x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission | Registrant, State of Incorporation, | I.R.S. Employer | ||
File Number | Address and Telephone Number | Identification No. | ||
1-8809 | SCANA Corporation (a South Carolina corporation) | 57-0784499 | ||
1-3375 | South Carolina Electric & Gas Company (a South Carolina corporation) | 57-0248695 | ||
100 SCANA Parkway, Cayce, South Carolina 29033 | ||||
(803) 217-9000 |
SCANA Corporation | Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | Emerging growth company o |
South Carolina Electric & Gas Company | Large accelerated filer o | Accelerated filer o | Non-accelerated filer x | Smaller reporting company o | Emerging growth company o |
Description of | Shares Outstanding | |
Registrant | Common Stock | at April 24, 2018 |
SCANA Corporation | Without Par Value | 142,628,142 |
South Carolina Electric & Gas Company | Without Par Value | 40,296,147 (a) |
Page | |||
TERM | MEANING | |
AFC | Allowance for Funds Used During Construction | |
ANI | American Nuclear Insurers | |
AOCI | Accumulated Other Comprehensive Income (Loss) | |
ARO | Asset Retirement Obligation | |
Bankruptcy Court | U.S. Bankruptcy Court for the Southern District of New York | |
BLRA | Base Load Review Act | |
CAA | Clean Air Act, as amended | |
CAIR | Clean Air Interstate Rule | |
CCR | Coal Combustion Residuals | |
CEO | Chief Executive Officer | |
CFO | Chief Financial Officer | |
CFTC | Commodity Futures Trading Commission | |
Citibank | Citibank, N.A. | |
CO2 | Carbon Dioxide | |
Company | SCANA, together with its consolidated subsidiaries | |
Consolidated SCE&G | SCE&G and its consolidated affiliates | |
Consortium | A consortium consisting of WEC and WECTEC | |
Court of Appeals | United States Court of Appeals for the District of Columbia | |
CSAPR | Cross-State Air Pollution Rule | |
CUT | Customer Usage Tracker (decoupling mechanism) | |
CWA | Clean Water Act | |
DER | Distributed Energy Resource | |
DHEC | South Carolina Department of Health and Environmental Control | |
District Court | United States District Court for the District of South Carolina | |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act | |
Dominion Energy | Dominion Energy, Inc. | |
DOR | South Carolina Department of Revenue | |
DSM Programs | Electric Demand Side Management Programs | |
ELG Rule | Federal effluent limitation guidelines for steam electric generating units | |
EMANI | European Mutual Association for Nuclear Insurance | |
EPA | United States Environmental Protection Agency | |
Exchange Act | Securities Exchange Act of 1934, as amended | |
FASB | Financial Accounting Standards Board | |
FERC | United States Federal Energy Regulatory Commission | |
FILOT | Fee in Lieu of Taxes | |
Fluor | Fluor Corporation | |
Fuel Company | South Carolina Fuel Company, Inc. | |
GAAP | Accounting principles generally accepted in the United States of America | |
GENCO | South Carolina Generating Company, Inc. | |
GHG | Greenhouse Gas | |
GPSC | Georgia Public Service Commission | |
GWh | Gigawatt hour | |
IAA | Interim Assessment Agreement dated March 28, 2017, as amended, among SCE&G, Santee Cooper, WEC and WECTEC | |
IRC | Internal Revenue Code of 1986, as amended | |
IRS | Internal Revenue Service | |
Joint Petition | Joint application and petition of SCE&G and Dominion Energy for review and approval of a proposed business combination as set forth in the Merger Agreement and for a prudency determination regarding the abandonment of the Nuclear Project and associated merger benefits and cost recovery plans, filed with the SCPSC on January 12, 2018 |
Level 1 | A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities | |
Level 2 | A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means | |
Level 3 | A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability | |
LOC | Lines of Credit | |
MATS | Mercury and Air Toxics Standards | |
Merger Agreement | Agreement and Plan of Merger, dated as of January 2, 2018, by and among Dominion Energy, Sedona and SCANA | |
MGP | Manufactured Gas Plant | |
MMBTU | Million British Thermal Units | |
MW or MWh | Megawatt or Megawatt-hour | |
NAAQS | National Ambient Air Quality Standards | |
NASDAQ | The NASDAQ Stock Market, Inc. | |
NAV | Net Asset Value | |
NCUC | North Carolina Utilities Commission | |
NEIL | Nuclear Electric Insurance Limited | |
NERC | North American Electric Reliability Corporation | |
NOL | Net Operating Loss | |
NOX | Nitrogen Oxide | |
NPDES | National Pollutant Discharge Elimination System | |
NRC | United States Nuclear Regulatory Commission | |
NSPS | New Source Performance Standards | |
Nuclear Project | Project to construct Unit 2 and Unit 3 under the EPC Contract | |
NYMEX | New York Mercantile Exchange | |
OCI | Other Comprehensive Income | |
ORS | South Carolina Office of Regulatory Staff | |
PHMSA | United States Pipeline Hazardous Materials Safety Administration | |
Price-Anderson | Price-Anderson Indemnification Act | |
PSNC Energy | Public Service Company of North Carolina, Incorporated | |
Registrants | SCANA and SCE&G | |
Reorganization Plan | Modified Second Amended Joint Chapter 11 Plan of Reorganization, filed by WEC | |
Request | Request for Rate Relief filed by the ORS on September 26, 2017, as subsequently amended | |
RICO | The Racketeer Influenced and Corrupt Organizations Act | |
RSA | Natural Gas Rate Stabilization Act | |
RTO/ISO | Regional Transmission Organization/Independent System Operator | |
Santee Cooper | South Carolina Public Service Authority | |
SCANA | SCANA Corporation, the parent company | |
SCANA Energy | SCANA Energy Marketing, Inc. | |
SCANA Services | SCANA Services, Inc. | |
SCE&G | South Carolina Electric & Gas Company | |
SCEUC | South Carolina Energy Users Committee | |
SCPSC | Public Service Commission of South Carolina | |
SEC | United States Securities and Exchange Commission | |
Sedona | Sedona Corp., a wholly-owned subsidiary of Dominion Energy | |
SIP | State Implementation Plan | |
SLED | South Carolina Law Enforcement Division | |
SO2 | Sulfur Dioxide | |
Summer Station | V. C. Summer Nuclear Station | |
Supreme Court | United States Supreme Court | |
Tax Act | An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017 | |
Toshiba | Toshiba Corporation, parent company of WEC |
Toshiba Settlement | Settlement Agreement dated as of July 27, 2017, by and among Toshiba, SCE&G and Santee Cooper | |
Unit 1 | Nuclear Unit 1 at Summer Station | |
Unit 2 | Nuclear Unit 2 at Summer Station (abandoned prior to construction completion) | |
Unit 3 | Nuclear Unit 3 at Summer Station (abandoned prior to construction completion) | |
VIE | Variable Interest Entity | |
WEC | Westinghouse Electric Company LLC | |
WEC Subcontractors | Subcontractors to the Consortium | |
WECTEC | WECTEC Global Project Services, Inc. (formerly known as Stone & Webster, Inc.), a wholly-owned subsidiary of WEC | |
Williams Station | A.M. Williams Generating Station, owned by GENCO | |
WNA | Weather Normalization Adjustment |
Millions of dollars | March 31, 2018 | December 31, 2017 | ||||||
Assets | ||||||||
Utility Plant In Service | $ | 14,465 | $ | 14,370 | ||||
Accumulated Depreciation and Amortization | (4,659 | ) | (4,611 | ) | ||||
Construction Work in Progress | 487 | 471 | ||||||
Nuclear Fuel, Net of Accumulated Amortization | 191 | 208 | ||||||
Goodwill, net of writedown of $230 | 210 | 210 | ||||||
Utility Plant, Net | 10,694 | 10,648 | ||||||
Nonutility Property and Investments: | ||||||||
Nonutility property, net of accumulated depreciation of $137 and $133 | 268 | 270 | ||||||
Assets held in trust, net-nuclear decommissioning | 133 | 136 | ||||||
Other investments | 174 | 68 | ||||||
Nonutility Property and Investments, Net | 575 | 474 | ||||||
Current Assets: | ||||||||
Cash and cash equivalents | 199 | 409 | ||||||
Receivables: | ||||||||
Customer, net of allowance for uncollectible accounts of $7 and $6 | 578 | 665 | ||||||
Income taxes | 198 | 198 | ||||||
Other | 88 | 105 | ||||||
Inventories (at average cost): | ||||||||
Fuel and gas supply | 119 | 143 | ||||||
Materials and supplies | 165 | 161 | ||||||
Prepayments | 85 | 99 | ||||||
Other current assets | 15 | 17 | ||||||
Derivative financial instruments | — | 54 | ||||||
Total Current Assets | 1,447 | 1,851 | ||||||
Deferred Debits and Other Assets: | ||||||||
Regulatory assets | 5,578 | 5,580 | ||||||
Other | 290 | 186 | ||||||
Total Deferred Debits and Other Assets | 5,868 | 5,766 | ||||||
Total | $ | 18,584 | $ | 18,739 |
Millions of dollars | March 31, 2018 | December 31, 2017 | ||||||
Capitalization and Liabilities | ||||||||
Common Stock - no par value, 143 million shares outstanding | $ | 2,389 | $ | 2,390 | ||||
Retained Earnings | 2,997 | 2,915 | ||||||
Accumulated Other Comprehensive Loss | (42 | ) | (50 | ) | ||||
Total Common Equity | 5,344 | 5,255 | ||||||
Long-Term Debt, net | 6,001 | 5,906 | ||||||
Total Capitalization | 11,345 | 11,161 | ||||||
Current Liabilities: | ||||||||
Short-term borrowings | 248 | 350 | ||||||
Current portion of long-term debt | 727 | 727 | ||||||
Accounts payable | 266 | 438 | ||||||
Customer deposits and customer prepayments | 206 | 112 | ||||||
Taxes accrued | 64 | 214 | ||||||
Interest accrued | 94 | 87 | ||||||
Dividends declared | 86 | 86 | ||||||
Derivative financial instruments | 4 | 6 | ||||||
Other | 80 | 93 | ||||||
Total Current Liabilities | 1,775 | 2,113 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Deferred income taxes, net | 1,315 | 1,261 | ||||||
Asset retirement obligations | 572 | 568 | ||||||
Pension and other postretirement benefits | 359 | 360 | ||||||
Unrecognized tax benefits | 19 | 19 | ||||||
Regulatory liabilities | 3,008 | 3,059 | ||||||
Other | 191 | 198 | ||||||
Total Deferred Credits and Other Liabilities | 5,464 | 5,465 | ||||||
Commitments and Contingencies (Note 10) | ||||||||
Total | $ | 18,584 | $ | 18,739 |
Three Months Ended | ||||||||
March 31, | ||||||||
Millions of dollars, except per share amounts | 2018 | 2017 | ||||||
Operating Revenues: | ||||||||
Electric | $ | 546 | $ | 577 | ||||
Gas - regulated | 361 | 322 | ||||||
Gas - nonregulated | 273 | 274 | ||||||
Total Operating Revenues | 1,180 | 1,173 | ||||||
Operating Expenses: | ||||||||
Fuel used in electric generation | 159 | 136 | ||||||
Purchased power | 52 | 11 | ||||||
Gas purchased for resale | 406 | 370 | ||||||
Other operation and maintenance | 201 | 175 | ||||||
Impairment loss | 4 | — | ||||||
Depreciation and amortization | 99 | 95 | ||||||
Other taxes | 70 | 66 | ||||||
Total Operating Expenses | 991 | 853 | ||||||
Operating Income | 189 | 320 | ||||||
Other Income (Expense), net | 128 | 12 | ||||||
Interest charges, net of allowance for borrowed funds used during construction of $3, and $6 | (97 | ) | (87 | ) | ||||
Income Before Income Tax Expense | 220 | 245 | ||||||
Income Tax Expense | 51 | 74 | ||||||
Net Income | $ | 169 | $ | 171 | ||||
Earnings Per Share of Common Stock | $ | 1.18 | $ | 1.19 | ||||
Weighted Average Common Shares Outstanding (millions) | 143 | 143 | ||||||
Dividends Declared Per Share of Common Stock | $ | 0.6125 | $ | 0.6125 |
Three Months Ended March 31, | ||||||||
Millions of dollars | 2018 | 2017 | ||||||
Net Income | $ | 169 | $ | 171 | ||||
Other Comprehensive Income (Loss), net of tax: | ||||||||
Unrealized Gains (Losses) on Cash Flow Hedging Activities: | ||||||||
Arising during period, net of tax of $1 and $(1) | 3 | (2 | ) | |||||
Reclassified as increases to interest expense, net of tax of $1 and $1 | 2 | 2 | ||||||
Reclassified as increases (decreases) to gas purchased for resale, net of tax of $1 and $(1) | 2 | (2 | ) | |||||
Net unrealized gains (losses) on cash flow hedging activities | 7 | (2 | ) | |||||
Deferred cost of employee benefit plans, net of tax of $- and $- | 1 | — | ||||||
Other Comprehensive Income | 8 | (2 | ) | |||||
Total Comprehensive Income | $ | 177 | $ | 169 |
Three Months Ended March 31, | ||||||||
Millions of dollars | 2018 | 2017 | ||||||
Cash Flows From Operating Activities: | ||||||||
Net income | $ | 169 | $ | 171 | ||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||
Impairment loss | 4 | — | ||||||
Deferred income taxes, net | 52 | 27 | ||||||
Depreciation and amortization | 106 | 100 | ||||||
Amortization of nuclear fuel | 13 | 14 | ||||||
Allowance for equity funds used during construction | (4 | ) | (9 | ) | ||||
Carrying cost recovery | (1 | ) | (5 | ) | ||||
Changes in certain assets and liabilities: | ||||||||
Receivables | 75 | 67 | ||||||
Income taxes receivable | — | 136 | ||||||
Inventories | 2 | 6 | ||||||
Prepayments | 17 | (5 | ) | |||||
Regulatory assets | (9 | ) | (4 | ) | ||||
Regulatory liabilities | (115 | ) | (3 | ) | ||||
Accounts payable | (40 | ) | (48 | ) | ||||
Unrecognized tax benefits | — | 55 | ||||||
Taxes accrued | (150 | ) | (142 | ) | ||||
Derivative financial instruments | (1 | ) | (3 | ) | ||||
Other assets | (113 | ) | (2 | ) | ||||
Other liabilities | 87 | (46 | ) | |||||
Net Cash Provided From Operating Activities | 92 | 309 | ||||||
Cash Flows From Investing Activities: | ||||||||
Property additions and construction expenditures | (227 | ) | (342 | ) | ||||
Proceeds from investments and sales of assets (including derivative collateral returned) | 32 | 19 | ||||||
Purchase of investments (including derivative collateral posted) | (125 | ) | (20 | ) | ||||
Proceeds upon interest rate derivative contract settlements | 115 | — | ||||||
Net Cash Used For Investing Activities | (205 | ) | (343 | ) | ||||
Cash Flows From Financing Activities: | ||||||||
Proceeds from issuance of long-term debt | 100 | — | ||||||
Repayment of long-term debt | (8 | ) | (8 | ) | ||||
Dividends | (87 | ) | (82 | ) | ||||
Short-term borrowings, net | (102 | ) | (72 | ) | ||||
Net Cash Used For Financing Activities | (97 | ) | (162 | ) | ||||
Net Decrease In Cash and Cash Equivalents | (210 | ) | (196 | ) | ||||
Cash and Cash Equivalents, January 1 | 409 | 208 | ||||||
Cash and Cash Equivalents, March 31 | $ | 199 | $ | 12 | ||||
Supplemental Cash Flow Information: | ||||||||
Cash for–Interest paid (net of capitalized interest of $3 and $6) | $ | 82 | $ | 76 | ||||
–Income taxes received | — | 123 | ||||||
Noncash Investing and Financing Activities: | ||||||||
Accrued construction expenditures | 36 | 57 | ||||||
Capital leases | 3 | — |
Common Stock | Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||||||||||||||
Millions | Shares | Outstanding Amount | Treasury Amount | Retained Earnings | Gains (Losses) from Cash Flow Hedges | Deferred Employee Benefit Plans | Total AOCI | Total | ||||||||||||||||||||||||
Balance as of January 1, 2018 | 143 | $ | 2,402 | $ | (12 | ) | $ | 2,915 | $ | (37 | ) | $ | (13 | ) | $ | (50 | ) | $ | 5,255 | |||||||||||||
Net Income | 169 | 169 | ||||||||||||||||||||||||||||||
Other Comprehensive Income (Loss) | ||||||||||||||||||||||||||||||||
Losses arising during the period | 3 | — | 3 | 3 | ||||||||||||||||||||||||||||
Losses/amortization reclassified from AOCI | 4 | 1 | 5 | 5 | ||||||||||||||||||||||||||||
Total Comprehensive Income | 169 | 7 | 1 | 8 | 177 | |||||||||||||||||||||||||||
Purchase of Treasury Stock | — | — | (1 | ) | (1 | ) | ||||||||||||||||||||||||||
Dividends Declared | (87 | ) | (87 | ) | ||||||||||||||||||||||||||||
Balance as of March 31, 2018 | 143 | $ | 2,402 | $ | (13 | ) | $ | 2,997 | 0.000002 | $ | (30 | ) | $ | (12 | ) | $ | (42 | ) | 0.000004 | $ | 5,344 | |||||||||||
Balance as of January 1, 2017 | 143 | $ | 2,402 | $ | (12 | ) | $ | 3,384 | $ | (36 | ) | $ | (13 | ) | $ | (49 | ) | $ | 5,725 | |||||||||||||
Net Income | 171 | 171 | ||||||||||||||||||||||||||||||
Other Comprehensive Income (Loss) | ||||||||||||||||||||||||||||||||
Losses arising during the period | (2 | ) | — | (2 | ) | (2 | ) | |||||||||||||||||||||||||
Losses/amortization reclassified from AOCI | — | — | — | — | ||||||||||||||||||||||||||||
Total Comprehensive Income | 171 | (2 | ) | — | (2 | ) | 169 | |||||||||||||||||||||||||
Purchase of Treasury Stock | — | — | (1 | ) | (1 | ) | ||||||||||||||||||||||||||
Dividends Declared | (87 | ) | (87 | ) | ||||||||||||||||||||||||||||
Balance as of March 31, 2017 | 143 | $ | 2,402 | $ | (13 | ) | $ | 3,468 | $ | (38 | ) | $ | (13 | ) | $ | (51 | ) | $ | 5,806 |
Millions of dollars | March 31, 2018 | December 31, 2017 | ||||||
Assets | ||||||||
Utility Plant In Service | $ | 12,224 | $ | 12,161 | ||||
Accumulated Depreciation and Amortization | (4,163 | ) | (4,124 | ) | ||||
Construction Work in Progress | 382 | 375 | ||||||
Nuclear Fuel, Net of Accumulated Amortization | 191 | 208 | ||||||
Utility Plant, Net ($691 and $711 related to VIEs) | 8,634 | 8,620 | ||||||
Nonutility Property and Investments: | ||||||||
Nonutility property, net of accumulated depreciation | 71 | 71 | ||||||
Assets held in trust, net-nuclear decommissioning | 133 | 136 | ||||||
Other investments | 2 | 2 | ||||||
Nonutility Property and Investments, Net | 206 | 209 | ||||||
Current Assets: | ||||||||
Cash and cash equivalents | 190 | 395 | ||||||
Receivables: | ||||||||
Customer, net of allowance for uncollectible accounts of $4 and $4 | 339 | 390 | ||||||
Affiliated companies | 159 | 32 | ||||||
Income taxes | 198 | 198 | ||||||
Other | 65 | 85 | ||||||
Inventories (at average cost): | ||||||||
Fuel | 84 | 90 | ||||||
Materials and supplies | 152 | 149 | ||||||
Prepayments | 74 | 82 | ||||||
Derivative financial instrument | — | 54 | ||||||
Other current assets | 2 | 2 | ||||||
Total Current Assets ($110 and $191 related to VIEs) | 1,263 | 1,477 | ||||||
Deferred Debits and Other Assets: | ||||||||
Regulatory assets | 5,471 | 5,476 | ||||||
Other | 264 | 164 | ||||||
Other affiliate | 111 | — | ||||||
Total Deferred Debits and Other Assets ($34 and $50 related to VIEs) | 5,846 | 5,640 | ||||||
Total | $ | 15,949 | $ | 15,946 |
Millions of dollars | March 31, 2018 | December 31, 2017 | ||||||
Capitalization and Liabilities | ||||||||
Common Stock - no par value, 40.3 million shares outstanding | $ | 2,860 | $ | 2,860 | ||||
Retained Earnings | 2,034 | 1,982 | ||||||
Accumulated Other Comprehensive Loss | (4 | ) | (4 | ) | ||||
Total Common Equity | 4,890 | 4,838 | ||||||
Noncontrolling Interest | 144 | 142 | ||||||
Total Equity | 5,034 | 4,980 | ||||||
Long-Term Debt, net | 4,536 | 4,441 | ||||||
Total Capitalization | 9,570 | 9,421 | ||||||
Current Liabilities: | ||||||||
Short-term borrowings | 146 | 252 | ||||||
Current portion of long-term debt | 723 | 723 | ||||||
Accounts payable | 129 | 251 | ||||||
Affiliated payables | 256 | 102 | ||||||
Customer deposits and customer prepayments | 159 | 70 | ||||||
Taxes accrued | 58 | 208 | ||||||
Interest accrued | 72 | 67 | ||||||
Dividends declared | 74 | 82 | ||||||
Derivative financial instruments | 1 | 2 | ||||||
Other | 40 | 47 | ||||||
Total Current Liabilities | 1,658 | 1,804 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Deferred income taxes, net | 1,212 | 1,173 | ||||||
Asset retirement obligations | 533 | 529 | ||||||
Pension and other postretirement benefits | 217 | 217 | ||||||
Unrecognized tax benefits | 19 | 19 | ||||||
Regulatory liabilities | 2,617 | 2,667 | ||||||
Other | 105 | 97 | ||||||
Other affiliate | 18 | 19 | ||||||
Total Deferred Credits and Other Liabilities | 4,721 | 4,721 | ||||||
Commitments and Contingencies (Note 10) | ||||||||
Total | $ | 15,949 | $ | 15,946 |
Three Months Ended | ||||||||
March 31, | ||||||||
Millions of dollars | 2018 | 2017 | ||||||
Operating Revenues: | ||||||||
Electric | $ | 546 | $ | 577 | ||||
Electric - nonconsolidated affiliate | 1 | 1 | ||||||
Gas | 155 | 141 | ||||||
Total Operating Revenues | 702 | 719 | ||||||
Operating Expenses: | ||||||||
Fuel used in electric generation | 128 | 112 | ||||||
Fuel used in electric generation - nonconsolidated affiliate | 31 | 24 | ||||||
Purchased power | 52 | 11 | ||||||
Gas purchased for resale | 75 | 66 | ||||||
Other operation and maintenance | 102 | 101 | ||||||
Other operation and maintenance - nonconsolidated affiliate | 44 | 41 | ||||||
Impairment loss | 4 | — | ||||||
Depreciation and amortization | 80 | 77 | ||||||
Other taxes | 63 | 60 | ||||||
Other taxes - nonconsolidated affiliate | 2 | 1 | ||||||
Total Operating Expenses | 581 | 493 | ||||||
Operating Income | 121 | 226 | ||||||
Other Income (Expense), net | 123 | 7 | ||||||
Interest charges, net of allowance for borrowed funds used during construction of $2, and $6 | (77 | ) | (69 | ) | ||||
Income Before Income Tax Expense | 167 | 164 | ||||||
Income Tax Expense | 39 | 52 | ||||||
Net Income and Total Comprehensive Income | 128 | 112 | ||||||
Less Net Income and Total Comprehensive Income Attributable to Noncontrolling Interest | 4 | 3 | ||||||
Earnings and Comprehensive Income Available to Common Shareholder | $ | 124 | $ | 109 | ||||
Dividends Declared on Common Stock | $ | 74 | $ | 79 |
Three Months Ended March 31, | ||||||||
Millions of dollars | 2018 | 2017 | ||||||
Cash Flows From Operating Activities: | ||||||||
Net income | $ | 128 | $ | 112 | ||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||
Impairment loss | 4 | — | ||||||
Deferred income taxes, net | 39 | 12 | ||||||
Depreciation and amortization | 84 | 79 | ||||||
Amortization of nuclear fuel | 13 | 14 | ||||||
Allowance for equity funds used during construction | (3 | ) | (9 | ) | ||||
Carrying cost recovery | (1 | ) | (5 | ) | ||||
Changes in certain assets and liabilities: | ||||||||
Receivables | 41 | 45 | ||||||
Receivables - affiliate | (6 | ) | 2 | |||||
Income tax receivable | — | 53 | ||||||
Inventories | (9 | ) | (7 | ) | ||||
Prepayments | 8 | — | ||||||
Regulatory assets | (6 | ) | (2 | ) | ||||
Regulatory liabilities | (112 | ) | — | |||||
Accounts payable | (15 | ) | (11 | ) | ||||
Accounts payable - affiliate | (5 | ) | (21 | ) | ||||
Taxes accrued | (150 | ) | (93 | ) | ||||
Unrecognized tax benefit | — | 97 | ||||||
Other assets | (112 | ) | 1 | |||||
Other liabilities | 95 | (14 | ) | |||||
Net Cash (Used For) Provided From Operating Activities | (7 | ) | 253 | |||||
Cash Flows From Investing Activities: | ||||||||
Property additions and construction expenditures | (159 | ) | (282 | ) | ||||
Proceeds from investments and sales of assets (including derivative collateral returned) | 25 | 10 | ||||||
Purchase of investments (including derivative collateral posted) | (10 | ) | (12 | ) | ||||
Purchase of investments - affiliate | (111 | ) | — | |||||
Proceeds from interest rate derivative contract settlement | 115 | — | ||||||
Investment in affiliate | (121 | ) | — | |||||
Net Cash Used For Investing Activities | (261 | ) | (284 | ) | ||||
Cash Flows From Financing Activities: | ||||||||
Proceeds from issuance of debt | 100 | — | ||||||
Repayment of long-term debt | (8 | ) | (8 | ) | ||||
Dividends | (82 | ) | (79 | ) | ||||
Money pool borrowings, net | 159 | (1 | ) | |||||
Short-term borrowings, net | (106 | ) | (34 | ) | ||||
Net Cash Provided From (Used For) Financing Activities | 63 | (122 | ) | |||||
Net Decrease In Cash and Cash Equivalents | (205 | ) | (153 | ) | ||||
Cash and Cash Equivalents, January 1 | 395 | 164 | ||||||
Cash and Cash Equivalents, March 31 | $ | 190 | $ | 11 | ||||
Supplemental Cash Flow Information: | ||||||||
Cash for–Interest (net of capitalized interest of $2 and $6) | $ | 63 | $ | 61 | ||||
– Income taxes paid | — | 3 | ||||||
– Income taxes received | — | 143 | ||||||
Noncash Investing and Financing Activities: | ||||||||
Accrued construction expenditures | 21 | 46 | ||||||
Capital leases | 3 | — |
Common Stock | |||||||||||||||||||||||
Millions | Shares | Amount | Retained Earnings | AOCI | Noncontrolling Interest | Total Equity | |||||||||||||||||
Balance at January 1, 2018 | 40 | $ | 2,860 | $ | 1,982 | $ | (4 | ) | $ | 142 | $ | 4,980 | |||||||||||
Earnings available to common shareholder | 124 | 4 | 128 | ||||||||||||||||||||
Total Comprehensive Income | 124 | — | 4 | 128 | |||||||||||||||||||
Cash dividend declared | (72 | ) | (2 | ) | (74 | ) | |||||||||||||||||
Balance at March 31, 2018 | 40 | $ | 2,860 | $ | 2,034 | $ | (4 | ) | $ | 144 | $ | 5,034 | |||||||||||
Balance at January 1, 2017 | 40 | $ | 2,860 | $ | 2,481 | $ | (3 | ) | $ | 134 | $ | 5,472 | |||||||||||
Earnings available to common shareholder | 109 | 3 | 112 | ||||||||||||||||||||
Total Comprehensive Income | 109 | — | 3 | 112 | |||||||||||||||||||
Cash dividend declared | (77 | ) | (2 | ) | (79 | ) | |||||||||||||||||
Balance at March 31, 2017 | 40 | $ | 2,860 | $ | 2,513 | $ | (3 | ) | $ | 135 | $ | 5,505 |
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
• | In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018, and its adoption had no impact on its financial statements. |
• | Effective January 1, 2018, the Company and Consolidated SCE&G adopted new accounting guidance for revenue arising from contracts with customers. This guidance uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods are not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3. |
• | Effective January 1, 2018, the Company and Consolidated SCE&G adopted accounting guidance that changed the required presentation of net periodic pension and postretirement benefit costs. As a result, net periodic pension and postretirement benefit costs have been separated into their service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees during the period. Non-service cost components are now excluded from operating income. This guidance has been applied on a retrospective basis for the presentation of the service cost components and other components, and resulted in the following changes to the amounts reported in 2017. |
For the three months ended March 31, 2017 | ||||||||
Increase (Decrease) Millions of dollars | The Company | Consolidated SCE&G | ||||||
Other operation and maintenance | $ | (4 | ) | $ | (4 | ) | ||
Total Operating Expenses | (4 | ) | (4 | ) | ||||
Operating Income | 4 | 4 | ||||||
Other Income (Expense), Net | (4 | ) | (4 | ) |
• | Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things. Entities were required to record a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance was effective, with certain exceptions. The Company and Consolidated SCE&G adopted this guidance when required in the first quarter of 2018 and its adoption did not have a significant impact on their respective financial statements. |
• | Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance had no impact on the financial statements of the Company and Consolidated SCE&G. |
• | Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented. The adoption of this guidance had no impact on the financial statements of the Company and Consolidated SCE&G. |
Rates Effective | Incremental Increase | |
March 1, 2017 | $1.9 million | |
September 1, 2017 | $0.7 million | |
March 1, 2018 | $14.7 million |
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | March 31, 2018 | December 31, 2017 | March 31, 2018 | December 31, 2017 | ||||||||||||
Regulatory Assets: | ||||||||||||||||
Unrecovered Nuclear Project costs | $ | 3,966 | $ | 3,976 | $ | 3,966 | $ | 3,976 | ||||||||
AROs and related funding | 447 | 434 | 423 | 410 | ||||||||||||
Deferred employee benefit plan costs | 300 | 305 | 269 | 273 | ||||||||||||
Deferred losses on interest rate derivatives | 451 | 456 | 451 | 456 | ||||||||||||
Other unrecovered plant | 102 | 105 | 102 | 105 | ||||||||||||
DSM Programs | 59 | 59 | 59 | 59 | ||||||||||||
Pipeline integrity management costs | 55 | 51 | 8 | 8 | ||||||||||||
Environmental remediation costs | 29 | 30 | 24 | 25 | ||||||||||||
Deferred storm damage costs | 24 | 24 | 24 | 24 | ||||||||||||
Other | 145 | 140 | 145 | 140 | ||||||||||||
Total Regulatory Assets | $ | 5,578 | $ | 5,580 | $ | 5,471 | $ | 5,476 |
Regulatory Liabilities: | ||||||||||||||||
Monetization of guaranty settlement | $ | 1,094 | $ | 1,095 | $ | 1,094 | $ | 1,095 | ||||||||
Accumulated deferred income taxes | 1,072 | 1,076 | 914 | 914 | ||||||||||||
Asset removal costs | 763 | 757 | 530 | 527 | ||||||||||||
Deferred gains on interest rate derivatives | 79 | 131 | 79 | 131 | ||||||||||||
Total Regulatory Liabilities | $ | 3,008 | $ | 3,059 | $ | 2,617 | $ | 2,667 |
• | To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others; |
• | To recover carrying costs associated with debt-based financing; |
• | To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and, |
• | For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors, such as through the WNA at SCE&G or the CUT at PSNC Energy. |
The Company | Consolidated SCE&G | PSNC Energy | Total Gas-regulated | Gas-nonregulated | ||||||||||||||||
Segments (Millions of dollars) | Electric | Gas-regulated | Gas-regulated | |||||||||||||||||
Three months ended March 31, 2018 | ||||||||||||||||||||
Customer class: | ||||||||||||||||||||
Residential | $ | 252 | $ | 86 | $ | 145 | $ | 231 | $ | 106 | ||||||||||
Commercial | 169 | 39 | 48 | 87 | 34 | |||||||||||||||
Industrial | 85 | 24 | 6 | 30 | 120 | |||||||||||||||
Other | 37 | 5 | 8 | 13 | 13 | |||||||||||||||
Revenues from contracts with customers | 543 | 154 | 207 | 361 | 273 | |||||||||||||||
Other operating revenues | 3 | 1 | (1 | ) | — | — | ||||||||||||||
Total Operating Revenues | $ | 546 | $ | 155 | $ | 206 | $ | 361 | $ | 273 |
The Company and Consolidated SCE&G | ||||
Millions of dollars | Regulatory Assets | |||
January 1, 2018 | $ | 16.3 | ||
Additional costs | — | |||
Amortization | (0.4 | ) | ||
Impairment | — | |||
March 31, 2018 | $ | 15.9 |
March 31, 2018 (Millions of dollars) | Total | SCANA | Consolidated SCE&G | PSNC Energy | ||||||||||||
Lines of credit: | + | |||||||||||||||
Five-year, expiring December 2020 | $ | 1,300.0 | $ | 400.0 | $ | 700.0 | $ | 200.0 | ||||||||
Fuel Company five-year, expiring December 2020 | 500.0 | — | 500.0 | — | ||||||||||||
Three-year, expiring December 2018 | 200.0 | — | 200.0 | — | ||||||||||||
Total committed long-term | 2,000.0 | 400.0 | 1,400.0 | 200.0 | ||||||||||||
LOC advances | 100.0 | — | 100.0 | — | ||||||||||||
Weighted average interest rate | — | 2.97 | % | — | ||||||||||||
Outstanding commercial paper (270 or fewer days) | 248.0 | 10.9 | 145.8 | 91.3 | ||||||||||||
Weighted average interest rate | 2.70 | % | 2.75 | % | 2.52 | % | ||||||||||
Letters of credit supported by LOC | 46.7 | 46.4 | 0.3 | — | ||||||||||||
Available | $ | 1,605.3 | $ | 342.7 | $ | 1,153.9 | $ | 108.7 |
December 31, 2017 (Millions of dollars) | Total | SCANA | Consolidated SCE&G | PSNC Energy | ||||||||||||
Lines of credit: | ||||||||||||||||
Five-year, expiring December 2020 | $ | 1,300.0 | $ | 400.0 | $ | 700.0 | $ | 200.0 | ||||||||
Fuel Company five-year, expiring December 2020 | 500.0 | — | 500.0 | — | ||||||||||||
Three-year, expiring December 2018 | 200.0 | — | 200.0 | — | ||||||||||||
Total committed long-term | 2,000.0 | 400.0 | 1,400.0 | 200.0 | ||||||||||||
Outstanding commercial paper (270 or fewer days) | 350.3 | — | 251.6 | 98.7 | ||||||||||||
Weighted average interest rate | — | 1.92 | % | 1.93 | % | |||||||||||
Letters of credit supported by LOC | 3.3 | 3.0 | 0.3 | — | ||||||||||||
Available | $ | 1,646.4 | $ | 397.0 | $ | 1,148.1 | $ | 101.3 |
Commodity and Other Energy Management Contracts (in MMBTU) | |||||||||
Hedge designation | Gas Distribution | Gas Marketing | Total | ||||||
As of March 31, 2018 | |||||||||
Commodity contracts | 6,190,000 | 11,310,000 | 17,500,000 | ||||||
Energy management contracts (a) | — | 34,281,713 | 34,281,713 | ||||||
Total (a) | 6,190,000 | 45,591,713 | 51,781,713 | ||||||
As of December 31, 2017 | |||||||||
Commodity contracts | 6,430,000 | 13,433,000 | 19,863,000 | ||||||
Energy management contracts (a) | — | 41,856,890 | 41,856,890 | ||||||
Total (a) | 6,430,000 | 55,289,890 | 61,719,890 |
Interest Rate Swaps | ||||||||||||||||
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | March 31, 2018 | December 31, 2017 | March 31, 2018 | December 31, 2017 | ||||||||||||
Designated as hedging instruments | $ | 111.2 | $ | 111.2 | $ | 36.4 | $ | 36.4 | ||||||||
Not designated as hedging instruments | 35.0 | 735.0 | 35.0 | 735.0 |
Fair Values of Derivative Instruments | ||||||||||||||||||
The Company | Consolidated SCE&G | |||||||||||||||||
Millions of dollars | Balance Sheet Location | Asset | Liability | Asset | Liability | |||||||||||||
As of March 31, 2018 | ||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||
Interest rate contracts | ||||||||||||||||||
Derivative financial instruments | — | $ | 2 | — | $ | 1 | ||||||||||||
Other deferred credits and other liabilities | — | 20 | — | 7 | ||||||||||||||
Commodity contracts | ||||||||||||||||||
Prepayments | — | 1 | — | — | ||||||||||||||
Total | — | $ | 23 | — | $ | 8 | ||||||||||||
Not designated as hedging instruments | ||||||||||||||||||
Interest rate contracts | ||||||||||||||||||
Other deferred credits and other liabilities | — | $ | 3 | — | $ | 3 | ||||||||||||
Commodity contracts | ||||||||||||||||||
Other current assets | $ | 1 | — | — | — | |||||||||||||
Energy management contracts | ||||||||||||||||||
Prepayments | — | 1 | — | — | ||||||||||||||
Other current assets | 2 | — | — | — | ||||||||||||||
Other deferred debits and other assets | 1 | — | — | — | ||||||||||||||
Derivative financial instruments | — | 2 | — | — | ||||||||||||||
Total | $ | 4 | $ | 6 | — | $ | 3 | |||||||||||
As of December 31, 2017 | ||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||
Interest rate contracts | ||||||||||||||||||
Derivative financial instruments | — | $ | 3 | — | $ | 1 | ||||||||||||
Other deferred credits and other liabilities | — | 24 | — | 9 | ||||||||||||||
Commodity contracts | ||||||||||||||||||
Prepayments | — | 2 | — | — | ||||||||||||||
Other current assets | — | 1 | — | — | ||||||||||||||
Total | — | $ | 30 | — | $ | 10 | ||||||||||||
Not designated as hedging instruments | ||||||||||||||||||
Interest rate contracts | ||||||||||||||||||
Derivative financial instruments | $ | 54 | $ | 1 | $ | 54 | $ | 1 | ||||||||||
Other deferred credits and other liabilities | — | 4 | — | 4 | ||||||||||||||
Commodity contracts | ||||||||||||||||||
Other current assets | 1 | — | — | — | ||||||||||||||
Energy management contracts | ||||||||||||||||||
Prepayments | — | 1 | — | — | ||||||||||||||
Other current assets | 3 | — | — | — | ||||||||||||||
Other deferred debits and other assets | 1 | — | — | — | ||||||||||||||
Derivative financial instruments | — | 2 | — | — | ||||||||||||||
Total | $ | 59 | $ | 8 | $ | 54 | $ | 5 |
The Company and Consolidated SCE&G: | ||||||||||||||||
Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||
Millions of dollars | 2018 | 2017 | Location | 2018 | 2017 | |||||||||||
Three Months Ended March 31, | ||||||||||||||||
Interest rate contracts | $ | 2 | — | Interest expense | — | $ | (1 | ) |
The Company: | ||||||||||||||||||
Gain (Loss) Recognized in OCI, net of tax | Gain (Loss) Reclassified from AOCI into Income, net of tax | |||||||||||||||||
Millions of dollars | 2018 | 2017 | Location | 2018 | 2017 | |||||||||||||
Three Months Ended March 31, | ||||||||||||||||||
Interest rate contracts | $ | 2 | — | Interest expense | $ | (2 | ) | $ | (2 | ) | ||||||||
Commodity contracts | 1 | $ | (2 | ) | Gas purchased for resale | (2 | ) | 2 | ||||||||||
Total | $ | 3 | $ | (2 | ) | $ | (4 | ) | — |
Derivatives Not designated as Hedging Instruments | ||||||||||||||||||
The Company and Consolidated SCE&G: | ||||||||||||||||||
Gain Deferred in Regulatory Accounts | Gain (Loss) Reclassified from Deferred Accounts into Income | |||||||||||||||||
Millions of dollars | 2018 | 2017 | Location | 2018 | 2017 | |||||||||||||
Three Months Ended March 31, | ||||||||||||||||||
Interest rate contracts | $ | 65 | $ | 11 | Interest Expense | — | $ | (1 | ) | |||||||||
Other Income | $ | 115 | — |
Derivative Contracts with Credit Contingent Features | ||||||||||||||||
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | March 31, 2018 | December 31, 2017 | March 31, 2018 | December 31, 2017 | ||||||||||||
in Net Liability Position | ||||||||||||||||
Aggregate fair value of derivatives in net liability position | $ | 26.2 | $ | 33.7 | $ | 10.8 | $ | 14.7 | ||||||||
Fair value of collateral already posted | 27.1 | 28.9 | 10.9 | 10.1 | ||||||||||||
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | $ | (0.9 | ) | $ | 4.8 | $ | (0.1 | ) | $ | 4.6 | ||||||
in Net Asset Position | ||||||||||||||||
Aggregate fair value of derivatives in net asset position | — | $ | 53.5 | — | $ | 53.5 | ||||||||||
Fair value of collateral already posted | — | — | — | — | ||||||||||||
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | — | $ | 53.5 | — | $ | 53.5 |
Derivative Assets | The Company | Consolidated SCE&G | ||||||||||||||||||
Millions of dollars | Interest Rate Contracts | Commodity Contracts | Energy Management Contracts | Total | Interest Rate Contracts | |||||||||||||||
As of March 31, 2018 | ||||||||||||||||||||
Gross Amounts of Recognized Assets | — | $ | 1 | $ | 3 | $ | 4 | — | ||||||||||||
Gross Amounts Offset in Statement of Financial Position | — | — | — | — | — | |||||||||||||||
Net Amounts Presented in Statement of Financial Position | — | 1 | 3 | 4 | — | |||||||||||||||
Gross Amounts Not Offset - Financial Instruments | — | — | — | — | — | |||||||||||||||
Gross Amounts Not Offset - Cash Collateral Received | — | — | — | — | — | |||||||||||||||
Net Amount | — | $ | 1 | $ | 3 | $ | 4 | — | ||||||||||||
Balance sheet location | ||||||||||||||||||||
Other current assets | $ | 3 | — | |||||||||||||||||
Other deferred debits and other assets | 1 | — | ||||||||||||||||||
Total | $ | 4 | — | |||||||||||||||||
As of December 31, 2017 | ||||||||||||||||||||
Gross Amounts of Recognized Assets | $ | 54 | $ | 1 | $ | 4 | $ | 59 | $ | 54 | ||||||||||
Gross Amounts Offset in Statement of Financial Position | — | — | — | — | — | |||||||||||||||
Net Amounts Presented in Statement of Financial Position | 54 | 1 | 4 | 59 | 54 | |||||||||||||||
Gross Amounts Not Offset - Financial Instruments | — | — | — | — | — | |||||||||||||||
Gross Amounts Not Offset - Cash Collateral Received | — | — | — | — | — | |||||||||||||||
Net Amount | $ | 54 | $ | 1 | $ | 4 | $ | 59 | $ | 54 | ||||||||||
Balance sheet location | ||||||||||||||||||||
Other current assets | $ | 58 | $ | 54 | ||||||||||||||||
Other deferred debits and other assets | 1 | — | ||||||||||||||||||
Total | $ | 59 | $ | 54 |
Derivative Liabilities | The Company | Consolidated SCE&G | ||||||||||||||||||
Millions of dollars | Interest Rate Contracts | Commodity Contracts | Energy Management Contracts | Total | Interest Rate Contracts | |||||||||||||||
As of March 31, 2018 | ||||||||||||||||||||
Gross Amounts of Recognized Liabilities | $ | 25 | $ | 1 | $ | 3 | $ | 29 | $ | 11 | ||||||||||
Gross Amounts Offset in Statement of Financial Position | — | — | — | — | — | |||||||||||||||
Net Amounts Presented in Statement of Financial Position | 25 | 1 | 3 | 29 | 11 | |||||||||||||||
Gross Amounts Not Offset - Financial Instruments | — | — | — | — | — | |||||||||||||||
Gross Amounts Not Offset - Cash Collateral Posted | (26 | ) | — | (1 | ) | (27 | ) | (11 | ) | |||||||||||
Net Amount | $ | (1 | ) | $ | 1 | $ | 2 | $ | 2 | $ | — | |||||||||
Balance sheet location | ||||||||||||||||||||
Prepayments | $ | 2 | — | |||||||||||||||||
Derivative financial instruments | 4 | $ | 1 | |||||||||||||||||
Other deferred credits and other liabilities | 23 | 10 | ||||||||||||||||||
Total | $ | 29 | $ | 11 | ||||||||||||||||
As of December 31, 2017 | ||||||||||||||||||||
Gross Amounts of Recognized Liabilities | $ | 32 | $ | 3 | $ | 3 | $ | 38 | $ | 15 | ||||||||||
Gross Amounts Offset in Statement of Financial Position | — | — | (1 | ) | (1 | ) | — | |||||||||||||
Net Amounts Presented in Statement of Financial Position | 32 | 3 | 2 | 37 | 15 | |||||||||||||||
Gross Amounts Not Offset - Financial Instruments | — | — | — | — | — | |||||||||||||||
Gross Amounts Not Offset - Cash Collateral Posted | 28 | — | (1 | ) | 27 | — | ||||||||||||||
Net Amount | $ | 60 | $ | 3 | $ | 1 | $ | 64 | $ | 15 | ||||||||||
Balance sheet location | ||||||||||||||||||||
Other current assets | $ | 2 | — | |||||||||||||||||
Derivative financial instruments | 7 | $ | 2 | |||||||||||||||||
Other deferred credits and other liabilities | 28 | 13 | ||||||||||||||||||
Total | $ | 37 | $ | 15 |
As of March 31, 2018 | As of December 31, 2017 | |||||||||||||||||||||||||||
The Company | Consolidated SCE&G | The Company | Consolidated SCE&G | |||||||||||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 2 | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||
Available for sale securities | $ | 19 | — | — | $ | 119 | — | $ | 100 | — | ||||||||||||||||||
Held to maturity securities | — | $ | 6 | — | — | $ | 6 | — | — | |||||||||||||||||||
Interest rate contracts | — | — | — | — | 54 | — | $ | 54 | ||||||||||||||||||||
Commodity contracts | 1 | — | — | 1 | — | — | — | |||||||||||||||||||||
Energy management contracts | — | 3 | — | — | 4 | — | — | |||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||
Interest rate contracts | — | 25 | $ | 11 | — | 32 | — | 15 | ||||||||||||||||||||
Commodity contracts | 1 | — | — | 2 | 1 | — | — | |||||||||||||||||||||
Energy management contracts | 1 | 4 | — | 1 | 4 | — | — |
Long-Term Debt | March 31, 2018 | December 31, 2017 | ||||||||||||||
Millions of dollars | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
The Company | $ | 6,728.9 | $ | 7,220.1 | $ | 6,632.9 | $ | 7,399.7 | ||||||||
Consolidated SCE&G | 5,259.0 | 5,649.1 | 5,163.3 | 5,790.3 |
The Company | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Three months ended March 31, | ||||||||||||||||
Service cost | $ | 5.0 | $ | 5.3 | $ | 1.2 | $ | 1.2 | ||||||||
Interest cost | 8.5 | 9.4 | 2.7 | 2.9 | ||||||||||||
Expected return on assets | (14.3 | ) | (13.8 | ) | — | — | ||||||||||
Prior service cost amortization | 0.1 | 0.4 | — | — | ||||||||||||
Amortization of actuarial losses | 3.0 | 3.9 | 0.5 | 0.4 | ||||||||||||
Net periodic benefit cost | $ | 2.3 | $ | 5.2 | $ | 4.4 | $ | 4.5 |
Consolidated SCE&G | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Three months ended March 31, | ||||||||||||||||
Service cost | $ | 4.1 | $ | 4.4 | $ | 1.0 | $ | 1.0 | ||||||||
Interest cost | 7.2 | 8.1 | 2.1 | 2.4 | ||||||||||||
Expected return on assets | (12.1 | ) | (11.8 | ) | — | — | ||||||||||
Prior service cost amortization | 0.1 | 0.3 | — | — | ||||||||||||
Amortization of actuarial losses | 2.5 | 3.4 | 0.4 | 0.3 | ||||||||||||
Net periodic benefit cost | $ | 1.8 | $ | 4.4 | $ | 3.5 | $ | 3.7 |
The Company | ||||||||||||||||
Millions of dollars | External Revenue | Intersegment Revenue | Operating Income | Net Income | ||||||||||||
Three Months Ended March 31, 2018 | ||||||||||||||||
Electric Operations | $ | 546 | $ | 1 | $ | 74 | n/a | |||||||||
Gas Distribution | 361 | — | 113 | n/a | ||||||||||||
Gas Marketing | 273 | 31 | n/a | $ | 17 | |||||||||||
All Other | — | 105 | — | (25 | ) | |||||||||||
Adjustments/Eliminations | — | (137 | ) | 2 | 177 | |||||||||||
Consolidated Total | $ | 1,180 | $ | — | $ | 189 | $ | 169 |
Three Months Ended March 31, 2017 | ||||||||||||||||
Electric Operations | $ | 577 | $ | 1 | $ | 182 | n/a | |||||||||
Gas Distribution | 322 | — | 113 | n/a | ||||||||||||
Gas Marketing | 274 | 24 | n/a | $ | 15 | |||||||||||
All Other | — | 94 | — | — | ||||||||||||
Adjustments/Eliminations | — | (119 | ) | 25 | 156 | |||||||||||
Consolidated Total | $ | 1,173 | $ | — | $ | 320 | $ | 171 |
Consolidated SCE&G | ||||||||||||
Millions of dollars | External Revenue | Operating Income | Earnings Available to Common Shareholder | |||||||||
Three Months Ended March 31, 2018 | ||||||||||||
Electric Operations | $ | 547 | $ | 74 | n/a | |||||||
Gas Distribution | 155 | 47 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 124 | ||||||||
Consolidated Total | $ | 702 | $ | 121 | $ | 124 |
Three Months Ended March 31, 2017 | ||||||||||||
Electric Operations | $ | 578 | $ | 182 | n/a | |||||||
Gas Distribution | 141 | 44 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 109 | ||||||||
Consolidated Total | $ | 719 | $ | 226 | $ | 109 |
Segment Assets | The Company | Consolidated SCE&G | ||||||||||||||
March 31, | December 31, | March 31, | December 31, | |||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Electric Operations | $ | 11,876 | $ | 11,979 | $ | 11,876 | $ | 11,979 | ||||||||
Gas Distribution | 3,256 | 3,259 | 883 | 869 | ||||||||||||
Gas Marketing | 227 | 230 | n/a | n/a | ||||||||||||
All Other | 1,199 | 1,042 | n/a | n/a | ||||||||||||
Adjustments/Eliminations | 2,026 | 2,229 | 3,190 | 3,098 | ||||||||||||
Consolidated Total | $ | 18,584 | $ | 18,739 | $ | 15,949 | $ | 15,946 |
The Company | Consolidated SCE&G | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Revenues from contracts with customers | $ | 5 | $ | — | $ | 1 | $ | — | ||||||||
Other income | 129 | 17 | 126 | 8 | ||||||||||||
Other expense | (10 | ) | (14 | ) | (7 | ) | (10 | ) | ||||||||
Allowance for equity funds used during construction | 4 | 9 | 3 | 9 | ||||||||||||
Other income (expense), net | $ | 128 | $ | 12 | $ | 123 | $ | 7 |
Three Months Ended March 31, | ||||||||
Millions of Dollars | 2018 | 2017 | ||||||
Purchases from Canadys Refined Coal, LLC | $ | 32.5 | $ | 44.6 | ||||
Sales to Canadys Refined Coal, LLC | 32.3 | 44.4 |
Millions of Dollars | March 31, 2018 | December 31, 2017 | ||||||
Receivable from Canadys Refined Coal, LLC | $ | 9.9 | $ | 4.9 | ||||
Payable to Canadys Refined Coal, LLC | 10.0 | 4.9 |
Three Months Ended March 31, | ||||||||
Millions of Dollars | 2018 | 2017 | ||||||
Purchases from SCANA Energy | $ | 31.3 | $ | 23.9 | ||||
Direct and Allocated Costs from SCANA Services | 59.4 | 72.5 |
Millions of Dollars | March 31, 2018 | December 31, 2017 | ||||||
Payable to SCANA Energy | $ | 8.1 | $ | 10.0 | ||||
Payable to SCANA Services | 36.7 | 42.0 |
The Company | 2018 | 2017 | ||||||
Earnings per share | $ | 1.18 | $ | 1.19 | ||||
Consolidated SCE&G | ||||||||
Net income (millions of dollars) | $ | 127.7 | $ | 112.3 |
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues | $ | 547.4 | $ | 578.5 | $ | 547.4 | $ | 578.5 | ||||||||
Fuel used in electric generation | 159.3 | 136.4 | 159.3 | 136.4 | ||||||||||||
Purchased power | 52.1 | 11.1 | 52.1 | 11.1 | ||||||||||||
Other operation and maintenance | 125.1 | 120.9 | 128.5 | 124.5 | ||||||||||||
Impairment loss | 3.6 | — | 3.6 | — | ||||||||||||
Depreciation and amortization | 75.9 | 73.0 | 73.0 | 70.0 | ||||||||||||
Other taxes | 57.3 | 54.7 | 56.8 | 54.1 | ||||||||||||
Operating Income | $ | 74.1 | $ | 182.4 | $ | 74.1 | $ | 182.4 |
• | Operating revenues decreased by $113.7 million in 2018 pursuant to a previously received SCPSC order whereby fuel cost recovery is offset with gains realized upon the settlement of certain interest rate derivative contracts, as further described in Other Income (Expense) below. Operating revenues also decreased by $25.6 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act, lower collections under the rate rider for pension costs of $2.3 million and lower residential and commercial average use of $1.9 million. The downward adjustment related to fuel cost recovery had no effect on net income as it was fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts. The lower pension rider collections had no impact on net income as they were fully offset by the recognition, within other operation and maintenance expenses and other expense, of lower pension costs. These revenue decreases were partially offset by the effects of weather of $48.7 million, residential and commercial growth of $6.5 million, industrial growth and higher usage of $2.6 million, higher revenue recognized under the DER program of $2.1 million and higher fuel cost recovery of $48.3 million. |
• | Fuel used in electric generation and purchased power expenses increased due to higher fuel prices of $48.3 million, higher amortization of DER program costs of $1.6 million, increased sales volumes associated with residential and commercial customer growth of $1.4 million, higher industrial usage of $0.8 million, higher sales volumes associated with the effects of weather of $10.6 million and higher fuel handling expenses of $1.4 million. These increases were partially offset by lower residential and commercial average use of $0.2 million. |
• | Other operation and maintenance expenses increased due to wind down costs associated with the abandonment of the Nuclear Project of $3.7 million. |
• | Impairment loss represents the writedown of nuclear fuel acquired for use in Unit 2 and Unit 3 to its estimated fair value. |
• | Depreciation and amortization increased primarily due to net plant additions. |
• | Other taxes increased primarily due to higher property taxes associated with net plant additions. |
Classification | 2018 | 2017 | ||||
Residential | 1,987 | 1,636 | ||||
Commercial | 1,704 | 1,635 | ||||
Industrial | 1,489 | 1,459 | ||||
Other | 131 | 134 | ||||
Total Retail Sales | 5,311 | 4,864 | ||||
Wholesale | 242 | 213 | ||||
Total Sales | 5,553 | 5,077 |
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues | $ | 361.0 | $ | 322.1 | $ | 154.6 | $ | 140.9 | ||||||||
Gas purchased for resale | 170.6 | 134.8 | 75.4 | 65.9 | ||||||||||||
Other operation and maintenance | 42.0 | 42.4 | 17.3 | 17.3 | ||||||||||||
Depreciation and amortization | 22.9 | 20.8 | 7.5 | 7.0 | ||||||||||||
Other taxes | 12.1 | 10.9 | 8.1 | 7.2 | ||||||||||||
Operating Income | $ | 113.4 | $ | 113.2 | $ | 46.3 | $ | 43.5 |
• | Operating revenues increased at SCE&G primarily due to increased base rates under the RSA of $4.6 million, customer growth of $3.8 million, higher average use of $1.2 million and higher gas cost recovery of $6.7 million. These increases were partially offset by a decrease of $3.3 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act. In addition to these factors, operating revenues at the Company increased due to colder weather at PSNC Energy of $53.9 million and customer growth of $5.0 million. These increases were partially offset by a CUT adjustment of $17.8 million, decreased cost of gas recoveries of $14.3 million and $6.7 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act. |
• | Gas purchased for resale at SCE&G reflects increased sales volumes due to weather of $12.6 million, firm customer growth of $1.8 million and higher average use of $1.1 million. These increases were partially offset by lower gas prices of $5.9 million. In addition to these factors, gas purchased for resale at the Company reflects increased sales volumes due to weather at PSNC of $27.0 million, customer growth of $2.4 million, and the effect of a CUT adjustment that decreased gas purchased for resale by $9.0 million in 2017. These increases were partially offset by decreased gas costs of $14.3 million. |
• | Depreciation and amortization increased primarily due to net plant additions. |
• | Other taxes increased primarily due to higher property taxes associated with net plant additions. |
The Company | Consolidated SCE&G | |||||||||||
Classification (in thousands) | 2018 | 2017 | 2018 | 2017 | ||||||||
Residential | 23,189 | 16,560 | 7,035 | 4,905 | ||||||||
Commercial | 12,057 | 9,469 | 4,418 | 3,752 | ||||||||
Industrial | 5,507 | 5,322 | 4,650 | 4,654 | ||||||||
Transportation | 12,147 | 10,954 | 1,502 | 1,556 | ||||||||
Total | 52,900 | 42,305 | 17,605 | 14,867 |
Millions of dollars | 2018 | 2017 | ||||||
Operating revenues | $ | 304.1 | $ | 298.0 | ||||
Net income | 17.0 | 15.1 |
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Other operation and maintenance | $ | 200.8 | $ | 175.2 | $ | 145.8 | $ | 141.8 | ||||||||
Impairment loss | 3.6 | — | 3.6 | — | ||||||||||||
Depreciation and amortization | 99.2 | 94.4 | 80.5 | 77.0 | ||||||||||||
Other taxes | 69.9 | 65.9 | 64.9 | 61.3 |
The Company | Consolidated SCE&G | |||||||||||||||
Millions of dollars | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Other income | $ | 134.0 | $ | 17.0 | $ | 127.4 | $ | 7.7 | ||||||||
Other expense | (10.5 | ) | (13.7 | ) | (6.9 | ) | (9.5 | ) | ||||||||
AFC - equity funds | 4.2 | 9.1 | 2.9 | 8.6 |
Expected Maturity | 2018 | 2019 | 2020 | ||||||
Futures - Long | |||||||||
Settlement Price (a) | 2.86 | 2.92 | 2.95 | ||||||
Contract Amount (b) | 32.3 | 22.2 | 0.7 | ||||||
Fair Value (b) | 31.8 | 21.8 | 0.7 | ||||||
Futures - Short | |||||||||
Settlement Price (a) | 2.80 | — | — | ||||||
Contract Amount (b) | 2.1 | — | — | ||||||
Fair Value (b) | 2.1 | — | — | ||||||
Options - Purchased Call (Long) | |||||||||
Strike Price (a) | 3.06 | 3.13 | — | ||||||
Contract Amount (b) | 10.3 | 8.9 | — | ||||||
Fair Value (b) | 0.4 | 0.7 | — | ||||||
Swaps - Commodity | |||||||||
Pay fixed/receive variable (b) | 9.0 | 7.0 | 3.1 | ||||||
Average pay rate (a) | 3.2275 | 2.9260 | 2.8725 | ||||||
Average received rate (a) | 2.8484 | 2.8411 | 2.7870 | ||||||
Fair value (b) | 8.0 | 6.8 | 3.0 | ||||||
Pay variable/receive fixed (b) | 20.7 | 14.9 | 2.8 | ||||||
Average pay rate (a) | 2.8512 | 2.8410 | 2.7894 | ||||||
Average received rate (a) | 3.0724 | 2.9137 | 2.8758 | ||||||
Fair value (b) | 22.3 | 15.3 | 2.9 | ||||||
Swaps - Basis | |||||||||
Pay variable/receive variable (b) | 0.4 | 0.3 | — | ||||||
Average pay rate (a) | 2.8855 | 3.0809 | — | ||||||
Average received rate (a) | 2.8071 | 3.0111 | — | ||||||
Fair value (b) | 0.4 | 0.3 | — | ||||||
(a) Weighted average, in dollars | |||||||||
(b) Millions of dollars |
ITEM 4. | CONTROLS AND PROCEDURES |
• | the price of SCANA common stock may decline to the extent that the current market price reflects an expectation by the market that the merger will be completed; |
• | obligations to pay certain costs relating to the merger, such as legal, accounting, financial advisory, filing, proxy solicitation, printing and mailing fees; |
• | the disruption of the Company’s and Consolidated SCE&G’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies due to management’s focus on the merger, any of which could adversely affect the ability of the Company and Consolidated SCE&G to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect the business and financial results of the Company or Consolidated SCE&G, without realizing any of the benefits of having the merger completed; |
• | the potential negative impact on the Company and Consolidated SCE&G ultimately resolving the rate and regulatory issues, including pending investigations and legal challenges, relating to the abandonment of the Nuclear Project in a manner satisfactory to SCANA on account of SCANA working with Dominion Energy to pursue the resolution of these issues as contemplated by the Merger Agreement rather than pursuing its regulatory and legal options for resolving these issues independently of considerations and obligations related to the merger; and |
• | the loss of other opportunities that could be beneficial to the Company and Consolidated SCE&G that could have been pursued during the pendency of the merger, without realizing any of the benefits of having the merger completed. |
• | the complexities associated with integrating SCANA and its utility businesses, while at the same time continuing to provide consistent, high quality services; |
• | the complexities of integrating a company with different core services, markets and customers; |
• | the inability to attract and retain key employees; |
• | potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger; |
• | difficulties in managing political and regulatory conditions related to SCANA’s utility businesses after the merger; |
• | the cost recovery plan includes a moratorium on filing requests for adjustments in SCANA’s base electric rates until 2021 if the merger is approved by the SCPSC, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; and |
• | performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses. |
• | The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; |
• | Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States; |
• | The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States; |
• | Uncertainties with respect to procurement of nuclear fuel and suppliers thereof, fabrication of nuclear fuel and related vendors, and the storage of spent nuclear fuel; |
• | Uncertainties with respect to contingencies if insurance coverage is inadequate; |
• | Uncertainties with respect to possible future increased regulation of nuclear facilities and nuclear generation, and related costs thereof; and |
• | Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives. |
Issuer Purchases of Equity Securities | ||||||||||||
(a) | (b) | (c) | (d) | |||||||||
Period | Total number of shares (or units) purchased | Average price paid per share (or unit) | Total number of shares (or units) purchased as part of publicly announced plans or programs | Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs | ||||||||
January 1 - 31 | 8,928 | $ | 42.14 | 8,928 | ||||||||
February 1 - 28 | — | — | — | |||||||||
March 1 - 31 | — | — | — | |||||||||
Total | 8,928 | 8,928 | * |
Applicable to Form 10-Q of | |||
Exhibit No. | SCANA | SCE&G | Description |
2.01* | X | Agreement and Plan of Merger by and among Dominion Energy, Sedona, and SCANA, dated as of January 2, 2018 (Filed as Exhibit 2.1 to Form 8-K on January 5, 2018 (File No. 001-08809 (SCANA)) and incorporated by reference herein) | |
3.01 | X | Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | |
3.02 | X | Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-A to Registration Statement No. 33-62421 and incorporated by reference herein) | |
3.03 | X | Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein) | |
3.04 | X | Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein) | |
3.05 | X | By-Laws of SCANA as amended and restated as of December 30, 2016 (Filed as Exhibit 3.05 to Form 10-K for the period ended December 31, 2016 (File No. 001-08809) and incorporated by reference herein) | |
3.06 | X | By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein) | |
12.01 | X | X | Statement Re Computation of Ratios (Filed herewith) |
31.01 | X | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |
31.02 | X | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |
31.03 | X | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |
31.04 | X | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |
32.01 | X | ||
32.02 | X | ||
101. INS** | X | X | XBRL Instance Document |
101. SCH** | X | X | XBRL Taxonomy Extension Schema |
101. CAL** | X | X | XBRL Taxonomy Extension Calculation Linkbase |
101. DEF** | X | X | XBRL Taxonomy Extension Definition Linkbase |
101. LAB** | X | X | XBRL Taxonomy Extension Label Linkbase |
101. PRE** | X | X | XBRL Taxonomy Extension Presentation Linkbase |
SCANA CORPORATION |
SOUTH CAROLINA ELECTRIC & GAS COMPANY |
(Registrants) |
By: | /s/James E. Swan, IV | |
Date: April 30, 2018 | James E. Swan, IV | |
Vice President and Controller | ||
(Principal accounting officer) |
SCANA: | Three Months Ended March 31, 2018 | Twelve Months Ended March 31, 2018 | Years ended December 31, | |||||||||||||||||||||
Dollars in Millions | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||||||
Fixed Charges as defined: | ||||||||||||||||||||||||
Interest on debt | $98.7 | $383.5 | $377.6 | $356.8 | $327.8 | $318.2 | $305.9 | |||||||||||||||||
Amortization of debt premium, discount and expense (net) | 1.0 | 4.0 | 4.0 | 4.5 | 4.7 | 9.7 | 5.3 | |||||||||||||||||
Interest component on rentals | 0.8 | 3.3 | 3.3 | 3.5 | 3.7 | 4.1 | 4.9 | |||||||||||||||||
Total Fixed Charges (A) | $100.5 | $390.8 | $384.9 | $364.8 | $336.2 | $332.0 | $316.1 | |||||||||||||||||
Earnings as defined: | ||||||||||||||||||||||||
Pretax income (loss) from continuing operations | $219.6 | ($256.0) | ($230.7) | $865.6 | $1,138.4 | $786.0 | $693.8 | |||||||||||||||||
Total fixed charges above | 100.5 | 390.8 | 384.9 | 364.8 | 336.2 | 332.0 | 316.1 | |||||||||||||||||
Pretax equity in (earnings) losses of investees | 0.9 | 9.6 | 8.9 | (0.7 | ) | 0.8 | (1.4 | ) | (3.2 | ) | ||||||||||||||
Cash distributions from equity investees | — | 1.9 | 2.7 | 3.7 | 4.0 | 7.4 | 9.6 | |||||||||||||||||
Total Earnings (B) | $321.0 | $146.3 | $165.8 | $1,233.4 | $1,479.4 | $1,124.0 | $1,016.3 | |||||||||||||||||
Ratio of Earnings to Fixed Charges (B/A) | 3.19 | 0.37 | 0.43 | 3.38 | 4.40 | 3.39 | 3.22 | |||||||||||||||||
Amount of Earnings Deficiency Below Fixed Charges | $244.5 | $219.1 |
SCE&G: | Three Months Ended March 31, 2018 | Twelve Months Ended March 31, 2018 | Years ended December 31, | |||||||||||||||||||||
Dollars in Millions | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||||||
Fixed Charges as defined: | ||||||||||||||||||||||||
Interest on debt | $78.5 | $304.4 | $300.2 | $284.6 | $258.4 | $237.6 | $226.4 | |||||||||||||||||
Amortization of debt premium, discount and expense (net) | 0.7 | 2.9 | 2.9 | 3.5 | 3.7 | 4.4 | 4.2 | |||||||||||||||||
Interest component on rentals | 0.9 | 3.8 | 3.8 | 4.0 | 4.1 | 4.0 | 4.5 | |||||||||||||||||
Total Fixed Charges (A) | $80.1 | $311.1 | $306.9 | $292.1 | $266.2 | $246.0 | $235.1 | |||||||||||||||||
Earnings as defined: | ||||||||||||||||||||||||
Pretax income (loss) from continuing operations | $166.9 | ($339.5 | ) | ($342.6 | ) | $774.1 | $711.0 | $676.0 | $579.7 | |||||||||||||||
Total fixed charges above | 80.1 | 311.1 | 306.9 | 292.1 | 266.2 | 246.0 | 235.1 | |||||||||||||||||
Pretax equity in losses of investees | 1.3 | 5.1 | 4.6 | 3.1 | 5.0 | 5.3 | 3.5 | |||||||||||||||||
Total Earnings (B) | $248.3 | ($23.3 | ) | ($31.1) | $1069.3 | $982.2 | $927.3 | $818.3 | ||||||||||||||||
Ratio of Earnings to Fixed Charges (B/A) | 3.10 | (0.07) | (0.10) | 3.66 | 3.69 | 3.77 | 3.48 | |||||||||||||||||
Amount of Earnings Deficiency Below Fixed Charges | $334.4 | $338.0 |
1. | I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: April 30, 2018 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Chief Executive Officer and President |
1. | I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: April 30, 2018 | |
/s/Iris N. Griffin | |
Iris N. Griffin | |
Senior Vice President and Chief Financial Officer |
1. | I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: April 30, 2018 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Chief Executive Officer |
1. | I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: April 30, 2018 | |
/s/Iris N. Griffin | |
Iris N. Griffin | |
Senior Vice President and Chief Financial Officer |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: April 30, 2018 | ||
/s/Jimmy E. Addison | /s/Iris N. Griffin | |
Jimmy E. Addison | Iris N. Griffin | |
Chief Executive Officer and President | Senior Vice President and Chief Financial Officer |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: April 30, 2018 | ||
/s/Jimmy E. Addison | /s/Iris N. Griffin | |
Jimmy E. Addison | Iris N. Griffin | |
Chief Executive Officer | Senior Vice President and Chief Financial Officer |
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Document and Entity Information Document - shares |
3 Months Ended | |
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Mar. 31, 2018 |
Apr. 24, 2018 |
|
Entity Information [Line Items] | ||
Entity Registrant Name | SCANA Corporation | |
Entity Central Index Key | 0000754737 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 142,628,142 | |
SCEG | ||
Entity Information [Line Items] | ||
Entity Registrant Name | SOUTH CAROLINA ELECTRIC & GAS CO | |
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, 2018 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 40,296,147 |
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions |
Mar. 31, 2018 |
Dec. 31, 2017 |
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Common Stock, Shares, Outstanding | 143.0 | 143.0 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 137 | $ 133 |
Public Utilities, Property, Plant and Equipment, Net | 10,694 | 10,648 |
Allowance for Doubtful Accounts Receivable, Current | 7 | 6 |
Write-down, Goodwill | 230 | 230 |
Assets, Current | 1,447 | 1,851 |
Regulated Entity, Other Assets, Noncurrent | $ 5,868 | $ 5,766 |
SCEG | ||
Common Stock, Shares, Outstanding | 40.3 | 40.3 |
Public Utilities, Property, Plant and Equipment, Net | $ 8,634 | $ 8,620 |
Allowance for Doubtful Accounts Receivable, Current | 4 | 4 |
Assets, Current | 1,263 | 1,477 |
Regulated Entity, Other Assets, Noncurrent | 5,846 | 5,640 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 691 | 711 |
Assets, Current | 110 | 191 |
Regulated Entity, Other Assets, Noncurrent | $ 34 | $ 50 |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
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Mar. 31, 2018 |
Mar. 31, 2017 |
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Allowance for Funds Used During Construction, Capitalized Interest | $ 3 | $ 6 |
SCEG | ||
Allowance for Funds Used During Construction, Capitalized Interest | $ 4 | $ 3 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
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Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $ 1 | $ (1) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 1 | 1 |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax | 1 | (1) |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax | $ 0 | $ 0 |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Interest Paid, Capitalized | $ 3 | $ 6 |
SCEG | ||
Interest Paid, Capitalized | $ 2 | $ 6 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] |
Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed 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 SCE&G 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 approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 32% and 39% of PSNC Energy’s natural gas inventory at March 31, 2018 and December 31, 2017, respectively, with a carrying value of $5.5 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019. Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. Reclassifications In the statement of operations, amounts previously reported under the captions “Other income”, “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net”. Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated.
In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost components, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. Amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.
Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further, and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G currently intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G are evaluating, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable continues. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Preliminary system configuration has been completed and data from certain leases are being entered. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019, though early adoption is permitted, and have not determined what impact such adoption will have on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G must adopt this guidance beginning in 2019, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position. No impact is expected on statements of operations or cash flows. |
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SCEG | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] |
Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed 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 SCE&G 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 approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 32% and 39% of PSNC Energy’s natural gas inventory at March 31, 2018 and December 31, 2017, respectively, with a carrying value of $5.5 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019. Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. Reclassifications In the statement of operations, amounts previously reported under the captions “Other income”, “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net”. Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. New Accounting Matters Recently Adopted In the first quarter of 2018, the Company and Consolidated SCE&G adopted the following accounting guidance, as applicable, issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated.
In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost components, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs, and the adoption of this guidance did not result in a material impact on the Company’s and Consolidated SCE&G’s respective financial statements. Amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.
Pending Adoption The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below. In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further, and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In the first quarter of 2018, FASB amended this accounting guidance to clarify that land easements are within the scope of the new guidance and to provide an optional transition practical expedient, that the Company and Consolidated SCE&G currently intend to adopt, that allows adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases. FASB also approved a new transition option in the first quarter of 2018, that the Company and Consolidated SCE&G are evaluating, that will allow the new standard to be adopted without revising comparative period reporting or disclosures. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the location on their respective statements of operations where certain expenses are recorded. No impact on net income is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable continues. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Preliminary system configuration has been completed and data from certain leases are being entered. In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and in certain instances may result in impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements. In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2019, though early adoption is permitted, and have not determined what impact such adoption will have on their respective financial statements. In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied either in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G must adopt this guidance beginning in 2019, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position. No impact is expected on statements of operations or cash flows. |
RATE AND OTHER REGULATORY MATTERS |
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Schedule of Regulatory Assets and Liabilities [Text Block] | RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act contained provisions that lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. SCE&G and PSNC Energy provided to their respective commissions the requested information. The ORS filed a petition with the SCPSC that, among other things, requested that the SCPSC order that rates in effect as of January 1, 2018, be subject to refund so that ratepayers receive the benefit of the tax law changes as of January 1, 2018. The ORS has made subsequent filings with the SCPSC making specific recommendations for how it should direct SCE&G to account for the effects of the Tax Act and for the accrual of interest on deferred amounts until new customer rates are made effective. On April 25, 2018, the SCPSC issued an order that requires utilities to track and defer as a regulatory liability the effects resulting from the Tax Act. SCE&G and PSNC Energy cannot determine when their respective commissions will take final action on this matter or what form that action will take. In the first quarter of 2018, estimates of income tax amounts charged through customer rates that relate to the effects of the Tax Act are being deferred as amounts subject to refund. Such deferrals include the accrual of estimated carrying costs. Such estimates totaled $40.0 million for the Company, of which $33.2 million was attributable to Consolidated SCE&G, and are included within Customer Deposits and Customer Prepayments on their respective condensed consolidated balance sheets. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators. Electric - Cost of Fuel On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved SCE&G’s increase to certain environmental, avoided capacity and DER cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel costs recovery with the gains realized from the settlement of certain interest rate derivatives. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Electric - Base Rates In January 2018, SCE&G requested in its annual DSM Programs filing to recover approximately $33.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 25, 2018, the SCPSC approved SCE&G’s request effective beginning with the first billing cycle of May 2018. Electric - BLRA and Joint Petition On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. A hearing on this matter has not yet been scheduled. On January 19, 2018, the ORS filed a report with the SCPSC in response to the SCPSC's order for a thorough inspection and audit of SCE&G's statements regarding potential adverse effects that could result from the removal of annual BLRA revenues. SCE&G subsequently filed responses to the ORS report. On January 31, 2018, the SCPSC ordered the ORS to complete the previously ordered thorough audit, inspection and examination of SCE&G's accounting records by March 30, 2018, encouraged them to employ the assistance of a utility financial professional if needed, and indicated that a request by the ORS for an extension of time would not be considered unreasonable. On February 7, 2018, the ORS requested clarification of the SCPSC's January 31, 2018 order. On February 15, 2018, the SCPSC instructed the ORS to evaluate a total of eight different scenarios to be included in its report and instructed the ORS to inform them by March 2, 2018 whether the ORS needed additional time to complete its work, By letter dated March 2, 2018, the ORS informed the SCPSC that it anticipates completing its scope of work in June 2018. Gas - PSNC Energy The NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy has filed biannual applications to adjust its rates for this purpose, and the NCUC has approved those applications for the incremental annual revenue requirements, as follows:
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, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, 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.
Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC 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 unrecovered nuclear project costs that are the subject of regulatory proceedings as further discussed in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts that are embodied in rate orders or current state law. The costs are currently not being recovered, but are expected to be recovered 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, the Company or Consolidated SCE&G 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 the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and of certain assets that have been or will be placed in service. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 107 years. Employee benefit plan costs of the regulated utilities 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 SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of 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. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of March 31, 2018 costs of $30.6 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 17 years, and PSNC Energy's remediation costs totaling $6.9 million are being recovered over a five year period that will end in 2021. Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047. Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement, net of certain expenses. The SCPSC is expected to determine how SCE&G's customers will realize the value of these net proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see Note 10). Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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 approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. |
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Schedule of Regulatory Assets and Liabilities [Text Block] | RATE AND OTHER REGULATORY MATTERS Rate Matters Tax Act Regulatory Proceedings The Tax Act contained provisions that lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and the NCUC have sought information from utilities under their respective jurisdictions that would disclose the impact of the Tax Act on their individual company's operations and would propose procedures for changing customer rates to reflect those impacts. SCE&G and PSNC Energy provided to their respective commissions the requested information. The ORS filed a petition with the SCPSC that, among other things, requested that the SCPSC order that rates in effect as of January 1, 2018, be subject to refund so that ratepayers receive the benefit of the tax law changes as of January 1, 2018. The ORS has made subsequent filings with the SCPSC making specific recommendations for how it should direct SCE&G to account for the effects of the Tax Act and for the accrual of interest on deferred amounts until new customer rates are made effective. On April 25, 2018, the SCPSC issued an order that requires utilities to track and defer as a regulatory liability the effects resulting from the Tax Act. SCE&G and PSNC Energy cannot determine when their respective commissions will take final action on this matter or what form that action will take. In the first quarter of 2018, estimates of income tax amounts charged through customer rates that relate to the effects of the Tax Act are being deferred as amounts subject to refund. Such deferrals include the accrual of estimated carrying costs. Such estimates totaled $40.0 million for the Company, of which $33.2 million was attributable to Consolidated SCE&G, and are included within Customer Deposits and Customer Prepayments on their respective condensed consolidated balance sheets. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of these amounts are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of these amounts will be amortized to the benefit of customers over a prescribed period as instructed by regulators. Electric - Cost of Fuel On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved SCE&G’s increase to certain environmental, avoided capacity and DER cost components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel costs recovery with the gains realized from the settlement of certain interest rate derivatives. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Electric - Base Rates In January 2018, SCE&G requested in its annual DSM Programs filing to recover approximately $33.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 25, 2018, the SCPSC approved SCE&G’s request effective beginning with the first billing cycle of May 2018. Electric - BLRA and Joint Petition On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. A hearing on this matter has not yet been scheduled. On January 19, 2018, the ORS filed a report with the SCPSC in response to the SCPSC's order for a thorough inspection and audit of SCE&G's statements regarding potential adverse effects that could result from the removal of annual BLRA revenues. SCE&G subsequently filed responses to the ORS report. On January 31, 2018, the SCPSC ordered the ORS to complete the previously ordered thorough audit, inspection and examination of SCE&G's accounting records by March 30, 2018, encouraged them to employ the assistance of a utility financial professional if needed, and indicated that a request by the ORS for an extension of time would not be considered unreasonable. On February 7, 2018, the ORS requested clarification of the SCPSC's January 31, 2018 order. On February 15, 2018, the SCPSC instructed the ORS to evaluate a total of eight different scenarios to be included in its report and instructed the ORS to inform them by March 2, 2018 whether the ORS needed additional time to complete its work, By letter dated March 2, 2018, the ORS informed the SCPSC that it anticipates completing its scope of work in June 2018. Gas - PSNC Energy The NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy has filed biannual applications to adjust its rates for this purpose, and the NCUC has approved those applications for the incremental annual revenue requirements, as follows:
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, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Except for certain unrecovered nuclear project costs and other unrecovered plant, 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.
Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC 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 unrecovered nuclear project costs that are the subject of regulatory proceedings as further discussed in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts that are embodied in rate orders or current state law. The costs are currently not being recovered, but are expected to be recovered 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, the Company or Consolidated SCE&G 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 the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded. Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and of certain assets that have been or will be placed in service. AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 107 years. Employee benefit plan costs of the regulated utilities 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 SCPSC regulatory orders. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees up to approximately 11 years. Deferred losses or gains on interest rate derivatives represent (i) the effective portions of 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. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through approximately 2025. Unamortized amounts are included in rate base and are earning a current return. DSM Programs represent SCE&G's deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Pipeline integrity management costs represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of March 31, 2018 costs of $30.6 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs annually. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 17 years, and PSNC Energy's remediation costs totaling $6.9 million are being recovered over a five year period that will end in 2021. Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047. Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement, net of certain expenses. The SCPSC is expected to determine how SCE&G's customers will realize the value of these net proceeds in connection with its consideration of the Request by the ORS and the Joint Petition (see Note 10). Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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 approximately 85 years). See also Note 6. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. |
REVENUE RECOGNITION Notes |
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Revenue from Contract with Customer [Text Block] | REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice, and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product, or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 12). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further disclosed in Note 12. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed revenue disclosures are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:
Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase customer bills when weather is milder than normal and decrease customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas-regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts, and is shown as Other revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, the impact of weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:
Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the condensed consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs are amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows:
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Revenue from Contract with Customer [Text Block] | REVENUE RECOGNITION Identifying Revenue Streams and Related Performance Obligations Operating Revenues Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC. Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies. Performance obligations which have not been satisfied by the Company or Consolidated SCE&G relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&G for these charges is equal to the amount of consideration they have a right to invoice, and corresponds directly to the value transferred to the customer. As a result, amounts related to performance obligations that have not been fully satisfied are not disclosed. Contracts governing the transactions above do not have a significant financing component. Also, due to the nature of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billed to customers are excluded from the transaction price. Such amounts are recorded as liabilities until they are remitted to the respective taxing authority and are not included in revenues or expenses in the statements of operations. Non-Operating Revenues Non-operating revenues are derived from the sale of appliances and water heaters, as well as from contracts covering the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognized to be incentives for the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues. Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advance of the period of coverage. Additional charges for service calls and non-covered repairs are billed and collected at the time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, which corresponds to timing of the value received by the customer. The point at which the customer controls the use of a purchased product, or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material. Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 12). Such revenues are outside the scope of revenues from contracts with customers. Non-operating revenues are further disclosed in Note 12. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed revenue disclosures are not provided. Significant Judgments and Estimates Electricity and natural gas are sold and delivered to the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date but which are to be invoiced in the normal cycle. Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:
Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas regulated on the statements of operations, consistent with revenues from underlying tariff based sales. Adjustments for SCE&G’s WNA increase customer bills when weather is milder than normal and decrease customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recorded as operating revenue, are deferred within regulatory assets until customers are subsequently billed for the excess with the approval of the SCPSC. PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrement to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period. Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas-regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts, and is shown as Other revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues. Disaggregation of Revenues The impact of several factors on the amount, timing and uncertainty of operating revenues and cash flows can vary significantly by customer class. For electric revenues and nonregulated gas revenues, which do not have weather normalization mechanisms in place, the impact of weather and conservation measures on energy usage typically affect residential and commercial customers to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff rates approved by regulatory bodies and often vary by customer class. Also, certain cost recovery and other mechanisms may have an uneven impact on a particular customer class depending on the underlying tariffs affected. For nonregulated gas, revenues are impacted by competitive market rates tailored to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:
Contract Costs Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&G provides economic development grants intended to support economic growth within SCE&G’s electric service territory and defers such grants as regulatory assets on the condensed consolidated balance sheet. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G, they are considered costs to obtain that underlying contract. Such costs are amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years. Balances and activity related to contract costs deferred as regulatory assets were as follows:
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COMMON EQUITY |
3 Months Ended |
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Mar. 31, 2018 | |
Common Equity Note [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | SCANA had 200 million shares of common stock authorized as of March 31, 2018 and December 31, 2017. |
SCEG | |
Common Equity Note [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | Authorized shares of SCE&G common stock were 50 million as of March 31, 2018 and December 31, 2017. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were issued and outstanding as of March 31, 2018 and December 31, 2017. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending. SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (which is defined as the excess of net assets over capital) 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, 2018 and 2017, retained earnings of approximately $95.3 million and $80.6 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of March 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million. |
LONG-TERM AND SHORT-TERM DEBT |
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Long-term Debt [Text Block] | LONG-TERM DEBT AND LIQUIDITY Long-term Debt Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows:
In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at March 31, 2018 was 2.97%, and this draw is classified as long term debt. Proceeds from the draw were deposited with a natural gas supplier to provide contractually required credit support. The interest rate on this deposit currently exceeds the interest rate on the draw. Also, in February 2018 SCANA issued a $43.4 million letter of credit in favor of a natural gas supplier to provide contractually required credit support. Portions of the proceeds received under or arising from the monetization of the Toshiba Settlement in late September and early October 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt to fund such requirement. However, were the SCPSC to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered nuclear project costs would be adversely impacted (see Note 2). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 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. Consolidated SCE&G 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. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $197 million and investments due from an affiliate of $149 million at March 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money poo1 borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables. |
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Long-term Debt [Text Block] | LONG-TERM DEBT AND LIQUIDITY Long-term Debt Substantially all electric utility plant is pledged as collateral in connection with long-term debt. Liquidity Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows:
In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at March 31, 2018 was 2.97%, and this draw is classified as long term debt. Proceeds from the draw were deposited with a natural gas supplier to provide contractually required credit support. The interest rate on this deposit currently exceeds the interest rate on the draw. Also, in February 2018 SCANA issued a $43.4 million letter of credit in favor of a natural gas supplier to provide contractually required credit support. Portions of the proceeds received under or arising from the monetization of the Toshiba Settlement in late September and early October 2017 have been utilized to repay maturing commercial paper balances, which short-term borrowings had been incurred for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction (see Note 10). Should the SCPSC or a court direct that these proceeds be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would issue commercial paper, draw on its credit facilities or issue long-term debt to fund such requirement. However, were the SCPSC to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered nuclear project costs would be adversely impacted (see Note 2). Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities. Borrowing costs for long-term debt issuances could also be impacted. Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 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. Consolidated SCE&G 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. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $197 million and investments due from an affiliate of $149 million at March 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money poo1 borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its condensed consolidated balance sheet, Consolidated SCE&G includes money pool borrowings within Affiliated payables and money pool investments within Affiliated companies receivables. |
INCOME TAXES |
3 Months Ended |
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Mar. 31, 2018 | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | 6. INCOME TAXES The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The Company’s federal returns through 2007 are closed. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. The IRS is also currently examining SCANA's federal returns for years 2010 through 2016 as a result of those claims. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company expects to claim similar deductions and credits in its 2017 tax return when it is filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2016 income tax returns, and it is expected that the IRS will also examine later returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G anticipate that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of March 31, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits. As of March 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2018 (see Note 10). In connection with the research and experimentation deduction and credit claims reflected on the 2015 and 2016 income tax returns and similar claims made in determining taxable income for 2017, and under the terms of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years (see Note 2). However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017. Also under the terms of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset through December 31, 2017 and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $4.5 million and interest income of $0.7 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017 and were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented. In December of 2017, the Tax Act was enacted to lower the federal statutory tax rate from 35% to 21%. The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of March 31, 2018, the amortization of amounts arising from remeasurement have not affected the Company’s or Consolidated SCE&G’s effective tax rate due to such amortizations being deferred until such time as regulators determine how the benefits of such excess deferred tax amounts will be realized by customers. Upon the filing of the Company’s 2017 consolidated income tax return, adjustments to deferred income taxes may be recorded; however, these adjustments are not expected to have a material impact on the Company’s financial position, results of operations, or cash flows. The State of North Carolina lowered its corporate income tax rate to 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. |
SCEG | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | 6. INCOME TAXES The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns. The Company’s federal returns through 2007 are closed. In addition, federal returns for 2008 and 2009 are closed except to the extent of the examination of amended return claims discussed below. The IRS is also currently examining SCANA's federal returns for years 2010 through 2016 as a result of those claims. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010. During 2013 and 2014, the Company amended certain of its income tax returns for 2008 through 2012 to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. The Company expects to claim similar deductions and credits in its 2017 tax return when it is filed in 2018. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models. The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2016 income tax returns, and it is expected that the IRS will also examine later returns. These IRC Section 174 income tax deductions and IRC Section 41 credits were considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G anticipate that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of March 31, 2018. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits. As of March 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2018 (see Note 10). In connection with the research and experimentation deduction and credit claims reflected on the 2015 and 2016 income tax returns and similar claims made in determining taxable income for 2017, and under the terms of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years (see Note 2). However, an impairment loss with respect to such deferred regulatory asset was recorded in 2017. Also under the terms of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset through December 31, 2017 and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Related to the unrecognized tax benefits noted above, the Company and Consolidated SCE&G accrued interest expense of $4.5 million and interest income of $0.7 million during 2018. Amounts recorded for such interest income and interest expense were mostly deferred within regulatory assets during 2017 and were subsequently included within the impairment loss recorded by the Company and Consolidated SCE&G in 2017. Penalties were not material in either period presented. In December of 2017, the Tax Act was enacted to lower the federal statutory tax rate from 35% to 21%. The rate change resulted in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate as of December 31, 2017. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in deferred income tax balances within regulatory liabilities. As of March 31, 2018, the amortization of amounts arising from remeasurement have not affected the Company’s or Consolidated SCE&G’s effective tax rate due to such amortizations being deferred until such time as regulators determine how the benefits of such excess deferred tax amounts will be realized by customers. Upon the filing of the Company’s 2017 consolidated income tax return, adjustments to deferred income taxes may be recorded; however, these adjustments are not expected to have a material impact on the Company’s financial position, results of operations, or cash flows. The State of North Carolina lowered its corporate income tax rate to 3.0% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows. |
DERIVATIVE FINANCIAL INSTRUMENTS |
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Derivative Instruments and Hedging Activities Disclosure [Text Block] | 7. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not 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 have generally been amortized over the lives of subsequent debt issuances and gains have been amortized to interest expense or may be applied as otherwise directed by the SCPSC. See Note 2 and Note 12 regarding the settlement gain recorded in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes amounts related to basis swap contracts totaling 236,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017. The aggregate notional amounts of the interest rate swaps were as follows:
The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.
Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for either period presented. The effect of derivative instruments on the consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships
As of March 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.6 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.8 million as an increase to interest expense. As of March 31, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2020. As of March 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.2 million as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.
As of March 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.7 million as an increase to interest expense. 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.
In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.9 million related to $3.2 million in commodity derivatives that are in a net asset position at March 31, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets follows:
Information related to the offsetting of derivative liabilities follows:
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Derivative Instruments and Hedging Activities Disclosure [Text Block] | 7. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. Commodity Derivatives The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows. PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. Interest Rate Swaps Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not 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 have generally been amortized over the lives of subsequent debt issuances and gains have been amortized to interest expense or may be applied as otherwise directed by the SCPSC. See Note 2 and Note 12 regarding the settlement gain recorded in the first quarter of 2018. Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. Quantitative Disclosures Related to Derivatives The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes amounts related to basis swap contracts totaling 236,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017. The aggregate notional amounts of the interest rate swaps were as follows:
The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.
Derivatives Designated as Fair Value Hedges The Company had no interest rate or commodity derivatives designated as fair value hedges for either period presented. The effect of derivative instruments on the consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships
As of March 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $0.6 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.8 million as an increase to interest expense. As of March 31, 2018, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2020. As of March 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.2 million as an increase to interest expense. Hedge Ineffectiveness For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was insignificant during all periods presented.
As of March 31, 2018, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $2.7 million as an increase to interest expense. 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.
In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $0.9 million related to $3.2 million in commodity derivatives that are in a net asset position at March 31, 2018, compared to letters of credit in the amount of $1.2 million related to derivatives of $4.0 million at December 31, 2017, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets follows:
Information related to the offsetting of derivative liabilities follows:
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Fair Value Disclosures [Text Block] | 8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows:
Fair values of long-term debt instruments are 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. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. In connection with the impairment loss described in Note 10, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At March 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 10 on a quarterly basis. |
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SCEG | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Text Block] | 8. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&G value available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, on which the securities are actively traded or are open-ended mutual funds registered with the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
The Company and Consolidated SCE&G had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during either period presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows:
Fair values of long-term debt instruments are 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. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. In connection with the impairment loss described in Note 10, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At March 31, 2018, this nuclear fuel had an estimated fair value of $40.2 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 10 on a quarterly basis. |
EMPLOYEE BENEFIT PLANS |
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Pension and Other Postretirement Benefits Disclosure [Text Block] | 9. EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows:
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. SCE&G 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. PSNC Energy recovers pension costs through cost of service rat |
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Pension and Other Postretirement Benefits Disclosure [Text Block] | 9. EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows:
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. SCE&G 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. PSNC Energy recovers pension costs through cost of service rat |
COMMITMENTS AND CONTINGENCIES |
3 Months Ended | 9 Months Ended |
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Mar. 31, 2018 |
Sep. 30, 2017 |
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Statement [Line Items] | ||
Commitments and Contingencies Disclosure [Text Block] | Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies regarding the abandoned Nuclear Project subsequent to December 31, 2017 are disclosed below. EPC Contract and BLRA Matters Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim are based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC and WECTEC any and all claims that are based thereon or that may be related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018. WEC has projected that its Reorganization Plan will 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 Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $290 million of filed liens in Fairfield County. 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. WEC has indicated that Fluor may attempt to include an approximately$270 million claim (Fluor Claim) for contractual termination damages arising from a breach of Fluor’s subcontract with WEC, in a class of general unsecured creditors that includes the pre-petition trade creditors. However, amounts approved in the Reorganization Plan to pay general unsecured creditors did not contemplate the Fluor Claim. As such, if Fluor is successful in its attempt to include the Fluor Claim as part of the class of general unsecured creditors, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full its pre-petition trade creditors. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing, to the extent such owed amounts exceeded (1) the amounts advanced to WEC for such purposes while the IAA was in effect or (2) the amounts held by WEC after the IAA was terminated. Sufficient funds were not advanced to WEC under the IAA to pay the Fluor claim. If the Fluor Claim is asserted against SCE&G, whether directly or indirectly by a claim through the IAA, SCE&G intends to oppose that claim. To the extent any of these claims are determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.094 billion for SCE&G's 55% share, net of certain expenses). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed below. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. The proceeds received under or arising from the monetization of the Toshiba Settlement were recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. While this determination is pending, SCE&G has utilized the proceeds to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction. See further discussion in Note 5. As described above, several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ($33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. The investigations have continued since those events. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and may attempt to apply such action retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections, including collections related to transmission assets which have been or are expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of March 31, 2018 total approximately $2.0 billion. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. On September 28, 2017, SCE&G filed a motion to dismiss the Request. After conducting a hearing, the SCPSC denied SCE&G's motion on December 20, 2017 and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable. Parties who have intervened and continue to intervene in the Request or who filed a letter in support of the Request include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. The hearing on the Request has not been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. See also Note 2. In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and certain adverse proposals have been or are being considered by the General Assembly in 2018. In January 2018, these committees also reconvened for the purpose of considering the effects of the proposed merger discussed below on Nuclear Project stakeholders. More recent actions by the General Assembly are discussed below. On January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate by effectively suspending collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. On April 18, 2018, the South Carolina Senate passed a joint resolution (S. 954) which would, among other things, (1) create a temporary experimental rate that reduces SCE&G electric rates related to nuclear construction costs from 18% to 5%, which reduction would remain in effect from April 1, 2018 until the SCPSC issues a final order on the merits of a docket currently before the SCPSC made pursuant to the BLRA (which docket (i.e., Joint Petition) is discussed below); (2) require the SCPSC to conduct a hearing within 30 days of the experimental rate being ordered to determine if an adjustment to the rate is necessary to ensure SCANA does not become insolvent prior to the SCPSC issuing a final order on the merits of such docket; (3) prohibit the SCPSC from holding a hearing on the merits for such docket (other than administrative or procedural hearings), or making any final determination on any related requests, before November 1, 2018; and (4) require the SCPSC to issue a final order for such docket no later than December 21, 2018. Also, S. 954 would require the SCPSC to order each investor-owned utility to provide an accounting of its estimated tax savings arising from the enactment of the Tax Act for calendar year 2018 and to provide that customers of such utility receive the benefit of these estimated savings, subject to an adjustment in 2019 for the actual savings and benefits realized. On April 25, 2018, the House voted to "non-concur" on S. 954. As a result, differences between legislation approved by the House and Senate will be the subject of conference committee proceedings. Any bill or joint resolution, including any legislation resulting from a conference committee proceeding, must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these pieces of legislation will become law, or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA. Proposals to Resolve Outstanding Issues On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for liquidation of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues. On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties commit to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills, shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and to SCE&G's purchasing an existing 540-MW natural gas fired power plant with no initial investment borne by customers. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition. Impairment Considerations Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G have determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). For the three months ended March 31, 2018, the Company and Consolidated SCE&G have recognized an additional pre-tax impairment loss of approximately $3.6 million ($2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented.. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $846 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.061 billion, which amount represents the monetization of guaranty settlement of $1.094 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, if the BLRA is found to be unconstitutional or if the General Assembly amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.9 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.966 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $2.0 billion, net of approximately $1.061 billion, which amount represents the monetization of guaranty settlement of $1.094 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $2.0 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter. Liquidity Considerations As a result of the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies occurred. The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $248 million for the Company (including $146 million for Consolidated SCE&G), interest payments of approximately $301 million for the Company (including $256 million for Consolidated SCE&G), and future minimum payments for operating leases of $33 million for the Company (including $26 million for Consolidated SCE&G). Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect in customer rates amounts previously approved under the BLRA, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. However, certain of SCANA's credit ratings have fallen below investment grade, which has constrained its ability and that of Fuel Company to issue commercial paper. Regulatory and legislative proceedings described above, and/or proceedings described under Claims and Litigation below, which are outside of the Company’s and Consolidated SCE&G’s control, may result in the temporary or permanent suspension of all or a portion of the approximately $445 million annually of rates being collected currently under the BLRA, the return of such amounts previously collected of $2.0 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.094 billion) be placed in escrow or be refunded to customers in the near term. Neither the Company nor Consolidated SCE&G can predict if or when these matters may be resolved or what additional actions, if any, may be proposed or taken, including other legislative or regulatory actions related to the BLRA or other litigation. Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling as much as approximately $4.9 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further stress the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements. Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, possible future actions related to rates or refunds could have a material adverse effect on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change. Claims and Litigation Following the Company’s decision to stop construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project. Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. In addition, one plaintiff alleges that director defendants violated Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. Lawsuits seeking class action status have also been filed on behalf of investors in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. The plaintiffs allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper. A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees. The Company has also been served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. In addition, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee have requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. The Company and Consolidated SCE&G intend to fully cooperate with any such investigations. On January 26, 2018, the DOR notified SCANA that it was initiating an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The Company and Consolidated SCE&G understand that the DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. The Company and Consolidated SCE&G intend to vigorously contest the DOR's position. While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, they cannot predict the timing or outcome of these matters or others that may arise, including any claims that may be asserted by Santee Cooper, and adverse outcomes from some of these matters would not be covered by insurance. As noted above, the various claims for damages do not specify an amount for those damages and the number of plaintiffs that are ultimately certified in the potential class action lawsuits is unknown. In addition, each of the cases referred to above is in its early stages. For these reasons, the Company and Consolidated SCE&G cannot provide any estimate or range of potential loss for these matters at this time, and no accrual for these potential losses has been included in the condensed consolidated financial statements. However, outcomes could have a material adverse effect on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition. The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition. Nuclear Insurance Under Price-Anderson, SCE&G (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 Unit 1. Price-Anderson provides funds up to $13.4 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 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, SCE&G’s portion of the retrospective premium assessment would not exceed $22.3 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 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, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G 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 the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position. Environmental On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO2 from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO2 per MWh and new natural gas units to meet 1,000 pounds CO2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule included state-specific goals for reducing national CO2 emissions by 32% from 2005 levels by 2030, and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeded the EPA's statutory authority. In a separate but related action, the EPA issued an Advance Notice of Proposed Rulemaking on December 18, 2017, to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing units. The Company and Consolidated SCE&G expect 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 SO2 and NOX 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 NOX emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO2 and NOX 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 SCE&G 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 April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G 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 had become effective on January 4, 2016, after which state regulators could 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 resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 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 the Company and Consolidated SCE&G expect 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. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications 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 SCE&G's and GENCO's coal-fired generating facilities. SCE&G 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. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates. SCE&G 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 DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2019 and will cost an additional $9.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 million and are included in regulatory assets. Other The Company and Consolidated SCE&G have recorded an estimated liability for amounts collected in customer rates during the period that arise from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2. |
0. COMMITMENTS AND CONTINGENCIES |
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Statement [Line Items] | ||
Commitments and Contingencies Disclosure [Text Block] | Abandoned Nuclear Project SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. Various difficulties were encountered which affected the ability of the Consortium to adhere to established budgets and construction schedules for the Nuclear Project and which, in light of Santee Cooper's decision to suspend construction of the Nuclear Project, led to the Company's decision on July 31, 2017 to stop the construction and seek recovery under the abandonment provisions of the BLRA. These difficulties and other developments occurring prior to the bankruptcy filing by WEC and WECTEC and other matters are described in Note 10 to the consolidated financial statements included in the Company's and Consolidated SCE&G's combined Form 10-K for the year ended December 31, 2017. Significant developments and continuing contingencies regarding the abandoned Nuclear Project subsequent to December 31, 2017 are disclosed below. EPC Contract and BLRA Matters Contractor Bankruptcy Proceedings and Related Uncertainties On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract. On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim are based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC and WECTEC any and all claims that are based thereon or that may be related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract. WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018. WEC has projected that its Reorganization Plan will 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 Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $290 million of filed liens in Fairfield County. 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. WEC has indicated that Fluor may attempt to include an approximately$270 million claim (Fluor Claim) for contractual termination damages arising from a breach of Fluor’s subcontract with WEC, in a class of general unsecured creditors that includes the pre-petition trade creditors. However, amounts approved in the Reorganization Plan to pay general unsecured creditors did not contemplate the Fluor Claim. As such, if Fluor is successful in its attempt to include the Fluor Claim as part of the class of general unsecured creditors, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full its pre-petition trade creditors. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement. SCE&G and Santee Cooper are responsible for amounts owed to WEC for work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing, to the extent such owed amounts exceeded (1) the amounts advanced to WEC for such purposes while the IAA was in effect or (2) the amounts held by WEC after the IAA was terminated. Sufficient funds were not advanced to WEC under the IAA to pay the Fluor claim. If the Fluor Claim is asserted against SCE&G, whether directly or indirectly by a claim through the IAA, SCE&G intends to oppose that claim. To the extent any of these claims are determined to be valid, SCE&G may be responsible for paying its 55% share thereof. Toshiba Settlement and Subsequent Monetization Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed below. In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.094 billion for SCE&G's 55% share, net of certain expenses). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed below. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. The proceeds received under or arising from the monetization of the Toshiba Settlement were recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. While this determination is pending, SCE&G has utilized the proceeds to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction. See further discussion in Note 5. As described above, several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for the reduction. On January 2, 2018, the purchase agreement with Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor pre-petition liens to $60 million ($33 million for SCE&G's 55% share). Regulatory, Political and Legal Developments In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. The investigations have continued since those events. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and may attempt to apply such action retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges. On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, and in reliance on the opinion from the Office of Attorney General, the ORS filed the Request seeking an order from the SCPSC directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections, including collections related to transmission assets which have been or are expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of March 31, 2018 total approximately $2.0 billion. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which motion the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. On September 28, 2017, SCE&G filed a motion to dismiss the Request. After conducting a hearing, the SCPSC denied SCE&G's motion on December 20, 2017 and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable. Parties who have intervened and continue to intervene in the Request or who filed a letter in support of the Request include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, Santee Cooper, the SCEUC, certain large industrial customers, and several environmental groups. The hearing on the Request has not been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. See also Note 2. In 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, conducted public hearings regarding the Company's decision to abandon the Nuclear Project. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and certain adverse proposals have been or are being considered by the General Assembly in 2018. In January 2018, these committees also reconvened for the purpose of considering the effects of the proposed merger discussed below on Nuclear Project stakeholders. More recent actions by the General Assembly are discussed below. On January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate by effectively suspending collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. On April 18, 2018, the South Carolina Senate passed a joint resolution (S. 954) which would, among other things, (1) create a temporary experimental rate that reduces SCE&G electric rates related to nuclear construction costs from 18% to 5%, which reduction would remain in effect from April 1, 2018 until the SCPSC issues a final order on the merits of a docket currently before the SCPSC made pursuant to the BLRA (which docket (i.e., Joint Petition) is discussed below); (2) require the SCPSC to conduct a hearing within 30 days of the experimental rate being ordered to determine if an adjustment to the rate is necessary to ensure SCANA does not become insolvent prior to the SCPSC issuing a final order on the merits of such docket; (3) prohibit the SCPSC from holding a hearing on the merits for such docket (other than administrative or procedural hearings), or making any final determination on any related requests, before November 1, 2018; and (4) require the SCPSC to issue a final order for such docket no later than December 21, 2018. Also, S. 954 would require the SCPSC to order each investor-owned utility to provide an accounting of its estimated tax savings arising from the enactment of the Tax Act for calendar year 2018 and to provide that customers of such utility receive the benefit of these estimated savings, subject to an adjustment in 2019 for the actual savings and benefits realized. On April 25, 2018, the House voted to "non-concur" on S. 954. As a result, differences between legislation approved by the House and Senate will be the subject of conference committee proceedings. Any bill or joint resolution, including any legislation resulting from a conference committee proceeding, must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these pieces of legislation will become law, or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA. Proposals to Resolve Outstanding Issues On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for liquidation of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues. On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties commit to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills, shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and to SCE&G's purchasing an existing 540-MW natural gas fired power plant with no initial investment borne by customers. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition. Impairment Considerations Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G have determined that a disallowance of recovery of part of the cost of the abandoned Nuclear Project is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, in 2017 the Company and Consolidated SCE&G recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). For the three months ended March 31, 2018, the Company and Consolidated SCE&G have recognized an additional pre-tax impairment loss of approximately $3.6 million ($2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. It is reasonably possible that a change in estimated impairment loss could occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The impairment loss recorded in 2017 reflects impacts similar to those that would have resulted had the proposed solution announced on November 16, 2017 been implemented.. If the merger benefits and cost recovery plan outlined in the Joint Petition are implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion (approximately $1.3 billion net of tax) would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $846 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.061 billion, which amount represents the monetization of guaranty settlement of $1.094 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, if the BLRA is found to be unconstitutional or if the General Assembly amends or revokes the BLRA or approves other legislation with a similar effect, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.9 billion (approximately $3.7 billion net of tax). This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.966 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $2.0 billion, net of approximately $1.061 billion, which amount represents the monetization of guaranty settlement of $1.094 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $2.0 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter. Liquidity Considerations As a result of the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies occurred. The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $248 million for the Company (including $146 million for Consolidated SCE&G), interest payments of approximately $301 million for the Company (including $256 million for Consolidated SCE&G), and future minimum payments for operating leases of $33 million for the Company (including $26 million for Consolidated SCE&G). Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs. Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect in customer rates amounts previously approved under the BLRA, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. However, certain of SCANA's credit ratings have fallen below investment grade, which has constrained its ability and that of Fuel Company to issue commercial paper. Regulatory and legislative proceedings described above, and/or proceedings described under Claims and Litigation below, which are outside of the Company’s and Consolidated SCE&G’s control, may result in the temporary or permanent suspension of all or a portion of the approximately $445 million annually of rates being collected currently under the BLRA, the return of such amounts previously collected of $2.0 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.094 billion) be placed in escrow or be refunded to customers in the near term. Neither the Company nor Consolidated SCE&G can predict if or when these matters may be resolved or what additional actions, if any, may be proposed or taken, including other legislative or regulatory actions related to the BLRA or other litigation. Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling as much as approximately $4.9 billion (approximately $3.7 billion net of tax) may be required. Such an impairment loss or other charges would further stress the Company’s and Consolidated SCE&G’s debt to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of debt to total capitalization exceeding maximum levels prescribed in their respective credit agreements. Such an event likely would limit the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends or may trigger events of default under such agreements. Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, possible future actions related to rates or refunds could have a material adverse effect on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change. Claims and Litigation Following the Company’s decision to stop construction of Unit 2 and Unit 3, purported derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project. Purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder and RICO. In addition, one plaintiff alleges that director defendants violated Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper. Lawsuits seeking class action status have also been filed on behalf of investors in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona. The plaintiffs allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona aided and abetted these actions. Among other remedies, the plaintiffs seek to enjoin the merger and rescind the Merger Agreement or to have the Merger Agreement amended to provide more favorable terms for plaintiffs, monetary damages, attorneys' fees and such further relief as the court deems proper. A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees. The Company has also been served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. In addition, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee have requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. The Company and Consolidated SCE&G intend to fully cooperate with any such investigations. On January 26, 2018, the DOR notified SCANA that it was initiating an audit of SCE&G's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The Company and Consolidated SCE&G understand that the DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. The Company and Consolidated SCE&G intend to vigorously contest the DOR's position. While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, they cannot predict the timing or outcome of these matters or others that may arise, including any claims that may be asserted by Santee Cooper, and adverse outcomes from some of these matters would not be covered by insurance. As noted above, the various claims for damages do not specify an amount for those damages and the number of plaintiffs that are ultimately certified in the potential class action lawsuits is unknown. In addition, each of the cases referred to above is in its early stages. For these reasons, the Company and Consolidated SCE&G cannot provide any estimate or range of potential loss for these matters at this time, and no accrual for these potential losses has been included in the condensed consolidated financial statements. However, outcomes could have a material adverse effect on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition. The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition. Nuclear Insurance Under Price-Anderson, SCE&G (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 Unit 1. Price-Anderson provides funds up to $13.4 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 $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 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, SCE&G’s portion of the retrospective premium assessment would not exceed $22.3 million. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 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, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G 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 the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position. Environmental On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO2 from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO2 per MWh and new natural gas units to meet 1,000 pounds CO2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule included state-specific goals for reducing national CO2 emissions by 32% from 2005 levels by 2030, and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeded the EPA's statutory authority. In a separate but related action, the EPA issued an Advance Notice of Proposed Rulemaking on December 18, 2017, to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing units. The Company and Consolidated SCE&G expect 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 SO2 and NOX 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 NOX emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO2 and NOX 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 SCE&G 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 April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G 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 had become effective on January 4, 2016, after which state regulators could 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 resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 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 the Company and Consolidated SCE&G expect 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. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications 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 SCE&G's and GENCO's coal-fired generating facilities. SCE&G 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. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates. SCE&G 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 DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2019 and will cost an additional $9.9 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.3 million and are included in regulatory assets. Other The Company and Consolidated SCE&G have recorded an estimated liability for amounts collected in customer rates during the period that arise from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2. |
0. COMMITMENTS AND CONTINGENCIES |
SEGMENT OF BUSINESS INFORMATION |
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Segment Reporting Disclosure [Text Block] | SEGMENT OF BUSINESS INFORMATION Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income. The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.
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Segment Reporting Disclosure [Text Block] | SEGMENT OF BUSINESS INFORMATION Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income. The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.
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OTHER INCOME (EXPENSE), NET OTHER INCOME (EXPENSE), NET |
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Other Income and Other Expense Disclosure [Text Block] | OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows:
The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1, and as permitted, prior periods have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense. |
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Other Income and Other Expense Disclosure [Text Block] | OTHER INCOME (EXPENSE), NET Components of other income (expense), net are as follows:
The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1, and as permitted, prior periods have not been restated. Other income in 2018 includes gains from the settlement of interest rate derivatives of approximately $115 million (see Note 7). Non-service cost components of pension and other postretirement benefits are included in Other expense. |
AFFILIATED TRANSACTIONS |
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Related Party Transactions Disclosure [Text Block] | AFFILIATED TRANSACTIONS The Company and Consolidated SCE&G: SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G).
Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, 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, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. SCE&G provided $110.7 million to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.
Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9. |
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Related Party Transactions Disclosure [Text Block] | Consolidated SCE&G: SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, 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, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other Income (Expense), net on the consolidated statements of comprehensive income. SCE&G provided $110.7 million to a rabbi trust consolidated with SCANA in connection with the potential change in control arising from the Merger Agreement. This funding is recorded as long-term Other affiliate assets on the condensed consolidated balance sheet of Consolidated SCE&G.
Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 5. Certain disclosures regarding SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
3 Months Ended |
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Mar. 31, 2018 | |
Significant Accounting Policies | |
Basis Of Consolidation And Variable Interest Entities [Policy Text Block] | Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed 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 SCE&G 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 approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. |
Income Statement policy [Policy Text Block] | Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). |
Asset Management and Supply Service Agreements | Asset Management and Supply Service Agreement PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship, 32% and 39% of PSNC Energy’s natural gas inventory at March 31, 2018 and December 31, 2017, respectively, with a carrying value of $5.5 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019. |
Earnings Per Share [Text Block] | Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. |
Reclassification, Policy [Policy Text Block] | Reclassifications In the statement of operations, amounts previously reported under the captions “Other income”, “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net”. Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. |
SCEG | |
Significant Accounting Policies | |
Basis Of Consolidation And Variable Interest Entities [Policy Text Block] | Basis of Consolidation and Variable Interest Entities The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G. SCE&G has determined that it has a controlling financial interest in each of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed 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 SCE&G 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 approximately $500 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5. |
Income Statement policy [Policy Text Block] | Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 11) are presented within Operating Income, and other activities are presented within Other Income (Expense). |
Reclassification, Policy [Policy Text Block] | Reclassifications In the statement of operations, amounts previously reported under the captions “Other income”, “Other expense” and “Allowance for equity funds used during construction” have been combined into a single caption titled “Other Income (Expense), Net”. Details of the composition of this caption are described in Note 12. Also, the subtotal captioned “Total Other Expense” that previously appeared on the statements of operations has been eliminated. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATION (Tables) |
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Statement of Income [Table Text Block] |
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Statement of Income [Table Text Block] |
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RATE AND OTHER REGULATORY MATTERS (Tables) |
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Pipeline integrity management revenue requirement [Table Text Block] |
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Schedule of Regulatory Assets [Table Text Block] |
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Schedule of Regulatory Liabilities [Table Text Block] |
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Schedule of Regulatory Assets [Table Text Block] |
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Schedule of Regulatory Liabilities [Table Text Block] |
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REVENUE RECOGNITION Revenue Recognition (Tables) |
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Disaggregation of Revenue [Table Text Block] |
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Contract with Customer, Asset and Liability [Table Text Block] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capitalized Contract Cost [Table Text Block] |
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Disaggregation of Revenue [Table Text Block] |
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Capitalized Contract Cost [Table Text Block] |
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LONG-TERM AND SHORT-TERM DEBT (Tables) |
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Schedule of Line of Credit Facilities [Table Text Block] |
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Schedule of Line of Credit Facilities [Table Text Block] |
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DERIVATIVE FINANCIAL INSTRUMENTS (Tables) |
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Derivative [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Nonmonetary Notional Amounts of Outstanding Derivative Positions [Table Text Block] | The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes amounts related to basis swap contracts totaling 236,000 MMBTU in 2018 and 2,582,000 MMBTU in 2017. |
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Schedule of Derivative Instruments [Table Text Block] | The aggregate notional amounts of the interest rate swaps were as follows:
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Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.
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Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Disclosure of Credit Derivatives [Table Text Block] |
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Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets follows:
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Offsetting Liabilities [Table Text Block] |
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SCEG | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivative Instruments [Table Text Block] | The aggregate notional amounts of the interest rate swaps were as follows:
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Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross, and cash collateral on the derivatives has not been netted against the fair values shown.
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Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | For |
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Disclosure of Credit Derivatives [Table Text Block] |
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Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets follows:
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Offsetting Liabilities [Table Text Block] |
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FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
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Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value were as follows:
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SCEG | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
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Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value were as follows:
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EMPLOYEE BENEFIT PLANS (Tables) |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] |
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SCEG | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] |
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SEGMENT OF BUSINESS INFORMATION (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Schedule of Segment Reporting Information, by Segment [Table Text Block] |
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Schedule of Segment Reporting Information, by Segment [Table Text Block] |
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OTHER INCOME (EXPENSE), NET Other Income (Expense) (Tables) |
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Schedule of Other Operating Cost and Expense, by Component [Table Text Block] |
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Schedule of Other Operating Cost and Expense, by Component [Table Text Block] |
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AFFILIATED TRANSACTIONS Canadys Refined Coal (Tables) - USD ($) $ in Millions |
3 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Mar. 31, 2018 |
Mar. 31, 2017 |
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Canadys Refined Coal [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transaction, Purchases from Related Party | $ 32.5 | $ 44.6 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Related Party Transactions [Table Text Block] |
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Schedule of Related Party Transactions [Table Text Block] |
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SCEG | Canadys Refined Coal [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Schedule of Related Party Transactions [Table Text Block] |
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AFFILIATED TRANSACTIONS SCANA Services (Tables) |
3 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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SCEG | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Schedule of Related Party Transactions [Table Text Block] |
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REVENUE RECOGNITION Contract Costs (Details) - USD ($) $ in Millions |
3 Months Ended | |
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Mar. 31, 2018 |
Dec. 31, 2017 |
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Capitalized Contract Cost, Amortization | $ (0.4) | |
Capitalized Contract Cost, Net | $ 15.9 | $ 16.3 |
REVENUE RECOGNITION Contract Balances (Details) - USD ($) $ in Millions |
Mar. 31, 2018 |
Dec. 31, 2017 |
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Customer Advances and Deposits, Current | $ 206 | $ 112 |
SCEG | ||
Customer Advances and Deposits, Current | $ 159 | $ 70 |
LONG-TERM AND SHORT-TERM DEBT (Details) - USD ($) $ in Millions |
Mar. 31, 2018 |
Dec. 31, 2017 |
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Debt Instrument [Line Items] | ||
Related Party Transaction, Due from (to) Related Party, Current | $ 197.0 | $ 28.0 |
SCEG | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | 67.8 | 67.8 |
Related Party Transaction, Due from (to) Related Party, Current | $ 149.0 | $ 37.0 |
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions |
3 Months Ended | |
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Mar. 31, 2018 |
Dec. 31, 2017 |
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | $ 6,728.9 | $ 6,632.9 |
Long-term Debt, Fair Value | 7,220.1 | 7,399.7 |
SCEG | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | 5,259.0 | 5,163.3 |
Long-term Debt, Fair Value | $ 5,649.1 | $ 5,790.3 |
Nuclear Fuel [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Level 3 fair value measurements | 40.2 |
OTHER INCOME (EXPENSE), NET Other Income (Expense) (Details) - USD ($) $ in Millions |
3 Months Ended | |
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Mar. 31, 2018 |
Mar. 31, 2017 |
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Contracts Revenue | $ 5 | $ 0 |
Other income | 129 | 17 |
Other Nonoperating Expense | (10) | (14) |
Public Utilities, Allowance for Funds Used During Construction, Additions | 4 | 9 |
Other Nonoperating Income (Expense) | 128 | 12 |
SCEG | ||
Contracts Revenue | 1 | 0 |
Other income | 126 | 8 |
Other Nonoperating Expense | (7) | (10) |
Public Utilities, Allowance for Funds Used During Construction, Additions | 3 | 9 |
Other Nonoperating Income (Expense) | $ 123 | $ 7 |
AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions |
3 Months Ended | ||
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Mar. 31, 2018 |
Mar. 31, 2017 |
Dec. 31, 2017 |
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Related Party Transaction [Line Items] | |||
Advances to Affiliate | $ 110.7 | ||
Canadys Refined Coal [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Due from (to) Related Party | $ 9.9 | $ 4.9 | |
Equity Method Investment, Ownership Percentage | 40.00% | ||
Related Party Transaction, Purchases from Related Party | $ 32.5 | $ 44.6 | |
Sales to Affiliates | 32.3 | 44.4 | |
Due to Related Parties | 10.0 | 4.9 | |
Energy Marketing [Member] | |||
Related Party Transaction [Line Items] | |||
Due to Affiliate, Current | 8.1 | 10.0 | |
Cost of Natural Gas Purchases | 31.3 | 23.9 | |
SCANA Services [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Expenses from Transactions with Related Party | 59.4 | $ 72.5 | |
Accounts Payable, Related Parties, Current | 36.7 | 42.0 | |
SCEG | |||
Related Party Transaction [Line Items] | |||
Due to Affiliate, Current | 256.0 | 102.0 | |
Due from Affiliate, Current | $ 159.0 | $ 32.0 |