Document and Entity Information
Document and Entity Information Document | 3 Months Ended |
Mar. 31, 2016shares | |
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, 2016 |
Document Fiscal Year Focus | 2,016 |
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, 2016 |
Document Fiscal Year Focus | 2,016 |
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, 2016 | Dec. 31, 2015 |
Assets | ||
Utility Plant In Service | $ 12,942 | $ 12,883 |
Accumulated Depreciation and Amortization | (4,327) | (4,307) |
Construction Work in Progress | 4,245 | 4,051 |
Nuclear Fuel, Net of Accumulated Amortization | 295 | 308 |
Goodwill, Net of Writedown of $230 | 210 | 210 |
Utility Plant, Net | 13,365 | 13,145 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 280 | 280 |
Assets held in trust, net-nuclear decommissioning | 119 | 115 |
Other investments | 73 | 71 |
Nonutility Property and Investments, Net | 472 | 466 |
Current Assets: | ||
Cash and cash equivalents | 86 | 176 |
Receivables, net of allowance for uncollectible accounts | 505 | 505 |
Other | 142 | 227 |
Inventories (at average cost): | ||
Fuel | 134 | 164 |
Materials and supplies | 148 | 148 |
Prepaid Expense | 119 | 115 |
Other current assets | 83 | 43 |
Total Current Assets | 1,217 | 1,378 |
Deferred Debits and Other Assets: | ||
Regulatory Assets, Noncurrent | 2,068 | 1,937 |
Other | 246 | 220 |
Total Deferred Debits and Other Assets | 2,314 | 2,157 |
Total | 17,368 | 17,146 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,390 | 2,390 |
Retained Earnings, Unappropriated | 3,212 | 3,118 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (63) | (65) |
Stockholders' Equity Attributable to Parent | 5,539 | 5,443 |
Long-term Debt, Excluding Current Maturities | 5,879 | 5,882 |
Total Capitalization | 11,418 | 11,325 |
Current Liabilities: | ||
Short-term borrowings | 917 | 531 |
Current portion of long-term debt | 116 | 116 |
Accounts payable | 369 | 590 |
Customer deposits and customer prepayments | 176 | 137 |
Taxes accrued | 83 | 242 |
Interest accrued | 85 | 83 |
Dividends declared | 80 | 76 |
Derivative financial instruments | 113 | 50 |
Other | 92 | 127 |
Total Current Liabilities | 2,031 | 1,952 |
Deferred Credits and Other Liabilities: | ||
Deferred income taxes, net | 1,898 | 1,907 |
Asset retirement obligations | 522 | 520 |
Pension and other postretirement benefits | 318 | 315 |
Regulatory Liabilities | 847 | 855 |
Other | 334 | 272 |
Total Deferred Credits and Other Liabilities | $ 3,919 | $ 3,869 |
Commitments and Contingencies | ||
Total | $ 17,368 | $ 17,146 |
SCEG | ||
Assets | ||
Utility Plant In Service | 11,195 | 11,153 |
Accumulated Depreciation and Amortization | (3,883) | (3,869) |
Construction Work in Progress | 4,141 | 3,997 |
Nuclear Fuel, Net of Accumulated Amortization | 295 | 308 |
Utility Plant, Net | 11,748 | 11,589 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 68 | 68 |
Assets held in trust, net-nuclear decommissioning | 119 | 115 |
Other investments | 1 | 1 |
Nonutility Property and Investments, Net | 188 | 184 |
Current Assets: | ||
Cash and cash equivalents | 57 | 130 |
Receivables, net of allowance for uncollectible accounts | 320 | 324 |
Other | 114 | 202 |
Due from Affiliate, Current | 15 | 22 |
Inventories (at average cost): | ||
Fuel | 92 | 98 |
Materials and supplies | 135 | 136 |
Prepaid Expense | 87 | 92 |
Other current assets | 52 | 15 |
Total Current Assets | 872 | 1,019 |
Deferred Debits and Other Assets: | ||
Regulatory Assets, Noncurrent | 1,986 | 1,857 |
Other | 138 | 116 |
Total Deferred Debits and Other Assets | 2,124 | 1,973 |
Total | 14,932 | 14,765 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,760 | 2,760 |
Retained Earnings, Unappropriated | 2,306 | 2,265 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (3) | (3) |
Stockholders' Equity Attributable to Parent | 5,063 | 5,022 |
Stockholders' Equity Attributable to Noncontrolling Interest | 130 | 129 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,193 | 5,151 |
Long-term Debt, Excluding Current Maturities | 4,656 | 4,659 |
Total Capitalization | 9,849 | 9,810 |
Current Liabilities: | ||
Short-term borrowings | 870 | 420 |
Current portion of long-term debt | 111 | 110 |
Accounts payable | 245 | 469 |
Due to Affiliate, Current | 116 | 113 |
Customer deposits and customer prepayments | 129 | 93 |
Taxes accrued | 76 | 299 |
Interest accrued | 66 | 66 |
Dividends declared | 74 | 75 |
Derivative financial instruments | 101 | 34 |
Other | 42 | 61 |
Total Current Liabilities | 1,830 | 1,740 |
Deferred Credits and Other Liabilities: | ||
Deferred income taxes, net | 1,717 | 1,732 |
Asset retirement obligations | 490 | 488 |
Pension and other postretirement benefits | 188 | 186 |
Regulatory Liabilities | 623 | 635 |
Other | 218 | 157 |
Other -affiliate | 17 | 17 |
Total Deferred Credits and Other Liabilities | 3,253 | 3,215 |
Total | $ 14,932 | $ 14,765 |
CONDENSED CONSOLIDATED BALANCE3
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Common Stock, Shares, Outstanding | 142.9 | 142.9 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | $ 128 | $ 124 |
Public Utilities, Property, Plant and Equipment, Net | 13,365 | 13,145 |
Allowance for Doubtful Accounts Receivable, Current | 5 | 5 |
Write-down, Goodwill | 230 | 230 |
Assets, Current | 1,217 | 1,378 |
Regulated Entity, Other Assets, Noncurrent | $ 2,314 | $ 2,157 |
SCEG | ||
Common Stock, Shares, Outstanding | 40.3 | 40.3 |
Public Utilities, Property, Plant and Equipment, Net | $ 11,748 | $ 11,589 |
Allowance for Doubtful Accounts Receivable, Current | 3 | 3 |
Assets, Current | 872 | 1,019 |
Regulated Entity, Other Assets, Noncurrent | 2,124 | 1,973 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 683 | 700 |
Assets, Current | 90 | 88 |
Regulated Entity, Other Assets, Noncurrent | $ 58 | $ 53 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Operating Revenues: | ||
Electric Domestic Regulated Revenue | $ 592 | $ 629 |
Regulated Operating Revenue, Gas | 299 | 369 |
Gas-nonregulated | 281 | 391 |
Regulated and Unregulated Operating Revenue | 1,172 | 1,389 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 136 | 174 |
Purchased power | 11 | 13 |
Gas purchased for resale | 359 | 523 |
Other operation and maintenance | 181 | 173 |
Depreciation and amortization | 91 | 96 |
Other taxes | 63 | 59 |
Total Operating Expenses | 841 | 1,038 |
Gain (Loss) on Disposition of Regulated Business Net of Transaction Costs | 0 | 235 |
Operating Income | 331 | 586 |
Other Income (Expense): | ||
Other income | 16 | 19 |
Other expense | (14) | (12) |
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs | 0 | 107 |
Interest Expense | (83) | (77) |
Allowance for equity funds used during construction | 5 | 5 |
Total Other Expense | (76) | 42 |
Income Before Income Tax Expense | 255 | 628 |
Income Tax Expense | 79 | 228 |
Net Income | $ 176 | $ 400 |
Earnings Per Share, Basic and Diluted | $ 1.23 | $ 2.80 |
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 | $ 82 | |
SCEG | ||
Operating Revenues: | ||
Electric Domestic Regulated Revenue | 593 | $ 630 |
Regulated Operating Revenue, Gas | 124 | 142 |
Regulated Operating Revenue | 717 | 772 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 136 | 174 |
Purchased power | 11 | 13 |
Gas purchased for resale | 56 | 74 |
Other operation and maintenance | 146 | 139 |
Depreciation and amortization | 74 | 80 |
Other taxes | 58 | 55 |
Total Operating Expenses | 481 | 535 |
Operating Income | 236 | 237 |
Other Income (Expense): | ||
Other income | 5 | 9 |
Other expense | (8) | (8) |
Interest Expense | (66) | (59) |
Allowance for equity funds used during construction | 5 | 5 |
Total Other Expense | (64) | (53) |
Income Before Income Tax Expense | 172 | 184 |
Income Tax Expense | 56 | 58 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 116 | 126 |
Net Income (Loss) Attributable to Noncontrolling Interest | (3) | (4) |
Earnings Available to Common Shareholder | 113 | 122 |
Weighted Average Common Shares Outstanding (millions) | ||
Dividends, Common Stock | $ 74 | $ 71 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Allowance for Funds Used During Construction, Capitalized Interest | $ 4 | $ 3 |
SCEG | ||
Allowance for Funds Used During Construction, Capitalized Interest | $ 3 | $ 3 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 176 | $ 400 |
Other Comprehensive Income (Loss) | ||
Unrealized gains (losses) on cash flow hedging activities arising during period | (5) | (3) |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 2 | 6 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax | 0 | 4 |
Other Comprehensive Income (Loss) | 2 | 2 |
Comprehensive income available to common shareholder | 178 | 402 |
SCEG | ||
Other Comprehensive Income (Loss) | ||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 116 | 126 |
Genco | ||
Other Comprehensive Income (Loss) | ||
Less comprehensive income attributable to noncontrolling interest | 3 | 4 |
SCE&G (including Fuel Company) | ||
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | 113 | 122 |
Other Comprehensive Income (Loss) | ||
Comprehensive income available to common shareholder | 113 | 122 |
Commodity Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 5 | 7 |
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, 2016 | Mar. 31, 2015 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax | $ 0 | $ (3) |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | (3) | (2) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 1 | 1 |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax | 3 | 5 |
Commodity Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ 5 | $ 7 |
CONDENSED CONSOLIDATED STATEME8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Cash Flows From Operating Activities: | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 176 | $ 400 |
Adjustments to reconcile net income to net cash provided from operating activities: | ||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | (353) | |
Loss from Equity Method Investments, Net of Dividends or Distributions | 1 | |
Deferred Income Tax Expense (Benefit) | (11) | (74) |
Depreciation and amortization | 94 | 100 |
Amortization of nuclear fuel | 14 | 13 |
Allowance for equity funds used during construction | (5) | (5) |
Carrying cost recovery | (4) | (3) |
Cash provided (used) by changes in certain assets and liabilities: | ||
Increase (Decrease) in Receivables | 0 | 33 |
Increase (Decrease) in Inventories | 11 | 31 |
increase (Decrease) in Prepaid Expense | (11) | 218 |
Increase (Decrease) in Other Regulatory Assets | 0 | 28 |
Increase (Decrease) in Regulatory liabilities | (1) | 6 |
Increase (Decrease ) in Accounts payable | (39) | (67) |
Increase (Decrease) in Taxes accrued | (159) | (71) |
Increase (Decrease) in Derivative Assets and Liabilities | (3) | (22) |
Changes in other assets | (20) | (6) |
Changes in other liabilities | 19 | (34) |
Net Cash Provided From Operating Activities | 61 | 195 |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | (385) | (352) |
Proceeds from Sale of Property, Plant, and Equipment | 0 | 645 |
Proceeds from investments (including derivative collateral posted) | 198 | 318 |
Purchase of investments (including derivative collateral posted) | (264) | (400) |
Net Cash Used in Investing Activities | (451) | 211 |
Cash Flows From Financing Activities: | ||
Proceeds from Issuance of Common Stock | 0 | 14 |
Repayments of Long-term Debt | (8) | (158) |
Dividends | (78) | (75) |
Short-term borrowings, net | 386 | (293) |
Net Cash Provided From Financing Activities | 300 | (512) |
Net (Decrease) Increase in Cash and Cash Equivalents | (90) | (106) |
Cash and Cash Equivalents, January 1 | 176 | 137 |
Cash and Cash Equivalents, March 31 | 86 | 31 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 77 | 81 |
Cash paid for-Income taxes | 141 | 8 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | 142 | 84 |
Capital Lease Obligations Incurred | 5 | 2 |
SCEG | ||
Cash Flows From Operating Activities: | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 116 | 126 |
Adjustments to reconcile net income to net cash provided from operating activities: | ||
Loss from Equity Method Investments | 1 | 1 |
Deferred Income Tax Expense (Benefit) | (15) | 7 |
Depreciation and amortization | 76 | 82 |
Amortization of nuclear fuel | 14 | 13 |
Allowance for equity funds used during construction | (5) | (5) |
Carrying cost recovery | (4) | (3) |
Cash provided (used) by changes in certain assets and liabilities: | ||
Increase (Decrease) in Receivables | 7 | (68) |
Increase (Decrease) in Due from Affiliates, Current | (2) | 90 |
Increase (Decrease) in Inventories | (3) | 0 |
increase (Decrease) in Prepaid Expense | (3) | 75 |
Increase (Decrease) in Other Regulatory Assets | 2 | 22 |
Increase (Decrease) in Regulatory liabilities | (1) | 6 |
Increase (Decrease ) in Accounts payable | (23) | (205) |
Increase (Decrease) in Due to Affiliate, Current | (8) | 185 |
Increase (Decrease) in Taxes accrued | (223) | (50) |
Changes in other assets | (9) | (3) |
Changes in other liabilities | 25 | (49) |
Net Cash Provided From Operating Activities | (55) | 224 |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | (337) | (319) |
Proceeds from investments (including derivative collateral posted) | 171 | 274 |
Purchase of investments (including derivative collateral posted) | (239) | (356) |
Investment In Affiliate | 9 | 80 |
Net Cash Used in Investing Activities | (396) | (321) |
Cash Flows From Financing Activities: | ||
Repayments of Long-term Debt | (8) | (8) |
Dividends | (75) | (74) |
Return of Capital to Parent | (4) | |
Short-term borrowings-affiliate,net | 11 | 192 |
Short-term borrowings, net | 450 | (99) |
Net Cash Provided From Financing Activities | 378 | 7 |
Net (Decrease) Increase in Cash and Cash Equivalents | (73) | (90) |
Cash and Cash Equivalents, January 1 | 130 | 100 |
Cash and Cash Equivalents, March 31 | 57 | 10 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 63 | 62 |
Income Taxes Paid | 175 | |
Proceeds from Income Tax Refunds | 7 | 83 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | 109 | 76 |
Capital Lease Obligations Incurred | $ 5 | $ 2 |
CONDENSED CONSOLIDATED STATEME9
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Interest Paid, Capitalized | $ 4 | $ 3 |
SCEG | ||
Interest Paid, Capitalized | $ 3 | $ 3 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON EQUITY Statement - USD ($) shares in Millions, $ in Millions | Total | AOCI Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | SCEG | SCEG excluding VIEs [Member] | Noncontrolling Interest [Member] |
Stockholders' Equity before Treasury Stock | $ 2,388 | |||||
Treasury Stock, Value | (10) | |||||
Retained Earnings, Appropriated | 2,684 | $ 2,077 | ||||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (63) | |||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (12) | |||||
Accumulated Other Comprehensive Income (Loss) | (75) | $ (3) | ||||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 123 | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ 4,757 | |||||
Stockholders' Equity Attributable to Parent | $ 4,987 | |||||
Shares, Outstanding | 143 | 40 | ||||
Common Stock, Value, Outstanding | $ 2,560 | |||||
Stock Issued During Period, Value, Other | $ 14 | |||||
Common Stock, Dividends, Per Share, Declared | $ 0.545 | |||||
Net Income (Loss) Available to Common Stockholders, Basic | $ 400 | 122 | ||||
Net Income (Loss) Attributable to Noncontrolling Interest | 4 | 4 | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | |||||
Proceeds from Contribution from Parent, net of return of Proceeds | (4) | |||||
Dividends | 70 | 69 | ||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | (1) | |||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (3) | |||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | (4) | |||||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 6 | |||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 9 | |||||
Other Comprehensive Income (Loss) | 2 | |||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | $ 402 | 122 | ||||
Stock Issued During Period, Shares, New Issues | 0 | |||||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | $ 0 | |||||
Dividends, Common Stock | (71) | |||||
Stockholders' Equity before Treasury Stock | 2,402 | |||||
Treasury Stock, Value | (10) | |||||
Retained Earnings, Appropriated | 3,006 | 2,130 | ||||
AOCI before Tax, Attributable to Parent | $ (7) | $ (9) | ||||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | (57) | |||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | (16) | |||||
Accumulated Other Comprehensive Income (Loss) | (73) | $ (3) | ||||
Stockholders' Equity Attributable to Noncontrolling Interest | 126 | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,809 | |||||
Stockholders' Equity Attributable to Parent | $ 5,325 | |||||
Shares, Outstanding | 143 | 40 | ||||
Common Stock, Value, Outstanding | $ 2,556 | |||||
Stockholders' Equity before Treasury Stock | $ 2,402 | |||||
Treasury Stock, Value | (12) | |||||
Retained Earnings, Appropriated | 3,118 | 2,265 | 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 | 129 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,151 | |||||
Stockholders' Equity Attributable to Parent | $ 5,443 | 5,022 | ||||
Shares, Outstanding | 143 | 40 | ||||
Common Stock, Value, Outstanding | $ 2,390 | 2,760 | $ 2,760 | |||
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) | ||||
Stockholders' Equity before Treasury Stock | 2,402 | |||||
Treasury Stock, Value | (12) | |||||
Retained Earnings, Appropriated | 3,212 | 2,306 | 2,306 | |||
AOCI before Tax, Attributable to Parent | $ (5) | $ (7) | ||||
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 | $ 130 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 5,193 | |||||
Stockholders' Equity Attributable to Parent | $ 5,539 | 5,063 | ||||
Shares, Outstanding | 143 | 40 | ||||
Common Stock, Value, Outstanding | $ 2,390 | $ 2,760 | $ 2,760 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 3 Months Ended |
Mar. 31, 2016 | |
Significant Accounting Policies | |
Significant Accounting Policies [Text Block] | 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 $488 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 allowances. See also Note 4. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI 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 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million , respectively, through an agency relationship. Under the terms of the asset management agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017. 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. 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. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical. Dispositions In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income. CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations. Reclassifications Certain prior period amounts within the reconciliations of Net income to Net Cash Provided From Operating Activities on the Condensed Consolidated Statements of Cash Flows of the Company and Consolidated SCE&G have been reclassified to conform to the current period presentation. Specifically, $81 million of non-cash changes in fair value of interest rate swaps has been reclassified from the Derivative financial instruments caption, with offsetting reclassifications of $96 million and $(15) million within changes in the Regulatory assets and changes in Other liabilities captions, respectively. Additionally, due to insignificance, the captions for changes in Interest accrued and changes in Pension and other postretirement benefits which were utilized in the reconciliation for the prior period have been eliminated and their amounts included within changes in Other liabilities. These reclassifications had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the Condensed Consolidated Statements of Cash Flows. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This 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. This guidance must be adopted no later than the first quarter of 2018, and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent 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 expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments 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. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have 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 twelve 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 of 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. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements. |
SCEG | |
Significant Accounting Policies | |
Significant Accounting Policies [Text Block] | 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 $488 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 allowances. See also Note 4. Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI 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 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million , respectively, through an agency relationship. Under the terms of the asset management agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017. 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. 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. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical. Dispositions In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income. CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations. Reclassifications Certain prior period amounts within the reconciliations of Net income to Net Cash Provided From Operating Activities on the Condensed Consolidated Statements of Cash Flows of the Company and Consolidated SCE&G have been reclassified to conform to the current period presentation. Specifically, $81 million of non-cash changes in fair value of interest rate swaps has been reclassified from the Derivative financial instruments caption, with offsetting reclassifications of $96 million and $(15) million within changes in the Regulatory assets and changes in Other liabilities captions, respectively. Additionally, due to insignificance, the captions for changes in Interest accrued and changes in Pension and other postretirement benefits which were utilized in the reconciliation for the prior period have been eliminated and their amounts included within changes in Other liabilities. These reclassifications had no effect on Net Cash Provided From Operating Activities or on any other subtotal in the Condensed Consolidated Statements of Cash Flows. New Accounting Matters In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This 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. This guidance must be adopted no later than the first quarter of 2018, and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent 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 expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments 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. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have 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 twelve 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 of 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. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance 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, 2016 | |
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 a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program 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. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016. By Order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G will reduce the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G will also recover projected DER program costs of $6.9 million beginning with the first billing cycle of May 2016. Electric - Base Rates Pursuant to a SCPSC order, SCE&G removes from rate base 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, 2016 totaled $3.1 million , and during the three months ended March 31, 2015 totaled $1.9 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 April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs component rider. This pension rider is subject to an annual true-up, depending on conditions in financial markets and other factors. The adjustment is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016. In April 2016, ORS filed a report arising from its review of SCE&G’s annual DSM Programs rate rider filing. ORS concluded the updated DSM Programs rider proposal was developed in accordance with terms and conditions approved by the SCPSC in prior orders and recommended that SCE&G's request be approved. In addition, ORS recommended SCE&G update the three-year planning models used to calculate the overall effectiveness of the DSM Programs for future program years. By Order dated April 29, 2016, the SCPSC accepted ORS's recommendations and approved SCE&G's request to recover $37.6 million of costs and net lost revenues associated with the DSM Programs. Gas - PSNC Energy On March 31, 2016, PSNC Energy filed a general rate case application with the NCUC requesting a general rate increase of approximately $41.6 million , or approximately 9.7% , in annual revenue. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In its application, PSNC Energy is also requesting approval of a rider to its rates to track and provide for ongoing recovery of capital expenditures related to PSNC Energy’s transmission and distribution pipeline integrity management programs. A hearing on the application is scheduled for the week of August 29, 2016. 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 $ 297 $ 298 $ 290 $ 291 Environmental remediation costs 41 42 34 35 AROs and related funding 402 405 381 384 Deferred employee benefit plan costs 323 325 293 295 Deferred losses on interest rate derivatives 666 535 666 535 Unrecovered plant 125 127 125 127 DSM Programs 61 61 61 61 Other 153 144 136 129 Total Regulatory Assets $ 2,068 $ 1,937 $ 1,986 $ 1,857 Regulatory Liabilities: Asset removal costs $ 739 $ 732 $ 522 $ 519 Deferred gains on interest rate derivatives 81 96 81 96 Other 27 27 20 20 Total Regulatory Liabilities $ 847 $ 855 $ 623 $ 635 Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all 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. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company or Consolidated SCE&G, and are expected to be recovered over periods of up to approximately 24 years. ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station 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. Accordingly, 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 12 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 will amortize 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. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. 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 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 a settlement agreement among SCE&G and certain other parties concerning SCE&G's petition for approval to participate in a DER program and to recover DER program 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. SCE&G is to make a good faith effort to have at least 30 MW of utility-scale solar capacity in service by the end of 2016. By Order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G will reduce the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G will also recover projected DER program costs of $6.9 million beginning with the first billing cycle of May 2016. Electric - Base Rates Pursuant to a SCPSC order, SCE&G removes from rate base 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, 2016 totaled $3.1 million , and during the three months ended March 31, 2015 totaled $1.9 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 April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs component rider. This pension rider is subject to an annual true-up, depending on conditions in financial markets and other factors. The adjustment is designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016. In April 2016, ORS filed a report arising from its review of SCE&G’s annual DSM Programs rate rider filing. ORS concluded the updated DSM Programs rider proposal was developed in accordance with terms and conditions approved by the SCPSC in prior orders and recommended that SCE&G's request be approved. In addition, ORS recommended SCE&G update the three-year planning models used to calculate the overall effectiveness of the DSM Programs for future program years. By Order dated April 29, 2016, the SCPSC accepted ORS's recommendations and approved SCE&G's request to recover $37.6 million of costs and net lost revenues associated with the DSM Programs. Gas - PSNC Energy On March 31, 2016, PSNC Energy filed a general rate case application with the NCUC requesting a general rate increase of approximately $41.6 million , or approximately 9.7% , in annual revenue. The rate increase is largely associated with recovering costs related to expanding and operating PSNC Energy's pipeline system. In its application, PSNC Energy is also requesting approval of a rider to its rates to track and provide for ongoing recovery of capital expenditures related to PSNC Energy’s transmission and distribution pipeline integrity management programs. A hearing on the application is scheduled for the week of August 29, 2016. 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 $ 297 $ 298 $ 290 $ 291 Environmental remediation costs 41 42 34 35 AROs and related funding 402 405 381 384 Deferred employee benefit plan costs 323 325 293 295 Deferred losses on interest rate derivatives 666 535 666 535 Unrecovered plant 125 127 125 127 DSM Programs 61 61 61 61 Other 153 144 136 129 Total Regulatory Assets $ 2,068 $ 1,937 $ 1,986 $ 1,857 Regulatory Liabilities: Asset removal costs $ 739 $ 732 $ 522 $ 519 Deferred gains on interest rate derivatives 81 96 81 96 Other 27 27 20 20 Total Regulatory Liabilities $ 847 $ 855 $ 623 $ 635 Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all 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. Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company or Consolidated SCE&G, and are expected to be recovered over periods of up to approximately 24 years. ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station 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. Accordingly, 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 12 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 will amortize 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. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. 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 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, 2016 | |
Schedule of Capitalization, Equity [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | SCANA had 200 million shares of common stock authorized as of March 31, 2016 and December 31, 2015. Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2016 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $5 million . Such reclassifications during the comparable period in 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million . |
SCEG | |
Schedule of Capitalization, Equity [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | Authorized shares of SCE&G common stock were 50 million as of March 31, 2016 and December 31, 2015. 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, 2016 and December 31, 2015. 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, 2016 | |
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, 2016 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 917 $ 10 $ 870 $ 37 Weighted average interest rate 0.90 % 0.83 % 0.81 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,080 $ 387 $ 530 $ 163 December 31, 2015 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 531 $ 37 $ 420 $ 74 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,466 $ 360 $ 980 $ 126 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. At March 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $43.9 million . At December 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.0 million and money pool investments due from an affiliate of $9.0 million . On Consolidated SCE&G's balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included 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, 2016 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 917 $ 10 $ 870 $ 37 Weighted average interest rate 0.90 % 0.83 % 0.81 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,080 $ 387 $ 530 $ 163 December 31, 2015 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 531 $ 37 $ 420 $ 74 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,466 $ 360 $ 980 $ 126 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. At March 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $43.9 million . At December 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.0 million and money pool investments due from an affiliate of $9.0 million . On Consolidated SCE&G's balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2016 | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | INCOME TAXES Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA and files various applicable state and local income tax returns. During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. SCANA also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company and Consolidated SCE&G recorded an unrecognized tax benefit of $49 million . If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2016. 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. |
SCEG | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | INCOME TAXES Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA and files various applicable state and local income tax returns. During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits and its related impact on domestic production activities. SCANA also made similar claims in filing its 2013 and 2014 returns in 2014 and 2015, respectively. In connection with these federal and state filings, the Company and Consolidated SCE&G recorded an unrecognized tax benefit of $49 million . If recognized, $17 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate. It is reasonably possible that these tax benefits will increase by an additional $7 million within the next 12 months. It is also reasonably possible that these tax benefits may decrease by $8 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through March 31, 2016. 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. |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 3 Months Ended |
Mar. 31, 2016 | |
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 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, SEMI, 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 where swaps that are 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. Treasury rate lock or 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 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 applied to under-collected fuel, 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) Retail Gas Hedge designation Gas Distribution Marketing Energy Marketing Total As of March 31, 2016 Commodity contracts 9,240,000 6,236,000 4,632,500 20,108,500 Energy management contracts (a) — — 30,994,204 30,994,204 Total (a) 9,240,000 6,236,000 35,626,704 51,102,704 As of December 31, 2015 Commodity contracts 7,530,000 7,869,000 3,973,500 19,372,500 Energy management contracts (b) — — 38,857,480 38,857,480 Total (b) 7,530,000 7,869,000 42,830,980 58,229,980 (a) Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. 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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (1 ) $ — The Company: Loss Recognized in OCI, net of tax Loss Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (2 ) $ (2 ) Commodity contracts (2 ) (1 ) Gas purchased for resale (5 ) (7 ) Total $ (5 ) $ (3 ) $ (7 ) $ (9 ) As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase 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, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019. As of March 31, 2016, 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 $2.1 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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
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 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, SEMI, 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 where swaps that are 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. Treasury rate lock or 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 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 applied to under-collected fuel, 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) Retail Gas Hedge designation Gas Distribution Marketing Energy Marketing Total As of March 31, 2016 Commodity contracts 9,240,000 6,236,000 4,632,500 20,108,500 Energy management contracts (a) — — 30,994,204 30,994,204 Total (a) 9,240,000 6,236,000 35,626,704 51,102,704 As of December 31, 2015 Commodity contracts 7,530,000 7,869,000 3,973,500 19,372,500 Energy management contracts (b) — — 38,857,480 38,857,480 Total (b) 7,530,000 7,869,000 42,830,980 58,229,980 (a) Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. 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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (1 ) $ — The Company: Loss Recognized in OCI, net of tax Loss Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (2 ) $ (2 ) Commodity contracts (2 ) (1 ) Gas purchased for resale (5 ) (7 ) Total $ (5 ) $ (3 ) $ (7 ) $ (9 ) As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase 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, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019. As of March 31, 2016, 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 $2.1 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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
FAIR VALUE MEASUREMENTS, INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 3 Months Ended |
Mar. 31, 2016 | |
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, 2016 As of December 31, 2015 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 $ 11 $ 11 Held to maturity securities $ 7 Interest rate contracts $ 15 $ 15 Commodity contracts 2 1 Energy management contracts 13 14 Liabilities: Interest rate contracts 222 $ 196 87 65 Commodity contracts 2 1 4 Energy management contracts 1 13 4 12 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, 2016 December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 5,995.4 $ 6,704.5 $ 5,997.6 $ 6,445.7 Consolidated SCE&G $ 4,766.9 $ 5,368.3 $ 4,769.0 $ 5,129.1 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, 2016 As of December 31, 2015 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 $ 11 $ 11 Held to maturity securities $ 7 Interest rate contracts $ 15 $ 15 Commodity contracts 2 1 Energy management contracts 13 14 Liabilities: Interest rate contracts 222 $ 196 87 65 Commodity contracts 2 1 4 Energy management contracts 1 13 4 12 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, 2016 December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 5,995.4 $ 6,704.5 $ 5,997.6 $ 6,445.7 Consolidated SCE&G $ 4,766.9 $ 5,368.3 $ 4,769.0 $ 5,129.1 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, 2016 | |
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 2016 2015 2016 2015 Three months ended March 31, Service cost $ 5.5 $ 5.8 $ 1.3 $ 1.4 Interest cost 9.9 9.5 3.0 2.9 Expected return on assets (14.1 ) (15.5 ) — — Prior service cost amortization 1.0 1.0 0.1 0.1 Amortization of actuarial losses 3.7 3.5 0.1 0.6 Net periodic benefit cost $ 6.0 $ 4.3 $ 4.5 $ 5.0 Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Three months ended March 31, Service cost $ 4.5 $ 4.6 $ 1.0 $ 1.1 Interest cost 8.4 8.0 2.5 2.3 Expected return on assets (11.9 ) (13.0 ) — — Prior service cost amortization 0.8 0.8 0.1 0.1 Amortization of actuarial losses 3.1 3.0 0.1 0.4 Net periodic benefit cost $ 4.9 $ 3.4 $ 3.7 $ 3.9 No significant contribution to the pension trust is expected for the foreseeable future, 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 2016 2015 2016 2015 Three months ended March 31, Service cost $ 5.5 $ 5.8 $ 1.3 $ 1.4 Interest cost 9.9 9.5 3.0 2.9 Expected return on assets (14.1 ) (15.5 ) — — Prior service cost amortization 1.0 1.0 0.1 0.1 Amortization of actuarial losses 3.7 3.5 0.1 0.6 Net periodic benefit cost $ 6.0 $ 4.3 $ 4.5 $ 5.0 Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Three months ended March 31, Service cost $ 4.5 $ 4.6 $ 1.0 $ 1.1 Interest cost 8.4 8.0 2.5 2.3 Expected return on assets (11.9 ) (13.0 ) — — Prior service cost amortization 0.8 0.8 0.1 0.1 Amortization of actuarial losses 3.1 3.0 0.1 0.4 Net periodic benefit cost $ 4.9 $ 3.4 $ 3.7 $ 3.9 No significant contribution to the pension trust is expected for the foreseeable future, 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, 2016 | |
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 Summer Station 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 $375 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 currently 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 Summer Station 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 Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.25 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 $43.5 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 Summer Station 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 Summer Station 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 In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's current ownership share in the New Units is 55% . As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. 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. As of March 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $3.8 billion , for which the financing costs on $3.2 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, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the fabrication of shield building components and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of Containment Vessel Ring 1 and placement of concrete in certain areas of the nuclear island to form a foundation for the shield building. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below. During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ( $245 million ) and other capital costs ( $453 million ), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion , respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, the updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5% . This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. 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, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor Corporation as a subcontracted construction manager. Among other things, the October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million ) to be applied to the target component of the contract price, (ii) revised the 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 Internal Revenue Code Section 45J production tax credits (see also below), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million ) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015. In addition, SCE&G has updated project costs for estimated change orders related to certain outstanding disputes not resolved by the October 2015 Amendment. As of April 30, 2016, these estimated change orders total approximately $53 million . The estimated gross construction cost of the project (including the effects of these change orders, escalation and AFC) as of March 31, 2016 totals approximately $7.2 billion . As of March 31, 2016, payments related to (i) above had been made totaling $62.5 million (SCE&G's 55% portion being approximately $34.4 million ), and payments related to (v) above had been made totaling $300 million (SCE&G's 55% portion being $165 million ). Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, 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 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 has obtained payment and performance bonds from WEC in the form of standby letters of credit totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit expire annually and 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. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition and in enabling construction activities to continue. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. An escrow arrangement and a schedule for deposit of intellectual property and software are being developed. While there have been no indications to date that WEC will not meet its obligations under the EPC Contract, SCE&G cannot predict the outcome of these matters, and continues to monitor developments for potential impacts to both the construction schedule and costs. In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract 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 subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015. This increase does not include the estimated change orders described previously totaling approximately $53 million and additional sales tax that would be due under this fixed price option of approximately $10 million . The estimated gross construction cost of the project (including the effects of these change orders and additional sales tax, escalation and AFC) under this fixed price option would total approximately $7.7 billion . Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC in September 2015; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in the second quarter of 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which incorporates the impact of the October 2015 Amendment. Such update would also incorporate any cost or schedule changes identified since that time. Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates. Santee Cooper Matters As noted above, 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 will not affect the payment obligations between the parties during construction for 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. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper. 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 Internal Revenue Code 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 the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. 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. 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 is currently 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 carbon dioxide 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 states from one to three years to issue SIPs, 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. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G are currently evaluating the rule and 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 sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual and ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. 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 Company's and Consolidated SCE&G's decision to retire certain coal-fired units and its project to build the New Units along with other actions are expected to result in the Company's and Consolidated SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO were granted a one year extension (through April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions allowed time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants to enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate. In December 2015, the Court of Appeals ruled that the MATS rule would remain in effect while the EPA assesses the cost of the rule. These rulings are not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently 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. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. 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. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. 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. The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. 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 2017 and will cost an additional $18.4 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, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.4 million and are included in regulatory assets. |
SCEG | |
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 Summer Station 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 $375 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 currently 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 Summer Station 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 Summer Station Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.25 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 $43.5 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 Summer Station 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 Summer Station 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 In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's current ownership share in the New Units is 55% . As discussed below, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. 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. As of March 31, 2016, SCE&G’s investment in the New Units, including related transmission, totaled $3.8 billion , for which the financing costs on $3.2 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, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule. Shield building construction remains a principal focus area for SCE&G’s oversight of the project. The primary critical path for both Unit 2 and Unit 3 runs through the fabrication of shield building components and the completion of shield building construction. For Unit 3, the critical path also runs through the setting of Containment Vessel Ring 1 and placement of concrete in certain areas of the nuclear island to form a foundation for the shield building. Plans to accelerate the work needed to permit placing this concrete are underway. In addition, WEC has reached agreement on a mitigation plan to accelerate shield building panel fabrication with one of its subcontractors. Additional mitigation will be required in critical path areas to support the updated substantial completion dates described below. During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies and other items. The result was a revised fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. In September 2015, the SCPSC approved an updated BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively, each subject to an 18-month contingency period. In addition, the SCPSC approved certain updated owner's costs ( $245 million ) and other capital costs ( $453 million ), of which $539 million were associated with the schedule delays and other contested costs. In this proceeding, SCE&G's total projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) were estimated to be $5.2 billion and $6.8 billion , respectively. These projections included cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G had not accepted responsibility and which were the subject of dispute. As such, the updated milestone schedule and projections did not reflect the resolution of negotiations. In addition, the SCPSC approved a revision to the allowed return on equity for new nuclear construction from 11.0% to 10.5% . This revised return on equity will be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2016, until such time as the New Units are completed. On October 27, 2015, SCE&G, Santee Cooper and the Consortium reached a settlement regarding the above mentioned disputes, and the EPC Contract was amended. 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, Stone & Webster continues to be a member of the Consortium as a subsidiary of WEC rather than CB&I, and WEC has engaged Fluor Corporation as a subcontracted construction manager. Among other things, the October 2015 Amendment: (i) resolved by settlement and release most outstanding disputes between SCE&G and the Consortium, in exchange for (a) an additional cost to be paid by SCE&G and Santee Cooper of $300 million (SCE&G’s 55% portion being $165 million and an increase in the fixed component of the contract price by that amount, and (b) a credit to SCE&G and Santee Cooper of $50 million (SCE&G’s 55% portion being approximately $27 million ) to be applied to the target component of the contract price, (ii) revised the 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 Internal Revenue Code Section 45J production tax credits (see also below), and capped those aggregate liquidated damages at $463 million per New Unit (SCE&G’s 55% portion being approximately $255 million per New Unit), (iv) provides for payment to the Consortium of a completion bonus of $275 million per New Unit (SCE&G’s 55% portion being approximately $151 million per New Unit) for each New Unit placed in service by the deadline to qualify for production tax credits, (v) provides for development of a revised construction milestone payment schedule, with SCE&G and Santee Cooper making monthly payments of $100 million (SCE&G’s 55% portion being $55 million ) for each of the first five months following effectiveness, followed by payments made based on milestones achieved, and (vi) provided that SCE&G and Santee Cooper waive and cancel the CB&I parent company guaranty with respect to the project. Under the October 2015 Amendment, SCE&G’s total estimated project costs increased by approximately $286 million over the $6.8 billion approved by the SCPSC in September 2015. In addition, SCE&G has updated project costs for estimated change orders related to certain outstanding disputes not resolved by the October 2015 Amendment. As of April 30, 2016, these estimated change orders total approximately $53 million . The estimated gross construction cost of the project (including the effects of these change orders, escalation and AFC) as of March 31, 2016 totals approximately $7.2 billion . As of March 31, 2016, payments related to (i) above had been made totaling $62.5 million (SCE&G's 55% portion being approximately $34.4 million ), and payments related to (v) above had been made totaling $300 million (SCE&G's 55% portion being $165 million ). Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and Stone & Webster, and in connection with the October 2015 Amendment, Toshiba Corporation, 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 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 has obtained payment and performance bonds from WEC in the form of standby letters of credit totalin g $45 million (or approximatel y $25 million for SCE&G's 55% share). These standby letters of credit expire annually and 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. In the event that WEC would be unable to meet its payment and performance obligations under the EPC Contract, it is anticipated this funding would provide a source of liquidity to assist in an orderly transition and in enabling construction activities to continue. In addition, the EPC Contract provides that upon the request of SCE&G, the Consortium must escrow certain intellectual property and software for SCE&G's benefit to enable completion of the New Units. An escrow arrangement and a schedule for deposit of intellectual property and software are being developed. While there have been no indications to date that WEC will not meet its obligations under the EPC Contract, SCE&G cannot predict the outcome of these matters, and continues to monitor developments for potential impacts to both the construction schedule and costs. In addition to the above, the October 2015 Amendment provided for an explicit definition of a Change in Law designed to reduce the likelihood of certain future commercial disputes, and the Consortium also acknowledged and agreed that the project scope includes providing New Units that meet the standards of the NRC approved Design Control Document Revision 19. The October 2015 Amendment also established a dispute resolution board process for certain commercial claims and disputes, including any dispute that might arise with respect to the development of the revised construction milestone payment schedule referred to above. The EPC Contract was also revised to eliminate the requirement or ability to bring suit before substantial completion of the project. Finally, the October 2015 Amendment provides SCE&G and Santee Cooper an irrevocable option, until November 1, 2016 and subject to regulatory approvals, to further amend the EPC Contract 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 subject to adjustment for amounts paid since June 30, 2015. Were this fixed price option to be exercised, the aggregate delay-related liquidated damages referred to in (iii) above would be capped at $338 million per unit (SCE&G’s 55% portion being approximately $186 million per unit), and the completion bonus referred to in (iv) above would be $150 million per New Unit (SCE&G’s 55% portion being approximately $83 million per New Unit). The exercise of this fixed price option would result in SCE&G’s total estimated project costs increasing by approximately $774 million over the $6.8 billion approved by the SCPSC in September 2015. This increase does not include the estimated change orders described previously totaling approximately $53 million and additional sales tax that would be due under this fixed price option of approximately $10 million . The estimated gross construction cost of the project (including the effects of these change orders and additional sales tax, escalation and AFC) under this fixed price option would total approximately $7.7 billion . Resolution of the disputes as described in (i) above, or in the case of the exercise of the fixed price option, would result in estimated project costs above the amounts approved by the SCPSC in September 2015; however, the guaranteed substantial completion dates fall within the SCPSC approved 18-month contingency periods. SCE&G held an allowable ex parte communication briefing with the SCPSC on November 19, 2015 and, following an evaluation as to whether to exercise the fixed price option, expects to file a petition in the second quarter of 2016, as provided under the BLRA, for an update to the project’s estimated capital cost and milestone schedule which incorporates the impact of the October 2015 Amendment. Such update would also incorporate any cost or schedule changes identified since that time. Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes through both the informal and formal procedures and currently anticipates that any costs that arise through such dispute resolution processes (including those reflected in the October 2015 Amendment described above), as well as other costs identified from time to time, will be recoverable through rates. Santee Cooper Matters As noted above, 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 will not affect the payment obligations between the parties during construction for 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. Based on the October 2015 Amendment, which has not been approved by the SCPSC, SCE&G’s currently projected cost would be approximately $750 million to $850 million for the additional 5% interest being acquired from Santee Cooper. 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 Internal Revenue Code 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 the guaranteed substantial completion dates provided above, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. 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. 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 is currently 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 carbon dioxide 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 states from one to three years to issue SIPs, 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. The order of the Supreme Court has no immediate impact on SCE&G and GENCO or their generation operations. The Company and Consolidated SCE&G are currently evaluating the rule and 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 sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, which delayed the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual and ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. On July 28, 2015, the Court of Appeals held that Phase 2 emissions budgets for certain states, including South Carolina, required reductions in emissions beyond the point necessary to achieve downwind attainment and were, therefore, invalid. The Court of Appeals remanded CSAPR, without vacating the rule, to the EPA for further consideration. The opinion of the Court of Appeals has no immediate impact on SCE&G and GENCO or their generation operations. 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 Company's and Consolidated SCE&G's decision to retire certain coal-fired units and its project to build the New Units along with other actions are expected to result in the Company's and Consolidated SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities under the MATS rule. SCE&G and GENCO were granted a one year extension (through April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions allowed time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants to enhance the control of certain MATS-regulated pollutants. On June 29, 2015, the Supreme Court ruled that the EPA unreasonably failed to consider costs in its decision to regulate. In December 2015, the Court of Appeals ruled that the MATS rule would remain in effect while the EPA assesses the cost of the rule. These rulings are not expected to have an impact on SCE&G or GENCO due to the aforementioned retirements and conversions. SCE&G and GENCO currently 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. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. 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. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. 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. The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2015, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. 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 2017 and will cost an additional $18.4 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, 2016, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $34.4 million and are included in regulatory assets. |
SEGMENT OF BUSINESS INFORMATION
SEGMENT OF BUSINESS INFORMATION | 3 Months Ended |
Mar. 31, 2016 | |
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. Marketing segments measure 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. In addition, All Other includes gains from the sales of CGT and SCI (see Dispositions in Note 1) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million million and $202 million , respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during either period presented. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended March 31, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Retail Gas Marketing 171 — n/a $ 22 Energy Marketing 110 22 n/a 2 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Three Months Ended March 31, 2015 Electric Operations $ 629 — $ 199 n/a Gas Distribution 368 — 96 n/a Retail Gas Marketing 204 — n/a $ 27 Energy Marketing 187 $ 35 n/a 6 All Other 4 114 238 207 Adjustments/Eliminations (3 ) (149 ) 53 160 Consolidated Total $ 1,389 $ — $ 586 $ 400 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distributions 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Three Months Ended March 31, 2015 Electric Operations $ 630 $ 199 n/a Gas Distributions 142 38 n/a Adjustments/Eliminations — — $ 122 Consolidated Total $ 772 $ 237 $ 122 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2016 2015 2016 2015 Electric Operations $ 11,039 $ 10,883 $ 11,039 $ 10,883 Gas Distribution 2,676 2,606 768 757 Retail Gas Marketing 140 106 n/a n/a Energy Marketing 84 95 n/a n/a All Other 994 998 n/a n/a Adjustments/Eliminations 2,435 2,458 3,125 3,125 Consolidated Total $ 17,368 $ 17,146 $ 14,932 $ 14,765 |
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. Marketing segments measure 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. In addition, All Other includes gains from the sales of CGT and SCI (see Dispositions in Note 1) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million million and $202 million , respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during either period presented. The Company Millions of dollars External Revenue Intersegment Revenue Operating Income Net Income Three Months Ended March 31, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Retail Gas Marketing 171 — n/a $ 22 Energy Marketing 110 22 n/a 2 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Three Months Ended March 31, 2015 Electric Operations $ 629 — $ 199 n/a Gas Distribution 368 — 96 n/a Retail Gas Marketing 204 — n/a $ 27 Energy Marketing 187 $ 35 n/a 6 All Other 4 114 238 207 Adjustments/Eliminations (3 ) (149 ) 53 160 Consolidated Total $ 1,389 $ — $ 586 $ 400 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distributions 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Three Months Ended March 31, 2015 Electric Operations $ 630 $ 199 n/a Gas Distributions 142 38 n/a Adjustments/Eliminations — — $ 122 Consolidated Total $ 772 $ 237 $ 122 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2016 2015 2016 2015 Electric Operations $ 11,039 $ 10,883 $ 11,039 $ 10,883 Gas Distribution 2,676 2,606 768 757 Retail Gas Marketing 140 106 n/a n/a Energy Marketing 84 95 n/a n/a All Other 994 998 n/a n/a Adjustments/Eliminations 2,435 2,458 3,125 3,125 Consolidated Total $ 17,368 $ 17,146 $ 14,932 $ 14,765 |
AFFILIATED TRANSACTIONS - SCEG
AFFILIATED TRANSACTIONS - SCEG | 3 Months Ended |
Mar. 31, 2016 | |
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. SCE&G’s total purchases from this affiliate were $52.8 million and $70.1 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s total sales to this affiliate were $52.5 million and $69.7 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $15.2 million at March 31, 2016 and $12.8 million at December 31, 2015. SCE&G’s payable to this affiliate was $15.3 million at March 31, 2016 and $12.9 million at December 31, 2015. |
SCEG | |
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. SCE&G’s total purchases from this affiliate were $52.8 million and $70.1 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s total sales to this affiliate were $52.5 million and $69.7 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s receivable from this affiliate was $15.2 million at March 31, 2016 and $12.8 million at December 31, 2015. SCE&G’s payable to this affiliate was $15.3 million at March 31, 2016 and $12.9 million at December 31, 2015. Consolidated SCE&G: Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. SCE&G's purchases from CGT totaled approximately $3.4 million in January 2015. SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $22.4 million and $34.6 million for the three months ended March 31, 2016 and 2015, respectively. SCE&G’s payables to SEMI for such purchases were $4.0 million at March 31, 2016 and $7.5 million at December 31, 2015. SCANA Services, Inc., 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 services, telecommunications services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $75.6 million and $73.1 million for the three months ended March 31, 2016 and 2015, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.1 million at March 31, 2016 and $57 million at December 31, 2015. Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4. |
SUMMARY OF SIGNIFICANT ACCOUN22
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 3 Months Ended |
Mar. 31, 2016 | |
Significant Accounting Policies | |
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. 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. The weighted average number of common shares for each period presented for basic and diluted earnings per share purposes were identical. |
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 $488 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 allowances. See also Note 4. |
Dispositions [Policy Text Block] | Dispositions In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . As previously noted, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's condensed consolidated statement of income. CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within the All Other caption in Note 10. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations. |
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 29% and 46% of PSNC Energy’s natural gas inventory at March 31, 2016 and December 31, 2015, respectively, with a carrying value of $6.0 million and $17.7 million , respectively, through an agency relationship. Under the terms of the asset management agreement, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. No fees are received under the supply service agreement. This agreement expires on March 31, 2017. |
Income Statement policy [Policy Text Block] | Income Statement Presentation Revenues and expenses arising from regulated businesses and, in the case of the Company, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI 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 current revenue recognition guidance, including industry-specific guidance. This 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. This guidance must be adopted no later than the first quarter of 2018, and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent 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 expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments 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. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have 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 twelve 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 of 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. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance 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 $488 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 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, retail natural gas marketing businesses (including those activities of segments described in Note 10) are presented within operating income, and all other activities are presented within other income (expense). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within operating income and the 2015 gain on the sale of SCI 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 current revenue recognition guidance, including industry-specific guidance. This 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. This guidance must be adopted no later than the first quarter of 2018, and early adoption is permitted in the first quarter of 2017. Adoption using a retrospective method is required, with options to elect certain practical expedients or to recognize a cumulative effect in the year of initial adoption. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what practical expedients will be elected. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. In April 2015, the FASB issued accounting guidance related to fees paid by a customer in a cloud computing arrangement. Among other things, the guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. This guidance was adopted in the first quarter of 2016 and had no impact on the Company’s or Consolidated SCE&G's financial statements. In July 2015, the FASB issued accounting guidance intended to simplify the subsequent 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 expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have on their respective financial statements. In January 2016, the FASB issued accounting guidance intended to clarify the classification and measurement of financial instruments 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. The Company and Consolidated SCE&G are evaluating this guidance and have not determined what impact it will have 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 twelve 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 of 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. In March 2016, the FASB issued accounting guidance changing how companies account for certain aspects of share-based payments to employees. Entities will be required to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2017. The Company and Consolidated SCE&G are evaluating this guidance 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, 2016 | |
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 $ 297 $ 298 $ 290 $ 291 Environmental remediation costs 41 42 34 35 AROs and related funding 402 405 381 384 Deferred employee benefit plan costs 323 325 293 295 Deferred losses on interest rate derivatives 666 535 666 535 Unrecovered plant 125 127 125 127 DSM Programs 61 61 61 61 Other 153 144 136 129 Total Regulatory Assets $ 2,068 $ 1,937 $ 1,986 $ 1,857 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities: Asset removal costs $ 739 $ 732 $ 522 $ 519 Deferred gains on interest rate derivatives 81 96 81 96 Other 27 27 20 20 Total Regulatory Liabilities $ 847 $ 855 $ 623 $ 635 |
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 $ 297 $ 298 $ 290 $ 291 Environmental remediation costs 41 42 34 35 AROs and related funding 402 405 381 384 Deferred employee benefit plan costs 323 325 293 295 Deferred losses on interest rate derivatives 666 535 666 535 Unrecovered plant 125 127 125 127 DSM Programs 61 61 61 61 Other 153 144 136 129 Total Regulatory Assets $ 2,068 $ 1,937 $ 1,986 $ 1,857 |
Schedule of Regulatory Liabilities [Table Text Block] | Regulatory Liabilities: Asset removal costs $ 739 $ 732 $ 522 $ 519 Deferred gains on interest rate derivatives 81 96 81 96 Other 27 27 20 20 Total Regulatory Liabilities $ 847 $ 855 $ 623 $ 635 |
LONG-TERM AND SHORT-TERM DEBT (
LONG-TERM AND SHORT-TERM DEBT (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Short-term Debt [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | March 31, 2016 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 917 $ 10 $ 870 $ 37 Weighted average interest rate 0.90 % 0.83 % 0.81 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,080 $ 387 $ 530 $ 163 December 31, 2015 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 531 $ 37 $ 420 $ 74 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,466 $ 360 $ 980 $ 126 |
SCEG | |
Short-term Debt [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | March 31, 2016 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 917 $ 10 $ 870 $ 37 Weighted average interest rate 0.90 % 0.83 % 0.81 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,080 $ 387 $ 530 $ 163 December 31, 2015 Millions of dollars Total SCANA Consolidated SCE&G PSNC Energy Lines of credit: Five-year, expiring December 2020 $ 1,300 $ 400 $ 700 $ 200 Fuel Company five-year, expiring December 2020 $ 500 — $ 500 — Three-year, expiring December 2018 $ 200 — $ 200 — Total committed long-term $ 2,000 $ 400 $ 1,400 $ 200 Outstanding commercial paper (270 or fewer days) $ 531 $ 37 $ 420 $ 74 Weighted average interest rate 1.19 % 0.74 % 0.77 % Letters of credit supported by LOC $ 3.3 $ 3 $ 0.3 — Available $ 1,466 $ 360 $ 980 $ 126 |
DERIVATIVE FINANCIAL INSTRUME25
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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 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, SEMI, 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 where swaps that are 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. Treasury rate lock or 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 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 applied to under-collected fuel, 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) Retail Gas Hedge designation Gas Distribution Marketing Energy Marketing Total As of March 31, 2016 Commodity contracts 9,240,000 6,236,000 4,632,500 20,108,500 Energy management contracts (a) — — 30,994,204 30,994,204 Total (a) 9,240,000 6,236,000 35,626,704 51,102,704 As of December 31, 2015 Commodity contracts 7,530,000 7,869,000 3,973,500 19,372,500 Energy management contracts (b) — — 38,857,480 38,857,480 Total (b) 7,530,000 7,869,000 42,830,980 58,229,980 (a) Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. 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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (1 ) $ — The Company: Loss Recognized in OCI, net of tax Loss Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (2 ) $ (2 ) Commodity contracts (2 ) (1 ) Gas purchased for resale (5 ) (7 ) Total $ (5 ) $ (3 ) $ (7 ) $ (9 ) As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase 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, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019. As of March 31, 2016, 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 $2.1 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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
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) Retail Gas Hedge designation Gas Distribution Marketing Energy Marketing Total As of March 31, 2016 Commodity contracts 9,240,000 6,236,000 4,632,500 20,108,500 Energy management contracts (a) — — 30,994,204 30,994,204 Total (a) 9,240,000 6,236,000 35,626,704 51,102,704 As of December 31, 2015 Commodity contracts 7,530,000 7,869,000 3,973,500 19,372,500 Energy management contracts (b) — — 38,857,480 38,857,480 Total (b) 7,530,000 7,869,000 42,830,980 58,229,980 (a) Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. |
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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 |
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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 |
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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (1 ) $ — The Company: Loss Recognized in OCI, net of tax Loss Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (2 ) $ (2 ) Commodity contracts (2 ) (1 ) Gas purchased for resale (5 ) (7 ) Total $ (5 ) $ (3 ) $ (7 ) $ (9 ) |
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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 |
Disclosure of Credit Derivatives [Table Text Block] | Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 |
Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 |
Offsetting Liabilities [Table Text Block] | Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
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 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, SEMI, 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 where swaps that are 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. Treasury rate lock or 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 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 applied to under-collected fuel, 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) Retail Gas Hedge designation Gas Distribution Marketing Energy Marketing Total As of March 31, 2016 Commodity contracts 9,240,000 6,236,000 4,632,500 20,108,500 Energy management contracts (a) — — 30,994,204 30,994,204 Total (a) 9,240,000 6,236,000 35,626,704 51,102,704 As of December 31, 2015 Commodity contracts 7,530,000 7,869,000 3,973,500 19,372,500 Energy management contracts (b) — — 38,857,480 38,857,480 Total (b) 7,530,000 7,869,000 42,830,980 58,229,980 (a) Includes an aggregate 1,679,289 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 1,842,048 MMBTU related to basis swap contracts in Energy Marketing. 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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (1 ) $ — The Company: Loss Recognized in OCI, net of tax Loss Reclassified from AOCI into Income, net of tax (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (2 ) $ (2 ) Commodity contracts (2 ) (1 ) Gas purchased for resale (5 ) (7 ) Total $ (5 ) $ (3 ) $ (7 ) $ (9 ) As of March 31, 2016, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.1 million as an increase 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, 2016, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2019. As of March 31, 2016, 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 $2.1 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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 As of March 31, 2016, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include $0.7 million as an increase to interest expense. Credit Risk Considerations Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral. Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 In addition, for fixed price supply contracts offered to certain of SEMI's customers, the Company could have called on letters of credit in the amount of $3.0 million related to $13.0 million in commodity derivatives that are in a net asset position at March 31, 2016, compared to letters of credit of $3.0 million related to derivatives of $14.0 million at December 31, 2015, if all the contingent features underlying these instruments had been fully triggered. Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
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, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Designated as hedging instruments $ 120.0 $ 120.0 $ 36.4 $ 36.4 Not designated as hedging instruments 1,235.0 1,235.0 1,235.0 1,235.0 |
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, 2016 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 3 $ 1 Other deferred credits and other liabilities 36 12 Commodity contracts Other current assets $ 1 1 Derivative financial instruments 2 Total $ 1 $ 42 — $ 13 Not designated as hedging instruments Interest rate contracts Derivative financial instruments $ 100 $ 100 Other deferred credits and other liabilities 83 83 Commodity contracts Other current assets $ 2 Energy management contracts Other current assets 9 1 Other deferred debits and other assets 4 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 15 $ 196 — $ 183 As of December 31, 2015 Designated as hedging instruments Interest rate contracts Derivative financial instruments $ 4 $ 1 Other deferred credits and other liabilities 28 9 Commodity contracts Other current assets 1 Derivative financial instruments 4 Total $ — $ 37 — $ 10 Not designated as hedging instruments Interest rate contracts Other current assets $ 10 $ 10 Other deferred debits and other assets 5 5 Derivative financial instruments $ 33 $ 33 Other deferred credits and other liabilities 22 22 Commodity contracts Other current assets 1 2 Energy management contracts Other current assets 11 Other deferred debits and other assets 3 Derivative financial instruments 9 Other deferred credits and other liabilities 3 Total $ 30 $ 69 $ 15 $ 55 |
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 (Effective Portion) (Effective Portion) Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (3 ) $ (2 ) Interest expense $ (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: Loss Deferred in Regulatory Accounts Gain Reclassified from Deferred Accounts into Income Millions of dollars 2016 2015 Location 2016 2015 Three Months Ended March 31, Interest rate contracts $ (144 ) $ (94 ) Other income $ — $ 4 |
Disclosure of Credit Derivatives [Table Text Block] | Derivative Contracts with Credit Contingent Features The Company Consolidated SCE&G Millions of dollars March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 in Net Liability Position Aggregate fair value of derivatives in net liability position $ 234.1 $ 95.2 $ 196.1 $ 57.0 Fair value of collateral already posted 124.1 50.4 88.2 13.4 Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered 110.0 44.8 107.9 43.6 in Net Asset Position Aggregate fair value of derivatives in net asset position $ — $ 7.3 $ — $ 7.3 Fair value of collateral already posted — — — — Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered — 7.3 — 7.3 |
Offseting Assets [Table Text Block] | Information related to the offsetting of derivative assets 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, 2016 Gross Amounts of Recognized Assets — $ 3 $ 13 $ 16 — Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position — 2 13 15 — Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount — $ 2 $ 13 $ 15 — Balance sheet location Other current assets $ 11 — Other deferred debits and other assets 4 — Total $ 15 — As of December 31, 2015 Gross Amounts of Recognized Assets $ 15 $ 1 $ 15 $ 31 $ 15 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 15 1 14 30 15 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Received — — — — — Net Amount $ 7 $ 1 $ 14 $ 22 $ 7 Balance sheet location Other current assets $ 22 $ 10 Other deferred debits and other assets 8 5 Total $ 30 $ 15 |
Offsetting Liabilities [Table Text Block] | Information related to the offsetting of derivative liabilities follows: 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, 2016 Gross Amounts of Recognized Liabilities $ 222 $ 3 $ 13 $ 238 $ 196 Gross Amounts Offset in Statement of Financial Position — (1 ) — (1 ) — Net Amounts Presented in Statement of Financial Position 222 2 13 237 196 Gross Amounts Not Offset - Financial Instruments — — — — — Gross Amounts Not Offset - Cash Collateral Posted (116 ) (2 ) (6 ) (124 ) (88 ) Net Amount $ 106 $ — $ 7 $ 113 $ 108 Balance sheet location Other current assets $ 2 — Derivative financial instruments 113 $ 101 Other deferred credits and other liabilities 122 95 Total $ 237 $ 196 As of December 31, 2015 Gross Amounts of Recognized Liabilities $ 87 $ 5 $ 15 $ 107 $ 65 Gross Amounts Offset in Statement of Financial Position — — (1 ) (1 ) — Net Amounts Presented in Statement of Financial Position 87 5 14 106 65 Gross Amounts Not Offset - Financial Instruments (8 ) — — (8 ) (8 ) Gross Amounts Not Offset - Cash Collateral Posted (36 ) (5 ) (9 ) (50 ) (13 ) Net Amount $ 43 $ — $ 5 $ 48 $ 44 Balance sheet location Other current assets $ 3 — Derivative financial instruments 50 $ 34 Other deferred credits and other liabilities 53 31 Total $ 106 $ 65 |
FAIR VALUE MEASUREMENTS, INCL26
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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, 2016 As of December 31, 2015 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 $ 11 $ 11 Held to maturity securities $ 7 Interest rate contracts $ 15 $ 15 Commodity contracts 2 1 Energy management contracts 13 14 Liabilities: Interest rate contracts 222 $ 196 87 65 Commodity contracts 2 1 4 Energy management contracts 1 13 4 12 |
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, 2016 December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 5,995.4 $ 6,704.5 $ 5,997.6 $ 6,445.7 Consolidated SCE&G $ 4,766.9 $ 5,368.3 $ 4,769.0 $ 5,129.1 |
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, 2016 As of December 31, 2015 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 $ 11 $ 11 Held to maturity securities $ 7 Interest rate contracts $ 15 $ 15 Commodity contracts 2 1 Energy management contracts 13 14 Liabilities: Interest rate contracts 222 $ 196 87 65 Commodity contracts 2 1 4 Energy management contracts 1 13 4 12 |
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, 2016 December 31, 2015 Millions of dollars Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value The Company $ 5,995.4 $ 6,704.5 $ 5,997.6 $ 6,445.7 Consolidated SCE&G $ 4,766.9 $ 5,368.3 $ 4,769.0 $ 5,129.1 |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Pension and Other Postretirement Benefit Plans | |
Schedule of Net Benefit Costs [Table Text Block] | The Company Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Three months ended March 31, Service cost $ 5.5 $ 5.8 $ 1.3 $ 1.4 Interest cost 9.9 9.5 3.0 2.9 Expected return on assets (14.1 ) (15.5 ) — — Prior service cost amortization 1.0 1.0 0.1 0.1 Amortization of actuarial losses 3.7 3.5 0.1 0.6 Net periodic benefit cost $ 6.0 $ 4.3 $ 4.5 $ 5.0 |
SCEG | |
Pension and Other Postretirement Benefit Plans | |
Schedule of Net Benefit Costs [Table Text Block] | Consolidated SCE&G Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Three months ended March 31, Service cost $ 4.5 $ 4.6 $ 1.0 $ 1.1 Interest cost 8.4 8.0 2.5 2.3 Expected return on assets (11.9 ) (13.0 ) — — Prior service cost amortization 0.8 0.8 0.1 0.1 Amortization of actuarial losses 3.1 3.0 0.1 0.4 Net periodic benefit cost $ 4.9 $ 3.4 $ 3.7 $ 3.9 |
SEGMENT OF BUSINESS INFORMATI28
SEGMENT OF BUSINESS INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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, 2016 Electric Operations $ 592 $ 1 $ 198 n/a Gas Distribution 299 1 94 n/a Retail Gas Marketing 171 — n/a $ 22 Energy Marketing 110 22 n/a 2 All Other — 98 — — Adjustments/Eliminations — (122 ) 39 152 Consolidated Total $ 1,172 $ — $ 331 $ 176 Three Months Ended March 31, 2015 Electric Operations $ 629 — $ 199 n/a Gas Distribution 368 — 96 n/a Retail Gas Marketing 204 — n/a $ 27 Energy Marketing 187 $ 35 n/a 6 All Other 4 114 238 207 Adjustments/Eliminations (3 ) (149 ) 53 160 Consolidated Total $ 1,389 $ — $ 586 $ 400 Consolidated SCE&G Millions of dollars External Revenue Operating Income Earnings Available to Common Shareholder Three Months Ended March 31, 2016 Electric Operations $ 593 $ 198 n/a Gas Distributions 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Three Months Ended March 31, 2015 Electric Operations $ 630 $ 199 n/a Gas Distributions 142 38 n/a Adjustments/Eliminations — — $ 122 Consolidated Total $ 772 $ 237 $ 122 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2016 2015 2016 2015 Electric Operations $ 11,039 $ 10,883 $ 11,039 $ 10,883 Gas Distribution 2,676 2,606 768 757 Retail Gas Marketing 140 106 n/a n/a Energy Marketing 84 95 n/a n/a All Other 994 998 n/a n/a Adjustments/Eliminations 2,435 2,458 3,125 3,125 Consolidated Total $ 17,368 $ 17,146 $ 14,932 $ 14,765 |
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, 2016 Electric Operations $ 593 $ 198 n/a Gas Distributions 124 38 n/a Adjustments/Eliminations — — $ 113 Consolidated Total $ 717 $ 236 $ 113 Three Months Ended March 31, 2015 Electric Operations $ 630 $ 199 n/a Gas Distributions 142 38 n/a Adjustments/Eliminations — — $ 122 Consolidated Total $ 772 $ 237 $ 122 Segment Assets The Company Consolidated SCE&G March 31, December 31, March 31, December 31, Millions of dollars 2016 2015 2016 2015 Electric Operations $ 11,039 $ 10,883 $ 11,039 $ 10,883 Gas Distribution 2,676 2,606 768 757 Retail Gas Marketing 140 106 n/a n/a Energy Marketing 84 95 n/a n/a All Other 994 998 n/a n/a Adjustments/Eliminations 2,435 2,458 3,125 3,125 Consolidated Total $ 17,368 $ 17,146 $ 14,932 $ 14,765 |
SUMMARY OF SIGNIFICANT ACCOUN29
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2016USD ($)MW | Dec. 31, 2015USD ($) | |
Significant Accounting Policies | ||
Pre-tax gain on sale of CGT and SCI | $ 342,000,000 | |
Property, Plant and Equipment, Net | $ 280,000,000 | 280,000,000 |
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash | 96,000,000 | |
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash | 81,000,000 | |
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash | (15,000,000) | |
SCEG | ||
Significant Accounting Policies | ||
Property, Plant and Equipment, Net | 68,000,000 | $ 68,000,000 |
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash | 96,000,000 | |
Reclassifications, Cash Flow Statement, Derivative Financial Instruments, Source Of Cash | 81,000,000 | |
Reclassifications, Cash Flow Statement, Other Liabilities, Source Of Cash | $ (15,000,000) | |
Genco | ||
Significant Accounting Policies | ||
Power Generation Capacity Megawatts | MW | 605 | |
Property, Plant and Equipment, Net | $ 488,000,000 | |
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% | 46.00% |
Natural gas inventory, carrying amount | $ 6,000,000 | $ 17,700,000 |
PercentOfStorageFeesCreditedToRatePayers | 75.00% |
RATE AND OTHER REGULATORY MAT30
RATE AND OTHER REGULATORY MATTERS (Details) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016USD ($)MW | Mar. 31, 2015USD ($) | Dec. 31, 2013 | Dec. 31, 2015USD ($) | |
Rate Matters [Line Items] | ||||
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash | $ 96,000,000 | |||
Carrying cost recovery | (4,000,000) | $ (3,000,000) | ||
Regulatory Assets, Noncurrent | $ 2,068,000,000 | $ 1,937,000,000 | ||
MPG environmental remediation | 24 | |||
PSNC Energy Rate Case Application, Increase Amount | $ 41,600,000 | |||
PSNC Energy Rate Case Application, Percentage Increase | 0.00% | |||
SCEG | ||||
Rate Matters [Line Items] | ||||
Reclassifications, Cash Flow Statement, Regulatory Assets, Use Of Cash | $ 96,000,000 | |||
Capacity of renewable energy facilities by 2020 | MW | 80 | |||
Capacity of renewable energy facilities by 2016 | MW | 30 | |||
SCPSC Order Reduction Of Total Fuel Cost Component Of Retail Electric Rates To Reflect Lower Projected Fuel Costs And Eliminate Over-Collection Balances | $ 61,000,000 | |||
SCPSC Order, Recovery Of Projected DER Program Costs | 6,900,000 | |||
Carrying costs on deferred income tax assets | 3,100,000 | 1,900,000 | ||
Carrying cost recovery | (4,000,000) | $ (3,000,000) | ||
Regulatory Assets, Noncurrent | $ 1,986,000,000 | 1,857,000,000 | ||
Demand side management recovery period | 5 | |||
SCPSC Order, Annual DSM Program Rate Rider Recovery Amount | $ 37,600,000 | |||
Environmental Restoration Costs [Member] | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | 41,000,000 | 42,000,000 | ||
Environmental Restoration Costs [Member] | SCEG | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | $ 34,000,000 | 35,000,000 | ||
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 | $ 63,000,000 | |||
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 | 14,000,000 | |||
Pension Costs [Member] | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | 323,000,000 | 325,000,000 | ||
Pension Costs [Member] | SCEG | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | $ 293,000,000 | 295,000,000 | ||
Regulatory Noncurrent Asset Amortization Period | 12 years | |||
Other Regulatory Assets [Member] | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | $ 153,000,000 | 144,000,000 | ||
Regulatory Noncurrent Asset Amortization Period | 30 years | |||
Other Regulatory Assets [Member] | SCEG | ||||
Rate Matters [Line Items] | ||||
Regulatory Assets, Noncurrent | $ 136,000,000 | $ 129,000,000 |
RATE AND OTHER REGULATORY MAT31
RATE AND OTHER REGULATORY MATTERS (Details 2) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | |
Regulatory Assets | |||
Regulatory Liabilities | $ 847 | $ 855 | |
MPG environmental remediation | 24 | ||
Regulatory Assets, Noncurrent | $ 2,068 | 1,937 | |
SCEG | |||
Regulatory Assets | |||
Regulatory Liabilities | 623 | 635 | |
Carrying costs on deferred income tax assets | 3.1 | $ 1.9 | |
Regulatory Assets, Noncurrent | $ 1,986 | 1,857 | |
Demand side management recovery period | 5 | ||
Other Regulatory Liability [Member] | |||
Regulatory Assets | |||
Regulatory Liabilities | $ 27 | 27 | |
Other Regulatory Liability [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Liabilities | 20 | 20 | |
Asset Retirement Obligation Costs [Member] | |||
Regulatory Assets | |||
Regulatory Liabilities | 739 | 732 | |
Asset Retirement Obligation Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Liabilities | 522 | 519 | |
Deferred gains on interest rate derivatives [Member] | |||
Regulatory Assets | |||
Regulatory Liabilities | 81 | 96 | |
Deferred gains on interest rate derivatives [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Liabilities | $ 81 | 96 | |
Pension costs, electric [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Noncurrent Asset, Amortization Period | 30 years | ||
Deferred Losses On Interest Rate Derivatives [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 666 | 535 | |
Deferred Losses On Interest Rate Derivatives [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 666 | 535 | |
Asset Retirement Obligation Costs [Member] | |||
Regulatory Assets | |||
Regulatory Noncurrent Asset, Amortization Period | 110 years | ||
Regulatory Assets, Noncurrent | $ 402 | 405 | |
Asset Retirement Obligation Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 381 | 384 | |
unrecovered plant [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 125 | 127 | |
unrecovered plant [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 125 | 127 | |
Demand Side Management programs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 61 | 61 | |
Demand Side Management programs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 61 | 61 | |
Deferred Income Tax Charges [Member] | |||
Regulatory Assets | |||
Regulatory Noncurrent Asset, Amortization Period | 85 years | ||
Regulatory Assets, Noncurrent | $ 297 | 298 | |
Deferred Income Tax Charges [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 290 | 291 | |
Environmental Restoration Costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 41 | 42 | |
Environmental Restoration Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | 34 | 35 | |
Pension Costs [Member] | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 323 | 325 | |
Pension Costs [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Noncurrent Asset, Amortization Period | 12 years | ||
Regulatory Assets, Noncurrent | $ 293 | 295 | |
Other Regulatory Assets [Member] | |||
Regulatory Assets | |||
Regulatory Noncurrent Asset, Amortization Period | 30 years | ||
Regulatory Assets, Noncurrent | $ 153 | 144 | |
Other Regulatory Assets [Member] | SCEG | |||
Regulatory Assets | |||
Regulatory Assets, Noncurrent | $ 136 | $ 129 |
RATE AND OTHER REGULATORY MAT32
RATE AND OTHER REGULATORY MATTERS (Details 3) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Regulatory Liabilities [Line Items] | ||
Regulatory Assets, Noncurrent | $ 2,068 | $ 1,937 |
Regulatory Liabilities | 847 | 855 |
SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Assets, Noncurrent | 1,986 | 1,857 |
Regulatory Liabilities | 623 | 635 |
Asset Retirement Obligation Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 739 | 732 |
Asset Retirement Obligation Costs [Member] | SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 522 | 519 |
Deferred gains on interest rate derivatives [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 81 | 96 |
Deferred gains on interest rate derivatives [Member] | SCEG | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $ 81 | $ 96 |
COMMON EQUITY (Details)
COMMON EQUITY (Details) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Schedule of Capitalization, Equity [Line Items] | |||
Dividends, Common Stock | $ 82 | ||
Common Stock, Shares Authorized | 200 | 200 | |
COMMON EQUITY [Abstract] | |||
Common Stock, Shares, Outstanding | 142.9 | 142.9 | |
Other Comprehensive Income (Loss), Net of Tax | $ 2 | $ 2 | |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 2 | 6 | |
SCEG | |||
Schedule of Capitalization, Equity [Line Items] | |||
Dividends | 74 | 70 | |
Dividends, Common Stock | $ 74 | 71 | |
Common Stock, Shares Authorized | 50 | 50 | |
COMMON EQUITY [Abstract] | |||
Common Stock, Shares, Outstanding | 40.3 | 40.3 | |
Preferred Stock, Shares Authorized | 20 | 20 | |
Preferred Stock, Shares Outstanding | 0 | 0 | |
SCEG excluding VIEs [Member] | |||
Schedule of Capitalization, Equity [Line Items] | |||
Dividends | $ 72 | 69 | |
Commodity Contract | |||
Schedule of Capitalization, Equity [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (5) | (7) | |
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 | 5 | 7 | |
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) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,000 | $ 2,000 |
Long-Term Line of Credit - SC Fuel Co only | 500 | 500 |
Commercial Paper | 917 | 531 |
Letters of Credit Outstanding, Amount | 3.3 | 3.3 |
Line of Credit Facility, Remaining Borrowing Capacity | 1,080 | 1,466 |
Debt Instrument, Face Amount | 67.8 | |
SCE&G (including Fuel Company) | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400 | 1,400 |
Commercial Paper | $ 870 | $ 420 |
Debt, Weighted Average Interest Rate | 0.83% | 0.74% |
Letters of Credit Outstanding, Amount | $ 0.3 | $ 0.3 |
Line of Credit Facility, Remaining Borrowing Capacity | 530 | 980 |
SCEG | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | 67.8 | |
SCANA [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 400 | 400 |
Commercial Paper | $ 10 | $ 37 |
Debt, Weighted Average Interest Rate | 0.90% | 1.19% |
Letters of Credit Outstanding, Amount | $ 3 | $ 3 |
Line of Credit Facility, Remaining Borrowing Capacity | 387 | 360 |
PSNC Energy [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 200 | 200 |
Commercial Paper | $ 37 | $ 74 |
Debt, Weighted Average Interest Rate | 0.81% | 0.77% |
Line of Credit Facility, Remaining Borrowing Capacity | $ 163 | $ 126 |
Fuel Company | ||
Debt Instrument [Line Items] | ||
Long-Term Line of Credit - SC Fuel Co only | 500 | 500 |
Expires December 2020 [Domain] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,300 | 1,300 |
Expires December 2020 [Domain] | SCEG | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 700 | 700 |
Expires December 2020 [Domain] | SCANA [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 400 | 400 |
Expires December 2020 [Domain] | PSNC Energy [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 200 | 200 |
Expires December 2016 [Domain] | ||
Debt Instrument [Line Items] | ||
Long-term Line of Credit - SCE&G only | 200 | 200 |
Expires December 2016 [Domain] | SCEG | ||
Debt Instrument [Line Items] | ||
Long-term Line of Credit - SCE&G only | $ 200 | $ 200 |
LONG-TERM AND SHORT-TERM DEBT35
LONG-TERM AND SHORT-TERM DEBT (Details 2) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Debt Instruments [Abstract] | ||
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan | $ 67.8 | |
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 2,000 | $ 2,000 |
Commercial Paper | 917 | 531 |
Long-Term Line of Credit - SC Fuel Co only | 500 | 500 |
Letters of credit supported by LOC | (3.3) | (3.3) |
Line of Credit Facility, Remaining Borrowing Capacity | 1,080 | 1,466 |
SCANA [Member] | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 400 | 400 |
Commercial Paper | $ 10 | $ 37 |
Commercial paper, weighted average interest rate (as a percent) | 0.90% | 1.19% |
Letters of credit supported by LOC | $ (3) | $ (3) |
Line of Credit Facility, Remaining Borrowing Capacity | 387 | 360 |
SCEG | ||
Debt Instrument [Line Items] | ||
Due to Affiliate, Current | 116 | 113 |
Debt Instruments [Abstract] | ||
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan | 67.8 | |
Lines of credit: | ||
Related Party Transaction, Due from (to) Related Party, Current | 43.9 | 33 |
Due from Other Related Parties, Current | 9 | |
SCE&G (including Fuel Company) | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400 | 1,400 |
Commercial Paper | $ 870 | $ 420 |
Commercial paper, weighted average interest rate (as a percent) | 0.83% | 0.74% |
Letters of credit supported by LOC | $ (0.3) | $ (0.3) |
Line of Credit Facility, Remaining Borrowing Capacity | 530 | 980 |
Fuel Company | ||
Lines of credit: | ||
Long-Term Line of Credit - SC Fuel Co only | 500 | 500 |
PSNC Energy | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 200 | 200 |
Commercial Paper | $ 37 | $ 74 |
Commercial paper, weighted average interest rate (as a percent) | 0.81% | 0.77% |
Line of Credit Facility, Remaining Borrowing Capacity | $ 163 | $ 126 |
INCOME TAXES (Details)
INCOME TAXES (Details) $ in Millions | Mar. 31, 2016USD ($) |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $ 49 |
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 | 7 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound | 8 |
SCEG | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 49 |
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 | 7 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound | $ 8 |
DERIVATIVE FINANCIAL INSTRUME37
DERIVATIVE FINANCIAL INSTRUMENTS (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2016USD ($)MMBTU | Dec. 31, 2015MMBTU | |
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 51,102,704 | 58,229,980 |
Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 9,240,000 | 7,530,000 |
Retail Gas Marketing | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 6,236,000 | 7,869,000 |
Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 35,626,704 | 42,830,980 |
Commodity Contract | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 20,108,500 | 19,372,500 |
Commodity Contract | Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 9,240,000 | 7,530,000 |
Commodity Contract | Retail Gas Marketing | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 6,236,000 | 7,869,000 |
Commodity Contract | Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 4,632,500 | 3,973,500 |
Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 30,994,204 | 38,857,480 |
Energy Related Derivative [Member] | Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 30,994,204 | 38,857,480 |
Energy Related Derivative [Member] | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | 1,679,289 | 1,842,048 |
DERIVATIVE FINANCIAL INSTRUME38
DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 16 | $ 31 |
Derivative Liability, Fair Value, Gross Liability | 238 | 107 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | |
Derivative Liability, Fair Value, Gross Liability | 222 | 87 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 3 | 1 |
Derivative Liability, Fair Value, Gross Liability | 3 | 5 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 13 | 15 |
Derivative Liability, Fair Value, Gross Liability | 13 | 15 |
Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | |
Derivative Liability, Fair Value, Gross Liability | 42 | 37 |
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 3 | 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 | 36 | 28 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 2 | 4 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | |
Derivative Liability, Fair Value, Gross Liability | 1 | 1 |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | 30 |
Derivative Liability, Fair Value, Gross Liability | 196 | 69 |
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 1,235 | 1,235 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 100 | 33 |
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 | 5 | |
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 | 83 | 22 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 10 | |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2 | 1 |
Derivative Liability, Fair Value, Gross Liability | 2 | |
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 | 9 | 9 |
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 | 4 | 3 |
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 | 3 | 3 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 9 | 11 |
Derivative Liability, Fair Value, Gross Liability | 1 | |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | |
Derivative Liability, Fair Value, Gross Liability | 196 | 65 |
SCEG | Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | 13 | 10 |
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 | 12 | 9 |
SCEG | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | |
Derivative Liability, Fair Value, Gross Liability | 183 | 55 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 1,235 | 1,235 |
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 | 100 | 33 |
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 | 5 | |
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 | 83 | 22 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 10 | |
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | 120 | 120 |
Cash Flow Hedging [Member] | SCEG | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | $ 36.4 | $ 36.4 |
DERIVATIVE FINANCIAL INSTRUME39
DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Derivative [Line Items] | ||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ (5) | $ (3) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ (7) | $ (9) |
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 | $ 5 | $ 7 |
Commodity Contract | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | (2) | (1) |
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) | (2) |
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | (144) | (94) |
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | (3) | (2) |
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 | 4 |
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 | 1.1 | |
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 | (5) | (7) |
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] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 0.7 | |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | (1) | $ 0 |
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 | $ 2.1 | |
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 | $ (144) | $ (94) |
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | (3) | (2) |
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 | 0 | 4 |
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 | 0.7 | |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | (1) | $ 0 |
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 | $ 2.1 |
DERIVATIVE FINANCIAL INSTRUME40
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative [Line Items] | ||
LetterofCreditAvailableCommodityDerivativesassetposition | $ 3 | $ 3 |
Derivative, Net Asset Position, Aggregate Fair Value | 13 | 14 |
Collateral Already Posted, Aggregate Fair Value | 124.1 | 50.4 |
Additional Collateral, Aggregate Fair Value | 110 | 44.8 |
Derivative, Net Liability Position, Aggregate Fair Value | 234.1 | 95.2 |
Cash collateral to request from interest rate derivative counterparty | 0 | 7.3 |
Interest Rate Derivative, net asset position, Aggregate Fair Value | 0 | 7.3 |
SCEG | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | 88.2 | 13.4 |
Additional Collateral, Aggregate Fair Value | 107.9 | 43.6 |
Derivative, Net Liability Position, Aggregate Fair Value | 196.1 | 57 |
Cash collateral to request from interest rate derivative counterparty | 0 | 7.3 |
Interest Rate Derivative, net asset position, Aggregate Fair Value | $ 0 | $ 7.3 |
DERIVATIVE FINANCIAL INSTRUME41
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 16 | $ 31 |
Derivative Asset, Fair Value, Gross Liability | (1) | (1) |
Derivative Asset | 15 | 30 |
Derivative Liability, Fair Value, Gross Liability | 238 | 107 |
Derivative Liability, Fair Value, Gross Asset | (1) | (1) |
Derivative Liability | 237 | 106 |
Derivative, Collateral, Right to Reclaim Securities | 0 | (8) |
Derivative, Collateral, Right to Reclaim Cash | (124) | (50) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 113 | 48 |
Derivative, Collateral, Obligation to Return Securities | 0 | (8) |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 15 | 22 |
Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 4 | 8 |
Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 11 | 22 |
Derivative Liability | 2 | 3 |
Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 113 | 50 |
Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 122 | 53 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | |
Derivative Asset | 15 | |
Derivative Liability, Fair Value, Gross Liability | 222 | 87 |
Derivative Liability | 222 | 87 |
Derivative, Collateral, Right to Reclaim Securities | (8) | |
Derivative, Collateral, Right to Reclaim Cash | (116) | (36) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 106 | 43 |
Derivative, Collateral, Obligation to Return Securities | (8) | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 7 | |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 3 | 1 |
Derivative Asset, Fair Value, Gross Liability | (1) | |
Derivative Asset | 2 | 1 |
Derivative Liability, Fair Value, Gross Liability | 3 | 5 |
Derivative Liability, Fair Value, Gross Asset | (1) | |
Derivative Liability | 2 | 5 |
Derivative, Collateral, Right to Reclaim Cash | (2) | (5) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 2 | 1 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 13 | 15 |
Derivative Asset, Fair Value, Gross Liability | (1) | |
Derivative Asset | 13 | 14 |
Derivative Liability, Fair Value, Gross Liability | 13 | 15 |
Derivative Liability, Fair Value, Gross Asset | (1) | |
Derivative Liability | 13 | 14 |
Derivative, Collateral, Right to Reclaim Cash | (6) | (9) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 7 | 5 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 13 | 14 |
SCEG | ||
Derivative [Line Items] | ||
Derivative Asset | 15 | |
Derivative Liability | 196 | 65 |
SCEG | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 5 | |
SCEG | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 10 | |
SCEG | Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 101 | 34 |
SCEG | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 95 | 31 |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 15 | |
Derivative Asset | 15 | |
Derivative Liability, Fair Value, Gross Liability | 196 | 65 |
Derivative Liability | 196 | 65 |
Derivative, Collateral, Right to Reclaim Securities | (8) | |
Derivative, Collateral, Right to Reclaim Cash | (88) | (13) |
Derivative Liability, Fair Value, Amount Offset Against Collateral | $ 108 | 44 |
Derivative, Collateral, Obligation to Return Securities | (8) | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | $ 7 |
FAIR VALUE MEASUREMENTS, INCL42
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 15 | $ 30 |
Derivative Liability | 237 | 106 |
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 11 | 11 |
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | ||
Held-to-maturity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 7 | |
Interest Rate Contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 15 | |
Derivative Liability | $ 222 | $ 87 |
Interest Rate Contract | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | ||
Derivative Liability | ||
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 15 | |
Derivative Liability | $ 222 | 87 |
Commodity Contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 2 | 1 |
Derivative Liability | 2 | 5 |
Commodity Contract | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 2 | 1 |
Derivative Liability | $ 1 | |
Commodity Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | ||
Derivative Liability | $ 2 | $ 4 |
Other energy management contracts [Member] [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 13 | 14 |
Derivative Liability | $ 13 | $ 14 |
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] | ||
Derivative Asset | ||
Derivative Liability | $ 1 | $ 4 |
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] | ||
Derivative Asset | 13 | 14 |
Derivative Liability | 13 | 12 |
SCEG | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 15 | |
Derivative Liability | 196 | 65 |
SCEG | Interest Rate Contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 15 | |
Derivative Liability | 196 | 65 |
SCEG | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 15 | |
Derivative Liability | $ 196 | $ 65 |
FAIR VALUE MEASUREMENTS, INCL43
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | $ 5,995.4 | $ 5,997.6 |
Long-term Debt, Fair Value | 6,704.5 | 6,445.7 |
SCEG | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | 4,766.9 | 4,769 |
Long-term Debt, Fair Value | $ 5,368.3 | $ 5,129.1 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Pension and Other Postretirement Benefit Plans | ||
Pension Contributions | No | |
Pension Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | $ 5.5 | $ 5.8 |
Interest cost | 9.9 | 9.5 |
Expected return on assets | (14.1) | (15.5) |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 1 | 1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.7 | 3.5 |
Defined Benefit Plan, Net Periodic Benefit Cost | 6 | 4.3 |
Other Postretirement Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | 1.3 | 1.4 |
Interest cost | 3 | 2.9 |
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 | 0.1 | 0.1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.1 | 0.6 |
Defined Benefit Plan, Net Periodic Benefit Cost | $ 4.5 | 5 |
SCEG | ||
Pension and Other Postretirement Benefit Plans | ||
Pension Contributions | No | |
SCEG | Pension Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | $ 4.5 | 4.6 |
Interest cost | 8.4 | 8 |
Expected return on assets | (11.9) | (13) |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.8 | 0.8 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.1 | 3 |
Defined Benefit Plan, Net Periodic Benefit Cost | 4.9 | 3.4 |
SCEG | Other Postretirement Benefits | ||
Components of Net Periodic Benefit Cost | ||
Service cost | 1 | 1.1 |
Interest cost | 2.5 | 2.3 |
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 | 0.1 | 0.1 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.1 | 0.4 |
Defined Benefit Plan, Net Periodic Benefit Cost | $ 3.7 | $ 3.9 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Nuclear Generation | |||||
Goal For Reduced Carbon Dioxide Emissions From 2005 Levels By 2030 Under Clean Air Act | 32.00% | ||||
NPDES permit renewal permit period | five | ||||
Regulatory Assets, Noncurrent | $ 2,068 | $ 1,937 | |||
Forecasted Incremental Capital Costs Associated With Schedule Delays, 2015 Petition | 539 | ||||
EPC Contract Amendment, New Nuclear Construction Completion Bonus | 151 | ||||
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments | 62.5 | ||||
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments | 300 | ||||
EPC Contract Amendment, Payment and Performance Bonds | $ 45 | ||||
EPC Contract Amendment, Payment And Performance Bonds, Percentage of Billing | 0.00% | ||||
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage | $ 100 | ||||
EPC Contract Amendment, Additional Sales Tax on Fixed Price Option | 10 | ||||
EPC Contract Amendment, Fixed Price Option, Increase In Total New Nuclear Project Cost | 774 | ||||
SCEG | |||||
Commitments and contingencies | |||||
Federal Limit on Public Liability Claims from Nuclear Incident Approximate | 13,400 | ||||
Maximum Insurance Coverage For Each Nuclear Plant by ANI | 375 | ||||
Environmental Remediation Costs Recognized in Regulatory Assets | 34.4 | ||||
Nuclear Insurance | |||||
Maximum liability assessment per reactor for each nuclear incident | 127.3 | ||||
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 | 2,250 | ||||
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 | 43.5 | ||||
NEIL Maximum Insurance Coverage to Nuclear Facility for Property Damage and Outage Costs | $ 2,750 | ||||
Environmental | |||||
Number of MGP decommissioned sites that contain residues of byproduct chemicals | 4 | ||||
Site Contingency MGP Estimated Environmental Remediation Costs | $ 18.4 | ||||
Nuclear Generation | |||||
Number Of States Required To Reduce Emissions Under CSAPR | 28 | ||||
Regulatory Assets, Noncurrent | $ 1,986 | $ 1,857 | |||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 10.50% | 0.00% | |||
EPC Contract Amendment, Increase In Fixed Component Of Contract Price | $ 165 | ||||
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price | 27 | ||||
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | 255 | ||||
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month | 55 | ||||
EPC Contract Amendment, Increase In Total New Nuclear Project Cost | 286 | ||||
Total New Nuclear Project Cost Approved By SCPSC In September 2015 | 6,800 | ||||
EPC Contract Amendment, New Nuclear Project Costs, Estimated Change Orders as of April 30, 2016 | 53 | ||||
EPC Contract Amendment, Total New Nuclear Project Cost Including Amendment Increase | 7,200 | ||||
EPC Contract Amendment, Increase In Fixed Component Of Contract Price, Payments | 34.4 | ||||
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Payments | 165 | ||||
EPC Contract Amendment, Payment and Performance Bonds | 25 | ||||
EPC Contract Amendment, Payment And Performance Bonds, Maximum Aggregate Nominal Coverage | 55 | ||||
EPC Contract Amendment, Fixed Price Option, Project Cost Including Fixed Option Price Increase | 7,700 | ||||
EPC Contract Amendment, Fixed Price Option, Price For New Nuclear Construction After June 2015 | 3,000 | ||||
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | 186 | ||||
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus | 83 | ||||
Summer Station New Units and Transmission Assets [Domain] | |||||
Nuclear Generation | |||||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | $ 3,800 | ||||
SCEG | |||||
Nuclear Insurance | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 5.00% | ||||
Summer Station New Units [Domain] | |||||
Nuclear Insurance | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 55.00% | ||||
Nuclear Generation | |||||
jointly owned utility plant ownership, construction financing cost | $ 3,200 | ||||
EPC Contract Amendment, Increase In Fixed Component Of Contract Price | 300 | ||||
EPC Contract Amendment, Credit Applied To Target Component Of New Units Contract Price | 50 | ||||
EPC Contract Amendment, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | 463 | ||||
EPC Contract Amendment, New Nuclear Construction Completion Bonus | 275 | ||||
EPC Contract Amendment, Revised Construction Milestone Payment Schedule, Per Month | 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 | $ 6,000 | ||||
EPC Contract Amendment, Fixed Price Option, Cap On Delay Oriented Liquidated Damages Per New Nuclear Unit | 338 | ||||
EPC Contract Amendment, Fixed Price Option, New Nuclear Construction Completion Bonus | 150 | ||||
Capital costs, owners [Domain] | |||||
Nuclear Generation | |||||
Forecasted incremental capital costs, 2015 petition | 245 | ||||
Forecasted Total Capital Costs, 2015 Petition | 5,200 | ||||
Capital costs, Other [Domain] [Domain] | |||||
Nuclear Generation | |||||
Forecasted incremental capital costs, 2015 petition | 453 | ||||
Forecasted Total Capital Costs, 2015 Petition | 6,800 | ||||
Scenario, Forecast [Member] | SCEG | |||||
Nuclear Generation | |||||
Additional ownership in new units | 2.00% | 2.00% | 1.00% | ||
Minimum [Member] | SCEG | |||||
Nuclear Generation | |||||
Additional ownership in new units, dollars | 750 | ||||
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, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||
Gain (Loss) On Disposition Of Regulated Business Net Of Transaction Costs | $ 0 | $ 235 | |
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs | 202 | ||
Electric Domestic Regulated Revenue | 592 | 629 | |
Revenues | 0 | 0 | |
Net Income (Loss) Available to Common Stockholders, Basic | 176 | 400 | |
Operating Income | (331) | (586) | |
Regulated Operating Revenue, Gas | 299 | 369 | |
Regulated and Unregulated Operating Revenue | 1,172 | 1,389 | |
Segment Assets | 17,368 | $ 17,146 | |
Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 592 | 629 | |
Revenues | 1 | 0 | |
Operating Income | (198) | (199) | |
Segment Assets | 11,039 | 10,883 | |
Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Revenues | 1 | 0 | |
Operating Income | (94) | (96) | |
Regulated and Unregulated Operating Revenue | 299 | 368 | |
Segment Assets | 2,676 | 2,606 | |
Retail Gas Marketing | |||
Segment Reporting Information [Line Items] | |||
Revenues | 0 | 0 | |
Net Income (Loss) Available to Common Stockholders, Basic | 22 | 27 | |
Regulated and Unregulated Operating Revenue | 171 | 204 | |
Segment Assets | 140 | 106 | |
Energy Marketing [Member] | |||
Segment Reporting Information [Line Items] | |||
Revenues | 22 | 35 | |
Net Income (Loss) Available to Common Stockholders, Basic | 2 | 6 | |
Regulated and Unregulated Operating Revenue | 110 | 187 | |
Segment Assets | 84 | 95 | |
All Other [member] | |||
Segment Reporting Information [Line Items] | |||
Revenues | 98 | 114 | |
Net Income (Loss) Available to Common Stockholders, Basic | 0 | 207 | |
Operating Income | 0 | (238) | |
Regulated and Unregulated Operating Revenue | 0 | 4 | |
Segment Assets | 994 | 998 | |
Adjustments/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Revenues | (122) | (149) | |
Net Income (Loss) Available to Common Stockholders, Basic | 152 | 160 | |
Operating Income | 39 | (53) | |
Regulated and Unregulated Operating Revenue | 0 | (3) | |
Segment Assets | 2,435 | 2,458 | |
SCEG | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 593 | 630 | |
Operating Income | (236) | (237) | |
Regulated Operating Revenue, Gas | 124 | 142 | |
Net Income (Loss) Attributable to Parent | 113 | 122 | |
Segment Assets | 14,932 | 14,765 | |
Regulated Operating Revenue | 717 | 772 | |
SCEG | Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 593 | 630 | |
Operating Income | (198) | (199) | |
Segment Assets | 11,039 | 10,883 | |
SCEG | Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Operating Income | (38) | (38) | |
Regulated and Unregulated Operating Revenue | 124 | 142 | |
Segment Assets | 768 | 757 | |
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 | 113 | $ 122 | |
Segment Assets | $ 3,125 | $ 3,125 |
AFFILIATED TRANSACTIONS -SCEG (
AFFILIATED TRANSACTIONS -SCEG (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Related Party Transaction, Expenses from Transactions with Related Party | $ 75.6 | $ 73.1 | |
Canadys Refined Coal [Member] | |||
Related Party Transaction [Line Items] | |||
Equity Method Investment, Ownership Percentage | 40.00% | ||
Related Party Transaction, Purchases from Related Party | $ 52.8 | 70.1 | |
Sales to Affiliate | 52.5 | 69.7 | |
Related Party Tax Expense, Due from Affiliates, Current | 15.2 | 12.8 | |
Related Party Tax Expense, Due to Affiliates, Current | 15.3 | 12.9 | |
Carolina Gas Transmission [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Purchases from Related Party | $ 3.4 | ||
Energy Marketing [Member] | |||
Related Party Transaction [Line Items] | |||
Due to Affiliate, Current | 4 | 7.5 | |
Cost of Natural Gas Purchases | 22.4 | $ 34.6 | |
SCEG | |||
Related Party Transaction [Line Items] | |||
Due to Affiliate, Current | 116 | 113 | |
Due from Affiliate, Current | 15 | 22 | |
Accounts Payable, Related Parties, Current | $ 48.1 | $ 57 |