Document and Entity Information
Document and Entity Information Document | 3 Months Ended |
Mar. 31, 2017shares | |
Entity Information [Line Items] | |
Entity Registrant Name | SCANA Corporation |
Entity Central Index Key | 754,737 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Large Accelerated Filer |
Document Type | 10-Q |
Document Period End Date | Mar. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | Q1 |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 142,916,917 |
SCEG | |
Entity Information [Line Items] | |
Entity Registrant Name | SOUTH CAROLINA ELECTRIC & GAS CO |
Entity Central Index Key | 91,882 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Document Type | 10-Q |
Document Period End Date | Mar. 31, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | Q1 |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 40,296,147 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Utility Plant In Service | $ 13,543 | $ 13,444 |
Accumulated Depreciation and Amortization | (4,494) | (4,446) |
Construction Work in Progress | 5,011 | 4,845 |
Nuclear Fuel, Net of Accumulated Amortization | 265 | 271 |
Goodwill, Net of Writedown of $230 | 210 | 210 |
Utility Plant, Net | 14,535 | 14,324 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 275 | 276 |
Assets held in trust, net-nuclear decommissioning | 126 | 123 |
Other investments | 77 | 76 |
Nonutility Property and Investments, Net | 478 | 475 |
Current Assets: | ||
Cash and cash equivalents | 12 | 208 |
Receivables, net of allowance for uncollectible accounts | 549 | 616 |
Other | 94 | 127 |
Income Taxes receivable | 6 | 142 |
Inventories (at average cost): | ||
Fuel | 114 | 136 |
Materials and supplies | 153 | 155 |
Prepaid Expense | 103 | 105 |
Other current assets | 16 | 17 |
Total Current Assets | 1,047 | 1,506 |
Deferred Debits and Other Assets: | ||
Regulatory Assets, Noncurrent | 2,128 | 2,130 |
Other | 270 | 272 |
Total Deferred Debits and Other Assets | 2,398 | 2,402 |
Total | 18,458 | 18,707 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,389 | 2,390 |
Retained Earnings, Unappropriated | 3,468 | 3,384 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (51) | (49) |
Stockholders' Equity Attributable to Parent | 5,806 | 5,725 |
Long-term Debt, Excluding Current Maturities | 6,466 | 6,473 |
Total Capitalization | 12,272 | 12,198 |
Current Liabilities: | ||
Short-term borrowings | 869 | 941 |
Current portion of long-term debt | 17 | 17 |
Accounts payable | 269 | 404 |
Customer deposits and customer prepayments | 158 | 168 |
Taxes accrued | 59 | 201 |
Interest accrued | 92 | 84 |
Dividends declared | 85 | 80 |
Derivative financial instruments | 27 | 35 |
Other | 85 | 135 |
Total Current Liabilities | 1,661 | 2,065 |
Deferred Credits and Other Liabilities: | ||
Deferred Income Tax Liabilities, Net | 2,184 | 2,159 |
Asset retirement obligations | 562 | 558 |
Pension and other postretirement benefits | 375 | 373 |
Unrecognized Tax Benefits | 274 | 219 |
Regulatory Liabilities | 938 | 930 |
Other | 192 | 205 |
Total Deferred Credits and Other Liabilities | 4,525 | 4,444 |
Commitments and Contingencies | ||
Total | 18,458 | 18,707 |
SCEG | ||
Assets | ||
Utility Plant In Service | 11,588 | 11,510 |
Accumulated Depreciation and Amortization | (4,032) | (3,991) |
Construction Work in Progress | 4,950 | 4,813 |
Nuclear Fuel, Net of Accumulated Amortization | 265 | 271 |
Utility Plant, Net | 12,771 | 12,603 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 69 | 69 |
Assets held in trust, net-nuclear decommissioning | 126 | 123 |
Other investments | 3 | 3 |
Nonutility Property and Investments, Net | 198 | 195 |
Current Assets: | ||
Cash and cash equivalents | 11 | 164 |
Receivables, net of allowance for uncollectible accounts | 328 | 378 |
Other | 66 | 94 |
Income Taxes receivable | 0 | 53 |
Due from Affiliate, Current | 14 | 16 |
Inventories (at average cost): | ||
Fuel | 78 | 83 |
Materials and supplies | 143 | 143 |
Prepaid Expense | 88 | 88 |
Other current assets | 2 | 1 |
Total Current Assets | 730 | 1,020 |
Deferred Debits and Other Assets: | ||
Regulatory Assets, Noncurrent | 2,026 | 2,030 |
Other | 240 | 243 |
Total Deferred Debits and Other Assets | 2,266 | 2,273 |
Total | 15,965 | 16,091 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,860 | 2,860 |
Retained Earnings, Unappropriated | 2,513 | 2,481 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (3) | (3) |
Stockholders' Equity Attributable to Parent | 5,370 | 5,338 |
Stockholders' Equity Attributable to Noncontrolling Interest | 135 | 134 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,505 | 5,472 |
Long-term Debt, Excluding Current Maturities | 5,147 | 5,154 |
Total Capitalization | 10,652 | 10,626 |
Current Liabilities: | ||
Short-term borrowings | 770 | 804 |
Current portion of long-term debt | 12 | 12 |
Accounts payable | 152 | 247 |
Due to Affiliate, Current | 100 | 122 |
Customer deposits and customer prepayments | 114 | 126 |
Taxes accrued | 102 | 195 |
Interest accrued | 72 | 68 |
Dividends declared | 79 | 79 |
Derivative financial instruments | 23 | 28 |
Other | 37 | 55 |
Total Current Liabilities | 1,461 | 1,736 |
Deferred Credits and Other Liabilities: | ||
Deferred Income Tax Liabilities, Net | 1,951 | 1,939 |
Asset retirement obligations | 526 | 522 |
Pension and other postretirement benefits | 234 | 232 |
Unrecognized Tax Benefits | 333 | 236 |
Regulatory Liabilities | 705 | 695 |
Other | 88 | 89 |
Other -affiliate | 15 | 16 |
Total Deferred Credits and Other Liabilities | 3,852 | 3,729 |
Total | $ 15,965 | $ 16,091 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Common Stock, Shares, Outstanding | 142.9 | 142.9 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 137 | $ 138 |
Public Utilities, Property, Plant and Equipment, Net | 14,535 | 14,324 |
Allowance for Doubtful Accounts Receivable, Current | 6 | 6 |
Write-down, Goodwill | 230 | 230 |
Assets, Current | 1,047 | 1,506 |
Regulated Entity, Other Assets, Noncurrent | $ 2,398 | $ 2,402 |
SCEG | ||
Common Stock, Shares, Outstanding | 40.3 | 40.3 |
Public Utilities, Property, Plant and Equipment, Net | $ 12,771 | $ 12,603 |
Allowance for Doubtful Accounts Receivable, Current | 3 | 3 |
Assets, Current | 730 | 1,020 |
Regulated Entity, Other Assets, Noncurrent | 2,266 | 2,273 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 752 | 756 |
Assets, Current | 74 | 85 |
Regulated Entity, Other Assets, Noncurrent | $ 48 | $ 52 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating Revenues: | ||
Electric Domestic Regulated Revenue | $ 577 | $ 592 |
Regulated Operating Revenue, Gas | 322 | 299 |
Gas-nonregulated | 274 | 281 |
Regulated and Unregulated Operating Revenue | 1,173 | 1,172 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 136 | 136 |
Purchased power | 11 | 11 |
Gas purchased for resale | 370 | 359 |
Other operation and maintenance | 179 | 181 |
Depreciation and amortization | 95 | 91 |
Other taxes | 66 | 63 |
Total Operating Expenses | 857 | 841 |
Operating Income | 316 | 331 |
Other Income (Expense): | ||
Other income | 17 | 16 |
Other expense | (10) | (14) |
Interest Expense | (87) | (83) |
Allowance for equity funds used during construction | 9 | 5 |
Total Other Expense | (71) | (76) |
Income Before Income Tax Expense | 245 | 255 |
Income Tax Expense | 74 | 79 |
Net Income | $ 171 | $ 176 |
Earnings Per Share, Basic and Diluted | $ 1.19 | $ 1.23 |
Per Common Share Data | ||
Weighted Average Number of Shares Outstanding, Basic and Diluted | 142.9 | 142.9 |
Weighted Average Common Shares Outstanding (millions) | ||
Dividends, Common Stock | $ 87 | $ 82 |
Common Stock, Dividends, Per Share, Declared | $ 0.6125 | $ 0.575 |
SCEG | ||
Operating Revenues: | ||
Electric Domestic Regulated Revenue | $ 577 | $ 592 |
Regulated Operating Revenue, Gas | 141 | 124 |
Regulated Operating Revenue | 719 | 717 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 112 | 119 |
Purchased power | 11 | 11 |
Gas purchased for resale | 66 | 50 |
Other operation and maintenance | 101 | 96 |
Depreciation and amortization | 77 | 74 |
Other taxes | 60 | 56 |
Total Operating Expenses | 497 | 481 |
Operating Income | 222 | 236 |
Other Income (Expense): | ||
Other income | 8 | 5 |
Other expense | (6) | (8) |
Interest Expense | (69) | (66) |
Allowance for equity funds used during construction | 9 | 5 |
Total Other Expense | (58) | (64) |
Income Before Income Tax Expense | 164 | 172 |
Income Tax Expense | 52 | 56 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 112 | 116 |
Net Income (Loss) Attributable to Noncontrolling Interest | (3) | (3) |
Earnings Available to Common Shareholder | 109 | 113 |
Weighted Average Common Shares Outstanding (millions) | ||
Dividends, Common Stock | 79 | 74 |
Affiliated Entity [Member] | SCEG | ||
Operating Revenues: | ||
Electric Domestic Regulated Revenue | 1 | 1 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 24 | 17 |
Gas purchased for resale | 0 | 6 |
Other operation and maintenance | 45 | 50 |
Other taxes | $ 1 | $ 2 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Allowance for Funds Used During Construction, Capitalized Interest | $ 6 | $ 4 |
SCEG | ||
Allowance for Funds Used During Construction, Capitalized Interest | $ 6 | $ 3 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 171 | $ 176 |
Other Comprehensive Income (Loss) | ||
Unrealized gains (losses) on cash flow hedging activities arising during period | (2) | (5) |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | (2) | 2 |
Other Comprehensive Income (Loss) | (2) | 2 |
Comprehensive income available to common shareholder | 169 | 178 |
SCEG | ||
Other Comprehensive Income (Loss) | ||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 112 | 116 |
Genco | ||
Other Comprehensive Income (Loss) | ||
Less comprehensive income attributable to noncontrolling interest | 3 | 3 |
SCE&G (including Fuel Company) | ||
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | 109 | 113 |
Other Comprehensive Income (Loss) | ||
Comprehensive income available to common shareholder | 109 | 113 |
Commodity Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2) | 5 |
Interest Rate Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | 2 |
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ (2) | $ (2) |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax | $ 0 | $ 0 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | (1) | (3) |
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) | $ 3 |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash Flows From Operating Activities: | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 171 | $ 176 |
Adjustments to reconcile net income to net cash provided from operating activities: | ||
Deferred Income Tax Expense (Benefit) | 27 | (11) |
Depreciation and amortization | 100 | 94 |
Amortization of nuclear fuel | 14 | 14 |
Allowance for equity funds used during construction | (9) | (5) |
Carrying cost recovery | (5) | (4) |
Cash provided (used) by changes in certain assets and liabilities: | ||
Increase (Decrease) in Receivables | 67 | |
Increase (Decrease) Income Taxes Receivable | 136 | |
Increase (Decrease) in Inventories | 6 | 11 |
increase (Decrease) in Prepaid Expense | (5) | (11) |
Increase (Decrease) in Other Regulatory Assets | (4) | |
Increase (Decrease) in Regulatory liabilities | (3) | (1) |
Increase (Decrease ) in Accounts payable | (48) | (39) |
Unrecognized tax benefits, increase (decrease) | 55 | |
Increase (Decrease) in Taxes accrued | (142) | (159) |
Increase (Decrease) in Derivative Assets and Liabilities | (3) | (3) |
Changes in other assets | (2) | (20) |
Changes in other liabilities | (46) | 19 |
Net Cash Provided From Operating Activities | 309 | 61 |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | (342) | (385) |
Proceeds from investments (including derivative collateral posted) | 19 | 198 |
Purchase of investments (including derivative collateral posted) | (20) | (264) |
Net Cash Used in Investing Activities | (343) | (451) |
Cash Flows From Financing Activities: | ||
Repayments of Long-term Debt | (8) | (8) |
Dividends | (82) | (78) |
Short-term borrowings, net | (72) | 386 |
Net Cash Provided From Financing Activities | (162) | 300 |
Net (Decrease) Increase in Cash and Cash Equivalents | (196) | (90) |
Cash and Cash Equivalents, January 1 | 208 | 176 |
Cash and Cash Equivalents, March 31 | 12 | 86 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 76 | 77 |
Cash paid for-Income taxes | 0 | 141 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | 57 | 142 |
Capital Lease Obligations Incurred | 5 | |
SCEG | ||
Cash Flows From Operating Activities: | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 112 | 116 |
Adjustments to reconcile net income to net cash provided from operating activities: | ||
Deferred Income Tax Expense (Benefit) | 12 | (15) |
Depreciation and amortization | 79 | 76 |
Amortization of nuclear fuel | 14 | 14 |
Allowance for equity funds used during construction | (9) | (5) |
Carrying cost recovery | (5) | (4) |
Cash provided (used) by changes in certain assets and liabilities: | ||
Increase (Decrease) in Receivables | 45 | 7 |
Increase (Decrease) Income Taxes Receivable | 53 | |
Increase (Decrease) in Due from Affiliates, Current | 2 | (2) |
Increase (Decrease) in Inventories | (7) | (3) |
increase (Decrease) in Prepaid Expense | 0 | (3) |
Increase (Decrease) in Other Regulatory Assets | (2) | 2 |
Increase (Decrease) in Regulatory liabilities | 0 | (1) |
Increase (Decrease ) in Accounts payable | (11) | (23) |
Unrecognized tax benefits, increase (decrease) | 97 | 0 |
Increase (Decrease) in Due to Affiliate, Current | (21) | (8) |
Increase (Decrease) in Taxes accrued | (93) | (223) |
Changes in other assets | 1 | (8) |
Changes in other liabilities | (14) | 25 |
Net Cash Provided From Operating Activities | 253 | (55) |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | (282) | (337) |
Proceeds from investments (including derivative collateral posted) | 10 | 171 |
Purchase of investments (including derivative collateral posted) | (12) | (239) |
Investment In Affiliate | 9 | |
Net Cash Used in Investing Activities | (284) | (396) |
Cash Flows From Financing Activities: | ||
Repayments of Long-term Debt | (8) | (8) |
Dividends | (79) | (75) |
Short-term borrowings-affiliate,net | (1) | 11 |
Short-term borrowings, net | (34) | 450 |
Net Cash Provided From Financing Activities | (122) | 378 |
Net (Decrease) Increase in Cash and Cash Equivalents | (153) | (73) |
Cash and Cash Equivalents, January 1 | 164 | 130 |
Cash and Cash Equivalents, March 31 | 11 | 57 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 61 | 63 |
Income Taxes Paid | 3 | 175 |
Proceeds from Income Tax Refunds | 143 | 7 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | $ 46 | 109 |
Capital Lease Obligations Incurred | $ 5 |
CONDENSED CONSOLIDATED STATEME9
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Interest Paid, Capitalized | $ 6 | $ 4 |
SCEG | ||
Interest Paid, Capitalized | $ 6 | $ 3 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON EQUITY Statement - USD ($) shares in Millions, $ in Millions | Total | AOCI Attributable to Parent [Member] | SCEG | SCEG excluding VIEs [Member] | SCEG and GENCO [Member] |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Stockholders' Equity before Treasury Stock | $ 2,402 | ||||
Treasury Stock, Value | (12) | ||||
Retained Earnings, Appropriated | 3,118 | $ 2,265 | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (53) | ||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (12) | ||||
Accumulated Other Comprehensive Income (Loss) | (65) | (3) | |||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 129 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ 5,151 | ||||
Stockholders' Equity Attributable to Parent | $ 5,443 | ||||
Common Stock, Value, Outstanding | $ 2,760 | ||||
Shares, Outstanding | 143 | 40 | |||
Common Stock, Dividends, Per Share, Declared | $ 0.575 | ||||
Net Income (Loss) Available to Common Stockholders, Basic | $ 176 | $ 113 | |||
Net Income (Loss) Attributable to Noncontrolling Interest | 3 | 3 | |||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 116 | ||||
Dividends | 74 | 72 | |||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 2 | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (5) | ||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 0 | ||||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 2 | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 7 | ||||
Other Comprehensive Income (Loss) | 2 | ||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 178 | 113 | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | ||||
Dividends, Common Stock | (82) | (74) | |||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 2 | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (5) | ||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 0 | ||||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 2 | ||||
Stockholders' Equity before Treasury Stock | 2,402 | ||||
Treasury Stock, Value | (12) | ||||
Retained Earnings, Appropriated | 3,212 | 2,306 | |||
AOCI before Tax, Attributable to Parent | (7) | $ (5) | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (51) | ||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (12) | ||||
Accumulated Other Comprehensive Income (Loss) | (63) | $ (3) | |||
Stockholders' Equity Attributable to Noncontrolling Interest | 130 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,193 | ||||
Stockholders' Equity Attributable to Parent | $ 5,539 | ||||
Shares, Outstanding | 143 | 40 | |||
AOCI before Tax, Attributable to Parent | $ (7) | (5) | |||
Stockholders' Equity before Treasury Stock | 2,402 | ||||
Treasury Stock, Value | (12) | ||||
Retained Earnings, Appropriated | 3,384 | 2,481 | $ 2,481 | ||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (36) | ||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (13) | ||||
Accumulated Other Comprehensive Income (Loss) | (49) | (3) | |||
Stockholders' Equity Attributable to Noncontrolling Interest | 134 | 134 | |||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,472 | ||||
Stockholders' Equity Attributable to Parent | 5,725 | 5,338 | |||
Common Stock, Value, Outstanding | $ 2,390 | 2,860 | $ 2,860 | ||
Shares, Outstanding | 143 | 40 | |||
Common Stock, Dividends, Per Share, Declared | $ 0.6125 | ||||
Net Income (Loss) Available to Common Stockholders, Basic | $ 171 | $ 109 | |||
Net Income (Loss) Attributable to Noncontrolling Interest | 3 | 3 | |||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 112 | ||||
Dividends | 79 | 77 | |||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 2 | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (2) | ||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 0 | ||||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | (2) | ||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 0 | ||||
Other Comprehensive Income (Loss) | (2) | ||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 169 | 109 | |||
Treasury Stock Purchased | (1) | ||||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | ||||
Dividends, Common Stock | (87) | (79) | |||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 2 | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (2) | ||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 0 | ||||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | (2) | ||||
Stockholders' Equity before Treasury Stock | 2,402 | ||||
Treasury Stock, Value | (13) | ||||
Retained Earnings, Appropriated | 3,468 | 2,513 | 2,513 | ||
AOCI before Tax, Attributable to Parent | 0 | (2) | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (38) | ||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (13) | ||||
Accumulated Other Comprehensive Income (Loss) | (51) | (3) | |||
Stockholders' Equity Attributable to Noncontrolling Interest | 135 | $ 135 | |||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,505 | ||||
Stockholders' Equity Attributable to Parent | 5,806 | 5,370 | |||
Common Stock, Value, Outstanding | $ 2,389 | $ 2,860 | $ 2,860 | ||
Shares, Outstanding | 143 | 40 | |||
AOCI before Tax, Attributable to Parent | $ 0 | $ (2) |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 3 Months Ended |
Mar. 31, 2017 | |
Significant Accounting Policies | |
Significant Accounting Policies [Text Block] | 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 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 $487 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 4. 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 10) are presented within Operating Income, and all 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that 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. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer 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. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined that adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the initial identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. 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. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes 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 and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements. In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements. |
SCEG | |
Significant Accounting Policies | |
Significant Accounting Policies [Text Block] | 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 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 $487 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 4. 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 10) are presented within Operating Income, and all 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that 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. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer 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. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined that adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the initial identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. 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. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes 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 and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements. In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements. |
RATE AND OTHER REGULATORY MATTE
RATE AND OTHER REGULATORY MATTERS | 3 Months Ended |
Mar. 31, 2017 | |
Rate Matters [Line Items] | |
Public Utilities Disclosure [Text Block] | RATE AND OTHER REGULATORY MATTERS Rate Matters Electric - Cost of Fuel By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and to recover related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component in such a manner as to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying cost will be allowed for base fuel component under collected balances, as they occur. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three months ended March 31, 2017 totaled $4.3 million . During the three months ended March 31, 2016, carrying costs totaled $3.1 million . SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately $11.9 million . The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017. In January 2017, SCE&G requested in its annual DSM Programs filing to recover $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017. Gas - PSNC Energy PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of $1.9 million . The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017. 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. Other than 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. The Company Consolidated SCE&G Millions of dollars March 31, December 31, March 31, December 31, Regulatory Assets: Accumulated deferred income taxes $ 317 $ 316 $ 309 $ 307 AROs and related funding 425 425 402 403 Deferred employee benefit plan costs 336 342 303 309 Deferred losses on interest rate derivatives 614 620 614 620 Unrecovered plant 113 117 113 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to nuclear construction 37 32 37 32 Pipeline integrity management costs 37 33 6 6 Environmental remediation costs 31 32 25 26 Deferred storm damage costs 20 20 20 20 Deferred costs related to uncertain tax position 17 15 17 15 Other 122 119 121 116 Total Regulatory Assets $ 2,128 $ 2,130 $ 2,026 $ 2,030 Regulatory Liabilities: Asset removal costs $ 760 $ 755 $ 533 $ 529 Deferred gains on interest rate derivatives 157 151 157 151 Other 21 24 15 15 Total Regulatory Liabilities $ 938 $ 930 $ 705 $ 695 Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion of these regulatory assets 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. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. 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 110 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. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or 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 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. 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 such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020. Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling $20.3 million over a five -year period beginning November 2016, and remaining costs of $11.3 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years. 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. Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. 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 or other changes in the regulatory environment or changes in accounting requirements, 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. |
SCEG | |
Rate Matters [Line Items] | |
Public Utilities Disclosure [Text Block] | RATE AND OTHER REGULATORY MATTERS Rate Matters Electric - Cost of Fuel By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and to recover related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component in such a manner as to produce a projected under recovery of $61.0 million over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately $16.5 million . Additionally, deferral of carrying cost will be allowed for base fuel component under collected balances, as they occur. Electric - Base Rates Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three months ended March 31, 2017 totaled $4.3 million . During the three months ended March 31, 2016, carrying costs totaled $3.1 million . SCE&G anticipates that when the New Units are placed in service and accelerated tax depreciation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately $11.9 million . The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017. In January 2017, SCE&G requested in its annual DSM Programs filing to recover $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017. Gas - PSNC Energy PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of $1.9 million . The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017. 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. Other than 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. The Company Consolidated SCE&G Millions of dollars March 31, December 31, March 31, December 31, Regulatory Assets: Accumulated deferred income taxes $ 317 $ 316 $ 309 $ 307 AROs and related funding 425 425 402 403 Deferred employee benefit plan costs 336 342 303 309 Deferred losses on interest rate derivatives 614 620 614 620 Unrecovered plant 113 117 113 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to nuclear construction 37 32 37 32 Pipeline integrity management costs 37 33 6 6 Environmental remediation costs 31 32 25 26 Deferred storm damage costs 20 20 20 20 Deferred costs related to uncertain tax position 17 15 17 15 Other 122 119 121 116 Total Regulatory Assets $ 2,128 $ 2,130 $ 2,026 $ 2,030 Regulatory Liabilities: Asset removal costs $ 760 $ 755 $ 533 $ 529 Deferred gains on interest rate derivatives 157 151 157 151 Other 21 24 15 15 Total Regulatory Liabilities $ 938 $ 930 $ 705 $ 695 Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion of these regulatory assets 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. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. 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 110 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. In 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or 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 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. 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 such programs, and such deferred costs are currently being recovered over approximately five years through an approved rate rider. Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over ten years beginning in approximately 2020. Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling $20.3 million over a five -year period beginning November 2016, and remaining costs of $11.3 million have been deferred pending future approval of rate recovery. SCE&G began amortizing $1.9 million of such costs annually in November 2015. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately 18 years. 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. Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5. Various other regulatory assets are expected to be recovered through rates over varying periods through 2047. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders. 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 or other changes in the regulatory environment or changes in accounting requirements, 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. |
COMMON EQUITY
COMMON EQUITY | 3 Months Ended |
Mar. 31, 2017 | |
Common Equity Note [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | SCANA had 200 million shares of common stock authorized as of March 31, 2017 and December 31, 2016. Gains and losses on cash flow hedges reclassified from AOCI during the three months ended March 31, 2017 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $2 million . Such reclassifications during the comparable period in 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 million . |
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, 2017 and December 31, 2016. 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, 2017 and December 31, 2016. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. |
LONG-TERM AND SHORT-TERM DEBT
LONG-TERM AND SHORT-TERM DEBT | 3 Months Ended |
Mar. 31, 2017 | |
Debt Instrument [Line Items] | |
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: March 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) 869.5 50.4 769.9 49.2 Weighted average interest rate 1.47 % 1.22 % 1.27 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,127.2 $ 346.6 $ 629.8 $ 150.8 December 31, 2016 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) 940.5 64.4 804.3 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 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 $28 million at March 31, 2017, and $29 million at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables. |
SCEG | |
Debt Instrument [Line Items] | |
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: March 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) 869.5 50.4 769.9 49.2 Weighted average interest rate 1.47 % 1.22 % 1.27 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,127.2 $ 346.6 $ 629.8 $ 150.8 December 31, 2016 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) 940.5 64.4 804.3 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 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 $28 million at March 31, 2017, and $29 million at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2017 | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | 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 IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. 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, SCANA amended certain of its income tax returns 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). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. 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 2015 income tax returns. These income tax deductions and credits are 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 are required to be recorded as unrecognized tax benefits in the financial statements. As of March 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $382 million ( $274 million and $333 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $273 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $53 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2017. In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2). Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. 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. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any periods presented. Effective January 1, 2017, the State of North Carolina reduced its corporate income tax rate from 4% to 3% . This reduction did not 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] | 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 IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. 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, SCANA amended certain of its income tax returns 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). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the ongoing design and construction activities of the New Units, in its 2015 income tax returns. 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 2015 income tax returns. These income tax deductions and credits are 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 are required to be recorded as unrecognized tax benefits in the financial statements. As of March 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $382 million ( $274 million and $333 million for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). It is reasonably possible that these unrecognized tax benefits may increase by an additional $273 million within the next 12 months as additional expenditures giving rise to pilot model tax benefits are incurred. It is also reasonably possible that these unrecognized tax benefits may decrease by $53 million within the next 12 months if the claims on the amended returns which are currently in appeals are resolved and that resolution were also applied to the 2013 and 2014 returns. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2017. In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2). Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. 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. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any periods presented. Effective January 1, 2017, the State of North Carolina reduced its corporate income tax rate from 4% to 3% . This reduction did not have a material impact on the Company's financial position, results of operations or cash flows. |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 3 Months Ended |
Mar. 31, 2017 | |
Derivative [Line Items] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | 6. 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 condensed 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 the 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 as cash flow hedges, and fair value changes and settlement amounts related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances, and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. 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: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of March 31, 2017 Commodity contracts 6,500,000 10,134,000 16,634,000 Energy management contracts (a) — 55,028,797 55,028,797 Total (a) 6,500,000 65,162,797 71,662,797 As of December 31, 2016 Commodity contracts 4,510,000 11,947,000 16,457,000 Energy management contracts (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Designated as hedging instruments $ 115.6 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,285.0 1,285.0 1,285.0 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. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of March 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 25 — 8 Commodity contracts Prepayments $ 1 — — — Other current assets 1 — — — Total $ 2 $ 27 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 77 — $ 77 — Derivative financial instruments — $ 22 — $ 22 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Prepayments 2 — — — Energy management contracts Prepayments 2 1 — — Other current assets 2 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 3 — — Other deferred credits and other liabilities — 1 — — Total $ 84 $ 30 $ 77 $ 25 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 4 — $ 1 Other deferred credits and other liabilities — 24 — 8 Commodity contracts Prepayments $ 5 — — — Other current assets 1 — — — Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 — $ 71 — Derivative financial instruments — $ 27 — $ 27 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Other current assets 3 — — — Energy management contracts Prepayments 6 2 — — Other current assets 2 1 — — Other deferred debits and other assets 2 — — — Derivative financial instruments — 4 — — Other deferred credits and other liabilities — 2 — — Total $ 84 $ 39 $ 71 $ 30 The effect of derivative instruments on the condensed consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (1 ) $ (1 ) The Company: Loss Recognized in OCI, net of tax Gain/(Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (2 ) $ (2 ) Commodity contracts $ (2 ) (2 ) Gas purchased for resale 2 (5 ) Total $ (2 ) $ (5 ) $ — $ (7 ) As of March 31, 2017, 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 a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense. As of March 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019. As of March 31, 2017, 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 $1.7 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. Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts $ 11 $ (144 ) Interest Expense $ (1 ) — As of March 31, 2017, 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 $2.4 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. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 46.0 $ 50.3 $ 26.4 $ 30.3 Fair value of collateral already posted 30.4 29.2 9.0 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 15.6 $ 21.1 $ 17.4 $ 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 69.9 $ 62.9 $ 69.6 $ 62.0 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 69.9 $ 62.9 $ 69.6 $ 62.0 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 $1.8 million related to $6.0 million in commodity derivatives that are in a net asset position at March 31, 2017, compared to letters of credit in the amount of $1.5 million related to derivatives of $9.0 million at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets and derivative liabilities follows: 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, 2017 Gross Amounts of Recognized Assets $ 77 $ 4 $ 5 $ 86 $ 77 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 77 4 4 85 77 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 69 $ 4 $ 4 $ 77 $ 69 Balance sheet location Prepayments $ 4 — Other current assets 2 — Other deferred debits and other assets 79 $ 77 Total $ 85 $ 77 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position — — (4 ) (4 ) — Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 — Other current assets 5 — Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 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, 2017 Gross Amounts of Recognized Liabilities $ 52 — $ 5 $ 57 $ 34 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 52 — 4 56 34 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — (1 ) (30 ) (9 ) Net Amount $ 15 — $ 3 $ 18 $ 17 Balance sheet location Derivative financial instruments $ 27 $ 23 Other deferred credits and other liabilities 29 11 Total $ 56 $ 34 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 — $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position — — (3 ) (3 ) — Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — — (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39 |
SCEG | |
Derivative [Line Items] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | 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 condensed 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 the 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 as cash flow hedges, and fair value changes and settlement amounts related to them are recorded as regulatory assets and liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances, and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC. 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: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of March 31, 2017 Commodity contracts 6,500,000 10,134,000 16,634,000 Energy management contracts (a) — 55,028,797 55,028,797 Total (a) 6,500,000 65,162,797 71,662,797 As of December 31, 2016 Commodity contracts 4,510,000 11,947,000 16,457,000 Energy management contracts (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016. The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Designated as hedging instruments $ 115.6 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,285.0 1,285.0 1,285.0 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. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of March 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 25 — 8 Commodity contracts Prepayments $ 1 — — — Other current assets 1 — — — Total $ 2 $ 27 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 77 — $ 77 — Derivative financial instruments — $ 22 — $ 22 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Prepayments 2 — — — Energy management contracts Prepayments 2 1 — — Other current assets 2 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 3 — — Other deferred credits and other liabilities — 1 — — Total $ 84 $ 30 $ 77 $ 25 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 4 — $ 1 Other deferred credits and other liabilities — 24 — 8 Commodity contracts Prepayments $ 5 — — — Other current assets 1 — — — Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 — $ 71 — Derivative financial instruments — $ 27 — $ 27 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Other current assets 3 — — — Energy management contracts Prepayments 6 2 — — Other current assets 2 1 — — Other deferred debits and other assets 2 — — — Derivative financial instruments — 4 — — Other deferred credits and other liabilities — 2 — — Total $ 84 $ 39 $ 71 $ 30 The effect of derivative instruments on the condensed consolidated statements of income is as follows: Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (1 ) $ (1 ) The Company: Loss Recognized in OCI, net of tax Gain/(Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (2 ) $ (2 ) Commodity contracts $ (2 ) (2 ) Gas purchased for resale 2 (5 ) Total $ (2 ) $ (5 ) $ — $ (7 ) As of March 31, 2017, 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 a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $6.5 million as an increase to interest expense. As of March 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the second quarter of 2019. As of March 31, 2017, 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 $1.7 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. Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts $ 11 $ (144 ) Interest Expense $ (1 ) — As of March 31, 2017, 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 $2.4 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. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 46.0 $ 50.3 $ 26.4 $ 30.3 Fair value of collateral already posted 30.4 29.2 9.0 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 15.6 $ 21.1 $ 17.4 $ 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 69.9 $ 62.9 $ 69.6 $ 62.0 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 69.9 $ 62.9 $ 69.6 $ 62.0 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 $1.8 million related to $6.0 million in commodity derivatives that are in a net asset position at March 31, 2017, compared to letters of credit in the amount of $1.5 million related to derivatives of $9.0 million at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets and derivative liabilities follows: 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, 2017 Gross Amounts of Recognized Assets $ 77 $ 4 $ 5 $ 86 $ 77 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 77 4 4 85 77 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 69 $ 4 $ 4 $ 77 $ 69 Balance sheet location Prepayments $ 4 — Other current assets 2 — Other deferred debits and other assets 79 $ 77 Total $ 85 $ 77 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position — — (4 ) (4 ) — Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 — Other current assets 5 — Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 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, 2017 Gross Amounts of Recognized Liabilities $ 52 — $ 5 $ 57 $ 34 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 52 — 4 56 34 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — (1 ) (30 ) (9 ) Net Amount $ 15 — $ 3 $ 18 $ 17 Balance sheet location Derivative financial instruments $ 27 $ 23 Other deferred credits and other liabilities 29 11 Total $ 56 $ 34 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 — $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position — — (3 ) (3 ) — Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — — (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39 |
FAIR VALUE MEASUREMENTS, INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Disclosures [Text Block] | 7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. 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: As of March 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 15 — — $ 14 — — Held to maturity securities — $ 7 — — $ 7 — Interest rate contracts — 77 $ 77 — 71 $ 71 Commodity contracts 3 1 — 8 1 — Energy management contracts 2 3 — 6 4 — Liabilities: Interest rate contracts — 52 34 — 58 39 Energy management contracts — 8 — 2 10 — The Company 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 the periods presented. Consolidated SCE&G had no Level 1 or 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 the periods presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt March 31, 2017 December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,482.7 $ 7,029.0 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,158.7 5,606.6 5,166.0 5,752.3 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. |
SCEG | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Disclosures [Text Block] | FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. 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: As of March 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 15 — — $ 14 — — Held to maturity securities — $ 7 — — $ 7 — Interest rate contracts — 77 $ 77 — 71 $ 71 Commodity contracts 3 1 — 8 1 — Energy management contracts 2 3 — 6 4 — Liabilities: Interest rate contracts — 52 34 — 58 39 Energy management contracts — 8 — 2 10 — The Company 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 the periods presented. Consolidated SCE&G had no Level 1 or 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 the periods presented. Financial instruments for which the carrying amount may not equal estimated fair value were as follows: Long-Term Debt March 31, 2017 December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,482.7 $ 7,029.0 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,158.7 5,606.6 5,166.0 5,752.3 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. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 3 Months Ended |
Mar. 31, 2017 | |
Pension and Other Postretirement Benefit Plans | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: The Company Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 5.3 $ 5.5 $ 1.2 $ 1.3 Interest cost 9.4 9.9 2.9 3.0 Expected return on assets (13.8 ) (14.1 ) — — Prior service cost amortization 0.4 1.0 — 0.1 Amortization of actuarial losses 3.9 3.7 0.4 0.1 Net periodic benefit cost $ 5.2 $ 6.0 $ 4.5 $ 4.5 Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 4.4 $ 4.5 $ 1.0 $ 1.0 Interest cost 8.1 8.4 2.4 2.5 Expected return on assets (11.8 ) (11.9 ) — — Prior service cost amortization 0.3 0.8 — 0.1 Amortization of actuarial losses 3.4 3.1 0.3 0.1 Net periodic benefit cost $ 4.4 $ 4.9 $ 3.7 $ 3.7 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. |
SCEG | |
Pension and Other Postretirement Benefit Plans | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows: The Company Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 5.3 $ 5.5 $ 1.2 $ 1.3 Interest cost 9.4 9.9 2.9 3.0 Expected return on assets (13.8 ) (14.1 ) — — Prior service cost amortization 0.4 1.0 — 0.1 Amortization of actuarial losses 3.9 3.7 0.4 0.1 Net periodic benefit cost $ 5.2 $ 6.0 $ 4.5 $ 4.5 Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 4.4 $ 4.5 $ 1.0 $ 1.0 Interest cost 8.1 8.4 2.4 2.5 Expected return on assets (11.8 ) (11.9 ) — — Prior service cost amortization 0.3 0.8 — 0.1 Amortization of actuarial losses 3.4 3.1 0.3 0.1 Net periodic benefit cost $ 4.4 $ 4.9 $ 3.7 $ 3.7 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. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 31, 2017 | |
Statement [Line Items] | |
Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. 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. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of 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 $45.8 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 $1.8 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. New Nuclear Construction 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 the New Units. SCE&G's ownership share in the New Units is 55% . As discussed below, various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses. EPC Contract and BLRA Matters The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are to be recovered through rates beginning when the construction of each New Unit is completed and it is placed into service. As of March 31, 2017, SCE&G’s investment in the New Units, including related transmission, totaled $4.6 billion , for which the financing costs on $3.8 billion have been reflected in rates under the BLRA. The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. It is anticipated that further approval by the SCPSC is likely to be required as a consequence of the Consortium’s bankruptcy proceedings, as further described below. October 2015 Amendment and WEC's Engagement of Fluor On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, WECTEC continues to be a member of the Consortium as a subsidiary of WEC, and WEC has engaged Fluor as a subcontracted construction manager. Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion ). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016. The October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, (ii) revised the contractual guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn IRC Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit), (iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provided for development of a revised construction milestone payment schedule, (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project, (vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19, and (viii) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25% . This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. Finally, following the expiration of the January 28, 2019 moratorium, SCE&G's right to file future budget increase requests with the SCPSC is limited in certain circumstances to the extent those requests are not associated with change orders, DRB orders, transmission costs, certain time and materials costs, and certain owners’ costs. On February 28, 2017, the SCPSC issued its order denying the Petitions for Rehearing filed by certain parties that were not included in the settlement. The time period to file a Notice of Appeal of the SCPSC’s decision with the South Carolina Supreme Court has expired for three of the four non-settling parties, and none of those parties has filed a Notice of Appeal. The remaining non-settling party has until May 8, 2017, to file a Notice of Appeal. DRB Activity The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties and, under the DRB process, amounts in dispute of less than $5 million are to be resolved by the DRB without recourse. Amounts in dispute greater than $5 million are to be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction. On February 24, 2017, following SCE&G’s nonpayment of certain invoices upon its assertion that WEC had not fulfilled documentation requirements imposed by the DRB, WEC referred a related claim to the DRB. SCE&G then provided the DRB a response and WEC in turn provided its rebuttal; however, following the Consortium’s bankruptcy filing on March 29, 2017, action regarding this DRB referral ceased. Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15% of the highest projected three months' billings during the applicable year, and their aggregate nominal coverage will not excee d $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds. In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G obtained annual standby letters of credit in lieu of payment and performance bonds from WEC totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC were not to meet its payment and performance obligations under the EPC Contract, it is anticipated that this funding would provide a source of liquidity. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, and WEC has reported that substantially all of the required intellectual property and software have been deposited. SCE&G is attempting to verify that this information is present in useable form. 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 New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. In connection with the filing, SCE&G, Santee Cooper, WEC and WECTEC entered into the Interim Assessment Agreement which, as amended, expires on June 26, 2017 unless otherwise terminated. Under the terms of the Interim Assessment Agreement and while it remains in effect, all parties have agreed to continue to perform under the EPC Contract and to give SCE&G and Santee Cooper the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them. SCE&G and Santee Cooper are obligated to pay all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remains in effect. SCE&G and Santee Cooper have also agreed not to draw on the letters of credit discussed above so long as the Interim Assessment Agreement is in effect. In April of 2017, Toshiba, following several announcements and media reports and following WEC’s and WECTEC’s bankruptcy petitions, announced that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there can be no assurance that these dates will be achieved in light of WEC’s historical inability to achieve forecasted productivity and work force efficiency levels and in light of the Consortium’s bankruptcy filing. Pursuant to the Interim Assessment Agreement, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, while construction continues and SCE&G and Santee Cooper continue to make payments for such work. The initial term of the Interim Assessment Agreement was 30 days and it has been amended to extend its term through June 26, 2017; however, it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to further extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project. If, as a result of the bankruptcy process, the benefit of the fixed-price terms provided by the EPC Contract is lost, and part or all of the cost overruns expected to be incurred by the Consortium become the responsibility of SCE&G and Santee Cooper, these cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. For example, certain parties may challenge such costs as not being subject to recovery under the BLRA as a result of the terms of the settlement agreement approved by the SCPSC on November 9, 2016. If, as part of the bankruptcy process, the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume responsibilities of the contractor under the EPC Contract in order to complete the New Units. Alternatively, SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should they decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits referred to above and disclosed below. A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units. SCE&G is contesting the filed liens. SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately $118 million (SCE&G’s 55% portion being approximately $65 million ), of which $50 million (SCE&G’s 55% share being $27.5 million ) have been paid. SCE&G will continue to evaluate the issues relating to these claims during the pendency of the bankruptcy proceeding. Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project. The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA’s and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time. Santee Cooper Matters SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s projected cost for the additional 5% interest being acquired from Santee Cooper was approximately $850 million at December 31, 2016, and is being further evaluated. Nuclear Production Tax Credits The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion . Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the dates of completion forecasted by WEC in February 2017) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers. During March 2017, legislation was introduced in both houses of Congress which would eliminate the requirement that the New Units be operational before January 1, 2021 in order for their electricity production to qualify for the nuclear production tax credits; however, there can be no assurance that such legislation will become law. Other Project Matters When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. Environmental 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 includes state-specific goals for reducing national CO 2 emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue its SIP, which will ultimately define the specific compliance methodology that will 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 is reconsidering the rule and the Court of Appeals agreed to hold the case in abeyance for 60 days. 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 SO 2 and NO X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO 2 emissions and annual and ozone season NO X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO 2 and NO X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that 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. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five-year permit cycle and thus may range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and will be stayed administratively when published in the Federal Register. 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 2018 and will cost an additional $10.1 million , which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.3 million and are included in regulatory assets. |
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Statement [Line Items] | |
Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. 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. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million of total coverage for accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of 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 $45.8 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 $1.8 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. New Nuclear Construction 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 the New Units. SCE&G's ownership share in the New Units is 55% . As discussed below, various difficulties have been encountered in connection with the project. The ability of the construction team to adhere to established budgets and construction schedules has been affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There have also been contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. No assurance can be given that these and other construction-related difficulties will not continue to be experienced as construction progresses. EPC Contract and BLRA Matters The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Estimated operating costs, including the depreciation of the utility plant costs, are to be recovered through rates beginning when the construction of each New Unit is completed and it is placed into service. As of March 31, 2017, SCE&G’s investment in the New Units, including related transmission, totaled $4.6 billion , for which the financing costs on $3.8 billion have been reflected in rates under the BLRA. The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. It is anticipated that further approval by the SCPSC is likely to be required as a consequence of the Consortium’s bankruptcy proceedings, as further described below. October 2015 Amendment and WEC's Engagement of Fluor On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, WECTEC continues to be a member of the Consortium as a subsidiary of WEC, and WEC has engaged Fluor as a subcontracted construction manager. Among other things, the October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion ). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016. The October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, (ii) revised the contractual guaranteed substantial completion dates of Units 2 and 3 to August 31, 2019 and 2020, respectively, (iii) revised the delay-related liquidated damages computation requirements, including those related to the eligibility of the New Units to earn IRC Section 45J production tax credits (see also below), resulting in escalating liquidated damages that are capped at an aggregate of $338 million per New Unit (SCE&G’s 55% portion being approximately $186 million per New Unit), (iv) provided for payment to the Consortium of a completion bonus of $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provided for development of a revised construction milestone payment schedule, (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project, (vii) provided for an explicit definition of Change in Law designed to reduce the likelihood of certain future commercial disputes, with the Consortium also acknowledging and agreeing that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19, and (viii) eliminated the requirement or ability of any party to bring suit regarding disputes before substantial completion of the project. November 2016 SCPSC Order In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for the New Units which were developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option. The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Units 2 and 3, respectively. The approved capital cost schedule includes incremental capital costs that total $831 million . Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from 10.5% to 10.25% . This revised ROE will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G may not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request is denied because SCE&G is out of compliance with its approved capital cost schedule or BLRA construction milestone schedule. In most circumstances, if the projected commercial operation date for Unit 2 is extended, the expiration of the January 28, 2019 moratorium will be extended by an equal amount of time. Finally, following the expiration of the January 28, 2019 moratorium, SCE&G's right to file future budget increase requests with the SCPSC is limited in certain circumstances to the extent those requests are not associated with change orders, DRB orders, transmission costs, certain time and materials costs, and certain owners’ costs. On February 28, 2017, the SCPSC issued its order denying the Petitions for Rehearing filed by certain parties that were not included in the settlement. The time period to file a Notice of Appeal of the SCPSC’s decision with the South Carolina Supreme Court has expired for three of the four non-settling parties, and none of those parties has filed a Notice of Appeal. The remaining non-settling party has until May 8, 2017, to file a Notice of Appeal. DRB Activity The October 2015 Amendment established a DRB process for resolving certain commercial claims and disputes. The DRB is comprised of three members chosen by the parties and, under the DRB process, amounts in dispute of less than $5 million are to be resolved by the DRB without recourse. Amounts in dispute greater than $5 million are to be resolved by the DRB for the remainder of the construction of the New Units, with a reserved right to further arbitrate or to litigate such issues at the conclusion of construction. On February 24, 2017, following SCE&G’s nonpayment of certain invoices upon its assertion that WEC had not fulfilled documentation requirements imposed by the DRB, WEC referred a related claim to the DRB. SCE&G then provided the DRB a response and WEC in turn provided its rebuttal; however, following the Consortium’s bankruptcy filing on March 29, 2017, action regarding this DRB referral ceased. Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. Additionally, the EPC Contract provides the owners the right, exercisable upon certain conditions, to obtain payment and performance bonds from WEC equal to 15% of the highest projected three months' billings during the applicable year, and their aggregate nominal coverage will not excee d $100 million (or $55 million for SCE&G's 55% share). SCE&G and Santee Cooper are responsible for the cost of the bonds. In late 2015, Toshiba's credit ratings declined to below investment grade following disclosures regarding its operating and financial performance and near-term liquidity. As a result, pursuant to the above-described terms of the EPC Contract, SCE&G obtained annual standby letters of credit in lieu of payment and performance bonds from WEC totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit automatically renew for successive one-year periods until their final expiration date of August 31, 2020, unless the issuer provides a minimum 60-day notice that it will not renew. If the issuer provides notice that it will not renew, SCE&G may draw upon the standby letter of credit prior to its expiration. In the event that WEC were not to meet its payment and performance obligations under the EPC Contract, it is anticipated that this funding would provide a source of liquidity. In addition, the EPC Contract provides that upon the request of SCE&G, and at owners' cost, the Consortium must escrow certain intellectual property and software for the owners' benefit to assist in completion of the New Units. An escrow arrangement has been established, and WEC has reported that substantially all of the required intellectual property and software have been deposited. SCE&G is attempting to verify that this information is present in useable form. 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 New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. In connection with the filing, SCE&G, Santee Cooper, WEC and WECTEC entered into the Interim Assessment Agreement which, as amended, expires on June 26, 2017 unless otherwise terminated. Under the terms of the Interim Assessment Agreement and while it remains in effect, all parties have agreed to continue to perform under the EPC Contract and to give SCE&G and Santee Cooper the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them. SCE&G and Santee Cooper are obligated to pay all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remains in effect. SCE&G and Santee Cooper have also agreed not to draw on the letters of credit discussed above so long as the Interim Assessment Agreement is in effect. In April of 2017, Toshiba, following several announcements and media reports and following WEC’s and WECTEC’s bankruptcy petitions, announced that it had recorded an impairment charge of approximately $6.2 billion relating to its nuclear power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raise substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. Additionally, Toshiba indicated that it intends to significantly alter its risk management oversight of its nuclear business, and in its filings with the Bankruptcy Court, the Consortium stated that it intends to discontinue its role in the construction of nuclear plants. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the EPC Contract. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, are not likely to be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020. These later dates remain within the SCPSC-approved 18-month contingency periods provided for under the BLRA, and achievement of such dates would also allow the output of both units to qualify, under current law, for federal production tax credits (see below). However, there can be no assurance that these dates will be achieved in light of WEC’s historical inability to achieve forecasted productivity and work force efficiency levels and in light of the Consortium’s bankruptcy filing. Pursuant to the Interim Assessment Agreement, SCE&G and Santee Cooper are evaluating the various elements of the project, including forecasted costs and completion dates, while construction continues and SCE&G and Santee Cooper continue to make payments for such work. The initial term of the Interim Assessment Agreement was 30 days and it has been amended to extend its term through June 26, 2017; however, it may also be terminated earlier by SCE&G or Santee Cooper. Any decision to further extend the Interim Assessment Agreement may be impacted by the willingness of the other parties thereto. Termination of the Interim Assessment Agreement prior to such time that SCE&G and Santee Cooper have completed a full evaluation may adversely impact the continuation of construction of the project. If, as a result of the bankruptcy process, the benefit of the fixed-price terms provided by the EPC Contract is lost, and part or all of the cost overruns expected to be incurred by the Consortium become the responsibility of SCE&G and Santee Cooper, these cost increases may or may not be recoverable from the Consortium or from Toshiba under its payment guaranty, or may materially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba, which in general are limited to 25 percent of the payments made to the Consortium at the time of its breach under the EPC Contract. The ability of SCE&G to recover any increased costs through rates will be subject to review and approval by the SCPSC, and such costs may or may not qualify for recovery under the BLRA. For example, certain parties may challenge such costs as not being subject to recovery under the BLRA as a result of the terms of the settlement agreement approved by the SCPSC on November 9, 2016. If, as part of the bankruptcy process, the EPC Contract is rejected, then SCE&G and Santee Cooper will need to engage replacement contractors and/or assume responsibilities of the contractor under the EPC Contract in order to complete the New Units. Alternatively, SCE&G and Santee Cooper could also decide to abandon the construction of one or both of the New Units, leaving SCE&G to pursue cost recovery under the abandonment provisions of the BLRA. The Consortium has agreed not to reject the EPC Contract prior to the date of termination of the Interim Assessment Agreement; however, after the end of the term of the Interim Assessment Agreement, it is likely that the EPC Contract will be rejected. If the EPC Contract is rejected during the bankruptcy process, it is unlikely that SCE&G and Santee Cooper will be able to negotiate replacement contracts on similar terms with members of the Consortium, and there can be no assurance that some or all of the members of the Consortium will have roles in connection with the design, engineering or construction of the New Units. Additionally, there can be no assurance that any such replacement contracts will provide protection against future construction cost increases through a negotiated fixed price or that they will not assign some or all of the risks for escalating costs onto the owners. There also can be no assurance that SCE&G and Santee Cooper will be able to complete the construction of the New Units without significant delay or additional costs, should they decide to move forward with the project. Such delays could result in the loss of qualification for production tax credits referred to above and disclosed below. A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units. SCE&G is contesting the filed liens. SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately $118 million (SCE&G’s 55% portion being approximately $65 million ), of which $50 million (SCE&G’s 55% share being $27.5 million ) have been paid. SCE&G will continue to evaluate the issues relating to these claims during the pendency of the bankruptcy proceeding. Jointly-owned projects, such as the current construction of the New Units, are also subject to risks such as (1) one or more of the joint owners becoming either unable or unwilling to continue to fund project financial commitments, (2) new joint owners being sought but not being secured at equivalent financial terms, or (3) disagreement among joint owners or changes in the joint ownership make-up which further increase project costs, further delay the completion of the project or result in the termination of all or a portion of the project. The Consortium’s bankruptcy filing could have a material impact on the construction of the New Units and could have a material impact on SCANA’s and SCE&G’s results of operations, cash flows and financial condition. The ultimate outcome of these matters cannot be determined at this time. Santee Cooper Matters SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost, including its cost of financing, of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction is subject to customary closing conditions, including receipt of necessary regulatory approvals. This transaction will not affect the payment obligations between the parties during construction of the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. SCE&G’s projected cost for the additional 5% interest being acquired from Santee Cooper was approximately $850 million at December 31, 2016, and is being further evaluated. Nuclear Production Tax Credits The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion . Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on current tax law and the contractual guaranteed substantial completion dates (and the dates of completion forecasted by WEC in February 2017) provided above, both New Units would be operational and would qualify for the nuclear production tax credits; however, any further delays in the schedule or changes in tax law could adversely impact these conclusions. See also the Payment and Performance Obligations, Contractor Bankruptcy Proceedings and Related Uncertainties discussion above. When and to the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers. During March 2017, legislation was introduced in both houses of Congress which would eliminate the requirement that the New Units be operational before January 1, 2021 in order for their electricity production to qualify for the nuclear production tax credits; however, there can be no assurance that such legislation will become law. Other Project Matters When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an overall integration plan for the New Units to the NRC in August 2013. That plan remains under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. Environmental 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 includes state-specific goals for reducing national CO 2 emissions by 32% from 2005 levels by 2030. The rule also provides for nuclear reactors under construction, such as the New Units, to count towards compliance and establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue its SIP, which will ultimately define the specific compliance methodology that will 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 is reconsidering the rule and the Court of Appeals agreed to hold the case in abeyance for 60 days. 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 SO 2 and NO X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO 2 emissions and annual and ozone season NO X emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO 2 and NO X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that 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. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five-year permit cycle and thus may range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and will be stayed administratively when published in the Federal Register. 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 2018 and will cost an additional $10.1 million , which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At March 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $25.3 million and are included in regulatory assets. |
SEGMENT OF BUSINESS INFORMATION
SEGMENT OF BUSINESS INFORMATION | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting Information [Line Items] | |
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. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended March 31, 2017 Electric Operations $ 577 $ 1 $ 178 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 $ — $ 316 $ 171 Three Months Ended March 31, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Gas Marketing 281 22 n/a $ 24 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2017 Electric Operations $ 578 $ 178 n/a Gas Distribution 141 44 n/a Adjustments/Eliminations — — $ 109 Consolidated Total $ 719 $ 222 $ 109 Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distribution 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2017 2016 2017 2016 Electric Operations $ 12,076 $ 11,929 $ 12,076 $ 11,929 Gas Distribution 2,926 2,892 836 825 Gas Marketing 202 230 n/a n/a All Other 997 1,124 n/a n/a Adjustments/Eliminations 2,257 2,532 3,053 3,337 Consolidated Total $ 18,458 $ 18,707 $ 15,965 $ 16,091 |
SCEG | |
Segment Reporting Information [Line Items] | |
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. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended March 31, 2017 Electric Operations $ 577 $ 1 $ 178 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 $ — $ 316 $ 171 Three Months Ended March 31, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Gas Marketing 281 22 n/a $ 24 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2017 Electric Operations $ 578 $ 178 n/a Gas Distribution 141 44 n/a Adjustments/Eliminations — — $ 109 Consolidated Total $ 719 $ 222 $ 109 Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distribution 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2017 2016 2017 2016 Electric Operations $ 12,076 $ 11,929 $ 12,076 $ 11,929 Gas Distribution 2,926 2,892 836 825 Gas Marketing 202 230 n/a n/a All Other 997 1,124 n/a n/a Adjustments/Eliminations 2,257 2,532 3,053 3,337 Consolidated Total $ 18,458 $ 18,707 $ 15,965 $ 16,091 |
AFFILIATED TRANSACTIONS
AFFILIATED TRANSACTIONS | 3 Months Ended |
Mar. 31, 2017 | |
Affiliated Transactions [Line Items] | |
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. Consolidated SCE&G’s total purchases from this affiliate were $44.6 million and $52.8 million for the three months ended March 31, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were $44.4 million and $52.5 million for the three months ended March 31, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was $13.5 million at March 31, 2017 and $16.0 million at December 31, 2016. Consolidated SCE&G’s payable to this affiliate was $13.6 million at March 31, 2017 and $16.1 million at December 31, 2016. |
SCEG | |
Affiliated Transactions [Line Items] | |
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. Consolidated SCE&G’s total purchases from this affiliate were $44.6 million and $52.8 million for the three months ended March 31, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were $44.4 million and $52.5 million for the three months ended March 31, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was $13.5 million at March 31, 2017 and $16.0 million at December 31, 2016. Consolidated SCE&G’s payable to this affiliate was $13.6 million at March 31, 2017 and $16.1 million at December 31, 2016. 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. Such purchases totaled approximately $23.9 million and $22.4 million for the three months ended March 31, 2017 and 2016, respectively. SCE&G’s payables to SCANA Energy for such purchases were $8.3 million at March 31, 2017 and $8.8 million at December 31, 2016. 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, including amounts capitalized, totaled $72.5 million and $75.6 million for the three months ended March 31, 2017 and 2016, respectively. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the condensed consolidated statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were $45.8 million at March 31, 2017 and $63.5 million at December 31, 2016. Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8. |
SUMMARY OF SIGNIFICANT ACCOUN22
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
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 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 $487 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 4. |
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 10) are presented within Operating Income, and all 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, 29% and 40% of PSNC Energy’s natural gas inventory at March 31, 2017 and December 31, 2016, respectively, with a carrying value of $4.2 million and $9.8 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. This agreement expired on March 31, 2017, and was replaced with a similar agreement that 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. |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer 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. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined that adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the initial identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. 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. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes 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 and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements. In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements. |
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 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 $487 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 4. |
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 10) are presented within Operating Income, and all other activities are presented within Other Income (Expense). |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer 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. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018. The guidance permits adoption using a retrospective method, with options to elect certain practical expedients, or recognition of a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined which method of adoption will be employed or what practical expedients may be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the analysis of contracts with customers to which the guidance might be applicable, particularly large customer contracts, has begun. In addition, activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the required treatment under the standard of contributions in aid of construction, alternative revenue programs and the collectibility of revenue of utilities subject to rate regulation. In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements. In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and have determined that adoption of this guidance will not have a significant impact on their respective financial statements. 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. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the initial identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. 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. 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 is intended to result in certain 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 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements. In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements. In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements. In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes 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 and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements. In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit cost. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018 and have not determined what impact it will have on their respective financial statements. |
RATE AND OTHER REGULATORY MAT23
RATE AND OTHER REGULATORY MATTERS (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Regulatory Assets | |
Schedule of Regulatory Assets [Table Text Block] | . The Company Consolidated SCE&G Millions of dollars March 31, December 31, March 31, December 31, Regulatory Assets: Accumulated deferred income taxes $ 317 $ 316 $ 309 $ 307 AROs and related funding 425 425 402 403 Deferred employee benefit plan costs 336 342 303 309 Deferred losses on interest rate derivatives 614 620 614 620 Unrecovered plant 113 117 113 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to nuclear construction 37 32 37 32 Pipeline integrity management costs 37 33 6 6 Environmental remediation costs 31 32 25 26 Deferred storm damage costs 20 20 20 20 Deferred costs related to uncertain tax position 17 15 17 15 Other 122 119 121 116 Total Regulatory Assets $ 2,128 $ 2,130 $ 2,026 $ 2,030 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities: Asset removal costs $ 760 $ 755 $ 533 $ 529 Deferred gains on interest rate derivatives 157 151 157 151 Other 21 24 15 15 Total Regulatory Liabilities $ 938 $ 930 $ 705 $ 695 |
SCEG | |
Regulatory Assets | |
Schedule of Regulatory Assets [Table Text Block] | The Company Consolidated SCE&G Millions of dollars March 31, December 31, March 31, December 31, Regulatory Assets: Accumulated deferred income taxes $ 317 $ 316 $ 309 $ 307 AROs and related funding 425 425 402 403 Deferred employee benefit plan costs 336 342 303 309 Deferred losses on interest rate derivatives 614 620 614 620 Unrecovered plant 113 117 113 117 DSM Programs 59 59 59 59 Carrying costs on deferred tax assets related to nuclear construction 37 32 37 32 Pipeline integrity management costs 37 33 6 6 Environmental remediation costs 31 32 25 26 Deferred storm damage costs 20 20 20 20 Deferred costs related to uncertain tax position 17 15 17 15 Other 122 119 121 116 Total Regulatory Assets $ 2,128 $ 2,130 $ 2,026 $ 2,030 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities: Asset removal costs $ 760 $ 755 $ 533 $ 529 Deferred gains on interest rate derivatives 157 151 157 151 Other 21 24 15 15 Total Regulatory Liabilities $ 938 $ 930 $ 705 $ 695 |
LONG-TERM AND SHORT-TERM DEBT (
LONG-TERM AND SHORT-TERM DEBT (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Short-term Debt [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | March 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) 869.5 50.4 769.9 49.2 Weighted average interest rate 1.47 % 1.22 % 1.27 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,127.2 $ 346.6 $ 629.8 $ 150.8 December 31, 2016 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) 940.5 64.4 804.3 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 |
SCEG | |
Short-term Debt [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | March 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) 869.5 50.4 769.9 49.2 Weighted average interest rate 1.47 % 1.22 % 1.27 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,127.2 $ 346.6 $ 629.8 $ 150.8 December 31, 2016 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) 940.5 64.4 804.3 71.8 Weighted average interest rate 1.43 % 1.04 % 1.07 % Letters of credit supported by LOC 3.3 3.0 0.3 — Available $ 1,056.2 $ 332.6 $ 595.4 $ 128.2 |
DERIVATIVE FINANCIAL INSTRUME25
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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: Commodity and Other Energy Management Contracts (in MMBTU) Hedge designation Gas Distribution Gas Marketing Total As of March 31, 2017 Commodity contracts 6,500,000 10,134,000 16,634,000 Energy management contracts (a) — 55,028,797 55,028,797 Total (a) 6,500,000 65,162,797 71,662,797 As of December 31, 2016 Commodity contracts 4,510,000 11,947,000 16,457,000 Energy management contracts (a) — 67,447,223 67,447,223 Total (a) 4,510,000 79,394,223 83,904,223 (a) Includes amounts related to basis swap contracts totaling 9,630,864 MMBTU in 2017 and 730,721 MMBTU in 2016. |
Schedule of Derivative Instruments [Table Text Block] | The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Designated as hedging instruments $ 115.6 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,285.0 1,285.0 1,285.0 |
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. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of March 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 25 — 8 Commodity contracts Prepayments $ 1 — — — Other current assets 1 — — — Total $ 2 $ 27 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 77 — $ 77 — Derivative financial instruments — $ 22 — $ 22 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Prepayments 2 — — — Energy management contracts Prepayments 2 1 — — Other current assets 2 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 3 — — Other deferred credits and other liabilities — 1 — — Total $ 84 $ 30 $ 77 $ 25 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 4 — $ 1 Other deferred credits and other liabilities — 24 — 8 Commodity contracts Prepayments $ 5 — — — Other current assets 1 — — — Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 — $ 71 — Derivative financial instruments — $ 27 — $ 27 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Other current assets 3 — — — Energy management contracts Prepayments 6 2 — — Other current assets 2 1 — — Other deferred debits and other assets 2 — — — Derivative financial instruments — 4 — — Other deferred credits and other liabilities — 2 — — Total $ 84 $ 39 $ 71 $ 30 |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (1 ) $ (1 ) The Company: Loss Recognized in OCI, net of tax Gain/(Loss) Reclassified from AOCI into Income, net of tax Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (2 ) $ (2 ) Commodity contracts $ (2 ) (2 ) Gas purchased for resale 2 (5 ) Total $ (2 ) $ (5 ) $ — $ (7 ) |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts $ 11 $ (144 ) Interest Expense $ (1 ) — |
Disclosure of Credit Derivatives [Table Text Block] | Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 46.0 $ 50.3 $ 26.4 $ 30.3 Fair value of collateral already posted 30.4 29.2 9.0 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 15.6 $ 21.1 $ 17.4 $ 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 69.9 $ 62.9 $ 69.6 $ 62.0 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 69.9 $ 62.9 $ 69.6 $ 62.0 |
Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets and derivative liabilities follows: 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, 2017 Gross Amounts of Recognized Assets $ 77 $ 4 $ 5 $ 86 $ 77 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 77 4 4 85 77 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 69 $ 4 $ 4 $ 77 $ 69 Balance sheet location Prepayments $ 4 — Other current assets 2 — Other deferred debits and other assets 79 $ 77 Total $ 85 $ 77 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position — — (4 ) (4 ) — Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 — Other current assets 5 — Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 |
Offsetting Liabilities [Table Text Block] | 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, 2017 Gross Amounts of Recognized Liabilities $ 52 — $ 5 $ 57 $ 34 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 52 — 4 56 34 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — (1 ) (30 ) (9 ) Net Amount $ 15 — $ 3 $ 18 $ 17 Balance sheet location Derivative financial instruments $ 27 $ 23 Other deferred credits and other liabilities 29 11 Total $ 56 $ 34 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 — $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position — — (3 ) (3 ) — Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — — (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39 |
SCEG | |
Derivative [Line Items] | |
Schedule of Derivative Instruments [Table Text Block] | The aggregate notional amounts of the interest rate swaps were as follows: Interest Rate Swaps The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 Designated as hedging instruments $ 115.6 $ 115.6 $ 36.4 $ 36.4 Not designated as hedging instruments 1,285.0 1,285.0 1,285.0 1,285.0 |
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. Fair Values of Derivative Instruments The Company Consolidated SCE&G Millions of dollars Balance Sheet Location Asset Liability Asset Liability As of March 31, 2017 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 2 — $ 1 Other deferred credits and other liabilities — 25 — 8 Commodity contracts Prepayments $ 1 — — — Other current assets 1 — — — Total $ 2 $ 27 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 77 — $ 77 — Derivative financial instruments — $ 22 — $ 22 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Prepayments 2 — — — Energy management contracts Prepayments 2 1 — — Other current assets 2 — — — Other deferred debits and other assets 1 — — — Derivative financial instruments — 3 — — Other deferred credits and other liabilities — 1 — — Total $ 84 $ 30 $ 77 $ 25 As of December 31, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments — $ 4 — $ 1 Other deferred credits and other liabilities — 24 — 8 Commodity contracts Prepayments $ 5 — — — Other current assets 1 — — — Total $ 6 $ 28 — $ 9 Not designated as hedging instruments Interest rate contracts Other deferred debits and other assets $ 71 — $ 71 — Derivative financial instruments — $ 27 — $ 27 Other deferred credits and other liabilities — 3 — 3 Commodity contracts Other current assets 3 — — — Energy management contracts Prepayments 6 2 — — Other current assets 2 1 — — Other deferred debits and other assets 2 — — — Derivative financial instruments — 4 — — Other deferred credits and other liabilities — 2 — — Total $ 84 $ 39 $ 71 $ 30 |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives in Cash Flow Hedging Relationships The Company and Consolidated SCE&G: Loss Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts — $ (3 ) Interest expense $ (1 ) $ (1 ) |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives Not designated as Hedging Instruments The Company and Consolidated SCE&G: Gain (Loss) Deferred in Regulatory Accounts Loss Reclassified from Deferred Accounts into Income Millions of dollars 2017 2016 Location 2017 2016 Three Months Ended March 31, Interest rate contracts $ 11 $ (144 ) Interest Expense $ (1 ) — |
Disclosure of Credit Derivatives [Table Text Block] | Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 46.0 $ 50.3 $ 26.4 $ 30.3 Fair value of collateral already posted 30.4 29.2 9.0 9.2 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 15.6 $ 21.1 $ 17.4 $ 21.1 in Net Asset Position Aggregate fair value of derivatives in net asset position $ 69.9 $ 62.9 $ 69.6 $ 62.0 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered $ 69.9 $ 62.9 $ 69.6 $ 62.0 |
Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets and derivative liabilities follows: 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, 2017 Gross Amounts of Recognized Assets $ 77 $ 4 $ 5 $ 86 $ 77 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 77 4 4 85 77 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 69 $ 4 $ 4 $ 77 $ 69 Balance sheet location Prepayments $ 4 — Other current assets 2 — Other deferred debits and other assets 79 $ 77 Total $ 85 $ 77 As of December 31, 2016 Gross Amounts of Recognized Assets $ 71 $ 9 $ 10 $ 90 $ 71 Gross Amounts Offset in Statement of Financial Position — — (4 ) (4 ) — Net Amounts Presented in Statement of Financial Position 71 9 6 86 71 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 62 $ 9 $ 6 $ 77 $ 62 Balance sheet location Prepayments $ 9 — Other current assets 5 — Other deferred debits and other assets 72 $ 71 Total $ 86 $ 71 |
Offsetting Liabilities [Table Text Block] | 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, 2017 Gross Amounts of Recognized Liabilities $ 52 — $ 5 $ 57 $ 34 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 52 — 4 56 34 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — (1 ) (30 ) (9 ) Net Amount $ 15 — $ 3 $ 18 $ 17 Balance sheet location Derivative financial instruments $ 27 $ 23 Other deferred credits and other liabilities 29 11 Total $ 56 $ 34 As of December 31, 2016 Gross Amounts of Recognized Liabilities $ 58 — $ 9 $ 67 $ 39 Gross Amounts Offset in Statement of Financial Position — — (3 ) (3 ) — Net Amounts Presented in Statement of Financial Position 58 — 6 64 39 Gross Amounts Not Offset - Financial Instruments (9 ) — — (9 ) (9 ) Gross Amounts Not Offset - Cash Collateral Posted (29 ) — — (29 ) (9 ) Net Amount $ 20 — $ 6 $ 26 $ 21 Balance sheet location Derivative financial instruments $ 35 $ 28 Other deferred credits and other liabilities 29 11 Total $ 64 $ 39 |
FAIR VALUE MEASUREMENTS, INCL26
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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: As of March 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 15 — — $ 14 — — Held to maturity securities — $ 7 — — $ 7 — Interest rate contracts — 77 $ 77 — 71 $ 71 Commodity contracts 3 1 — 8 1 — Energy management contracts 2 3 — 6 4 — Liabilities: Interest rate contracts — 52 34 — 58 39 Energy management contracts — 8 — 2 10 — |
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: Long-Term Debt March 31, 2017 December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,482.7 $ 7,029.0 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,158.7 5,606.6 5,166.0 5,752.3 |
SCEG [member] | |
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: As of March 31, 2017 As of December 31, 2016 The Company Consolidated SCE&G The Company Consolidated SCE&G Millions of dollars Level 1 Level 2 Level 2 Level 1 Level 2 Level 2 Assets: Available for sale securities $ 15 — — $ 14 — — Held to maturity securities — $ 7 — — $ 7 — Interest rate contracts — 77 $ 77 — 71 $ 71 Commodity contracts 3 1 — 8 1 — Energy management contracts 2 3 — 6 4 — Liabilities: Interest rate contracts — 52 34 — 58 39 Energy management contracts — 8 — 2 10 — |
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: Long-Term Debt March 31, 2017 December 31, 2016 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 6,482.7 $ 7,029.0 $ 6,489.8 $ 7,183.3 Consolidated SCE&G 5,158.7 5,606.6 5,166.0 5,752.3 |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Pension and Other Postretirement Benefit Plans | |
Schedule of Net Benefit Costs [Table Text Block] | The Company Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 5.3 $ 5.5 $ 1.2 $ 1.3 Interest cost 9.4 9.9 2.9 3.0 Expected return on assets (13.8 ) (14.1 ) — — Prior service cost amortization 0.4 1.0 — 0.1 Amortization of actuarial losses 3.9 3.7 0.4 0.1 Net periodic benefit cost $ 5.2 $ 6.0 $ 4.5 $ 4.5 Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 4.4 $ 4.5 $ 1.0 $ 1.0 Interest cost 8.1 8.4 2.4 2.5 Expected return on assets (11.8 ) (11.9 ) — — Prior service cost amortization 0.3 0.8 — 0.1 Amortization of actuarial losses 3.4 3.1 0.3 0.1 Net periodic benefit cost $ 4.4 $ 4.9 $ 3.7 $ 3.7 |
SCEG | |
Pension and Other Postretirement Benefit Plans | |
Schedule of Net Benefit Costs [Table Text Block] | Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Three months ended March 31, Service cost $ 4.4 $ 4.5 $ 1.0 $ 1.0 Interest cost 8.1 8.4 2.4 2.5 Expected return on assets (11.8 ) (11.9 ) — — Prior service cost amortization 0.3 0.8 — 0.1 Amortization of actuarial losses 3.4 3.1 0.3 0.1 Net periodic benefit cost $ 4.4 $ 4.9 $ 3.7 $ 3.7 |
SEGMENT OF BUSINESS INFORMATI28
SEGMENT OF BUSINESS INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | The Company Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended March 31, 2017 Electric Operations $ 577 $ 1 $ 178 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 $ — $ 316 $ 171 Three Months Ended March 31, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Gas Marketing 281 22 n/a $ 24 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2017 Electric Operations $ 578 $ 178 n/a Gas Distribution 141 44 n/a Adjustments/Eliminations — — $ 109 Consolidated Total $ 719 $ 222 $ 109 Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distribution 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2017 2016 2017 2016 Electric Operations $ 12,076 $ 11,929 $ 12,076 $ 11,929 Gas Distribution 2,926 2,892 836 825 Gas Marketing 202 230 n/a n/a All Other 997 1,124 n/a n/a Adjustments/Eliminations 2,257 2,532 3,053 3,337 Consolidated Total $ 18,458 $ 18,707 $ 15,965 $ 16,091 |
SCEG | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2017 Electric Operations $ 578 $ 178 n/a Gas Distribution 141 44 n/a Adjustments/Eliminations — — $ 109 Consolidated Total $ 719 $ 222 $ 109 Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distribution 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2017 2016 2017 2016 Electric Operations $ 12,076 $ 11,929 $ 12,076 $ 11,929 Gas Distribution 2,926 2,892 836 825 Gas Marketing 202 230 n/a n/a All Other 997 1,124 n/a n/a Adjustments/Eliminations 2,257 2,532 3,053 3,337 Consolidated Total $ 18,458 $ 18,707 $ 15,965 $ 16,091 |
SUMMARY OF SIGNIFICANT ACCOUN29
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | |
Significant Accounting Policies | ||
Property, Plant and Equipment, Net | $ 275 | $ 276 |
SCEG | ||
Significant Accounting Policies | ||
Property, Plant and Equipment, Net | $ 69 | $ 69 |
Genco | ||
Significant Accounting Policies | ||
Power Generation Capacity Megawatts | MW | 605 | |
Property, Plant and Equipment, Net | $ 487 | |
PSNC Energy [Member] | ||
Significant Accounting Policies | ||
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent) | 29.00% | 40.00% |
Natural gas inventory, carrying amount | $ 4.2 | $ 9.8 |
PercentOfStorageFeesCreditedToRatePayers | 75.00% |
RATE AND OTHER REGULATORY MAT30
RATE AND OTHER REGULATORY MATTERS (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2013 | |
SCEG | |||
Rate Matters [Line Items] | |||
Capacity of renewable energy facilities by 2020 | 84.5 | ||
SCPSC Order, Recovery Of Projected DER Program Costs | $ 16.5 | ||
SCPSC Order for Increase of Total Fuel Cost Component of Retail Electric Rates to produce a projected under recovery | 61 | ||
SCPSC Order, Approx Annual pension rider decrease amount | 11.9 | ||
Carrying costs on deferred income tax assets | 4.3 | $ 3.1 | |
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount | 37 | ||
PSNC Energy | |||
Rate Matters [Line Items] | |||
Pipeline integrity mgmt annual revenue requirement approved by NCUC | $ 1.9 | ||
Deferred Income Tax Charges [Member] | |||
Rate Matters [Line Items] | |||
Regulatory Noncurrent Asset Amortization Period | 85 years | ||
Asset Retirement Obligation Costs [Member] | |||
Rate Matters [Line Items] | |||
Regulatory Noncurrent Asset Amortization Period | 110 years | ||
Environmental Restoration Costs [Member] | |||
Rate Matters [Line Items] | |||
MPG environmental remediation | 18 | ||
Pension costs, electric [Member] | SCEG | |||
Rate Matters [Line Items] | |||
Regulatory Noncurrent Asset Amortization Period | 30 years | ||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | $ 63 | ||
Pension costs, gas [Member] | SCEG | |||
Rate Matters [Line Items] | |||
Regulatory Noncurrent Asset Amortization Period | 14 years | ||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | $ 14 | ||
Pension Costs [Member] | SCEG | |||
Rate Matters [Line Items] | |||
Regulatory Noncurrent Asset Amortization Period | 11 years |
RATE AND OTHER REGULATORY MAT31
RATE AND OTHER REGULATORY MATTERS (Details 2) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2013 | Dec. 31, 2016 | |
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 2,128 | $ 2,130 | |
SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 2,026 | 2,030 | |
PSNC Energy [Member] | |||
Regulatory Assets | |||
Pipeline integrity management costs, amount deferred pending future approval of rate recovery | 11.3 | ||
Pipeline integrity management costs, amount recovering beginning November 2016 | $ 20.3 | ||
Deferred Income Tax Charges [Member] | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 85 years | ||
Regulatory Assets, Noncurrent | $ 317 | 316 | |
Deferred Income Tax Charges [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 309 | 307 | |
Asset Retirement Obligation Costs [Member] | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 110 years | ||
Regulatory Assets, Noncurrent | $ 425 | 425 | |
Asset Retirement Obligation Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 402 | 403 | |
Pension Costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 336 | 342 | |
Pension Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 11 years | ||
Regulatory Assets, Noncurrent | $ 303 | 309 | |
Pension costs, electric [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 30 years | ||
Deferred Losses On Interest Rate Derivatives [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 614 | 620 | |
Deferred Losses On Interest Rate Derivatives [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 614 | 620 | |
unrecovered plant [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 113 | 117 | |
unrecovered plant [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 113 | 117 | |
Demand Side Management programs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 59 | 59 | |
Demand Side Management programs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 5 years | ||
Regulatory Assets, Noncurrent | $ 59 | 59 | |
carrying cost on nuclear [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 37 | 32 | |
carrying cost on nuclear [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 10 years | ||
Regulatory Assets, Noncurrent | $ 37 | 32 | |
Pipeline integrity management costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 37 | 33 | |
Pipeline integrity management costs [Member] | SCEG | |||
Regulatory Assets | |||
Pipeline integrity management costs, annual amortization amount | 1.9 | ||
Regulatory Assets, Noncurrent | $ 6 | 6 | |
Pipeline integrity management costs [Member] | PSNC Energy [Member] | |||
Regulatory Assets | |||
Regulatory Asset, Amortization Period | 5 years | ||
Environmental Restoration Costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 31 | 32 | |
Environmental Restoration Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 25 | 26 | |
Storm Costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 20 | 20 | |
Storm Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 20 | 20 | |
Deferred costs uncertain tax position [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 17 | 15 | |
Deferred costs uncertain tax position [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 17 | 15 | |
Other Regulatory Assets [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 122 | 119 | |
Other Regulatory Assets [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 121 | $ 116 |
RATE AND OTHER REGULATORY MAT32
RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Regulatory Liabilities [Line Items] | ||
Regulatory Assets, Noncurrent | $ 2,128 | $ 2,130 |
Regulatory Liabilities | 938 | 930 |
SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Assets, Noncurrent | 2,026 | 2,030 |
Regulatory Liabilities | 705 | 695 |
Asset Retirement Obligation Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 760 | 755 |
Asset Retirement Obligation Costs [Member] | SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 533 | 529 |
Deferred gains on interest rate derivatives [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 157 | 151 |
Deferred gains on interest rate derivatives [Member] | SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 157 | 151 |
Other Regulatory Liability [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 21 | 24 |
Other Regulatory Liability [Member] | SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $ 15 | $ 15 |
COMMON EQUITY (Details)
COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Schedule of Capitalization, Equity [Line Items] | |||
Common Stock, Shares Authorized | 200 | 200 | |
Common Stock, Shares, Outstanding | 142.9 | 142.9 | |
SCEG | |||
Schedule of Capitalization, Equity [Line Items] | |||
Common Stock, Shares Authorized | 50 | 50 | |
Common Stock, Shares, Outstanding | 40.3 | 40.3 | |
Preferred Stock, Shares Authorized | 20 | 20 | |
Preferred Stock, Shares Outstanding | 0 | 0 | |
Commodity Contract | |||
Schedule of Capitalization, Equity [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 2 | $ (5) | |
Interest Rate Contract [Member] | |||
Schedule of Capitalization, Equity [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2) | (2) | |
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract | |||
Schedule of Capitalization, Equity [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2) | 5 | |
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | |||
Schedule of Capitalization, Equity [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 2 | $ 2 |
LONG-TERM AND SHORT-TERM DEBT34
LONG-TERM AND SHORT-TERM DEBT (Details) - SCEG - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 67.8 | $ 67.8 |
Related Party Transaction, Due from (to) Related Party, Current | $ 28 | $ 29 |
LONG-TERM AND SHORT-TERM DEBT35
LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,000 | $ 2,000 |
Commercial Paper | 869.5 | 940.5 |
Letters of Credit Outstanding, Amount | 3.3 | 3.3 |
Line of Credit Facility, Remaining Borrowing Capacity | 1,127.2 | 1,056.2 |
five year credit [Domain] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,300 | 1,300 |
SCANA [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 400 | 400 |
Commercial Paper | $ 50.4 | $ 64.4 |
Debt, Weighted Average Interest Rate | 1.47% | 1.43% |
Letters of Credit Outstanding, Amount | $ 3 | $ 3 |
Line of Credit Facility, Remaining Borrowing Capacity | 346.6 | 332.6 |
SCEG including Fuel Company [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400 | 1,400 |
Commercial Paper | $ 769.9 | $ 804.3 |
Debt, Weighted Average Interest Rate | 1.22% | 1.04% |
Letters of Credit Outstanding, Amount | $ 0.3 | $ 0.3 |
Line of Credit Facility, Remaining Borrowing Capacity | 629.8 | 595.4 |
Fuel Company [Member] | ||
Debt Instrument [Line Items] | ||
Long-Term Line of Credit - SC Fuel Co only | 500 | 500 |
SCEG | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 700 | 700 |
Long-term Line of Credit - SCE&G only | 200 | 200 |
PSNC Energy [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 200 | 200 |
Commercial Paper | $ 49.2 | $ 71.8 |
Debt, Weighted Average Interest Rate | 1.27% | 1.07% |
Line of Credit Facility, Remaining Borrowing Capacity | $ 150.8 | $ 128.2 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $ 382 | |
Unrecognized Tax Benefits | 274 | $ 219 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 17 | |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 273 | |
Decrease in Unrecognized Tax Benefits is Reasonably Possible | $ 53 | |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.00% | 4.00% |
SCEG | ||
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $ 382 | |
Unrecognized Tax Benefits | 333 | $ 236 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 17 | |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 273 | |
Decrease in Unrecognized Tax Benefits is Reasonably Possible | $ 53 |
DERIVATIVE FINANCIAL INSTRUME37
DERIVATIVE FINANCIAL INSTRUMENTS (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017USD ($)MMBTU | Dec. 31, 2016MMBTU | |
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 71,662,797 | 83,904,223 |
Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 6,500,000 | 4,510,000 |
Gas Marketing segment [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 65,162,797 | 79,394,223 |
Commodity Contract | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 16,634,000 | 16,457,000 |
Commodity Contract | Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 6,500,000 | 4,510,000 |
Commodity Contract | Gas Marketing segment [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 10,134,000 | 11,947,000 |
Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 55,028,797 | 67,447,223 |
Energy Related Derivative [Member] | Gas Marketing segment [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 55,028,797 | 67,447,223 |
Energy Related Derivative [Member] | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | 9,630,864 | 730,721 |
DERIVATIVE FINANCIAL INSTRUME38
DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 86 | $ 90 |
Derivative Liability, Fair Value, Gross Liability | 57 | 67 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Derivative Liability, Fair Value, Gross Liability | 52 | 58 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 4 | 9 |
Derivative Liability, Fair Value, Gross Liability | 0 | |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 10 |
Derivative Liability, Fair Value, Gross Liability | 5 | 9 |
Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 6 |
Derivative Liability, Fair Value, Gross Liability | 27 | 28 |
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 115.6 | 115.6 |
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 2 | 4 |
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 25 | 24 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 5 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 1 |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 84 | 84 |
Derivative Liability, Fair Value, Gross Liability | 30 | 39 |
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 1,285 | 1,285 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 22 | 27 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 3 |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Prepayments [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 3 | |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 4 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 2 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 1 | 2 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Prepayments [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 6 |
Derivative Liability, Fair Value, Gross Liability | 1 | 2 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 2 |
Derivative Liability, Fair Value, Gross Liability | 1 | |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Derivative Liability, Fair Value, Gross Liability | 34 | 39 |
SCEG | Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 9 | 9 |
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 36.4 | 36.4 |
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 1 | 1 |
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 8 | 8 |
SCEG | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Derivative Liability, Fair Value, Gross Liability | 25 | 30 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 1,285 | 1,285 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 22 | 27 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | $ 3 | $ 3 |
DERIVATIVE FINANCIAL INSTRUME39
DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Derivative [Line Items] | ||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ (2) | $ (5) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ 0 | $ (7) |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant |
Commodity Contract | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ (2) | $ 5 |
Commodity Contract | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | (2) | (2) |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | 2 |
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | (3) | |
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | 11 | (144) |
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | (3) | |
Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 0 | |
Gas Purchased for Resale [Member] [Member] | Commodity Contract | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 0.6 | |
Gas Purchased for Resale [Member] [Member] | Commodity Contract | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | (5) |
Interest Expense [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 6.5 | |
Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2) | (2) |
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | (1) | |
Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 2.4 | |
Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 1.7 | |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | $ (1) | $ (1) |
SCEG | ||
Derivative [Line Items] | ||
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant |
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | $ 11 | $ (144) |
SCEG | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | (3) | |
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | (1) | |
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 2.4 | |
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 1.7 | |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | $ (1) | $ (1) |
DERIVATIVE FINANCIAL INSTRUME40
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Letter of Credit Available Commodity Derivatives asset position | $ 1.8 | $ 1.5 |
Commodity Derivative, Net Asset Position, Aggregate Fair Value | 6 | 9 |
Collateral Already Posted, Aggregate Fair Value | 30.4 | 29.2 |
Additional Collateral, Aggregate Fair Value | 15.6 | 21.1 |
Derivative, Net Liability Position, Aggregate Fair Value | 46 | 50.3 |
Cash collateral to request from interest rate derivative counterparty | 69.9 | 62.9 |
Interest Rate Derivative, net asset position, Aggregate Fair Value | 69.9 | 62.9 |
SCEG | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | 9 | 9.2 |
Additional Collateral, Aggregate Fair Value | 17.4 | 21.1 |
Derivative, Net Liability Position, Aggregate Fair Value | 26.4 | 30.3 |
Cash collateral to request from interest rate derivative counterparty | 69.6 | 62 |
Interest Rate Derivative, net asset position, Aggregate Fair Value | $ 69.6 | $ 62 |
DERIVATIVE FINANCIAL INSTRUME41
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 86 | $ 90 |
Derivative Asset, Fair Value, Gross Liability | (1) | (4) |
Derivative Asset | 85 | 86 |
Derivative Liability, Fair Value, Gross Liability | 57 | 67 |
Derivative Liability, Fair Value, Gross Asset | (1) | (3) |
Derivative, Collateral, Right to Reclaim Securities | (8) | (9) |
Derivative, Collateral, Right to Reclaim Cash | (30) | (29) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 18 | 26 |
Derivative Liability | 56 | 64 |
Derivative, Collateral, Obligation to Return Securities | (8) | (9) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 77 | 77 |
Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 27 | 35 |
Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 79 | 72 |
Prepayments [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 4 | 9 |
Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 2 | 5 |
Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 29 | 29 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Derivative Asset | 77 | 71 |
Derivative Liability, Fair Value, Gross Liability | 52 | 58 |
Derivative, Collateral, Right to Reclaim Securities | (8) | (9) |
Derivative, Collateral, Right to Reclaim Cash | (29) | (29) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 15 | 20 |
Derivative Liability | 52 | 58 |
Derivative, Collateral, Obligation to Return Securities | (8) | (9) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 69 | 62 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 4 | 9 |
Derivative Asset | 4 | 9 |
Derivative Liability, Fair Value, Gross Liability | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0 | |
Derivative Liability | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4 | 9 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 5 | 10 |
Derivative Asset, Fair Value, Gross Liability | (1) | (4) |
Derivative Asset | 4 | 6 |
Derivative Liability, Fair Value, Gross Liability | 5 | 9 |
Derivative Liability, Fair Value, Gross Asset | (1) | (3) |
Derivative, Collateral, Right to Reclaim Cash | (1) | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 3 | 6 |
Derivative Liability | 4 | 6 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4 | 6 |
SCEG | ||
Derivative [Line Items] | ||
Derivative Asset | 77 | 71 |
Derivative Liability | 34 | 39 |
SCEG | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 23 | 28 |
SCEG | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 77 | 71 |
SCEG | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 11 | 11 |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 77 | 71 |
Derivative Asset | 77 | 71 |
Derivative Liability, Fair Value, Gross Liability | 34 | 39 |
Derivative, Collateral, Right to Reclaim Securities | (8) | (9) |
Derivative, Collateral, Right to Reclaim Cash | (9) | (9) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 17 | 21 |
Derivative Liability | 34 | 39 |
Derivative, Collateral, Obligation to Return Securities | (8) | (9) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | $ 69 | $ 62 |
FAIR VALUE MEASUREMENTS, INCL42
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | $ 15 | $ 14 |
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 7 | 7 |
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 77 | 71 |
Liabilities, Fair Value Disclosure | 52 | 58 |
Commodity Contract | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 3 | 8 |
Commodity Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 1 | 1 |
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 2 | 6 |
Liabilities, Fair Value Disclosure | 2 | |
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 3 | 4 |
Liabilities, Fair Value Disclosure | 8 | 10 |
SCEG | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets, Fair Value Disclosure | 77 | 71 |
Liabilities, Fair Value Disclosure | $ 34 | $ 39 |
FAIR VALUE MEASUREMENTS, INCL43
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | $ 6,482.7 | $ 6,489.8 |
Long-term Debt, Fair Value | 7,029 | 7,183.3 |
SCEG | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | 5,158.7 | 5,166 |
Long-term Debt, Fair Value | $ 5,606.6 | $ 5,752.3 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Pension and Other Postretirement Benefit Plans | ||
Pension Contributions | No | |
Pension Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | $ 5.3 | $ 5.5 |
Interest cost | 9.4 | 9.9 |
Expected return on assets | (13.8) | (14.1) |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.4 | 1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.9 | 3.7 |
Defined Benefit Plan, Net Periodic Benefit Cost | 5.2 | 6 |
Other Postretirement Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | 1.2 | 1.3 |
Interest cost | 2.9 | 3 |
Expected return on assets | 0 | 0 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0 | 0.1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.4 | 0.1 |
Defined Benefit Plan, Net Periodic Benefit Cost | $ 4.5 | 4.5 |
SCEG | ||
Pension and Other Postretirement Benefit Plans | ||
Pension Contributions | No | |
SCEG | Pension Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | $ 4.4 | 4.5 |
Interest cost | 8.1 | 8.4 |
Expected return on assets | (11.8) | (11.9) |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.3 | 0.8 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.4 | 3.1 |
Defined Benefit Plan, Net Periodic Benefit Cost | 4.4 | 4.9 |
SCEG | Other Postretirement Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | 1 | 1 |
Interest cost | 2.4 | 2.5 |
Expected return on assets | 0 | 0 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0 | 0.1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.3 | 0.1 |
Defined Benefit Plan, Net Periodic Benefit Cost | $ 3.7 | $ 3.7 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Details) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2017USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Environmental | ||||||
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act | 32.00% | |||||
Time frame for CPP cases held in abeyance by Court of Appeals | 60 | |||||
NPDES permit renewal permit period | five | |||||
Nuclear Generation | ||||||
Toshiba impairment loss for the nine months ended 12/31/16 for fiscal year ended 3/31/17 | $ 6,200 | |||||
Limit calculation of Consortium's payment obligations guaranteed by Toshiba | 0.25 | |||||
SCEG | ||||||
Nuclear Insurance | ||||||
Maximum liability assessment per reactor for each nuclear incident | $ 127.3 | |||||
Maximum Insurance Coverage For Each Nuclear Plant by ANI | 450 | |||||
Federal Limit on Public Liability Claims from Nuclear Incident Approximate | 13,400 | |||||
Maximum Federal Limit on Public Liability Claims Per Reactor for Each Year | 18.9 | |||||
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3 | 84.8 | |||||
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year | $ 12.6 | |||||
Inflation adjustment period for nuclear insurance | 5 | |||||
Maximum loss for a single nuclear incident | $ 2,750 | |||||
NEIL Maximum Insurance Coverage of Accidental Property Damage | 500 | |||||
NEIL Maximum Insurance Coverage To Nuclear Facility For Property Damage And Outage Costs From Non-Nuclear Event | 2,330 | |||||
EMANI Maximum Retrospective Premium Assessment | 1.8 | |||||
EMANI Maximum Insurance Coverage for Summer Station Unit 1 For Property Damage And Outage Costs From Non-Nuclear Event | 415 | |||||
NEIL Maximum Prosepective Insurance Premium Per Nuclear Incident | 45.8 | |||||
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs | 2,750 | |||||
Environmental | ||||||
Environmental Remediation Costs Recognized in Regulatory Assets | $ 25.3 | |||||
Number of MGP decommissioned sites that contain residues of byproduct chemicals | 4 | |||||
Number Of States Required To Reduce Emissions Under CSAPR | 28 | |||||
Site Contingency MGP Estimated Environmental Remediation Costs | $ 10.1 | |||||
Nuclear Generation | ||||||
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus | 83 | |||||
EPC Contract Amendment, Payment and Performance Bonds | 25 | |||||
Estimate of aggregate amount of subcontractor and vendor liens filed | 65 | |||||
Aggregate amount of subcontractor and vendor liens paid | $ 27.5 | |||||
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing | 15.00% | |||||
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage | $ 55 | |||||
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015 | 3,345 | |||||
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | $ 186 | |||||
Dispute Review Board Resolution Without Recourse | less than $5 million | |||||
Dispute Review Board Resolution Subject To Litigation | greater than $5 million | |||||
November 2016 SCPSC Approved Project Costs above SCPSC 2015 order | $ 831 | |||||
Total New Nuclear Project Cost Nov 2016, excludes AFC and escalation | 6,800 | |||||
Total New Nuclear Project Cost 2016, including AFC and escalation | 7,700 | |||||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 10.50% | |||||
Summer Station New Units and Transmission Assets [Domain] | ||||||
Nuclear Generation | ||||||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 4,600 | |||||
Summer Station New Units [Domain] | ||||||
Nuclear Generation | ||||||
jointly owned utility plant ownership, construction financing cost | $ 3,800 | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 55.00% | |||||
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus | $ 150 | |||||
EPC Contract Amendment, Payment and Performance Bonds | 45 | |||||
Estimate of aggregate amount of subcontractor and vendor liens filed | 118 | |||||
Aggregate amount of subcontractor and vendor liens paid | 50 | |||||
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage | 100 | |||||
Nuclear Production Tax Credits | $ 1,400 | |||||
Nuclear Production Tax Credit realization period | 8 | |||||
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015 | $ 6,082 | |||||
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | 338 | |||||
Scenario, Forecast [Member] | SCEG | ||||||
Nuclear Generation | ||||||
Additional ownership in new units | 2.00% | 2.00% | 1.00% | |||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 10.25% | |||||
Maximum [Member] | SCEG | ||||||
Nuclear Generation | ||||||
Additional ownership in new units, dollars | $ 850 |
SEGMENT OF BUSINESS INFORMATI46
SEGMENT OF BUSINESS INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | $ 577 | $ 592 | |
Revenues | 0 | 0 | |
Net Income (Loss) Available to Common Stockholders, Basic | 171 | 176 | |
Operating Income | 316 | 331 | |
Regulated Operating Revenue, Gas | 322 | 299 | |
Regulated and Unregulated Operating Revenue | 1,173 | 1,172 | |
Segment Assets | 18,458 | $ 18,707 | |
Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 577 | 592 | |
Revenues | 1 | 1 | |
Operating Income | 178 | 198 | |
Segment Assets | 12,076 | 11,929 | |
Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 1 | |
Operating Income | 113 | 94 | |
Regulated and Unregulated Operating Revenue | 322 | 299 | |
Segment Assets | 2,926 | 2,892 | |
Gas Marketing [Member] | |||
Segment Reporting Information [Line Items] | |||
Revenues | 24 | 22 | |
Net Income (Loss) Available to Common Stockholders, Basic | 15 | 24 | |
Regulated and Unregulated Operating Revenue | 274 | 281 | |
Segment Assets | 202 | 230 | |
All Other [member] | |||
Segment Reporting Information [Line Items] | |||
Revenues | 94 | 98 | |
Net Income (Loss) Available to Common Stockholders, Basic | 0 | 0 | |
Operating Income | 0 | 0 | |
Regulated and Unregulated Operating Revenue | 0 | 0 | |
Segment Assets | 997 | 1,124 | |
Adjustments/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | (119) | (122) | |
Net Income (Loss) Available to Common Stockholders, Basic | 156 | 152 | |
Operating Income | 25 | 39 | |
Regulated and Unregulated Operating Revenue | 0 | 0 | |
Segment Assets | 2,257 | 2,532 | |
SCEG | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 577 | 592 | |
Operating Income | 222 | 236 | |
Regulated Operating Revenue, Gas | 141 | 124 | |
Net Income (Loss) Attributable to Parent | 109 | 113 | |
Segment Assets | 15,965 | 16,091 | |
Regulated Operating Revenue | 719 | 717 | |
SCEG | Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 578 | 593 | |
Operating Income | 178 | 198 | |
Segment Assets | 12,076 | 11,929 | |
SCEG | Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Operating Income | 44 | 38 | |
Regulated and Unregulated Operating Revenue | 141 | 124 | |
Segment Assets | 836 | 825 | |
SCEG | Adjustments/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Operating Income | 0 | 0 | |
Regulated and Unregulated Operating Revenue | 0 | 0 | |
Net Income (Loss) Attributable to Parent | 109 | $ 113 | |
Segment Assets | $ 3,053 | $ 3,337 |
AFFILIATED TRANSACTIONS (Detail
AFFILIATED TRANSACTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Canadys Refined Coal [Member] | |||
Affiliated Transactions [Line Items] | |||
Equity Method Investment, Ownership Percentage | 40.00% | ||
Related Party Transaction, Purchases from Related Party | $ 44.6 | $ 52.8 | |
Sales to Affiliate | 44.4 | 52.5 | |
Related Party Tax Expense, Due from Affiliates, Current | 13.5 | $ 16 | |
Related Party Tax Expense, Due to Affiliates, Current | 13.6 | 16.1 | |
Energy Marketing [Member] | |||
Affiliated Transactions [Line Items] | |||
Due to Affiliate, Current | 8.3 | 8.8 | |
Cost of Natural Gas Purchases | 23.9 | 22.4 | |
SCANA Services [Member] | |||
Affiliated Transactions [Line Items] | |||
Related Party Transaction, Expenses from Transactions with Related Party | 72.5 | $ 75.6 | |
Accounts Payable, Related Parties, Current | 45.8 | 63.5 | |
SCEG | |||
Affiliated Transactions [Line Items] | |||
Due to Affiliate, Current | 100 | 122 | |
Due from Affiliate, Current | $ 14 | $ 16 |