Document and Entity Information Document - shares	3 Months Ended
Document and Entity Information Document - shares	Mar. 31, 2019	Apr. 30, 2019
Entity Information [Line Items]
Entity Registrant Name	Dominion Energy South Carolina, Inc.
Entity Central Index Key	0000091882
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		40,296,147

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Inventories (at average cost):
Regulatory assets	$ 253	$ 223
Capitalization and Liabilities
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,867	4,315
Current Liabilities:
Regulatory liabilities	262	126
Ratepayer litigation settlement		0
Deferred Credits and Other Liabilities:
Unrecognized Tax Benefits	51	0
Commitments and Contingencies
SCEG
Assets
Utility Plant In Service	12,914	12,803
Accumulated Depreciation and Amortization	(4,694)	(4,581)
Construction Work in Progress	237	350
Nuclear Fuel, Net of Accumulated Amortization	198	211
Utility Plant, Net	8,655	8,783
Nonutility Property and Investments:
Nonutility property, net of accumulated depreciation	72	72
Assets held in trust, net-nuclear decommissioning	199	190
Other investments	0	1
Nonutility Property and Investments, Net	271	263
Current Assets:
Cash and cash equivalents	120	377
Receivables, net of allowance for uncollectible accounts	271	331
Other	43	68
Due from Affiliate, Current	6	359
Inventories (at average cost):
Fuel	96	89
Materials and supplies	159	158
Prepaid Expense	69	82
Other current assets	1	1
Total Current Assets	1,018	1,688
Deferred Debits and Other Assets:
Regulatory Assets, Noncurrent	3,810	4,046
Other	370	183
Total Deferred Debits and Other Assets	4,180	4,229
Total	14,124	14,963
Capitalization and Liabilities
Common Stock, Value, Outstanding	3,535	2,860
Retained Earnings, Unappropriated	151	1,279
Accumulated Other Comprehensive Income (Loss), Net of Tax	(4)	(3)
Stockholders' Equity Attributable to Parent	3,682	4,136
Stockholders' Equity Attributable to Noncontrolling Interest	185	179
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,867	4,315
Long-term Debt, Excluding Current Maturities	3,961	5,132
Total Capitalization	7,828	9,447
Current Liabilities:
Short-term borrowings	0	73
Current portion of long-term debt	14	14
Accounts payable	130	267
Due to Affiliate, Current	623	347
Customer deposits and customer prepayments	74	73
Customer Refund Liability, Current	11	77
Taxes accrued	133	239
Interest accrued	49	72
Ratepayer litigation settlement	158
Other	34	42
Total Current Liabilities	1,488	1,330
Deferred Credits and Other Liabilities:
Deferred Income Tax Liabilities, Net	573	989
Asset retirement obligations	499	542
Pension and other postretirement benefits	234	232
Unrecognized Tax Benefits	38	38
Regulatory Liabilities	3,323	2,264
Other	125	105
Other -affiliate	16	16
Total Deferred Credits and Other Liabilities	4,808	4,186
Total	$ 14,124	$ 14,963

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - SCEG - USD ($) shares in Millions, $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Common Stock, Shares, Outstanding	40.3	40.3
Public Utilities, Property, Plant and Equipment, Net	$ 8,655	$ 8,783
Allowance for Doubtful Accounts Receivable, Current	3	4
Assets, Current	1,018	1,688
Regulated Entity, Other Assets, Noncurrent	4,180	4,229
Variable Interest Entity, Primary Beneficiary [Member]
Public Utilities, Property, Plant and Equipment, Net	697	711
Assets, Current	89	96
Regulated Entity, Other Assets, Noncurrent	$ 37	$ 34

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)	3 Months Ended
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)	Mar. 31, 2019	Mar. 31, 2018
Operating Revenues:
Electric Regulated Revenue	$ (480,000,000)	$ 547,000,000
Electric Domestic Regulated Revenues - Affiliate	1,100	1,200,000
Regulated Operating Revenue, Gas	145,000,000	155,000,000
Regulated Operating Revenue	(335,000,000)	702,000,000
Operating Expenses
Fuel used in electric generation	137,000,000	159,000,000
Fuel used in electric generation, affiliate	33,200	31,300,000
Purchased power	8,000,000	52,000,000
Utilities Operating Expense, Gas and Petroleum Purchased	77,000,000	75,000,000
Other operation and maintenance	105,000,000	102,000,000
Other operation and maintenance, affiliate	48,000,000	44,000,000
Utilities Operating Expense, Impairments	262,000,000	4,000,000
Depreciation and amortization	102,000,000	80,000,000
Other taxes	69,000,000	65,000,000
Total Operating Expenses	808,000,000	581,000,000
Operating Income	(1,143,000,000)	121,000,000
Other Nonoperating Income (Expense)	(5,000,000)	123,000,000
Other Income (Expense):
Other income	4,000,000	126,000,000
Other expense	(10,000,000)	(7,000,000)
Interest Expense	(73,000,000)	(77,000,000)
Income Before Income Tax Expense	(1,221,000,000)	167,000,000
Income Tax Expense	(118,000,000)	39,000,000
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,103,000,000)	128,000,000
Net Income (Loss) Attributable to Noncontrolling Interest	6,000,000	4,000,000
Earnings Available to Common Shareholder	$ (1,109,000,000)	$ 124,000,000

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Allowance for Funds Used During Construction, Capitalized Interest	$ 0	$ 2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income (Loss) Attributable to Parent	$ (1,109)	$ 124
SCEG
Other Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(1,103)	128		$ 262	$ 280
Genco
Other Comprehensive Income (Loss)
Less comprehensive income attributable to noncontrolling interest	(6)		$ (4)	15	10
SCE&G (including Fuel Company)
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	(1,109)	$ 124
Other Comprehensive Income (Loss)
Comprehensive income available to common shareholder	$ (1,109)		$ 124	$ 247	$ 270

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows From Operating Activities:
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (1,103)	$ 128
Adjustments to reconcile net income to net cash provided from operating activities:
Asset Impairment Charges	262	4
Provision for rate credits	985
Deferred Income Tax Expense (Benefit)	(416)	39
Depreciation and amortization	104	84
Amortization of nuclear fuel	14	13
Cash provided (used) by changes in certain assets and liabilities:
Increase (Decrease) in Receivables	68	41
Increase (Decrease) in Due from Affiliates, Current	0	(6)
Increase (Decrease) in Inventories	(23)	(9)
increase (Decrease) in Prepaid Expense	13	8
Increase (Decrease) in Other Regulatory Assets	180	(6)
Increase (Decrease) in Regulatory liabilities	202	(112)
Increase (Decrease ) in Accounts payable	(75)	(15)
Customer Refundable Fees, Revenue Recognized	(66)
Increase (Decrease) in Due to Affiliate, Current	3	(5)
Increase (Decrease) in Taxes accrued	(106)	(150)
Other Operating Activities, Cash Flow Statement	(1)	(4)
Changes in other assets	(128)	(112)
Changes in other liabilities	(36)	95
Net Cash Provided From Operating Activities	(123)	(7)
Cash Flows From Investing Activities:
Property additions and construction expenditures	(120)	(159)
Proceeds from investments (including derivative collateral posted)	7	25
Purchase of investments (including derivative collateral posted)	(10)	(10)
Payments to Acquire Interest in Subsidiaries and Affiliates	0	(111)
Payments for (Proceeds from) Hedge, Financing Activities	0	115
Investment In Affiliate	353	(121)
Net Cash Used For Investing Activities	230	(261)
Proceeds from Issuance of Long-term Debt		100
Cash Flows From Financing Activities:
Repayments of Long-term Debt	(1,210)	(8)
Dividends	(29)	(82)
Short-term borrowings-affiliate,net	273	159
Proceeds from Contributions from Parent	675
Short-term borrowings, net	(73)	(106)
Proceeds from Issuance of Debt	0
Net Cash (Used For) Provided From Financing Activities	(364)	63
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	(257)	(205)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents January 1	377	395
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, March 31	120	190
Noncash Investing and Financing Activities:
Accrued construction expenditures	25	21
Capital Lease Obligations Incurred

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Interest Paid, Capitalized, Investing Activities	$ 0	$ 2

CONSOLIDATED STATEMENTS OF COMMON EQUITY - USD ($) shares in Millions, $ in Millions	Total	SCEG	SCEG excluding VIEs [Member]	SCEG and GENCO [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Retained Earnings, Appropriated			$ 1,982
Accumulated Other Comprehensive Income (Loss)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest				$ 142
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 4,980
Common Stock, Value, Outstanding			$ 2,860
Shares, Outstanding			40
Net Income (Loss) Available to Common Stockholders, Basic			$ 124
Net Income (Loss) Attributable to Noncontrolling Interest	4			4
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	128
Dividends	(74)		(72)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders				(2)
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders				(2)
Retained Earnings, Appropriated			2,034
Accumulated Other Comprehensive Income (Loss)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest				144
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	5,034
Common Stock, Value, Outstanding			$ 2,860
Shares, Outstanding			40
Retained Earnings, Appropriated		$ 1,279	$ 1,279
Accumulated Other Comprehensive Income (Loss)			(3)
Stockholders' Equity Attributable to Noncontrolling Interest		179		179
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	4,315	4,315
Stockholders' Equity Attributable to Parent		4,136
Common Stock, Value, Outstanding		2,860	$ 2,860
Shares, Outstanding			40
Proceeds from Contributions from Parent	675
Net Income (Loss) Available to Common Stockholders, Basic			$ (1,109)
Net Income (Loss) Attributable to Noncontrolling Interest	6			6
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(1,103)
Dividends	(20)		(20)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent			(1,109)
Retained Earnings, Appropriated		151	151
Accumulated Other Comprehensive Income (Loss)			(4)
Stockholders' Equity Attributable to Noncontrolling Interest		185		$ 185
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 3,867	3,867
Stockholders' Equity Attributable to Parent		3,682
Common Stock, Value, Outstanding		$ 3,535	$ 3,535
Shares, Outstanding			40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2019

Significant Accounting Policies

Significant Accounting Policies [Text Block]


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation and Variable Interest Entities

DESC has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, DESC's Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, DESC’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated Financial Statements.

GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to DESC under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of $499 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for DESC’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.

Additionally, DESC purchases shared services from DESS, an affiliated VIE that provides accounting legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DESS as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 13 for amounts attributable to related parties.

Significant Accounting Policies

There have been no significant changes from Note 1 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2018, with the exception of the item described below.

Leases

DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. Rent expense is expensed as incurred over the term of the lease and is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss).

Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of lease renewal options is at DESC's sole discretion. Leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets and DESC has concluded that the renewal of such leases is unlikely. Were such leases to contain renewal options that DESC is reasonably certain will be exercised, the related right-of-use asset and lease liability would be included in the Consolidated Balance Sheets.

The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Consolidated Balance Sheets. For DESC's leased assets, the discount rate implicit in the lease is generally unavailable to be determined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time that most closely corresponds to DESC's lease maturities.

Amortization expense and interest charges associated with finance leases are recorded in depreciation and amortization and interest expense, respectively, in the Consolidated Statement of Comprehensive Income (Loss) or deferred within regulatory assets in the Consolidated Balance Sheets. Costs associated with operating leases, short-term leases and variable leases are primarily recorded in other operations and maintenance expenses in the Consolidated Statements of Comprehensive Income (Loss).

Recently Adopted Accounting Matters

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded $19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 11 for additional information.

RATE AND OTHER REGULATORY MATTERS

3 Months Ended

Mar. 31, 2019

Rate Matters [Line Items]

Schedule of Regulatory Assets and Liabilities [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Other than the items discussed below, which are pending or have been resolved during the period, there have been no changes to the regulatory matters discussed in Note 2 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2018.

Electric - Cost of Fuel

In April 2019, the South Carolina Commission approved DESC’s proposal to decrease the total fuel cost component of retail electric rates. DESC's proposal included maintaining its base fuel component at the current level to produce a projected under-recovered balance of $35 million at the end of the 12-month period beginning with the first billing cycle of May 2019, and requested carrying costs for any base fuel under-collected balances, should they occur. DESC also proposed reducing its variable environmental component and maintaining or reducing its DER components. Changes in rates became effective beginning with the first billing cycle of May 2019.

Electric - Other

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, DESC filed an application with the South Carolina Commission seeking approval to recover $30 million of costs incurred and net lost future revenues associated with these programs, along with an incentive to invest in such programs. In April 2019, the South Carolina Commission approved the request for the rate year beginning with the first billing cycle of May 2019.

Regulatory Assets and Regulatory Liabilities

Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, DESC has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for unrecovered NND Project costs and certain other unrecovered plant costs, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.



Millions of dollars	March 31, 2019		December 31, 2018
Regulatory Assets:
Unrecovered NND Project costs	$	138	$	127
Deferred employee benefit plan costs	16		16
Other unrecovered plant	14		14
DSM programs	16		14
Other	69		52
Regulatory assets - current	253		223
Unrecovered NND Project costs	2,607		2,641
AROs	335		380
Deferred employee benefit plan costs	252		256
Deferred losses on interest rate derivatives	297		442
Other unrecovered plant	76		79
DSM programs	51		51
Environmental remediation costs	23		24
Deferred storm damage costs	34		35
Deferred transmission operating costs	21		15
Other	114		123
Regulatory assets - noncurrent	3,810		4,046
Total Regulatory Assets	$	4,063	$	4,269



Regulatory Liabilities:
Monetization of guaranty settlement	$	67	$	61
Income taxes refundable through future rates	49		52
Reserve for refunds to electric utility customers	137		—
Other	9		13
Regulatory liabilities - current	262		126
Monetization of guaranty settlement	1,020		1,037
Income taxes refundable through future rates	837		607
Asset removal costs	549		541
Deferred gains on interest rate derivatives	70		75
Reserve for refunds to electric utility customers	846		—
Other	1		4
Regulatory liabilities - noncurrent	3,323		2,264
Total Regulatory Liabilities	$	3,585	$	2,390

Regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under GAAP for regulated operations. The South Carolina Commission or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings discussed in Note 10. While such costs are not currently being recovered, management believes they would be allowable under existing rate-making concepts embodied in rate orders or applicable state law and expects to recover these costs through rates in future periods. In the future, as a result of deregulation, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, DESC could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on DESC's financial statements in the period the write-off would be recorded.

Unrecovered NND Project costs reflects expenditures associated with the NND Project, which pursuant to the Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 10 for more information.

AROs represent deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties, excluding amounts related to CCRs. The AROs primarily relate to nuclear decommissioning activities and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 106 years.

Employee benefit plan costs have historically been recovered as they have been recorded under GAAP. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years.

Deferred losses or gains on interest rate derivatives represent (i) the changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065.

Other unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM programs represent deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over five years through an approved rate rider.

Environmental remediation costs are associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 16 years.

Deferred storm damage costs represent storm restoration costs for which DESC expects to receive future recovery through customer rates.

Deferred transmission operating costs includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See also Note 10.

Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.

Monetization of guaranty settlement represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy certain liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 10.

Income taxes refundable through future rates includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See also Note 6.

Reserve for refunds to electric utility customers reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period in connection with the Merger Approval Order. See Note 10.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.

REVENUE RECOGNITION Notes

3 Months Ended

Mar. 31, 2019

Entity Information [Line Items]

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

DESC has disaggregated operating revenues by customer class as follows:



Operating Revenue Disaggregation	Three Months Ended March 31, 2019					Three Months Ended March 31, 2018
Millions of dollars	Electric			Gas		Electric		Gas
Customer class:
Residential	$	(271	)	$	78	$	252	$	86
Commercial	(139		)	38		169		39
Industrial	(82		)	26		85		24
Other	10			3		37		5
Revenues from contracts with customers	(482		)	145		543		154
Other operating revenues	2			—		3		1
Total Operating Revenues	$	(480	)	$	145	$	546	$	155

Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. DESC had contract liability balances of $4 million at March 31, 2019, and $4 million at December 31, 2018. During the three months ended March 31, 2019, DESC recognized as revenue $2 million that was included in contract liabilities as of December 31, 2018. Contract liabilities are recorded in Customer deposits and customer prepayments in the Consolidated Balance Sheets.

COMMON EQUITY	3 Months Ended
COMMON EQUITY	Mar. 31, 2019
SCEG
Common Equity Note [Line Items]
Stockholders' Equity Note Disclosure [Text Block]	uthorized shares of common stock, no par value, were 50 million, of which 40.3 million were issued and outstanding, and DESC's authorized shares of preferred stock, no par value, were 20 million, of which 1,000 shares were issued and outstanding. All outstanding shares of common and preferred stock are held by SCANA. In February 2019, DESC received an equity contribution of $675 million from its parent that was funded by Dominion Energy. DESC used these funds to redeem long-term debt. See Note 5. DESC’s bond indenture under which it issues first mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. DESC's bond indenture permits the payment of dividends on DESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At March 31, 2019 and December 31, 2018, retained earnings of $120 million and $115 million, respectively, were restricted by this requirement as to payment of cash dividends on DESC’s common stock. In addition, pursuant to the Merger Approval Order, the amount of any DESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry.

LONG-TERM AND SHORT-TERM DEBT

3 Months Ended

Mar. 31, 2019

Debt Instrument [Line Items]

Long-term Debt [Text Block]

LONG-TERM AND SHORT-TERM DEBT AND LIQUIDITY

Long-term Debt

In February 2019, DESC launched tender offers for certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price equal to $1.2 billion. DESC incurred a loss on reacquired debt of $187 million in connection with these tender offers, which is recorded in other deferred debits on the Consolidated Balance Sheet.

Substantially all electric utility plant is pledged as collateral in connection with long-term debt.

Liquidity

In March 2019, DESC became a co-borrower under Dominion Energy's $6 billion joint revolving credit facility. DESC's short-term financing is supported through its access to this joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy and certain other of its subsidiaries (co-borrowers), and for other general corporate purposes.

DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, were as follows:



Millions of dollars	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
At March 31, 2019	$	1,000	$	—	$	—

A maximum of $1.0 billion of the facility is available to DESC, less any amounts outstanding to co-borrowers. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At March 31, 2019, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.

Also in March 2019, DESC canceled its previous committed long-term facility which was a revolving line of credit under a credit agreement with a syndicate of banks. This previous credit agreement was used for general corporate purposes, including liquidity support for DESC's commercial paper program and working capital needs, and was set to expire in December 2020.



Millions of dollars	Facility Limit ⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2018	$	1,200	$	73	$	—

⁽¹⁾ Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated.

The weighted-average interest rate of the outstanding commercial paper supported by this credit facility was 3.82% at December 31, 2018.

In April 2019, DESC renewed its FERC authority to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act). DESC may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in April 2019, GENCO renewed its FERC authority to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authorities described herein will expire in April 2020, which reflects a one-year authorization period rather than the two-year period DESC and GENCO had requested. In granting the authorization for a shorter period, FERC cited certain regulatory and legislative proceedings at the state level, as well as certain legal proceedings, arising from the NND Project that could affect DESC's and GENCO's circumstances. Were adverse developments to occur with respect to these uncertainties, the ability of DESC or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted.

DESC is obligated with respect to an aggregate of $68 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.

DESC participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. For the three months ended March 31, 2019, DESC recorded interest income from money pool transactions of $3 million, and for the same period DESC recorded interest expense from money pool transactions of $3 million. Interest income and interest expense for the corresponding period in 2018 were not significant. DESC had outstanding money pool borrowings due to an affiliate of $555 million and no investments due from an affiliate at March 31, 2019. At December 31, 2018 DESC had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million. For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by DESC. On its Consolidated Balance Sheet, DESC includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables.

INCOME TAXES	3 Months Ended
INCOME TAXES	Mar. 31, 2019
income tax [Line Items]
Income Tax Disclosure [Text Block]	6. INCOME TAXES DESC’s effective tax rate for the three months ended March 31, 2019 is 9.7% compared to 23.4% for the three months ended March 31, 2018. Variances in the effective tax rate are primarily driven by charges resulting from the SCANA Combination. In connection with the Merger Approval Order, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. DESC's effective tax rate reflects income tax expense of $198 million in satisfaction of this commitment. In the first quarter, DESC’s unrecognized tax benefits increased by $51 million and income tax expense increased by $40 million related to a state income tax position taken in prior years. It is reasonably possible that this unrecognized tax benefit could be settled in the next twelve months, and as such it is included in taxes accrued on the Consolidated Balance Sheet. As of March 31, 2019, there have been no other material changes in DESC’s unrecognized tax benefits. See Note 6 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of these unrecognized tax benefits and potential changes due to the SCANA Combination. DESC has significant federal and state net operating loss carryforward-related deferred tax assets where the utilization of these tax benefits may be limited in future periods due to the SCANA Combination. For the period ended March 31, 2019, DESC has concluded a valuation allowance is not required on these deferred tax assets. If DESC concludes a valuation allowance is required in future periods, the impact could be material. The 2017 Tax Reform Act limits the deductibility of interest expense to 30% of adjusted taxable income for certain businesses, with any disallowed interest carried forward indefinitely. Subject to additional guidance in yet to be finalized regulations, DESC expects its interest expense to be deductible in 2019.

DERIVATIVE FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2019

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

7. DERIVATIVE FINANCIAL INSTRUMENTS

Derivative assets and liabilities are presented gross on the Consolidated Balance Sheets and are measured at fair value. See Note 8 for further information about fair value measurements and associated valuation methods for derivatives. Derivative contracts include over-the-counter transactions, which are bilateral contracts that are transacted directly with a third party. In general, most over-the-counter transactions are subject to collateral requirements.

Pursuant to regulatory orders, interest rate derivatives entered into by DESC after October 2013 have not been designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the South Carolina Commission. See Note 14 regarding the settlement gains realized in the first quarter of 2018.

The table below presents derivative balances by type of financial instrument, if the gross amounts recognized in the Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:



	March 31, 2019								December 31, 2018
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	14	$	—	$	14	$	—	$	11	$	—	$	11	$	—
Total derivatives	$	14	$	—	$	14	$	—	$	11	$	—	$	11	$	—

Volumes

The following table presents the volume of derivative activity at March 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions.



	Current		Noncurrent
Interest rate ⁽¹⁾	$	—	$	71,400,000

⁽¹⁾Maturity is determined based on final settlement period.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of derivatives and where they are presented in the Consolidated Balance Sheets:



(millions)	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
At March 31, 2019
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities ⁽¹⁾	1		—		1
Noncurrent Liabilities
Interest rate	9		4		13
Total noncurrent derivative liabilities ⁽²⁾	9		4		13
Total derivative liabilities	$	10	$	4	$	14

At December 31, 2018
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities ⁽¹⁾	1		—		1
Noncurrent Liabilities
Interest rate	7		3		10
Total noncurrent derivative liabilities ⁽²⁾	7		3		10
Total derivative liabilities	$	8	$	3	$	11

⁽¹⁾ Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets.

⁽²⁾ Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the Consolidated Balance Sheets.

The following tables present the gains and losses on derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Comprehensive Income (Loss):



Derivatives in Cash Flow Hedging Relationships	Increase (Decrease) in Derivatives Subject to Regulatory Treatment ⁽¹⁾
(millions)
Three Months Ended March 31, 2019
Derivative type and location of gains (losses):
Interest rate	$	(2	)
Total	$	(2	)

Three Months Ended March 31, 2018
Derivative type and location of gains (losses):
Interest rate	$	2
Total	$	2

⁽¹⁾ Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).



Derivatives Not designated as Hedging Instruments
(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment ⁽¹⁾						Amount of Gain (Loss) Recognized in Income on Derivatives ⁽²⁾
Three months ended March 31,	2019			2018		Location	2019		2018
Derivative type and location of gains (losses):
Interest rate contracts	$	(1	)	$	65	Other Income	$	—	$	115
Total	$	(1	)	$	65	Other Income	$	—	$	115

⁽¹⁾Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

⁽²⁾Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Income (Loss).

Credit Risk Considerations

Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.



Derivative Contracts with Credit Contingent Features
(millions)	March 31, 2019		December 31, 2018
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	14	$	11
Fair value of collateral already posted	14		11
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	—	$	—

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

3 Months Ended

Mar. 31, 2019

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Disclosures [Text Block]

8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of DESC’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). DESC applies fair value measurements to interest rate assets and liabilities. DESC’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. DESC applies credit adjustments to its derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information, DESC considers the ability to transact at the quoted price. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party sources.

The inputs and assumptions used in measuring fair value for interest rate derivative contracts include the following:


•	Interest rate curves


•	Credit quality of counterparties and DESC


•	Notional value


•	Credit enhancements


•	Time value

Levels

DESC utilizes the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:


•	Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date.

•

Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include interest rate swaps.


•	Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy.

All of DESC's interest rate swap agreements were in a liability position for all periods presented. Such agreements are valued using discounted cash flow models with independently sourced data, and are considered to be Level 2 fair value measurements. The fair value of these derivatives at March 31, 2019 was $14 million, and at December 31, 2018 was $11 million.

Fair Value of Financial Instruments

Substantially all of DESC’s financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of financial instruments classified within current assets and current liabilities are representative of fair value because of the short-term nature of these instruments. For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:



	March 31, 2019				December 31, 2018
(millions)	Carrying Amount		Estimated Fair Value ⁽¹⁾		Carrying Amount		Estimated Fair Value ⁽¹⁾
Long-term debt ⁽²⁾	$	3,975	$	4,567	$	5,146	$	5,470

⁽¹⁾

Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.


⁽²⁾	Carrying amount includes amounts which represent the unamortized debt issuance costs and discount or premium.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

EMPLOYEE BENEFIT PLANS

3 Months Ended

Mar. 31, 2019

Pension and Other Postretirement Benefit Plans

Pension and Other Postretirement Benefits Disclosure [Text Block]

9. EMPLOYEE BENEFIT PLANS

Components of net periodic benefit cost recorded by DESC were as follows:



Millions of dollars	Pension Benefits						Other Postretirement Benefits
Three months ended March 31,	2019			2018			2019		2018
Service cost	$	4		$	4		$	1	$	1
Interest cost	8			7			2		2
Expected return on assets	(10		)	(12		)	—		—
Amortization of actuarial losses	4			3			—		—
Net periodic benefit cost	$	6		$	2		$	3	$	3

No significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. DESC recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations.

Voluntary Retirement Program

In March 2019, Dominion Energy announced a voluntary retirement program to employees, including employees of DESC, that meet certain age and service requirements. DESC expects to incur a charge in the second quarter of 2019 as determinations are made concerning the number of employees that elect to participate in the program. The voluntary retirement program will not compromise safety or DESC's ability to comply with applicable laws and regulations. While DESC is unable to estimate the amount, the charge could be material to DESC's results of operations and financial condition.

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2019

Statement [Line Items]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Abandoned NND Project

A description of events and circumstances leading up to DESC's abandonment of the NND Project and subsequent regulatory, legislative, legal and investigative proceedings, as well as related impairments of NND Project and other costs are described in Note 11 in DESC's Annual Report on Form 10-K for the year ended December 31, 2018.

Merger Approval Order

In accordance with the terms of the South Carolina Commission's Merger Approval Order, DESC adopted the Plan-B Levelized Customer Benefits Plan, effective February 2019, whereby the average bill for a DESC residential electric customer approximates that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the South Carolina Commission in August 2018. DESC also recorded a significant impairment charge in the fourth quarter of 2018, which charge resulted from its conclusion that NND Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed. In addition, in the first quarter of 2019, DESC has recorded the following charges and liabilities which arose from or are related to provisions in the Merger Approval Order.


•	A charge of $105 million ($79 million net of tax) related to certain assets that had been constructed in connection with the NND Project for which DESC committed to forgo recovery.

•

A regulatory liability for refunds and restitution of amounts previously collected from retail electric customers of $1.0 billion pre-tax ($756 million net of tax), recorded as a reduction in operating revenue, which will be credited to customers over an estimated 11 years. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2.


•	A regulatory liability for refunds to natural gas customers totaling $2 million pre-tax ($2 million net of tax).


•	A tax charge of $198 million related to $264 million of regulatory assets for which DESC committed to forgo recovery.

Further, except for rate adjustments for fuel and environmental costs, DSM costs, and other rates routinely adjusted on an annual or biannual basis, DESC will freeze retail electric base rates at current levels until January 1, 2021.

The South Carolina Commission order also approved the removal of DESC's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of March 31, 2019, such investment in these assets included $334 million within utility plant, net and $21 million within regulatory assets, which amount represents certain deferred operating costs. The South Carolina Commission approved deferral of these operating costs related to the investment until recovery of the transmission capital costs and associated deferred operating costs is addressed in a future rate proceeding. DESC believes these transmission capital and deferred operating costs are probable of recovery; however, if the South Carolina Commission were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equal to the disallowed costs may be required.

Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. In January 2019, the South Carolina Commission issued an order (1) granting the request of various parties and finding that DESC was imprudent in its actions by not disclosing material information to the ORS and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The deadline to appeal the Merger Approval Order and the order on rehearing expired in April 2019, and no party has sought appeal.

Contractor Bankruptcy Proceedings and Related Uncertainties

WEC’s reorganization plan became effective August 1, 2018. Initially, WEC had projected that its reorganization plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the NND Project and have filed liens on related property in Fairfield County, South Carolina. DESC is contesting approximately$285 million of such filed liens. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy. It is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. In addition, payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, DESC and Santee Cooper, each in its pro rata share, would be required to make Citibank, which purchased the scheduled payments under the Toshiba Settlement, whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for DESC's 55% share).

DESC and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the NND Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. DESC does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. DESC intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, DESC may be responsible for paying its 55% share thereof.

Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the NND Project site. While DESC cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims DESC is presently disputing, DESC believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, DESC may be responsible for paying its 55% share thereof.

Claims and Litigation

Ratepayer Class Actions

In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the DESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that DESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that DESC committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that DESC may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and DESC’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the DESC Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provided that SCANA and DESC would establish an escrow account and proceeds from the escrow account would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain DESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the DESC Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and DESC funded the cash payment portion of the escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the escrow account is subject to court approval. As a result, in the first quarter of 2019, DESC recorded a charge of $157 million ($118 million after-tax), reflected in impairment of assets and other charges in the Consolidated Statements of Comprehensive Income (Loss).

In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the DESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against DESC. This case is pending. DESC cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, DESC and certain former executive officers in the U.S. District Court for the District of South Carolina. The plaintiff alleges, among other things, that SCANA, DESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The DESC Ratepayer Class Action settlement described previously contemplates dismissal of claims by DESC ratepayers in this case against DESC, SCANA and their officers. This case is pending. DESC cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Merger Action

In February 2018, a purported class action was filed against certain former directors of SCANA and DESC and Dominion Energy in the State Court of Common Pleas in Richland County, South Carolina (the Metzler Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with another lawsuit regarding the Merger Agreement to which DESC is not a party. This case is pending. DESC cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the U.S. District Court for the District of South Carolina was certified as a class action on behalf of persons who were formerly employed at the NND Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment and are seeking damages, which are estimated to be as much as $75 million. DESC as co-owner of the NND Project would have a 55% proportional share in any damages owed upon the ultimate outcome. The ultimate loss could rise due to the Fluor defendants seeking indemnification from DESC.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against DESC and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.

FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against DESC in the State Court of Common Pleas in Fairfield County, South Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to DESC’s termination of the FILOT agreement between DESC and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. DESC is currently unable to make an estimate of the potential impacts to its Consolidated Financial Statements related to this matter. This case is pending.

Governmental Proceedings and Investigations

In June 2018, DESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of DESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that DESC’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. DESC has protested the proposed assessment, which remains pending, and recorded a $20 million liability in its Consolidated Balance Sheet as of March 31, 2019.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and DESC. These matters are pending. SCANA and DESC are cooperating fully with the investigations, including responding to additional subpoenas and document requests; however, DESC cannot currently predict whether or to what extent it may incur a material liability.

Other Litigation

In December 2018, arbitration proceedings commenced between DESC and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which DESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that DESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. DESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. DESC cannot determine the outcome or timing of this matter.

Nuclear Insurance

Under Price-Anderson, DESC (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Summer. Price-Anderson provides funds up to $14.0 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to $138 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $21 million of the liability per reactor would be assessed per year. DESC’s maximum assessment, based on its two-thirds ownership of Summer, would be $92 million per incident, but not more than $14 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

DESC currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. The NEIL policies in aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. The NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, DESC’s portion of the retrospective premium assessment would not exceed $23 million. DESC currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, DESC's portion of the retrospective premium assessment would not exceed $2 million.

To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Summer exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that DESC's rates would not recover the cost of any purchased replacement power, DESC will retain the risk of loss as a self-insurer. DESC has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on DESC's results of operations, cash flows and financial position.

Environmental

In August 2018, the EPA proposed the ACE rule which would replace the CPP. The EPA had proposed in 2017 to replace the CPP on the grounds that it exceeded the EPA’s statutory authority and in response to federal court proceedings and an Executive Order. If implemented, the proposed ACE rule would define the “best system of emission reduction” for GHG emissions from existing power plants as on-site, heat-rate efficiency improvements; provide states with a list of “candidate technologies” that can be used to establish standards of performance and incorporated into their state plans; update the EPA’s NSR permitting program to incentivize efficiency improvements at existing power plants; and align CAA section 111(d) general implementing regulations to give states adequate time and flexibility to develop their state plans. DESC is currently evaluating the ACE rule for potential impact at its coal fired units and expects any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO₂and NO_X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO₂ emissions and annual and ozone season NO_X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO₂and NO_X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that DESC and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In December 2018, the EPA issued a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule promulgated in 2012 rule and containing new standards for mercury and other specified air pollutants would remain in place as the EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and is not expected to have an impact on DESC or GENCO due to plant retirements, conversions, and enhancements. DESC and GENCO are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule was final in September 2015, after which state regulators are required to modify facility NPDES permits to match more restrictive standards, which would require facilities to retrofit with new wastewater treatment technologies. Compliance dates varied by type of wastewater, and some were based on a facility's five-year permit cycle and thus could range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The EPA has decided to conduct a new rulemaking that could result in revisions to certain flue gas desulfurization wastewater and bottom ash transport water requirements in the ELG Rule. Accordingly, in September 2017 the EPA finalized a rule that postpones compliance dates under the ELG Rule to a range from November 2020 to December 2023. The EPA indicates that the new rulemaking process may take up to three years to complete, such that any revisions to the ELG Rule likely would not be final until the summer of 2020. While DESC expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations, any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.

The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. DESC and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.

The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at certain of DESC's and GENCO's coal-fired generating facilities. DESC and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. DESC does not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.

DESC is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by or under review by SCDHEC and the EPA. DESC anticipates that major remediation activities at all of these sites will continue at least through 2022 and will cost an additional $10 million. In February 2019 SCDHEC directed DESC to pursue a stakeholder-developed modified removal action plan for one site (Congaree River). DESC is developing an engineering design for this plan, which would require permits from the USACE and others and further approvals before it could be implemented. If DESC receives the necessary permits and approvals for this plan, remediation cost for the Congaree River site would increase by $8 million. DESC cannot predict if or when such permits or approvals will be received. Major remediation activities are accrued in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. DESC expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2019, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24 million and are included in regulatory assets.

LEASES (Notes)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases of Lessee Disclosure [Text Block]

LEASES

At March 31, 2019, DESC had the following lease assets and liabilities recorded in the Consolidated Balance Sheets:



Millions of dollars	March 31, 2019
Lease assets:
Operating lease assets ⁽¹⁾	$	19
Finance lease assets ⁽²⁾	29
Total lease assets	$	48
Lease liabilities:
Operating lease - current ⁽³⁾	$	2
Operating lease - noncurrent ⁽⁴⁾	15
Finance lease - current ⁽⁵⁾	7
Finance lease - noncurrent ⁽⁶⁾	22
Total lease liabilities	$	46

⁽¹⁾ Included in other deferred debits and other assets in the Consolidated Balance Sheets.

⁽²⁾ Included in utility plant, net, in the Consolidated Balance Sheets, net of $18 million of accumulated amortization at March 31, 2019.

⁽³⁾ Included in other current liabilities in the Consolidated Balance Sheets.

⁽⁴⁾ Included in other deferred credits and other liabilities in the Consolidated Balance Sheets.

⁽⁵⁾ Included in current portion of long-term debt in the Consolidated Balance Sheets.

⁽⁶⁾ Included in long-term debt in the Consolidated Balance Sheets.

For the three months ended March 31, 2019, total lease cost consisted of the following:



Millions of dollars	Three Months Ended March 31, 2019
Finance lease cost:
Amortization	$	2
Interest	—
Operating lease cost	1
Short-term lease cost	—
Variable lease cost	—
Total lease cost	$	3

For the three months ended March 31, 2019, cash paid for amounts included in the measurement of lease liabilities consisted of the following amounts, included in the Consolidated Statements of Cash Flows:



Millions of dollars	Three Months Ended March 31, 2019
Operating cash flows from finance leases	$	—
Operating cash flows from operating leases	1
Financing cash flows from finance leases	2

At March 31, 2019, the weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows:



	March 31, 2019
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	23 years
Weighted average discount rate - finance leases	2.91	%
Weighted average discount rate - operating leases	4.22	%

Lease liabilities have the following scheduled maturities:



Millions of dollars	Operating			Finance
2019	$	2		$	6
2020	1			7
2021	1			6
2022	1			4
2023	1			3
After 2023	23			5
Total undiscounted lease payments	29			31
Present value adjustment	(12		)	(2		)
Present value of lease liabilities	$	17		$	29

SEGMENT OF BUSINESS INFORMATION

3 Months Ended

Mar. 31, 2019

Segment Reporting Information [Line Items]

Segment Reporting Disclosure [Text Block]

SEGMENTS

Operating segments include Electric Operations and Gas Distribution and are organized primarily on the basis of products and services sold.

In connection with the SCANA Combination, effective January 2019, reportable segments were changed to include a Corporate and Other segment and to utilize comprehensive income (loss) as the measure of segment profitability. The Corporate and Other segment includes specific items attributable to DESC's operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources. Corresponding amounts in prior periods have been recast to conform to the current presentation.



Millions of dollars	External Revenue			Comprehensive Income (Loss) Available (Attributable) to Common Shareholder
Three Months Ended March 31, 2019
Electric Operations	$	527		48
Gas Distribution	147			22
Corporate and Other	(1,009		)	$	(1,173	)
Adjustments/Eliminations	—			(6		)
Consolidated Total	$	(335	)	$	(1,109	)

Three Months Ended March 31, 2018
Electric Operations	$	547		$	100
Gas Distribution	155			32
Corporate and Other	—			(4		)
Adjustments/Eliminations	—			(4		)
Consolidated Total	$	702		$	124

The items in Corporate and Other primarily relate to charges arising from the Merger Approval Order, as described in Note 10.

AFFILIATED TRANSACTIONS

3 Months Ended

Mar. 31, 2019

AFFILIATED TRANSACTIONS

DESC owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions at certain of DESC's generating facilities. DESC accounts for this investment using the equity method. Purchases and sales of the related coal are recorded as Other Income (Expense), net on the Consolidated Statements of Comprehensive Income (Loss).

DESC purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. to serve its retail gas customers and to satisfy certain electric generation requirements. These purchases are included within fuel used in electric generation on the Consolidated Statements of Comprehensive Income (Loss).

DESS, on behalf of itself and its parent company, provides the following services to DESC, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, DESS processes and pays invoices for DESC and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operation and maintenance - affiliated suppliers and Other Income (Expense), net on the Consolidated Statements of Comprehensive Income (Loss).



	Three Months Ended March 31,
Millions of Dollars	2019		2018
Purchases of coal from affiliate	$	28	$	33
Sales of coal to affiliate	28		32
Purchases of fuel used in electric generation from affiliate	33		31
Direct and allocated costs from services company affiliate⁽¹⁾	58		59
Operating Revenues - Electric from sales to affiliate	1		1
Operating Expenses - Other taxes from affiliate	2		2

⁽¹⁾ Includes capitalized expenditures of $9 million and $8 million for the three months ended March 31, 2019 and 2018, respectively.



Millions of Dollars	March 31, 2019		December 31, 2018
Receivable from Canadys Refined Coal, LLC	$	5	$	7
Payable to Canadys Refined Coal, LLC	5		7
Payable to SCANA Energy Marketing, Inc.	11		14
Payable to DESS	41		38

In connection with the SCANA Combination, purchases from certain entities owned by Dominion Energy became affiliated transactions. During the three months ended March 31, 2019, DESC purchased electricity generated by two such affiliates, Ridgeland Solar Farm I, LLC and Moffett Solar 1, LLC, totaling $1 million, which is recorded as Purchased power in the Statement of Comprehensive Income (Loss). At March 31, 2019, DESC had accounts payable balances to these affiliates totaling $1 million. In addition, during the three months ended March 31, 2019, DESC incurred demand and transportation charges from Dominion Energy Carolina Gas Transmission, LLC totaling $15 million, of which $11 million is recorded as Fuel used in electric generation and $4 million is recorded as Gas purchased for resale in the Statements of Comprehensive Income (Loss). At March 31, 2019, DESC had an accounts payable balance due to this affiliate totaling $6 million.

Borrowings from an affiliate are described in Note 5.

OTHER INCOME (EXPENSE), NET Notes

3 Months Ended

Mar. 31, 2019

Condensed Income Statements, Captions [Line Items]

Other Income and Other Expense Disclosure [Text Block]

OTHER INCOME (EXPENSE), NET

Components of other income (expense), net are as follows:



	Three Months Ended
	March 31,
Millions of dollars	2019			2018
Revenues from contracts with customers	$	1		$	1
Other income	4			126
Other expense	(10		)	(7		)
Allowance for equity funds used during construction	—			3
Other income (expense), net	$	(5	)	$	123

Other income in 2018 includes gains from the settlement of interest rate derivatives of $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in other expense.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Mar. 31, 2019
Significant Accounting Policies
Basis Of Consolidation And Variable Interest Entities [Policy Text Block]	Basis of Consolidation and Variable Interest Entities DESC has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, DESC's Consolidated Financial Statements include, after eliminating intercompany balances and transactions, the accounts of DESC, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, DESC’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated Financial Statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to DESC under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of $499 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for DESC’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Additionally, DESC purchases shared services from DESS, an affiliated VIE that provides accounting legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of DESS as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 13 for amounts attributable to related parties. Significant Accounting Policies There have been no significant changes from Note 1 to the Consolidated Financial Statements in DESC's Annual Report on Form 10-K for the year ended December 31, 2018, with the exception of the item described below. Leases DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. Rent expense is expensed as incurred over the term of the lease and is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss). Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of lease renewal options is at DESC's sole discretion. Leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets and DESC has concluded that the renewal of such leases is unlikely. Were such leases to contain renewal options that DESC is reasonably certain will be exercised, the related right-of-use asset and lease liability would be included in the Consolidated Balance Sheets.
Lessee, Leases [Policy Text Block]	Leases DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. Rent expense is expensed as incurred over the term of the lease and is primarily recorded in other operations and maintenance expense in the Consolidated Statements of Comprehensive Income (Loss). Certain leases include one or more options to renew, with renewal terms that can extend the lease from one to 70 years. The exercise of lease renewal options is at DESC's sole discretion. Leases with original lease terms of one year or less are not included in the Consolidated Balance Sheets and DESC has concluded that the renewal of such leases is unlikely. Were such leases to contain renewal options that DESC is reasonably certain will be exercised, the related right-of-use asset and lease liability would be included in the Consolidated Balance Sheets. The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the Consolidated Balance Sheets. For DESC's leased assets, the discount rate implicit in the lease is generally unavailable to be determined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the calculation of the present value of the lease liability. The incremental borrowing rates are determined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time that most closely corresponds to DESC's lease maturities. Amortization expense and interest charges associated with finance leases are recorded in depreciation and amortization and interest expense, respectively, in the Consolidated Statement of Comprehensive Income (Loss) or deferred within regulatory assets in the Consolidated Balance Sheets. Costs associated with operating leases, short-term leases and variable leases are primarily recorded in other operations and maintenance expenses in the Consolidated Statements of Comprehensive Income (Loss).

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATION (Tables)	3 Months Ended
	Mar. 31, 2019
Condensed Statement of Income Captions [Line Items]
Reclassifications [Text Block]	equires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged. The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded $19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 11 for additional information.

RATE AND OTHER REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2019

Public Utilities, General Disclosures [Line Items]

Schedule of Regulatory Assets [Table Text Block]



Millions of dollars	March 31, 2019		December 31, 2018
Regulatory Assets:
Unrecovered NND Project costs	$	138	$	127
Deferred employee benefit plan costs	16		16
Other unrecovered plant	14		14
DSM programs	16		14
Other	69		52
Regulatory assets - current	253		223
Unrecovered NND Project costs	2,607		2,641
AROs	335		380
Deferred employee benefit plan costs	252		256
Deferred losses on interest rate derivatives	297		442
Other unrecovered plant	76		79
DSM programs	51		51
Environmental remediation costs	23		24
Deferred storm damage costs	34		35
Deferred transmission operating costs	21		15
Other	114		123
Regulatory assets - noncurrent	3,810		4,046
Total Regulatory Assets	$	4,063	$	4,269

Schedule of Regulatory Liabilities [Table Text Block]



Regulatory Liabilities:
Monetization of guaranty settlement	$	67	$	61
Income taxes refundable through future rates	49		52
Reserve for refunds to electric utility customers	137		—
Other	9		13
Regulatory liabilities - current	262		126
Monetization of guaranty settlement	1,020		1,037
Income taxes refundable through future rates	837		607
Asset removal costs	549		541
Deferred gains on interest rate derivatives	70		75
Reserve for refunds to electric utility customers	846		—
Other	1		4
Regulatory liabilities - noncurrent	3,323		2,264
Total Regulatory Liabilities	$	3,585	$	2,390

REVENUE RECOGNITION Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2019

Disaggregation of Revenue [Table Text Block]



Operating Revenue Disaggregation	Three Months Ended March 31, 2019					Three Months Ended March 31, 2018
Millions of dollars	Electric			Gas		Electric		Gas
Customer class:
Residential	$	(271	)	$	78	$	252	$	86
Commercial	(139		)	38		169		39
Industrial	(82		)	26		85		24
Other	10			3		37		5
Revenues from contracts with customers	(482		)	145		543		154
Other operating revenues	2			—		3		1
Total Operating Revenues	$	(480	)	$	145	$	546	$	155

LONG-TERM AND SHORT-TERM DEBT (Tables)

3 Months Ended

12 Months Ended

Mar. 31, 2019

Dec. 31, 2018

Short-term Debt [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]



Millions of dollars	Facility Limit		Outstanding Commercial Paper		Outstanding Letters of Credit
At March 31, 2019	$	1,000	$	—	$	—



Millions of dollars	Facility Limit ⁽¹⁾		Outstanding Commercial Paper		Outstanding Letters of Credit
At December 31, 2018	$	1,200	$	73	$	—

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2019

Derivative [Line Items]

Schedule of Derivative Instruments [Table Text Block]



	Current		Noncurrent
Interest rate ⁽¹⁾	$	—	$	71,400,000

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]



(millions)	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
At March 31, 2019
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities ⁽¹⁾	1		—		1
Noncurrent Liabilities
Interest rate	9		4		13
Total noncurrent derivative liabilities ⁽²⁾	9		4		13
Total derivative liabilities	$	10	$	4	$	14

At December 31, 2018
Current Liabilities
Interest rate	$	1	$	—	$	1
Total current derivative liabilities ⁽¹⁾	1		—		1
Noncurrent Liabilities
Interest rate	7		3		10
Total noncurrent derivative liabilities ⁽²⁾	7		3		10
Total derivative liabilities	$	8	$	3	$	11

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]



Derivatives in Cash Flow Hedging Relationships	Increase (Decrease) in Derivatives Subject to Regulatory Treatment ⁽¹⁾
(millions)
Three Months Ended March 31, 2019
Derivative type and location of gains (losses):
Interest rate	$	(2	)
Total	$	(2	)

Three Months Ended March 31, 2018
Derivative type and location of gains (losses):
Interest rate	$	2
Total	$	2

Derivatives Not Designated as Hedging Instruments [Table Text Block]



Derivatives Not designated as Hedging Instruments
(millions)	Increase (Decrease) in Derivatives Subject to Regulatory Treatment ⁽¹⁾						Amount of Gain (Loss) Recognized in Income on Derivatives ⁽²⁾
Three months ended March 31,	2019			2018		Location	2019		2018
Derivative type and location of gains (losses):
Interest rate contracts	$	(1	)	$	65	Other Income	$	—	$	115
Total	$	(1	)	$	65	Other Income	$	—	$	115

Disclosure of Credit Derivatives [Table Text Block]



Derivative Contracts with Credit Contingent Features
(millions)	March 31, 2019		December 31, 2018
in Net Liability Position
Aggregate fair value of derivatives in net liability position	$	14	$	11
Fair value of collateral already posted	14		11
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered	$	—	$	—

Offsetting Liabilities [Table Text Block]



	March 31, 2019								December 31, 2018
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
(millions)	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
Interest rate contracts:
Over-the-counter	$	14	$	—	$	14	$	—	$	11	$	—	$	11	$	—
Total derivatives	$	14	$	—	$	14	$	—	$	11	$	—	$	11	$	—

- 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

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2019

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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



	March 31, 2019				December 31, 2018
(millions)	Carrying Amount		Estimated Fair Value ⁽¹⁾		Carrying Amount		Estimated Fair Value ⁽¹⁾
Long-term debt ⁽²⁾	$	3,975	$	4,567	$	5,146	$	5,470

⁽¹⁾

Fair value is estimated based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.


⁽²⁾	Carrying amount includes amounts which represent the unamortized debt issuance costs and discount or premium.

EMPLOYEE BENEFIT PLANS (Tables)

3 Months Ended

Mar. 31, 2019

Pension and Other Postretirement Benefit Plans

Schedule of Net Benefit Costs [Table Text Block]



Millions of dollars	Pension Benefits						Other Postretirement Benefits
Three months ended March 31,	2019			2018			2019		2018
Service cost	$	4		$	4		$	1	$	1
Interest cost	8			7			2		2
Expected return on assets	(10		)	(12		)	—		—
Amortization of actuarial losses	4			3			—		—
Net periodic benefit cost	$	6		$	2		$	3	$	3

LEASES (Tables)

3 Months Ended

Mar. 31, 2019

Schedule Of Lease Assets and Liabilities Recorded in Consolidated Balance Sheets [Table Text Block]



Millions of dollars	March 31, 2019
Lease assets:
Operating lease assets ⁽¹⁾	$	19
Finance lease assets ⁽²⁾	29
Total lease assets	$	48
Lease liabilities:
Operating lease - current ⁽³⁾	$	2
Operating lease - noncurrent ⁽⁴⁾	15
Finance lease - current ⁽⁵⁾	7
Finance lease - noncurrent ⁽⁶⁾	22
Total lease liabilities	$	46

Lease, Cost [Table Text Block]



Millions of dollars	Three Months Ended March 31, 2019
Finance lease cost:
Amortization	$	2
Interest	—
Operating lease cost	1
Short-term lease cost	—
Variable lease cost	—
Total lease cost	$	3

Summary of Cash Paid For Amounts Included In Measurement of Lease Liabilities In Consolidated Statements of Cash Flows [Table Text Block]



Millions of dollars	Three Months Ended March 31, 2019
Operating cash flows from finance leases	$	—
Operating cash flows from operating leases	1
Financing cash flows from finance leases	2

Summary of Weighted Average Remaining Lease Term And Discount Rate for Operating and Finance Leases [Table Text Block]



	March 31, 2019
Weighted average remaining lease term - finance leases	5 years
Weighted average remaining lease term - operating leases	23 years
Weighted average discount rate - finance leases	2.91	%
Weighted average discount rate - operating leases	4.22	%

Schedule of Maturity Analysis of Operating and Finance Lease Liabilities [Table Text Block]



Millions of dollars	Operating			Finance
2019	$	2		$	6
2020	1			7
2021	1			6
2022	1			4
2023	1			3
After 2023	23			5
Total undiscounted lease payments	29			31
Present value adjustment	(12		)	(2		)
Present value of lease liabilities	$	17		$	29

SEGMENT OF BUSINESS INFORMATION (Tables)

3 Months Ended

Mar. 31, 2019

Segment Reporting Information [Line Items]

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



Millions of dollars	External Revenue			Comprehensive Income (Loss) Available (Attributable) to Common Shareholder
Three Months Ended March 31, 2019
Electric Operations	$	527		48
Gas Distribution	147			22
Corporate and Other	(1,009		)	$	(1,173	)
Adjustments/Eliminations	—			(6		)
Consolidated Total	$	(335	)	$	(1,109	)

Three Months Ended March 31, 2018
Electric Operations	$	547		$	100
Gas Distribution	155			32
Corporate and Other	—			(4		)
Adjustments/Eliminations	—			(4		)
Consolidated Total	$	702		$	124

The items in Corporate and Other primarily relate to charges arising from the Merger Approval Order, as described in Note 10.

AFFILIATED TRANSACTIONS Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2019



	Three Months Ended March 31,
Millions of Dollars	2019		2018
Purchases of coal from affiliate	$	28	$	33
Sales of coal to affiliate	28		32
Purchases of fuel used in electric generation from affiliate	33		31
Direct and allocated costs from services company affiliate⁽¹⁾	58		59
Operating Revenues - Electric from sales to affiliate	1		1
Operating Expenses - Other taxes from affiliate	2		2

⁽¹⁾ Includes capitalized expenditures of $9 million and $8 million for the three months ended March 31, 2019 and 2018, respectively.



Millions of Dollars	March 31, 2019		December 31, 2018
Receivable from Canadys Refined Coal, LLC	$	5	$	7
Payable to Canadys Refined Coal, LLC	5		7
Payable to SCANA Energy Marketing, Inc.	11		14
Payable to DESS	41		38

OTHER INCOME (EXPENSE), NET Other Income (Expense) (Tables)

3 Months Ended

Mar. 31, 2018

Schedule of Other Nonoperating Income (Expense) [Table Text Block]



	Three Months Ended
	March 31,
Millions of dollars	2019			2018
Revenues from contracts with customers	$	1		$	1
Other income	4			126
Other expense	(10		)	(7		)
Allowance for equity funds used during construction	—			3
Other income (expense), net	$	(5	)	$	123

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - Genco $ in Millions	Mar. 31, 2019 USD ($) MW
Power Generation Capacity Megawatts \| MW	605
Property, Plant and Equipment, Net \| $	$ 499

RATE AND OTHER REGULATORY MATTERS (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Rate Matters [Line Items]
Deferred Tax Asset, Deferred Fuel Cost	$ 35
Accrual Term for Nuclear Refueling Charges	20
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Refund to Customer Related to Tax Act	$ 137
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount	30
Customer Refundable Fees, Refund Payments, Post Merger	$ (985)
Environmental Restoration Costs [Member]
Rate Matters [Line Items]
MPG environmental remediation	16

RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($)	3 Months Ended
RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($)	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Regulatory Assets
Regulatory Liability, Current	$ 262,000,000		$ 126,000,000
Refund to Customer Related to Tax Act	137,000,000
Regulatory Assets, Current	253,000,000		223,000,000
Asset Impairment Charges	262,000,000	$ 4,000,000
Assets for Plan Benefits, Defined Benefit Plan	11
SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	3,323,000,000		2,264,000,000
Regulatory Assets, Noncurrent	3,810,000,000		4,046,000,000
Regulatory Assets	4,063,000,000		4,269,000,000
Regulatory Liabilities	3,585,000,000		2,390,000,000
Settlement Proceeds [Member]
Regulatory Assets
Regulatory Liability, Current	67,000,000		61,000,000
Settlement Proceeds [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	1,020,000,000		1,037,000,000
Deferred Income Tax Charge [Member]
Regulatory Assets
Regulatory Liability, Current	49,000,000		52,000,000
Deferred Income Tax Charge [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	837,000,000		607,000,000
Asset Retirement Obligation Costs [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	549,000,000		541,000,000
Deferred gains on interest rate derivatives [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	70,000,000		75,000,000
Revenue Subject to Refund [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	846,000,000
Other Regulatory Liability [Member]
Regulatory Assets
Regulatory Liability, Current	9,000,000		13,000,000
Other Regulatory Liability [Member] \| SCEG
Regulatory Assets
Regulatory Liability, Noncurrent	1,000,000		4,000,000
Unrecovered nuclear project costs post impairment [Member]
Regulatory Assets
Regulatory Assets, Current	138,000,000		127,000,000
Regulatory Assets, Noncurrent	2,607,000,000
Unrecovered nuclear project costs post impairment [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent			2,641,000,000
Asset Retirement Obligation Costs [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	335,000,000		380,000,000
Pension Costs [Member]
Regulatory Assets
Regulatory Assets, Current	16,000,000		16,000,000
Pension Costs [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	252,000,000		256,000,000
Deferred Losses On Interest Rate Derivatives [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	297,000,000		442,000,000
unrecovered plant [Member]
Regulatory Assets
Regulatory Assets, Current	14,000,000		14,000,000
unrecovered plant [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	76,000,000		79,000,000
Demand Side Management programs [Member]
Regulatory Assets
Regulatory Assets, Current	$ 16,000,000		14,000,000
Demand Side Management programs [Member] \| SCEG
Regulatory Assets
Regulatory Asset, Amortization Period	5 years
Regulatory Assets, Noncurrent	$ 51,000,000		51,000,000
Environmental Restoration Costs [Member]
Regulatory Assets
MPG environmental remediation	16
Environmental Restoration Costs [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 23,000,000		24,000,000
Storm Costs [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	34,000,000		35,000,000
Other Regulatory Assets [Member]
Regulatory Assets
Regulatory Assets, Current	$ 69,000,000		52,000,000
Regulatory Asset Recovery Assessments	2047
Other Regulatory Assets [Member] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 114,000,000		123,000,000
Deferred transmission operating costs [Member] [Domain] \| SCEG
Regulatory Assets
Regulatory Assets, Noncurrent	$ 21,000,000		$ 15,000,000

RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Refund to Customer Related to Tax Act	$ 137
SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	3,323		$ 2,264
Settlement Proceeds [Member] \| SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,020		1,037
Deferred Income Tax Charge [Member] \| SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	837		607
Asset Retirement Obligation Costs [Member] \| SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	549		541
Deferred gains on interest rate derivatives [Member] \| SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	70		75
Other Regulatory Liability [Member] \| SCEG
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 1		$ 4
Environmental Restoration Costs [Member]
Regulatory Liabilities [Line Items]
MPG environmental remediation	16

REVENUE RECOGNITION (Details) - USD ($) $ in Millions	3 Months Ended
REVENUE RECOGNITION (Details) - USD ($) $ in Millions	Mar. 31, 2019	Mar. 31, 2018
Provision for rate credits	$ 1,009
Electric Regulated Revenue	(480)	$ 547
Regulated Operating Revenue, Gas	145	155
Regulated Operating Revenue	(335)	702
Electric Operations
Disaggregation of Revenue [Table Text Block]	(482)	543
Other Revenues	2	3
Regulated Operating Revenue	(480)	547
Residential [Member]
Electric Regulated Revenue	(271)	252
Regulated Operating Revenue, Gas	78	86
Wholesale [Member]
Electric Regulated Revenue	10	37
Regulated Operating Revenue, Gas	3	5
Industrial [Member]
Electric Regulated Revenue	(82)	85
Regulated Operating Revenue, Gas	26	24
Commercial [Member]
Electric Regulated Revenue	(139)	169
Regulated Operating Revenue, Gas	38	39
Gas Distribution
Disaggregation of Revenue [Table Text Block]	145	154
Other Revenues	0	1
Regulated Operating Revenue	$ 145	$ 155

REVENUE RECOGNITION Contract Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Contract with Customer, Liability	$ 4.4	$ 3.6
Contract with Customer, Liability, Revenue Recognized	$ 1.6

COMMON EQUITY (Details) - USD ($) $ in Millions	3 Months Ended
COMMON EQUITY (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018
Schedule of Capitalization, Equity [Line Items]
Retained Earnings, Appropriated	$ 120.4	$ 115.0
Common Stock, Shares Authorized	50,000,000		200,000,000
Shares, Issued	40.3
Preferred Stock, Shares Outstanding	0
Proceeds from Contributions from Parent	$ 675.0
SCEG
Schedule of Capitalization, Equity [Line Items]
Common Stock, Shares Authorized			50,000,000
Common Stock, Shares, Outstanding	40,300,000	40,300,000
Preferred Stock, Shares Authorized			20,000,000
Preferred Stock, Shares Outstanding			0

LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
First Mortgage Bonds	$ 1,200.0
Gain (Loss) on Repurchase of Debt Instrument	$ 187.0
Line of Credit Facility, Priority	6
Related Party Transaction, Due from (to) Related Party, Current	$ 555.0	$ 282.0
Line of Credit Facility, Increase (Decrease), Net	1,000.0	1,200.0
Commercial Paper		73.2
Letters of Credit Outstanding, Amount	0.3	$ 0.3
Debt, Weighted Average Interest Rate		3.82%
Sub limit for line of credit borrowings	500.0
SCEG
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 67.8	$ 67.8

LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Interest Income, Related Party	$ 3.0
Interest Expense, Related Party	3.1
Related Party Transaction, Due from (to) Related Party, Current	555.0	$ 282.0
Long-term Line of Credit	1,000.0
Commercial Paper		$ 73.2
Debt, Weighted Average Interest Rate		3.82%
Letters of Credit Outstanding, Amount	0.3	$ 0.3
Due to Related Parties		$ 353.0
SCEG including Fuel Company [Member]
Debt Instrument [Line Items]
Commercial paper borrowing limit	2,200.0
Genco
Debt Instrument [Line Items]
Commercial paper borrowing limit	$ 200.0

INCOME TAXES (Details) - USD ($)	3 Months Ended
INCOME TAXES (Details) - USD ($)	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Effective Income Tax Rate Reconciliation, Percent	9.70%	23.40%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	$ 198,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
Unrecognized Tax Benefits	$ 51,000,000		$ 0
Interest Expense	73,000,000	$ 77,000,000
Effective Income Tax Rate Reconciliation, Deduction, Amount	0.30
SCEG
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	98,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	98,000,000
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound	0
Decrease in Unrecognized Tax Benefits is Reasonably Possible	11,000,000
Unrecognized Tax Benefits	$ 38,000,000		$ 38,000,000

DERIVATIVE FINANCIAL INSTRUMENTS (Details) $ in Millions	Mar. 31, 2019 USD ($)
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 71,400,000

DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative Liability	$ 14	$ 11
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	13	10
Interest Rate Contract
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	14	11
Interest Rate Contract \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
Interest Rate Contract \| Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	13	10
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	10	8
Designated as Hedging Instrument [Member] \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		1
Designated as Hedging Instrument [Member] \| Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	9	7
Designated as Hedging Instrument [Member] \| Interest Rate Contract \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability		1
Designated as Hedging Instrument [Member] \| Interest Rate Contract \| Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	9	7
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability	4	3
Not Designated as Hedging Instrument [Member] \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	0
Not Designated as Hedging Instrument [Member] \| Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	4	3
Not Designated as Hedging Instrument [Member] \| Interest Rate Contract \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	0
Not Designated as Hedging Instrument [Member] \| Interest Rate Contract \| Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 4	$ 3

DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flow Hedging [Member]
Derivative [Line Items]
increase decrease in derivatives affecting regulatory assets and liabilities	$ (2)	$ 2
Interest Rate Contract \| Cash Flow Hedging [Member]
Derivative [Line Items]
increase decrease in derivatives affecting regulatory assets and liabilities	(2)	2
Not Designated as Hedging Instrument [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		115
increase decrease in derivatives affecting regulatory assets and liabilities	(1)	65
Not Designated as Hedging Instrument [Member] \| Interest Expense [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0
Not Designated as Hedging Instrument [Member] \| Other Income [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		$ 115

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Derivative [Line Items]
Additional Collateral, Aggregate Fair Value	$ 0.0		$ 0.0
SCEG
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	14.0
Derivative, Net Liability Position, Aggregate Fair Value	14.2
Interest Rate Contract
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	14.0		$ 11.0
Not Designated as Hedging Instrument [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		$ 115.0
Interest Expense [Member] \| Not Designated as Hedging Instrument [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income	$ 0.0
Other Income [Member] \| Not Designated as Hedging Instrument [Member] \| Interest Rate Contract
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		$ 115.0

DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Derivative Liability	$ 14	$ 11
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	1	1
Interest Rate Contract
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	14	11
Derivative Liability, Fair Value, Offset Against Collateral, Net of Not Subject to Master Netting Arrangement, Policy Election	0	0
Interest Rate Contract \| Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability	$ 1	$ 1

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Interest Rate Contract \| Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Fair Value Disclosure	$ 14	$ 11

FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 3,975.0	$ 5,145.6
Long-term Debt, Fair Value	$ 4,567.0	$ 5,469.7

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	3 Months Ended
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions	Mar. 31, 2019	Mar. 31, 2018
Pension and Other Postretirement Benefit Plans
Pension Contributions	No
Pension Benefits
Components of Net Periodic Benefit Cost
Service cost	$ 4.0	$ 4.0
Interest cost	7.8	7.2
Expected return on assets	(10.3)	(12.1)
Defined Benefit Plan, Actuarial Net (Gains) Losses	3.6	2.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	6.0	2.0
Other Postretirement Benefits
Components of Net Periodic Benefit Cost
Service cost	0.7	1.0
Interest cost	2.2	2.1
Expected return on assets	0.0	0.0
Defined Benefit Plan, Actuarial Net (Gains) Losses	0.0	0.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 3.0	$ 3.0
SCEG
Pension and Other Postretirement Benefit Plans
Pension Contributions	No

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	3 Months Ended		12 Months Ended
COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
Commitments and contingencies
Emission Rate Standard For Coal Fired Power Plants Under Clean Air Act	1,400
Emission Rate Standard for Natural Gas	1,000
Increase (Decrease) in Client Funds Held	$ 2,000,000
Utilities Operating Loss, Impairment, Net of Taxes	79,000
Impairment loss write off	105,000
Utilities Operating Expense, Impairments	262,000	$ 4,000
Long-term Line of Credit	1,000,000
Customer Refundable Fees, Refund Payments, Post Merger	(985,000)
Customer Refundable Fees, Alternative Plan	1,007,000
Customer refund fees alternative plan net of tax	756,000
Customer Refundable Fees, Alternative Plan over 20 yrs	1,032,000
Transmission Assets related to BLRA Capital Costs	334,000
Transmission Assets related to BLRA Regulatory Assets	21,000
Asset Impairment Charges	262,000	$ 4,000
Estimate of aggregate amount of subcontractor and vendor liens filed	285,000
Reduction of liens filed	60,000
Nuclear Insurance
Maximum liability assessment per reactor for each nuclear incident	137,700
Federal Limit on Public Liability Claims from Nuclear Incident Approximate	14,000,000
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year	20,500
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year	13,700
Environmental
Refundable Gas Costs	2,450
Increase (Decrease) in Recoverable Refundable Gas Costs	1,800
Liability for charitable contributions	22,000
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Charitable Contributions, Amount	17,000
Excess deferred taxes	198,000
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances	2,000,000
Managing Member or General Partner, Subsequent Distribution Amount	115,000
Legal Fees	60,000
Estimated maximum legal fees	85,000
Legal expense			$ 157,000
Legal Expense, net of taxes			118,000
Increase (Decrease) in Property and Other Taxes Payable	410,000
SCEG
Commitments and contingencies
Long-term Debt, Current Maturities	14,000		14,000
Short-term borrowings	0		73,000
Estimate of aggregate amount of subcontractor and vendor liens filed	33,000
Nuclear Insurance
Maximum Insurance Coverage For Each Nuclear Plant by ANI	450,000
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3	$ 91,800
Inflation adjustment period for nuclear insurance	5
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event	$ 2,330,000
NEIL Maximum Insurance Coverage of Accidental Property Damage	2,750,000
EMANI Maximum Retrospective Premium Assessment	2,000
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event	415,000
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident	23,400
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs	2,750,000
Environmental
Environmental Remediation Costs Recognized in Regulatory Assets	$ 23,600
Number of MGP decommissioned sites that contain residues of byproduct chemicals	4
Number Of States Required To Reduce Emissions Under CSAPR	28
Site Contingency MGP Estimated Environmental Remediation Costs	$ 9,600
Environmental Exit Costs, Reasonably Possible Additional Loss			$ 8,000

LEASES (Details)
$ in Millions

3 Months Ended

Mar. 31, 2019

USD ($)

Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year,

$ 1.9

Finance Lease, Liability, Payments, Remainder of Fiscal Year

$ 5.9

Finance Lease, Weighted Average Remaining Lease Term

5 years

Finance Lease, Interest Payment on Liability

$ 0.2

Finance Lease, Right-of-Use Asset, Amortization

1.7

Capital Lease Obligations

29.0

^[1]

Operating Lease, Right-of-Use Asset

19.0

^[2]

Operating and Finance lease Right of Use Asset

48.0

Operating Lease, Liability, Current

2.0

^[3]

Operating Lease, Liability, Noncurrent

15.0

^[4]

Finance Lease, Liability, Current

7.0

^[5]

Finance Lease, Liability, Noncurrent

22.0

^[6]

Operating and Finance Lease Liability

46.0

Finance Lease, Interest Expense

0.2

Operating Lease, Cost

0.8

Short-term Lease, Cost

0.4

Lease, Cost

3.0

Operating Lease, Payments

0.7

Finance Lease, Principal Payments

$ 1.7

Operating Lease, Weighted Average Remaining Lease Term

23 years

Finance Lease, Weighted Average Discount Rate, Percent

2.91%

Operating Lease, Weighted Average Discount Rate, Percent

4.22%

Lessee, Operating Lease, Liability, Payments, Due Year Two

$ 1.4

Finance Lease, Liability, Payments, Due Year Two

7.4

Lessee, Operating Lease, Liability, Payments, Due Year Three

1.1

Finance Lease, Liability, Payments, Due Year Three

5.7

Lessee, Operating Lease, Liability, Payments, Due Year Four

1.0

Finance Lease, Liability, Payments, Due Year Four

4.4

Operating Leases, Future Minimum Payments Receivable, in Five Years

1.0

Finance Lease, Liability, Payments, Due Year Five

3.1

Lessee, Operating Lease, Liability, Payments, Due after Year Five

22.7

Finance Lease, Liability, Payments, Due in Rolling after Year Five

4.7

Lessee, Operating Lease, Liability, Payments, Due

29.0

Finance Lease, Liability, Payments, Due

31.0

Lessee, Operating Lease, Liability, Undiscounted Excess Amount

(12.4)

Finance Lease, Liability, Undiscounted Excess Amount

(2.2)

Operating Lease, Liability

17.0

Finance Lease, Liability

$ 29.0

[1]	Included in utility plant, net, in the Consolidated Balance Sheets, net of $18 million of accumulated amortization at March 31, 2019.
[2]	Included in other deferred debits and other assets in the Consolidated Balance Sheets.
[3]	Included in other current liabilities in the Consolidated Balance Sheets.
[4]	Included in other deferred credits and other liabilities in the Consolidated Balance Sheet
[5]	Included in current portion of long-term debt in the Consolidated Balance Sheets.
[6]	Included in long-term debt in the Consolidated Balance Sheets.

SEGMENT OF BUSINESS INFORMATION (Details) - USD ($)	3 Months Ended
SEGMENT OF BUSINESS INFORMATION (Details) - USD ($)	Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Electric Regulated Revenue	$ (480,000,000)	$ 547,000,000
Operating Income	(1,143,000,000)	121,000,000
Provision for rate credits	(1,009,000,000)
Regulated Operating Revenue, Gas	145,000,000	155,000,000
Net Income (Loss) Attributable to Parent	(1,109,000,000)	124,000,000
Regulated Operating Revenue	(335,000,000)	702,000,000
Electric Operations
Segment Reporting Information [Line Items]
Regulated Operating Revenue, Before Adjustments	527,000,000
Net Income (Loss) Attributable to Parent	48,000,000	100,000,000
Regulated Operating Revenue	(480,000,000)	547,000,000
Gas Distribution
Segment Reporting Information [Line Items]
Regulated Operating Revenue, Before Adjustments	147,000,000
Net Income (Loss) Available to Common Stockholders, Basic	22,000,000
Regulated and Unregulated Operating Revenue		155,000,000
Net Income (Loss) Attributable to Parent		32,000,000
Regulated Operating Revenue	145,000,000	155,000,000
All Other [member]
Segment Reporting Information [Line Items]
Net Income (Loss) Attributable to Parent	(1,173,000,000)	(4,000,000)
Adjustments/Eliminations
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue	0	0
Net Income (Loss) Attributable to Parent	$ (6,000,000)	$ (4,000,000)

AFFILIATED TRANSACTIONS (Details) - USD ($)

3 Months Ended

Mar. 31, 2019

Mar. 31, 2018

Dec. 31, 2018

Due to Related Parties

$ 353,000,000

Utilities Operating Expense, Fuel Used, Affiliate

$ 33,200

$ 31,300,000

Electric Domestic Regulated Revenues - Affiliate

1,100

1,200,000

Reclass Other Taxes - nonconsolidated affiliate

2,400,000

2,200,000

Canadys Refined Coal [Member]

$ 5,100,000

6,800,000

Equity Method Investment, Ownership Percentage

40.00%

$ 28,100,000

32,500,000

Sales to Affiliates

27,900,000

32,300,000

Due to Related Parties

5,100,000

6,800,000

Solar Affiliates [Member]

Due to Affiliate, Current

700,000

1,200,000

Dominion Energy Carolina Gas Transmission LLC [Member]

Due to Affiliate, Current

5,500,000

14,500,000

Utilities Operating Expense, Fuel Used, Affiliate

11,000,000

Related Party Purchases - Cost of Gas

4,100,000

DEGM [Member]

Due to Affiliate, Current

11,000,000

14,100,000

DESS [Member]

Capitalized Related Costs

9,000,000

8,000,000

Due to Affiliate, Current

40,500,000

$ 37,700,000

^[1]

$ 58,400,000

^[1]

$ 59,000,000

[1]	Includes capitalized expenditures of $9 million and $8 million for the three months ended March 31, 2019 and 2018, respectively.

OTHER INCOME (EXPENSE), NET Other Income (Expense) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenue from Contract with Customer, Including Assessed Tax	$ 1	$ 1
Other income	4	126
Other Nonoperating Expense	(10)	(7)
Public Utilities, Allowance for Funds Used During Construction, Additions	0	3
Other Nonoperating Income (Expense)	$ (5)	123
Interest Rate Contract \| Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		115
Other Income [Member] \| Interest Rate Contract \| Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income		$ 115