [Line Items]
Short-term borrowings	$ 825,000,000	$ 825,000,000
Debt term	6 months
Maximum
Short-term Debt [Line Items]
Maximum ratio of consolidated debt to consolidated total capital	0.65	0.65
Revolving Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 1,500,000,000	$ 1,500,000,000
Current amount available	1,000,000,000	1,000,000,000
Letters of Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	1,200,000,000	1,200,000,000
CECONY
Short-term Debt [Line Items]
Commercial paper, outstanding	$ 1,192,000,000	$ 1,192,000,000	$ 150,000,000
Weighted average interest rate		3.00%	1.80%
Maximum ratio of consolidated debt to consolidated total capital	0.54	0.54
CECONY \| Revolving Credit
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 2,250,000,000	$ 2,250,000,000

Pension Benefits - Total Periodic Benefit Costs (Details) - Pension Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	$ 290	$ 263	$ 275
Interest cost on projected benefit obligation	561	591	596
Expected return on plan assets	(1,033)	(968)	(947)
Recognition of net actuarial loss	688	595	596
Recognition of prior service cost/(credit)	(17)	(17)	4
TOTAL PERIODIC BENEFIT COST	489	464	524
Cost capitalized	(127)	(181)	(214)
Reconciliation to rate level	(92)	(34)	54
Total expense/(credit) recognized	270	249	364
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost – including administrative expenses	272	246	258
Interest cost on projected benefit obligation	525	554	559
Expected return on plan assets	(979)	(917)	(898)
Recognition of net actuarial loss	651	563	565
Recognition of prior service cost/(credit)	(19)	(19)	2
TOTAL PERIODIC BENEFIT COST	450	427	486
Cost capitalized	(119)	(169)	(203)
Reconciliation to rate level	(100)	(41)	58
Total expense/(credit) recognized	$ 231	$ 217	$ 341

Pension Benefits - Schedule of Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$ 330
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	326	$ 330
Pension Benefits
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	15,536	14,095	$ 14,377
Service cost – excluding administrative expenses	286	259	271
Interest cost on projected benefit obligation	561	591	596
Net actuarial loss/(gain)	(1,219)	1,231	(302)
Plan amendments	0	6	(256)
Benefits paid	(715)	(646)	(591)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	14,449	15,536	14,095
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	14,274	12,472	11,759
Actual return on plan assets	(536)	2,041	829
Employer contributions	473	450	508
Benefits paid	(715)	(646)	(591)
Administrative expenses	(46)	(43)	(33)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	13,450	14,274	12,472
FUNDED STATUS	(999)	(1,262)	(1,623)
Unrecognized net loss	2,464	2,760	3,157
Unrecognized prior service costs	(205)	(223)	(244)
Accumulated benefit obligation	13,030	13,897	12,655
CECONY
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	301
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	301	301
CECONY \| Pension Benefits
CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	14,567	13,203	13,482
Service cost – excluding administrative expenses	267	241	254
Interest cost on projected benefit obligation	525	554	559
Net actuarial loss/(gain)	(1,159)	1,171	(282)
Plan amendments	0	0	(259)
Benefits paid	(658)	(602)	(551)
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	13,542	14,567	13,203
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	13,519	11,815	11,141
Actual return on plan assets	(507)	1,935	787
Employer contributions	434	412	469
Benefits paid	(658)	(602)	(551)
Administrative expenses	(44)	(41)	(31)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	12,744	13,519	11,815
FUNDED STATUS	(798)	(1,048)	(1,388)
Unrecognized net loss	2,338	2,624	2,995
Unrecognized prior service costs	(222)	(242)	(258)
Accumulated benefit obligation	$ 12,161	$ 12,972	$ 11,806

Pension Benefits - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Pension liability	$ 263,000,000
Investments value	326,000,000	$ 330,000,000
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets and liabilities for future income taxes, net	273,000,000
Charge to OCI	7,000,000
Net loss estimated to be amortized	512,000,000
Prior service cost estimated to be amortized	(17,000,000)
Investments value	13,450,000,000	14,274,000,000	$ 12,472,000,000	$ 11,759,000,000
Accumulated benefit obligation	13,030,000,000	13,897,000,000	12,655,000,000
Defined benefit plan, bond amount (excess of)	50,000,000
Estimated future employer contributions	332,000,000
Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	316,000,000	331,000,000
CECONY
Defined Benefit Plan Disclosure [Line Items]
Pension liability	250,000,000
Investments value	301,000,000	301,000,000
CECONY \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets and liabilities for future income taxes, net	265,000,000
Charge to OCI	1,000,000
Net loss estimated to be amortized	486,000,000
Prior service cost estimated to be amortized	(19,000,000)
Investments value	12,744,000,000	13,519,000,000	11,815,000,000	$ 11,141,000,000
Accumulated benefit obligation	12,161,000,000	12,972,000,000	$ 11,806,000,000
Estimated future employer contributions	301,000,000
CECONY \| Other Nonqualified Supplemental Defined Benefit Pension
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 285,000,000	$ 297,000,000

Pension Benefits - Schedule of Assumptions (Details)	12 Months Ended
Pension Benefits - Schedule of Assumptions (Details)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CECONY
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	4.25%	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	4.00%	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	4.25%	3.70%	4.25%
Discount rate, net periodic benefit cost	3.70%	4.25%	4.25%
Expected return on plan assets	7.50%	7.50%	7.80%

Pension Benefits - Schedule of Expected Benefit Payments (Details) - Pension Benefits $ in Millions	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2019	$ 707
2020	726
2021	740
2022	755
2023	772
2024-2028	4,072
CECONY
Defined Benefit Plan Disclosure [Line Items]
2019	658
2020	676
2021	689
2022	703
2023	718
2024-2028	$ 3,795

Pension Benefits - Schedule of Plan Assets Allocations (Details) - Pension Benefits	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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%	58.00%	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	39.00%	33.00%	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	10.00%	9.00%	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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 326	$ 330
Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		336
Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets		1,214
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(204)	(262)
Funds for retiree health benefits measured at NAV per share	(33)	(36)
Total funds for retiree health benefits	(237)	298
Investments (excluding funds for retiree health benefits)	14,105	14,683
Pending activities	(655)	(409)
Total fair value of plan net assets	13,450	14,274	$ 12,472	$ 11,759
Pension Benefits \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,525	3,900
Pension Benefits \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,896	4,132
Pension Benefits \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,886	1,786
Pension Benefits \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,619	2,450
Pension Benefits \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	6	3
Pension Benefits \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	121	125
Pension Benefits \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	716	476
Pension Benefits \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	568	308
Pension Benefits \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	12,337	13,180
Pension Benefits \| Private Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	440
Pension Benefits \| Real Estate
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,310
Pension Benefits \| Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	255	251
Pension Benefits \| Investments Valued Using NAV Per Share
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,005	1,801
Pension Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(118)	(168)
Investments (excluding funds for retiree health benefits)	7,021	8,268
Pension Benefits \| Level 1 \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	3,515	3,872
Pension Benefits \| Level 1 \| International Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,896	4,132
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	124
Pension Benefits \| Level 1 \| Futures
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	568	308
Pension Benefits \| Level 1 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	7,139	8,436
Pension Benefits \| Level 2
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	(86)	(94)
Investments (excluding funds for retiree health benefits)	5,112	4,650
Pension Benefits \| Level 2 \| U.S. Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	10	28
Pension Benefits \| Level 2 \| U.S. Government Issued Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	1,886	1,786
Pension Benefits \| Level 2 \| Corporate Bonds Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	2,619	2,450
Pension Benefits \| Level 2 \| Structured Assets Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	6	3
Pension Benefits \| Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	121	125
Pension Benefits \| Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	556	352
Pension Benefits \| Level 2 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 5,198	$ 4,744

Other Postretirement Benefits - Net Periodic Postretirement Benefit Costs (Details) - Other Postretirement Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 20	$ 20	$ 18
Interest cost on accumulated other postretirement benefit obligation	42	46	48
Expected return on plan assets	(73)	(69)	(77)
Recognition of net actuarial loss/(gain)	8	2	5
Recognition of prior service cost/(credit)	(6)	(17)	(20)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST/(CREDIT)	(9)	(18)	(26)
Cost capitalized	(8)	8	11
Reconciliation to rate level	8	(4)	22
Total expense/(credit) recognized	(9)	(14)	7
CECONY
Defined Benefit Plan Disclosure [Line Items]
Service cost	14	13	13
Interest cost on accumulated other postretirement benefit obligation	34	38	40
Expected return on plan assets	(63)	(61)	(67)
Recognition of net actuarial loss/(gain)	3	(3)	3
Recognition of prior service cost/(credit)	(2)	(11)	(14)
TOTAL PERIODIC POSTRETIREMENT BENEFIT COST/(CREDIT)	(14)	(24)	(25)
Cost capitalized	(6)	10	10
Reconciliation to rate level	9	(2)	22
Total expense/(credit) recognized	$ (11)	$ (16)	$ 7

Other Postretirement Benefits - Schedule of Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	$ 330
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	326	$ 330
CECONY
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	301
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	301	301
Other Postretirement Benefits
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	1,219	1,198	$ 1,287
Service cost	20	20	18
Interest cost on accumulated other postretirement benefit obligation	42	46	48
Net actuarial loss/(gain)	(70)	53	(57)
Benefits paid and administrative expenses, net of subsidies	(135)	(134)	(134)
Participant contributions	38	36	36
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	1,114	1,219	1,198
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	1,039	975	994
Actual return on plan assets	(66)	150	60
Employer contributions	6	17	7
Employer group waiver plan subsidies	34	34	35
Participant contributions	37	35	36
Benefits paid	(165)	(172)	(157)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	885	1,039	975
FUNDED STATUS	(229)	(180)	(223)
Unrecognized net loss/(gain)	14	(47)	(24)
Unrecognized prior service costs	(8)	(14)	(31)
Other Postretirement Benefits \| CECONY
CHANGE IN BENEFIT OBLIGATION
Projected benefit obligation at beginning of year	985	1,007	1,093
Service cost	14	13	13
Interest cost on accumulated other postretirement benefit obligation	34	38	40
Net actuarial loss/(gain)	(32)	16	(52)
Benefits paid and administrative expenses, net of subsidies	(125)	(124)	(122)
Participant contributions	37	35	35
PROJECTED BENEFIT OBLIGATION AT END OF YEAR	913	985	1,007
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year	893	851	870
Actual return on plan assets	(54)	130	52
Employer contributions	6	8	7
Employer group waiver plan subsidies	32	30	33
Participant contributions	37	35	35
Benefits paid	(155)	(161)	(146)
FAIR VALUE OF PLAN ASSETS AT END OF YEAR	759	893	851
FUNDED STATUS	(154)	(92)	(156)
Unrecognized net loss/(gain)	(2)	(85)	(42)
Unrecognized prior service costs	$ (5)	$ (7)	$ (18)

Other Postretirement Benefits - Additional Information (Details) - Other Postretirement Benefits $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Increase in liability for other postretirement benefits	$ 49
Increase (decrease) in regulatory liabilities	70
Net losses unrecognized to be amortized	(7)
Prior service cost estimated to be amortized	$ (2)
Health care cost trend rate for net periodic benefit cost, current	5.60%
Health care cost trend rate for net periodic benefit cost	4.50%
Health care cost trend rate for benefit obligations, current	5.40%
Health care cost trend rate for benefit obligations	4.50%
Expected contributions	$ 10
Clean Energy Businesses, Con Edison Transmission and RECO
Defined Benefit Plan Disclosure [Line Items]
Credit to OCI (net of taxes) for unrecognized net losses	4
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	62
Increase (decrease) in regulatory liabilities	(85)
Credit to OCI (net of taxes) for unrecognized net losses	1
Net losses unrecognized to be amortized	(10)
Prior service cost estimated to be amortized	(2)
Expected contributions	$ 8

Other Postretirement Benefits - Schedule of Actuarial Assumptions (Details) - Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Expected Return on Plan Assets	7.50%	7.50%	7.00%
CECONY
Defined Benefit Plan Disclosure [Line Items]
Discount Rate, Benefit Obligations	4.15%	3.55%	4.00%
Discount Rate, Net Periodic Benefit Cost	3.55%	4.00%	4.05%
O&R
Defined Benefit Plan Disclosure [Line Items]
Discount Rate, Benefit Obligations	4.30%	3.70%	4.20%
Discount Rate, Net Periodic Benefit Cost	3.70%	4.20%	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, 2018 USD ($)
Increase
Effect on accumulated other postretirement benefit obligation	$ 9
Effect on service cost and interest cost components for 2018	2
Decrease
Effect on accumulated other postretirement benefit obligation	11
Effect on service cost and interest cost components for 2018	(1)
CECONY
Increase
Effect on accumulated other postretirement benefit obligation	(18)
Effect on service cost and interest cost components for 2018	(1)
Decrease
Effect on accumulated other postretirement benefit obligation	31
Effect on service cost and interest cost components for 2018	$ 1

Other Postretirement Benefits - Schedule of Expected Benefit Payments (Details) - Other Postretirement Benefits $ in Millions	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
2019	$ 80
2020	78
2021	76
2022	75
2023	74
2024-2028	359
CECONY
Defined Benefit Plan Disclosure [Line Items]
2019	70
2020	67
2021	65
2022	64
2023	63
2024-2028	$ 302

Other Postretirement Benefits - Schedule of Plan Assets Allocations (Details) - Other Postretirement Benefits - CECONY	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	52.00%	60.00%	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	48.00%	40.00%	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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 326	$ 330
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	204	262
Investments (including funds for retiree health benefits)	829	984
Funds for retiree health benefits measured at NAV per share	33	36
Pending activities	23	19
Total fair value of plan net assets	885	1,039	$ 975	$ 994
Other Postretirement Benefits \| Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	322	420
Other Postretirement Benefits \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	289	286
Other Postretirement Benefits \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	14	16
Other Postretirement Benefits \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	625	722
Other Postretirement Benefits \| Level 1
Defined Benefit Plan Disclosure [Line Items]
Funds for retiree health benefits	118	168
Investments (including funds for retiree health benefits)	118	168
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	86	94
Investments (including funds for retiree health benefits)	711	816
Other Postretirement Benefits \| Level 2 \| Equity
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	322	420
Other Postretirement Benefits \| Level 2 \| Other Fixed Income Debt
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	289	286
Other Postretirement Benefits \| Level 2 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	14	16
Other Postretirement Benefits \| Level 2 \| Total investments
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan net assets	$ 625	$ 722

Environmental Matters - Accrued Liabilities and Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Site Contingency [Line Items]
Accrued Liabilities	$ 779	$ 737
Regulatory assets	4,370	4,333
Manufactured gas plant sites
Site Contingency [Line Items]
Accrued Liabilities	689	651
Other Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	90	86
Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	779	737
Regulatory assets	810	793
CECONY
Site Contingency [Line Items]
Accrued Liabilities	693	637
Regulatory assets	3,987	3,925
CECONY \| Manufactured gas plant sites
Site Contingency [Line Items]
Accrued Liabilities	603	551
CECONY \| Other Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	90	86
CECONY \| Superfund Sites
Site Contingency [Line Items]
Accrued Liabilities	693	637
Regulatory assets	$ 716	$ 677

Environmental Matters - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 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	$ 28
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	21
Superfund Sites \| CECONY \| Manufactured Gas Plant Sites \| Maximum
Site Contingency [Line Items]
Estimated aggregate undiscounted potential liability related environmental contaminants (up to)	$ 2,600

Environmental Matters - Accrued Liability for Asbestos Suits and Workers' Compensation Proceedings (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Site Contingency [Line Items]
Regulatory assets	$ 4,370	$ 4,333
Asbestos Suits
Site Contingency [Line Items]
Accrued liability	8	8
Regulatory assets	8	8
Workers' Compensation
Site Contingency [Line Items]
Accrued liability	79	84
Regulatory assets	5	10
CECONY
Site Contingency [Line Items]
Regulatory assets	3,987	3,925
CECONY \| Asbestos Suits
Site Contingency [Line Items]
Accrued liability	7	7
Regulatory assets	7	7
CECONY \| Workers' Compensation
Site Contingency [Line Items]
Accrued liability	75	80
Regulatory assets	$ 5	$ 10

Other Material Contingencies - Manhattan Explosion and Fire (Details) $ in Millions		1 Months Ended
	Mar. 12, 2014 building people	Feb. 28, 2017 USD ($)	Dec. 31, 2018 USD ($) lawsuit	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Accrued regulatory liability			$ 4,641	$ 4,577
Settlement of gas proceedings
Loss Contingencies [Line Items]
Accrued regulatory liability			$ 15	$ 27
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, 2018	Dec. 31, 2017
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 2,439	$ 2,073
Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	1,146
Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	683
Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	540
Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	70
0 – 3 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	1,411
0 – 3 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	742
0 – 3 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	462
0 – 3 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	137
0 – 3 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	70
4 – 10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	424
4 – 10 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	404
4 – 10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	20
4 – 10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	0
4 – 10 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	0
Greater than 10 years
Guarantor Obligations [Line Items]
Total guarantees, by type and term	604
Greater than 10 years \| Con Edison Transmission
Guarantor Obligations [Line Items]
Total guarantees, by type and term	0
Greater than 10 years \| Energy transactions
Guarantor Obligations [Line Items]
Total guarantees, by type and term	201
Greater than 10 years \| Renewable electric production projects
Guarantor Obligations [Line Items]
Total guarantees, by type and term	403
Greater than 10 years \| Other
Guarantor Obligations [Line Items]
Total guarantees, by type and term	$ 0

Other Material Contingencies - Con Edison Transmission (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2014
Guarantor Obligations [Line Items]
Guarantee obligations maximum exposure	$ 2,439	$ 2,073
Payment Guarantee by CET Electric of Contributions to New York Transco LLC
Guarantor Obligations [Line Items]
Estimated project cost percentage	175.00%
Financial Guarantee in Behalf of CET Gas for Proposed Gas Transmission Project
Guarantor Obligations [Line Items]
Guarantee obligations maximum exposure	$ 124
NY Transco \| Payment Guarantee by CET Electric of Contributions to New York Transco LLC
Guarantor Obligations [Line Items]
Ownership interest, percentage			45.70%

Electricity Purchase Agreements - Summary of Estimated Capacity and Other Fixed Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Long-term Contract for Purchase of Electric Power [Line Items]
2019	$ 206
2020	117
2021	65
2022	54
2023	55
All Years Thereafter	601
CECONY
Long-term Contract for Purchase of Electric Power [Line Items]
2019	202
2020	113
2021	64
2022	54
2023	55
All Years Thereafter	$ 601

Electricity Purchase Agreements - Summary of Capacity, Energy and Other Fixed Payments (Details) - CECONY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	$ 318	$ 552	$ 692
Indian Point
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	6	211	203
Linden Cogeneration
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	0	114	304
Astoria Energy
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	0	0	50
Astoria Generating Company
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	179	92	16
Brooklyn Navy Yard
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	124	117	119
Cogen Technologies
Long-term Contract for Purchase of Electric Power [Line Items]
Capacity, energy and other fixed payments	$ 9	$ 18	$ 0

Leases - Future Minimum Rental Payments for Operating Leases (Details) $ in Millions	Dec. 31, 2018 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)	12 Months Ended
Goodwill (Details)	Dec. 31, 2018 USD ($)	Dec. 31, 2016 USD ($) business_acquisition	Dec. 31, 2017 USD ($)
Goodwill [Line Items]
Goodwill	$ 440,000,000		$ 428,000,000
Impairment charge	0
CECONY
Goodwill [Line Items]
Goodwill	245,000,000		245,000,000
O&R
Goodwill [Line Items]
Goodwill	161,000,000		161,000,000
O&R Merger
Goodwill [Line Items]
Goodwill	406,000,000		406,000,000
Gas Storage Company \| CET Gas
Goodwill [Line Items]
Goodwill	8,000,000		8,000,000
Energy Services Company \| Clean Energy Businesses
Goodwill [Line Items]
Goodwill		$ 15,000,000
Number of businesses acquired included in goodwill impairment test \| business_acquisition		2
Impairment charge		$ 15,000,000
Impairment charge, net of tax		$ 12,000,000
Residential Solar Company \| Clean Energy Businesses
Goodwill [Line Items]
Goodwill	14,000,000		$ 14,000,000
Battery Storage Company [Member] \| Clean Energy Businesses
Goodwill [Line Items]
Goodwill	$ 12,000,000

Income Tax - Schedule of Components of Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
State
Current	$ (10)	$ (2)	$ (42)
Deferred	107	103	188
Federal
Current	3	(11)	(43)
Deferred	310	391	604
Amortization of investment tax credits	(9)	(9)	(9)
Total income tax expense	401	472	698
CECONY
State
Current	6	37	(1)
Deferred	82	75	114
Federal
Current	(34)	73	59
Deferred	275	504	435
Amortization of investment tax credits	(3)	(4)	(4)
Total income tax expense	$ 326	$ 685	$ 603

Income Tax - Schedule of Differences on Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities:
Property basis differences	$ 7,402	$ 6,555
Regulatory assets:
Unrecognized pension and other postretirement costs	627	697
Environmental remediation costs	227	219
Deferred storm costs	21	11
Other regulatory assets	273	269
Equity investments	102	263
Total deferred tax liabilities	8,652	8,014
Deferred tax assets:
Accrued pension and other postretirement costs	248	264
Future income tax	702	698
Other regulatory liabilities	632	593
Superfund and other environmental costs	218	203
Asset retirement obligations	114	86
Loss carryforwards	229	95
Tax credits carryforward	817	658
Valuation allowance	(33)	(33)
Other	53	112
Total deferred tax assets	2,980	2,676
Net deferred tax liabilities	5,672	5,338
Unamortized investment tax credits	148	157
Net deferred tax liabilities and unamortized investment tax credits	5,820	5,495
CECONY
Deferred tax liabilities:
Property basis differences	6,446	5,968
Regulatory assets:
Unrecognized pension and other postretirement costs	591	656
Environmental remediation costs	200	187
Deferred storm costs	0	0
Other regulatory assets	252	241
Equity investments	0	0
Total deferred tax liabilities	7,489	7,052
Deferred tax assets:
Accrued pension and other postretirement costs	180	187
Future income tax	662	660
Other regulatory liabilities	554	524
Superfund and other environmental costs	194	176
Asset retirement obligations	82	79
Loss carryforwards	0	0
Tax credits carryforward	0	0
Valuation allowance	0	0
Other	102	148
Total deferred tax assets	1,774	1,774
Net deferred tax liabilities	5,715	5,278
Unamortized investment tax credits	24	28
Net deferred tax liabilities and unamortized investment tax credits	$ 5,739	$ 5,306

Income Tax - Additional Information (Details) - USD ($)	1 Months Ended	12 Months Ended
Income Tax - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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
Deferred tax asset, valuation allowance	$ 33,000,000	33,000,000	33,000,000
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years		3,000,000	6,000,000	$ 0
Effective income tax rate reconciliation, uncertainty of taxes		4,000,000
Penalties for uncertain tax positions		0	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		6,000,000
New York State
Operating Loss Carryforwards [Line Items]
Decrease in effective tax rate resulting from tax settlement			6,000,000
Charitable Contribution
Operating Loss Carryforwards [Line Items]
Deferred tax asset, valuation allowance		0
General Business Tax Credit
Operating Loss Carryforwards [Line Items]
Tax credit carryovers		817,000,000
Expiring in 2020
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards					$ 5,000,000
Expiring in 2021
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards				5,000,000
Expiring in 2022
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards	7,000,000		7,000,000
Expiring in 2023
Operating Loss Carryforwards [Line Items]
Charitable contribution carryforwards		5,000,000
Federal
Operating Loss Carryforwards [Line Items]
Additional depreciation deducted			477,000,000
Operating loss carryforwards	563,000,000	711,000,000	563,000,000
Operating loss carryover subject to expiration	520,000,000		520,000,000
Operating loss carryover not subject to expiration		191,000,000
State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, valuation allowance		21,000,000
State \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	97,000,000	398,000,000	97,000,000
Operating loss carryforwards, valuation allowance		12,000,000
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years			9,000,000
State \| Carry Back to 2015 \| New York State
Operating Loss Carryforwards [Line Items]
Income tax recovery resulting from operating loss carry back			9,000,000
State \| Carry Back to 2015 and 2016 \| New York State
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards		99,000,000
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		299,000,000
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	0
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years		3,000,000	0	$ 0
Effective income tax rate reconciliation, uncertainty of taxes		2,000,000
Unrecognized tax benefits that would have an impact on effective tax rate		4,000,000
CECONY \| New York State
Operating Loss Carryforwards [Line Items]
Decrease in uncertain tax positions resulting from settlement of claims filed in previous years			4,000,000
Decrease in effective tax rate resulting from tax settlement			1,000,000
CECONY \| Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	153,000,000		153,000,000
CECONY \| Future Income Tax
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA	$ 3,513,000,000	49,000,000	3,513,000,000
CECONY \| Accelerated Tax Depreciation Benefits
Operating Loss Carryforwards [Line Items]
Increase in regulatory liability resulting from TCJA		2,593,000,000	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, 2018	Dec. 31, 2017	Dec. 31, 2016
STATUTORY TAX RATE
Federal	21.00%	35.00%	35.00%
Changes in computed taxes resulting from:
State income tax	4.00%	4.00%	4.00%
Cost of removal	1.00%	1.00%	(1.00%)
Other plant-related items	(1.00%)	(1.00%)	0.00%
TCJA deferred tax re-measurement	2.00%	(13.00%)	0.00%
Amortization of excess deferred federal income taxes	(3.00%)	(0.00%)	(0.00%)
Renewable energy credits	(1.00%)	(1.00%)	(1.00%)
Research and development credits	(0.00%)	(0.00%)	(1.00%)
Other	0.00%	(2.00%)	0.00%
Effective tax rate	23.00%	23.00%	36.00%
CECONY
STATUTORY TAX RATE
Federal	21.00%	35.00%	35.00%
Changes in computed taxes resulting from:
State income tax	5.00%	4.00%	4.00%
Cost of removal	1.00%	1.00%	(1.00%)
Other plant-related items	(1.00%)	(1.00%)	(1.00%)
TCJA deferred tax re-measurement	0.00%	0.00%	0.00%
Amortization of excess deferred federal income taxes	(3.00%)	(0.00%)	(0.00%)
Renewable energy credits	(0.00%)	(0.00%)	(0.00%)
Research and development credits	(1.00%)	(0.00%)	(1.00%)
Other	(1.00%)	(1.00%)	0.00%
Effective tax rate	21.00%	38.00%	36.00%

Income Tax - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 12	$ 42	$ 34
Additions based on tax positions related to the current year	2	1	2
Additions based on tax positions of prior years	1	1	19
Reductions for tax positions of prior years	(2)	(24)	(13)
Reductions from expiration of statute of limitations	(4)	(2)	0
Settlements	(3)	(6)	0
Balance at end of period	6	12	42
CECONY
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	5	21	2
Additions based on tax positions related to the current year	2	1	2
Additions based on tax positions of prior years	1	1	19
Reductions for tax positions of prior years	(1)	(18)	(2)
Reductions from expiration of statute of limitations	0	0	0
Settlements	(3)	0	0
Balance at end of period	$ 4	$ 5	$ 21

Stock-Based Compensation - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit realized from stock options exercised	$ 4,000,000	$ 25,000,000	$ 20,000,000
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	$ 4,000,000	22,000,000	18,000,000
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (years)	3 years
Income tax benefit realized from stock options exercised			1,000,000
Stock Options \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award expiration period (years)	10 years
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	$ 21,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 29,000,000	22,000,000	21,000,000
Performance RSUs \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense to be recognized	$ 18,000,000
Nonvested awards, compensation cost not yet recognized, period for recognition (years)	1 year
Payment for settlement of vested units	$ 28,000,000	21,000,000	20,000,000
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]
Compensation expense to be recognized	$ 2,000,000
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)	$ 77.94
Time-based Awards \| CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense to be recognized	$ 2,000,000
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)	$ 77.94
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)	$ 67.26
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)	$ 66.79
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)	$ 76.37
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)	$ 76.48
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units issued (in shares)	33,100
Weighted average grant date price per share (in dollars per share)	$ 76.08
Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares purchased on the open market	786,385	719,125	720,268
Weighted average share price per share, on shares purchased on open market (in dollars per share)	$ 78.27	$ 79.57	$ 72.67

Stock-Based Compensation - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 14	$ 63	$ 50
Income tax benefit	4	25	20
Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	3	53	42
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	3	2	2
Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	6	6	4
CECONY
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	13	55	44
Income tax benefit	4	22	18
CECONY \| Performance-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	3	45	36
CECONY \| Time-based restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1	2	2
CECONY \| Non-employee director deferred stock compensation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	3	2	2
CECONY \| Stock purchase plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 6	$ 6	$ 4

Stock-Based Compensation - Assumptions Used to Calculate Fair Value (Details) - Performance RSUs	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate, minimum	2.48%	1.76%	0.85%
Risk-free interest rate, maximum	2.63%	1.89%	1.20%
Expected term (years)	3 years	3 years	3 years
Expected share price volatility, minimum (percent)	14.76%	11.01%	17.72%
Expected share price volatility, maximum (percent)	17.71%	14.70%	18.22%

Stock-Based Compensation - Summary of Changes in Status of Performance RSUs' (Details) - Performance RSUs	12 Months Ended
	Dec. 31, 2018 $ / shares shares
Units
Non-vested at beginning of period (in shares) \| shares	1,028,932
Granted (in shares) \| shares	328,850
Vested (in shares) \| shares	(327,069)
Forfeited (in shares) \| shares	(24,877)
Transferred (in shares) \| shares	0
Non-vested at end of period (in shares) \| shares	1,005,836
CECONY
Units
Non-vested at beginning of period (in shares) \| shares	784,166
Granted (in shares) \| shares	247,532
Vested (in shares) \| shares	(261,167)
Forfeited (in shares) \| shares	(20,877)
Transferred (in shares) \| shares	12,252
Non-vested at end of period (in shares) \| shares	761,906
TSR Portion
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	$ 71.74
Granted (in dollars per share)	67.26
Vested (in dollars per share)	57.77
Forfeited (in dollars per share)	72.22
Transferred (in dollars per share)	0.00
Non-vested at end of period (in dollars per share)	$ 74.81
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)	$ 71.06
Granted (in dollars per share)	66.79
Vested (in dollars per share)	57.37
Forfeited (in dollars per share)	71.76
Transferred (in dollars per share)	78.47
Non-vested at end of period (in dollars per share)	74.47
Non-TSR Portion
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share)	70.11
Granted (in dollars per share)	76.37
Vested (in dollars per share)	63.27
Forfeited (in dollars per share)	74.97
Transferred (in dollars per share)	0.00
Non-vested at end of period (in dollars per share)	$ 74.27
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)	$ 70.08
Granted (in dollars per share)	76.48
Vested (in dollars per share)	63.18
Forfeited (in dollars per share)	75.14
Transferred (in dollars per share)	72.71
Non-vested at end of period (in dollars per share)	$ 74.42

Stock-Based Compensation - Summary of Changes in Status of Time-Based Awards (Details) - Time-based Awards	12 Months Ended
	Dec. 31, 2018 $ / shares shares
Units
Non-vested at beginning of period (in shares) \| shares	64,870
Granted (in shares) \| shares	23,000
Vested (in shares) \| shares	(20,523)
Forfeited (in shares) \| shares	(2,167)
Non-vested at end of period (in shares) \| shares	65,180
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share) \| $ / shares	$ 71.93
Granted (in dollars per share) \| $ / shares	77.94
Vested (in dollars per share) \| $ / shares	61.03
Forfeited (in dollars per share) \| $ / shares	73.93
Non-vested at end of period (in dollars per share) \| $ / shares	$ 77.42
CECONY
Units
Non-vested at beginning of period (in shares) \| shares	61,420
Granted (in shares) \| shares	21,400
Vested (in shares) \| shares	(19,473)
Forfeited (in shares) \| shares	(1,967)
Non-vested at end of period (in shares) \| shares	61,380
Weighted Average Grant Date Fair Value
Non-vested at beginning of period (in dollars per share) \| $ / shares	$ 71.93
Granted (in dollars per share) \| $ / shares	77.94
Vested (in dollars per share) \| $ / shares	61.03
Forfeited (in dollars per share) \| $ / shares	73.97
Non-vested at end of period (in dollars per share) \| $ / shares	$ 77.42

Financial Information by Business Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenues	$ 12,337	$ 12,033	$ 12,075
Depreciation and amortization	1,438	1,341	1,216
Operating income	2,664	2,774	2,780
Other Income (deductions)	(62)	(48)	(141)
Interest charges	819	729	696
Income taxes on operating income	406	459	714
Total assets	53,920	48,111	48,255
Capital expenditures	5,249	3,606	5,235
Income taxes on non-operating income	(5)	13	(16)
Federal income tax expense		259
Parent Company
Segment Reporting Information [Line Items]
Interest charges	59	50	41
Total assets	19,542	17,231
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	10,680	10,468	10,165
Depreciation and amortization	1,276	1,195	1,106
Operating income	2,354	2,549	2,451
Other Income (deductions)	(143)	(137)	(189)
Interest charges	689	623	603
Total assets	43,108	40,451
Income taxes on non-operating income	(2)	(3)	(14)
Operating segment \| Clean Energy Businesses
Segment Reporting Information [Line Items]
Revenues	763	694	1,091
Depreciation and amortization	85	74	42
Operating income	194	69	183
Other Income (deductions)	33	33	21
Interest charges	63	43	34
Income taxes on operating income	19	(273)	53
Total assets	5,821	2,735	2,551
Capital expenditures	1,791	447	1,235
Operating segment \| Con Edison Transmission
Segment Reporting Information [Line Items]
Revenues	4	2	0
Depreciation and amortization	1	1	0
Operating income	(7)	(8)	(3)
Other Income (deductions)	91	80	43
Interest charges	20	16	6
Income taxes on operating income	(1)	(11)	0
Total assets	1,425	1,222	1,150
Capital expenditures	248	66	1,078
Operating segment \| CECONY
Segment Reporting Information [Line Items]
Revenues	10,680	10,468	10,165
Depreciation and amortization	1,276	1,195	1,106
Operating income	2,354	2,549	2,451
Other Income (deductions)	(143)	(137)	(189)
Interest charges	689	623	603
Income taxes on operating income	328	688	617
Total assets	43,108	40,451	40,856
Capital expenditures	3,005	2,904	2,756
Operating segment \| CECONY \| Electric
Segment Reporting Information [Line Items]
Revenues	7,971	7,972	8,106
Depreciation and amortization	984	925	865
Operating income	1,799	1,974	1,996
Other Income (deductions)	(110)	(105)	(147)
Interest charges	519	472	459
Income taxes on operating income	233	511	495
Total assets	31,012	29,661	30,708
Capital expenditures	1,861	1,905	1,819
Operating segment \| CECONY \| Gas
Segment Reporting Information [Line Items]
Revenues	2,078	1,901	1,508
Depreciation and amortization	205	185	159
Operating income	478	495	387
Other Income (deductions)	(23)	(23)	(31)
Interest charges	131	113	105
Income taxes on operating income	87	152	92
Total assets	9,710	8,387	7,553
Capital expenditures	1,050	909	811
Operating segment \| CECONY \| Steam
Segment Reporting Information [Line Items]
Revenues	631	595	551
Depreciation and amortization	87	85	82
Operating income	77	80	68
Other Income (deductions)	(10)	(9)	(11)
Interest charges	39	38	39
Income taxes on operating income	8	25	30
Total assets	2,386	2,403	2,595
Capital expenditures	94	90	126
Operating segment \| O&R
Segment Reporting Information [Line Items]
Revenues	891	874	821
Depreciation and amortization	77	71	67
Operating income	132	161	146
Other Income (deductions)	(19)	(19)	(15)
Interest charges	39	36	36
Income taxes on operating income	21	42	40
Total assets	2,892	2,773	2,758
Capital expenditures	205	189	166
Operating segment \| O&R \| Electric
Segment Reporting Information [Line Items]
Revenues	642	642	637
Depreciation and amortization	56	51	49
Operating income	93	115	107
Other Income (deductions)	(14)	(14)	(11)
Interest charges	25	24	24
Income taxes on operating income	14	30	30
Total assets	2,036	1,949	1,949
Capital expenditures	138	128	114
Operating segment \| O&R \| Gas
Segment Reporting Information [Line Items]
Revenues	249	232	184
Depreciation and amortization	21	20	18
Operating income	39	46	39
Other Income (deductions)	(5)	(5)	(4)
Interest charges	14	12	12
Income taxes on operating income	7	12	10
Total assets	856	824	809
Capital expenditures	67	61	52
Other
Segment Reporting Information [Line Items]
Revenues	(1)	(5)	(2)
Depreciation and amortization	(1)	0	1
Operating income	(9)	3	3
Other Income (deductions)	(24)	(5)	(1)
Interest charges	8	11	17
Income taxes on operating income	39	13	4
Total assets	674	930	940
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	(7)
Inter-segment \| Clean Energy Businesses
Segment Reporting Information [Line Items]
Revenues	0	0	7
Inter-segment \| CECONY
Segment Reporting Information [Line Items]
Revenues	(98)	(97)	(111)
Inter-segment \| CECONY \| Electric
Segment Reporting Information [Line Items]
Revenues	16	16	17
Inter-segment \| CECONY \| Gas
Segment Reporting Information [Line Items]
Revenues	7	6	6
Inter-segment \| CECONY \| Steam
Segment Reporting Information [Line Items]
Revenues	$ 75	$ 75	$ 88

Derivative Instruments and Hedging Activities - Fair Values of Commodity Derivatives Including Offsetting of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Net fair value derivative assets/(liabilities)
Gross Amounts of Recognized Assets/ (Liabilities)	$ (23)	$ (17)
Gross Amounts Offset	(1)	0
Net Amounts of Assets/ (Liabilities)	(24)	(17)
Margin deposits	7	12
Interest Rate Swap
Fair value of derivative assets
Net Amounts of Assets/ (Liabilities)	2
Fair value of derivative liabilities
Net Amounts of Assets/ (Liabilities)	(6)
CECONY
Net fair value derivative assets/(liabilities)
Gross Amounts of Recognized Assets/ (Liabilities)	(7)	(14)
Gross Amounts Offset	1	(1)
Net Amounts of Assets/ (Liabilities)	(6)	(15)
Margin deposits	6	11
Fair Value of Derivative Liabilities, Current
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(61)	(67)
Gross Amounts Offset	11	50
Net Amounts of Assets/ (Liabilities)	(50)	(17)
Fair Value of Derivative Liabilities, Current \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(31)	(26)
Gross Amounts Offset	6	14
Net Amounts of Assets/ (Liabilities)	(25)	(12)
Fair Value of Derivative Liabilities, Non-current
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(19)	(43)
Gross Amounts Offset	9	5
Net Amounts of Assets/ (Liabilities)	(10)	(38)
Fair Value of Derivative Liabilities, Non-current \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(12)	(36)
Gross Amounts Offset	6	4
Net Amounts of Assets/ (Liabilities)	(6)	(32)
Fair Value of Derivative Liabilities
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(80)	(110)
Gross Amounts Offset	20	55
Net Amounts of Assets/ (Liabilities)	(60)	(55)
Fair Value of Derivative Liabilities \| CECONY
Fair value of derivative liabilities
Gross Amounts of Recognized Assets/ (Liabilities)	(43)	(62)
Gross Amounts Offset	12	18
Net Amounts of Assets/ (Liabilities)	(31)	(44)
Fair Value of Derivative Assets, Current
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	43	83
Gross Amounts Offset	(14)	(51)
Net Amounts of Assets/ (Liabilities)	29	32
Fair Value of Derivative Assets, Current \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	25	39
Gross Amounts Offset	(6)	(15)
Net Amounts of Assets/ (Liabilities)	19	24
Fair Value of Derivative Assets, Non-current
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	14	10
Gross Amounts Offset	(7)	(4)
Net Amounts of Assets/ (Liabilities)	7	6
Fair Value of Derivative Assets, Non-current \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	11	9
Gross Amounts Offset	(5)	(4)
Net Amounts of Assets/ (Liabilities)	6	5
Fair Value of Derivative Assets
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	57	93
Gross Amounts Offset	(21)	(55)
Net Amounts of Assets/ (Liabilities)	36	38
Fair Value of Derivative Assets \| CECONY
Fair value of derivative assets
Gross Amounts of Recognized Assets/ (Liabilities)	36	48
Gross Amounts Offset	(11)	(19)
Net Amounts of Assets/ (Liabilities)	$ 25	$ 29

Derivative Instruments and Hedging Activities - Realized and Unrealized Gains or Losses on Commodity Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ 3	$ 3
Total deferred gains/(losses)	5	(99)
Net deferred gains/(losses)	8	(96)
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	8
Purchased power expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
Gas purchased for resale
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(2)	3
Non-utility revenue
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	4	5
Non-utility operating revenue
Pre-tax gain/(loss) recognized in income
Unrealized gain/(loss) on derivatives	(5)	0
Other operations and maintenance expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(2)	0
Unrealized gain/(loss) on derivatives	(2)
Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(1)	3
Deferred Derivative Gains, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	4	0
Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	4	51
Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(26)	(154)
Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	27	4
CECONY
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	4	4
Total deferred gains/(losses)	8	(90)
Net deferred gains/(losses)	12	(86)
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	(2)	0
CECONY \| Purchased power expense
Pre-tax gain/(loss) recognized in income
Total pre-tax gain/(loss) recognized in income	0	0
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	(2)	0
CECONY \| Deferred Derivative Gains,Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	1	4
CECONY \| Deferred Derivative Gains, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	3	0
CECONY \| Deferred Derivative Losses, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	8	49
CECONY \| Recoverable Energy Costs, Current
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	(26)	(144)
CECONY \| Deferred Derivative Losses, Noncurrent
Pre-tax gains/(losses) deferred in accordance with accounting rules for regulated operations:
Total deferred gains/(losses)	$ 26	$ 5

Derivative Instruments and Hedging Activities - Hedged Volume of Derivative Transactions (Details) gal in Thousands	Dec. 31, 2018 MW gal MMBTU MWh
Electric Energy
Derivatives, Fair Value [Line Items]
Notional amount \| MWh	28,303,678
Capacity
Derivatives, Fair Value [Line Items]
Notional amount \| MW	18,519
Natural Gas
Derivatives, Fair Value [Line Items]
Notional amount \| MMBTU	164,668,697
Refined Fuels
Derivatives, Fair Value [Line Items]
Notional amount \| gal	3,780
CECONY \| Electric Energy
Derivatives, Fair Value [Line Items]
Notional amount \| MWh	25,458,600
CECONY \| Capacity
Derivatives, Fair Value [Line Items]
Notional amount \| MW	10,350
CECONY \| Natural Gas
Derivatives, Fair Value [Line Items]
Notional amount \| MMBTU	151,280,000
CECONY \| Refined Fuels
Derivatives, Fair Value [Line Items]
Notional amount \| gal	3,780

Derivative Instruments and Hedging Activities - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	$ 106
Makeup of net credit exposure with investment-grade counterparties	28
Makeup of net credit exposure independent system operators	31
Makeup of net credit exposure with commodity exchange brokers	19
Makeup of net credit exposure non-investment grade/non-rated counterparties	28
Interest Rate Swap
Investment Holdings [Line Items]
Derivative liability	6
Derivative asset	2
CECONY
Investment Holdings [Line Items]
Energy supply and hedging activities credit exposure total	13
Makeup of net credit exposure with investment-grade counterparties	7
Makeup of net credit exposure with commodity exchange brokers	6
Clean Energy Businesses \| Sempra Energy \| Interest Rate Swap
Investment Holdings [Line Items]
Derivative liability	5
Clean Energy Businesses \| Coram \| Interest Rate Swap
Investment Holdings [Line Items]
Derivative, fixed interest rate			2.0855%
Derivative liability		$ 0
Derivative asset	$ 1

Derivative Instruments and Hedging Activities - Aggregate Fair Value of Companies' Derivative Instruments with Credit-Risk-Related Contingent Features (Details) $ in Millions	Dec. 31, 2018 USD ($)
Derivatives, Fair Value [Line Items]
Aggregate fair value – net liabilities	$ 36
Collateral posted	6
Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	6
Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	66
Derivatives in net asset position additional collateral	20
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	24
Collateral posted	0
CECONY \| Downgrade One Level from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	2
CECONY \| Downgrade to Below Investment Grade from Current Ratings
Derivatives, Fair Value [Line Items]
Additional collateral	$ 37

Fair Value Measurements - Schedule of Commodity Derivatives (Details) - Level 3 $ in Millions	Dec. 31, 2018 USD ($) $ / kW-month $ / MWh
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (13)
CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	(2)
Electricity \| Forward Energy Prices
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (12)
Electricity \| Forward Energy Prices \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	21.34
Electricity \| Forward Energy Prices \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / MWh	64.45
Electricity \| Forward Capacity Prices \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (3)
Electricity \| Forward Capacity Prices \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	1.00
Electricity \| Forward Capacity Prices \| Minimum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	1.00
Electricity \| Forward Capacity Prices \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	6.30
Electricity \| Forward Capacity Prices \| Maximum \| CECONY
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	6.30
Natural Gas \| Forward Energy Prices
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value of commodity derivatives	$ (2)
Natural Gas \| Forward Natural Gas Prices \| Minimum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	0.92
Natural Gas \| Forward Natural Gas Prices \| Maximum
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Unobservable Inputs Range (dollar per unit) \| $ / kW-month	6.62
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	0.29
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	0.49
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	8.03
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	2.60

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, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 1	$ 1
Included in earnings	4	8
Included in regulatory assets and liabilities	(10)	(13)
Purchases	0	2
Settlements	(6)	(8)
Transfer out of level 3	(2)	11
Ending Balance	(13)	1
CECONY
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	4	1
Included in earnings	4	2
Included in regulatory assets and liabilities	(4)	(7)
Purchases	0	1
Settlements	(4)	(3)
Transfer out of level 3	(2)	10
Ending Balance	$ (2)	$ 4

Fair Value Measurements - Additional Information (Details) - Clean Energy Businesses - Non-utility revenue - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gain (loss) on Level 3 energy derivative assets and liabilities	$ (3)	$ 2
Fair value, assets and liabilities measured on recurring basis, change in unrealized gain (loss)	$ (3)	$ 2

Variable Interest Entities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) MW	Dec. 31, 2017 USD ($)
Variable Interest Entity [Line Items]
Noncontrolling interest	$ 113	$ 7
Texas Solar 4 \| Noncontrolling Interest
Variable Interest Entity [Line Items]
Noncontrolling interest	$ 7
Texas Solar 4 \| Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Generating capacity (MW AC) \| MW	40
VIE consolidated, carrying amount, assets and liabilities, net	$ 27	$ 26
Texas Solar 4 \| Variable Interest Entity, Primary Beneficiary \| Con Edison Development
Variable Interest Entity [Line Items]
Percentage of variable interests (less than)	80.00%
Tax Equity Projects \| Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
VIE consolidated, carrying amount, assets and liabilities, net	$ 870
Noncontrolling interest	$ 104
Tax Equity Projects \| Variable Interest Entity, Primary Beneficiary \| Con Edison Development
Variable Interest Entity [Line Items]
Percentage of variable interests (less than)	100.00%

Variable Interest Entities - Net Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Great Valley Solar
Business Acquisition [Line Items]
Restricted cash	$ 0
Non-utility property, less accumulated depreciation of $1 for each of the Tax Equity Projects and $15 and $12, for Texas Solar 4 in 2018 and 2017, respectively	313
Other assets	18
Total assets	331
Long-term debt due within one year	0
Other liabilities	17
Long-term debt	0
Total liabilities	17
Accumulated depreciation	1
Copper Mountain Solar - Mesquite Solar
Business Acquisition [Line Items]
Restricted cash	0
Non-utility property, less accumulated depreciation of $1 for each of the Tax Equity Projects and $15 and $12, for Texas Solar 4 in 2018 and 2017, respectively	492
Other assets	97
Total assets	589
Long-term debt due within one year	0
Other liabilities	33
Long-term debt	0
Total liabilities	33
Accumulated depreciation	1
Texas Solar 4
Business Acquisition [Line Items]
Restricted cash	4	$ 5
Non-utility property, less accumulated depreciation of $1 for each of the Tax Equity Projects and $15 and $12, for Texas Solar 4 in 2018 and 2017, respectively	98	101
Other assets	9	8
Total assets	111	114
Long-term debt due within one year	2	2
Other liabilities	26	28
Long-term debt	56	58
Total liabilities	84	88
Accumulated depreciation	$ 15	$ 12

Variable Interest Entities - Summary of VIEs (Details)	12 Months Ended
Variable Interest Entities - Summary of VIEs (Details)	Dec. 31, 2018 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	$ 281,000,000
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	$ 485,000,000
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	$ 33,000,000
Variable Interest Entity, Primary Beneficiary \| Copper Mountain Solar - Mesquite Solar
Variable Interest Entity [Line Items]
Maximum exposure for consolidated investments	$ 71,000,000
Variable Interest Entity, Primary Beneficiary \| Texas Solar 4
Variable Interest Entity [Line Items]
Generating Capacity Owned (MW AC) \| MW	32
Power Purchase Agreement Term in Years	25 years
Maximum Exposure to Loss	$ 20,000,000
Maximum exposure for consolidated investments	$ 7,000,000

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	$ 450	$ 314
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	168
Asset retirement obligations, accretion expense	13
Asset retirement obligations, liabilities settled	45
Asset retirement obligations, reductions	50	36
CECONY
Regulatory Liabilities [Line Items]
Accrued liability - asset retirement obligations	292	287
Increase in liabilities for asset retirement obligations due to changes in estimated cash flows	39
Asset retirement obligations, accretion expense	11
Asset retirement obligations, liabilities settled	45
Asset retirement obligations, reductions	$ 50	$ 36

Related Party Transactions - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018 USD ($) MMBTU agreement	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jan. 31, 2016
CECONY
Related Party Transaction [Line Items]
Net assets	$ 12,910,000,000
Sale of natural gas	83,000,000	$ 66,000,000	$ 47,000,000
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	250,000
CECONY \| Equity Method Investee \| Stagecoach \| Purchased Power Costs
Related Party Transaction [Line Items]
Amount of transaction	$ 28,000,000	31,000,000	$ 18,000,000
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)	3,000,000
O&R
Related Party Transaction [Line Items]
Net assets	712,000,000
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%

Related Party Transactions - Summary of Costs of Administrative and Other Services Provided and Received (Details) - CECONY - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Cost of services provided	$ 115	$ 111	$ 108
Cost of services received	$ 73	$ 64	$ 64

New Financial Accounting Standards (Details) - Scenario, Forecast - ASU 2016-02 $ in Millions	Jan. 01, 2019 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset	$ 875
Lease liabilities	875
CECONY
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use asset	635
Lease liabilities	$ 635

Acquisitions, Investments and Dispositions - Mountain Valley Pipeline (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investment		$ 0	$ 467
Mountain Valley Pipeline \| Maximum
Schedule of Equity Method Investments [Line Items]
Payments to acquire equity interest		$ 4,600
CET Gas \| Mountain Valley Pipeline
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		$ 363	$ 98

Acquisitions, Investments and Dispositions - Pilesgrove (Details) $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2016 USD ($)	Jun. 30, 2016 USD ($) MW	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Bargain purchase gain			$ 131	$ 0	$ 0
Pilesgrove
Business Acquisition [Line Items]
Generating capacity (MW AC) \| MW		18
Net assets			$ 45
Con Edison Development \| Pilesgrove
Business Acquisition [Line Items]
Percentage of voting interest acquired	50.00%
Purchase price	$ 16
Bargain purchase gain	8
Bargain purchase gain, net of taxes	5
Non-utility property	45
Other current assets	$ 3
Con Edison Development \| Pilesgrove
Business Acquisition [Line Items]
Equity method investment, impairment charge		$ 8
Equity method investment, impairment charge, net of taxes		$ 5
Percentage of equity interest owned		50.00%

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 ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Business acquisition, pre-tax gain from interests in projects	$ 131		$ 131
Long-term debt			$ 16,029	$ 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
Acquisition-date fair value of ownership interest held	568	$ 437
Property, plant and equipment acquired	1,454
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	$ 128

Acquisitions, Investments and Dispositions - Pro Forma Supplemental Information (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Dec. 13, 2018	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Revenues			$ 12,337	$ 12,033	$ 12,075
Net income			1,382	1,525	$ 1,245
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	$ 825
Fixed interest rate		4.64%	4.64%

Acquisitions, Investments and Dispositions - Con Edison Solutions' Retail Electric Supply Business (Details) - Con Edison Solutions - Retail Electric Supply Business - Discontinued Operations, Disposed of by Sale $ in Millions	1 Months Ended
	Sep. 30, 2016 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of business	$ 235
Gain on sale of business	104
Gain on sale of business, after tax	56
Gain on sale of derivatives	65
Gain on sale of derivatives, after tax	42
Tax effect of sale, state tax related to change in apportionment of state income taxes	16
Tax effect of sale, state tax related to change in apportionment of state income taxes, net of federal tax	$ 10

Acquisitions, Investments and Dispositions - Upton 2 (Details) - Con Edison Development $ in Millions	1 Months Ended	12 Months Ended
	May 31, 2017 USD ($)	Dec. 31, 2018 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Income Statements,Captions [Line Items]
Interest expense	$ (819)	$ (729)	$ (696)
NET INCOME	1,382	1,525	1,245
Comprehensive Income	$ 1,392	$ 1,526	$ 1,252
Net Income Per Share – Basic (in dollars per share)	$ 4.43	$ 4.97	$ 4.15
Net Income Per Share – Diluted (in dollars per share)	$ 4.42	$ 4.94	$ 4.12
Average Number Of Shares Outstanding—Basic (in shares)	311.7	307.1	300.4
Average Number Of Shares Outstanding—Diluted (in shares)	312.9	308.8	301.9
Parent Company
Condensed Income Statements,Captions [Line Items]
Equity in earnings of subsidiaries	$ 1,447	$ 1,544	$ 1,254
Other income (deductions), net of taxes	(6)	31	32
Interest expense	(59)	(50)	(41)
NET INCOME	1,382	1,525	1,245
Comprehensive Income	$ 1,392	$ 1,526	$ 1,252
Net Income Per Share – Basic (in dollars per share)	$ 4.43	$ 4.97	$ 4.15
Net Income Per Share – Diluted (in dollars per share)	4.42	4.94	4.12
Dividends Declared Per Share (in dollars per share)	$ 2.86	$ 2.76	$ 2.68
Average Number Of Shares Outstanding—Basic (in shares)	311.7	307.1	300.4
Average Number Of Shares Outstanding—Diluted (in shares)	312.9	308.8	301.9

Schedule I - Condensed Financial Information - Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	$ 1,382	$ 1,525	$ 1,245
Change in Assets:
Taxes receivable	27	15	87
Other – net	(62)	0	69
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,695	3,367	3,459
INVESTING ACTIVITIES
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(5,471)	(3,710)	(4,950)
FINANCING ACTIVITIES
Net proceeds of short-term debt	1,989	(477)	(475)
Issuance of long-term debt	3,030	1,697	2,590
Retirement of long-term debt	(1,938)	(434)	(735)
Debt issuance costs	(61)	(19)	(24)
Issuance of common shares for stock plans	53	51	51
Issuance of common shares - public offering	705	343	702
Common stock dividends	(842)	(803)	(763)
NET CASH FLOWS FROM FINANCING ACTIVITIES	2,938	357	1,345
BALANCE AT BEGINNING OF PERIOD	797
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	895	797
CECONY
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,196	1,104	1,056
Change in Assets:
Other – net	(96)	23	(11)
NET CASH FLOWS FROM OPERATING ACTIVITIES	2,204	2,866	3,038
INVESTING ACTIVITIES
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(3,306)	(3,080)	(2,753)
FINANCING ACTIVITIES
Net proceeds of short-term debt	1,042	(450)	(433)
Issuance of long-term debt	2,740	1,200	1,300
Retirement of long-term debt	(1,836)	0	(650)
Debt issuance costs	(30)	(15)	(13)
NET CASH FLOWS FROM FINANCING ACTIVITIES	1,190	240	(440)
BALANCE AT BEGINNING OF PERIOD	730
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	818	730
Parent Company
Condensed Cash Flow Statements, Captions [Line Items]
Net Income	1,382	1,525	1,245
Equity in earnings of subsidiaries	(1,447)	(1,544)	(1,254)
Change in Assets:
Special deposits	(8)	0	0
Taxes receivable	2	34	87
Other – net	187	21	(152)
NET CASH FLOWS FROM OPERATING ACTIVITIES	1,033	896	723
INVESTING ACTIVITIES
Contributions to subsidiaries	(1,110)	(434)	(691)
Debt receivable from affiliated companies	(825)	0	(900)
NET CASH FLOWS USED IN INVESTING ACTIVITIES	(1,935)	(434)	(1,591)
FINANCING ACTIVITIES
Net proceeds of short-term debt	164	(53)	(53)
Issuance of long-term debt	825	400	900
Retirement of long-term debt	(3)	(402)	(2)
Debt issuance costs	0	(2)	(5)
Issuance of common shares for stock plans	53	51	51
Issuance of common shares - public offering	705	343	702
Common stock dividends	(842)	(803)	(763)
NET CASH FLOWS FROM FINANCING ACTIVITIES	902	(466)	830
NET CHANGE FOR THE PERIOD	0	(4)	(38)
BALANCE AT BEGINNING OF PERIOD	9	13	51
BALANCE AT END OF PERIOD EXCLUDING HELD FOR SALE	9	9	13
Parent Company \| CECONY
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	846	796	744
Parent Company \| O&R
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	46	44	43
Parent Company \| Clean Energy Businesses
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	15	12	10
Parent Company \| Con Edison Transmission
Condensed Cash Flow Statements, Captions [Line Items]
Dividends received	$ 10	$ 8	$ 0

Schedule I - Condensed Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and temporary cash investments	$ 895	$ 797
Taxes receivable	49	76
Prepayments	187	178
Other current assets	122	177
TOTAL CURRENT ASSETS	3,864	3,537
Investments in subsidiaries	1,766	2,001
Goodwill	440	428
Other noncurrent assets	6,541	4,973
TOTAL ASSETS	53,920	48,111	$ 48,255
Current Liabilities
Long-term debt due within one year	650	1,298
Term Loan	825	0
Notes payable	1,741	577
Accounts payable	1,187	1,286
Accrued taxes	61	108
Other current liabilities	363	386
TOTAL CURRENT LIABILITIES	6,207	4,902
Long-term debt	17,495	14,731
Shareholders’ Equity
Equity	16,726	15,418
TOTAL LIABILITIES AND EQUITY	53,920	48,111
Parent Company
Current Assets
Cash and temporary cash investments	9	9	$ 13	$ 51
Taxes receivable	43	45
Term loan receivable from affiliated companies	825	0
Accounts receivable from affiliated companies	536	687
Prepayments	33	36
Other current assets	12	18
TOTAL CURRENT ASSETS	1,458	795
Investments in subsidiaries	16,707	15,110
Goodwill	406	406
Deferred income tax	69	18
Long-term debt receivable from affiliated companies	900	900
Other noncurrent assets	2	2
TOTAL ASSETS	19,542	17,231
Current Liabilities
Long-term debt due within one year	3	2
Term Loan	825	0
Notes payable	495	331
Accounts payable	9	0
Accounts payable to affiliated companies	274	274
Accrued taxes	2	0
Other current liabilities	13	10
TOTAL CURRENT LIABILITIES	1,621	617
Total Liabilities	1,621	617
Long-term debt	1,195	1,195
Shareholders’ Equity
Common stock, including additional paid-in capital	7,151	6,331
Retained earnings	9,575	9,088
Equity	16,726	15,419
TOTAL LIABILITIES AND EQUITY	$ 19,542	$ 17,231

Schedule II - Valuation and Qualifying Accounts (Details) - Allowance For Uncollectible Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 70	$ 83	$ 96
Charged To Costs And Expenses	62	64	63
Charged To Other Accounts	0	0	0
Deductions	64	77	76
Balance At End of Period	68	70	83
CECONY
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	65	78	91
Charged To Costs And Expenses	56	60	57
Charged To Other Accounts	0	0	0
Deductions	60	73	70
Balance At End of Period	$ 61	$ 65	$ 78

General (Details)	12 Months Ended
General (Details)	Dec. 31, 2018 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 - Other Receivables (Details) $ in Millions	Dec. 31, 2018 USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables from third parties related with power restoration	$ 104
CECONY
Accounts, Notes, Loans and Financing Receivable [Line Items]
Receivables from third parties related with power restoration	$ 98

Summary of Significant Accounting Policies and Other Matters - Goodwill (Details)	12 Months Ended
	Dec. 31, 2018 USD ($)
Accounting Policies [Abstract]
Goodwill, impairment charge	$ 0

Summary of Significant Accounting Policies and Other Matters - Recoverable Energy Costs (Details)	12 Months Ended
	Dec. 31, 2018
Minimum
Public Utilities, General Disclosures [Line Items]
Recovery or refund of energy costs, deferral period	1 month
Maximum
Public Utilities, General Disclosures [Line Items]
Recovery or refund of energy costs, deferral period	2 months

Summary of Significant Accounting Policies and Other Matters - Pension and Other Postretirement Benefits (Details)	12 Months Ended
	Dec. 31, 2018
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, 2018
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, 2018	Dec. 31, 2017
Environmental Exit Cost [Line Items]
Remediation costs incurred	$ 25	$ 24
CECONY
Environmental Exit Cost [Line Items]
Remediation costs incurred	$ 18	$ 19

Other Material Contingencies - Manhattan Steam Main Rupture (Details) $ in Millions	Dec. 31, 2018 USD ($)
Property, Damage, Clean Up and Other Costs Related With Manhattan Steam Main Rupture
Loss Contingencies [Line Items]
Loss contingency	$ 14
Capital, Retirement and Other Costs Related with Manhattan Steam Main Rupture
Loss Contingencies [Line Items]
Loss contingency	$ 8

Leases - Schedule of Capital Leases (Details) - Common - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property Subject to or Available for Operating Lease [Line Items]
Utility Plant	$ 1	$ 2
CECONY
Property Subject to or Available for Operating Lease [Line Items]
Utility Plant	$ 1	$ 1

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer out of level 3	$ (2)	$ 11
CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfer out of level 3	(2)	10
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(13)
Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(2)
Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities transferred from Level 3 to Level 2	2
Transfer out of level 3		11
Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities transferred from Level 3 to Level 2	2
Transfer out of level 3		10
Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Derivative liabilities	6
Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	446	453
Derivative liabilities	66	55
Recurring \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	407	414
Recurring \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(6)	(39)
Derivative liabilities	(11)	(52)
Recurring \| Netting Adjustment \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(1)	(7)
Recurring \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	293	288
Derivative liabilities	8	8
Recurring \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	270	263
Recurring \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	152	197
Derivative liabilities	49	93
Recurring \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	137	154
Recurring \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7	7
Derivative liabilities	20	6
Recurring \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	4
Recurring \| Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	43	50
Derivative liabilities	60	55
Recurring \| Commodity \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	31	40
Derivative liabilities	32	44
Recurring \| Commodity \| Netting Adjustment
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(6)	(39)
Derivative liabilities	(11)	(52)
Recurring \| Commodity \| Netting Adjustment \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(1)	(7)
Derivative liabilities	(6)	(18)
Recurring \| Commodity \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	6	5
Derivative liabilities	8	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	5	5
Recurring \| Commodity \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	36	77
Derivative liabilities	43	93
Recurring \| Commodity \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	28	40
Derivative liabilities	30	57
Recurring \| Commodity \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7	7
Derivative liabilities	20	6
Recurring \| Commodity \| Level 3 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	4
Derivative liabilities	3	0
Recurring \| Interest Rate Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2
Derivative liabilities	6	0
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	2
Derivative liabilities	6	0
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	401	403
Recurring \| Other \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	376	374
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	287	283
Recurring \| Other \| Level 1 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	267	260
Recurring \| Other \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	114	120
Recurring \| Other \| Level 2 \| CECONY
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	109	114
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