Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 20, 2015 | Jun. 30, 2014 | |
Document Information [Line Items] | |||
Entity Registrant Name | SCANA CORP | ||
Entity Central Index Key | 754737 | ||
Current Fiscal Year End Date | -19 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | FALSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Common Stock, Shares Outstanding | 142,916,917 | ||
Entity Public Float | $7,612,334,427 | ||
SCE&G | |||
Document Information [Line Items] | |||
Entity Registrant Name | SOUTH CAROLINA ELECTRIC & GAS CO | ||
Entity Central Index Key | 91882 | ||
Current Fiscal Year End Date | -19 | ||
Entity Filer Category | Non-accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | FALSE | ||
Entity Common Stock, Shares Outstanding | 40,296,147 |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Millions, unless otherwise specified | ||||
Assets | ||||
Utility Plant In Service | $12,289 | $12,213 | ||
Accumulated Depreciation and Amortization | -4,088 | -4,011 | ||
Construction Work in Progress | 3,323 | 2,724 | ||
Plant to be Retired, net | 169 | 177 | ||
Nuclear Fuel, Net of Accumulated Amortization | 329 | 310 | ||
Goodwill, Net of Writedown of $230 | 210 | 230 | ||
Utility Plant, Net | 12,232 | 11,643 | ||
Nonutility Property and Investments: | ||||
Nonutility property, net of accumulated depreciation | 284 | 317 | ||
Assets held in trust, net-nuclear decommissioning | 113 | 101 | ||
Other investments | 75 | 86 | ||
Nonutility Property and Investments, Net | 472 | 504 | ||
Current Assets: | ||||
Cash and cash equivalents | 137 | 136 | 72 | 29 |
Receivables, net of allowance for uncollectible accounts | 838 | 802 | ||
Inventories (at average cost): | ||||
Fuel | 221 | 231 | ||
Materials and supplies | 139 | 131 | ||
Emission allowances | 1 | 1 | ||
Prepaid Expense | 320 | 78 | ||
Other Assets, Current | 148 | 42 | ||
Disposal group current assets held for sale | 341 | 0 | ||
Total Current Assets | 2,145 | 1,421 | ||
Deferred Debits and Other Assets: | ||||
Regulatory assets | 1,823 | 1,360 | ||
Defined Benefit Plan, Amounts Recognized in Balance Sheet | 0 | 47 | ||
Other | 180 | 189 | ||
Total | 16,852 | 15,164 | 14,616 | |
Capitalization and Liabilities | ||||
Common Stock, Value, Outstanding | 2,378 | 2,280 | 1,983 | 1,886 |
Retained Earnings, Unappropriated | 2,684 | 2,444 | 2,257 | 2,097 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -75 | -60 | -86 | -94 |
Common equity | 4,987 | 4,664 | 4,154 | 3,889 |
Long-term Debt, Excluding Current Maturities | 5,531 | 5,395 | ||
Total Capitalization | 10,518 | 10,059 | ||
Current Liabilities: | ||||
Short-term borrowings | 918 | 376 | ||
Long-term Debt, Current Maturities | 166 | 54 | ||
Accounts payable | 520 | 425 | ||
Customer deposits and customer prepayments | 98 | 88 | ||
Taxes accrued | 182 | 206 | ||
Interest accrued | 83 | 82 | ||
Dividends declared | 73 | 69 | ||
Liabilities held for sale | 52 | 0 | ||
Derivative financial instruments | 233 | 8 | ||
Other | 208 | 134 | ||
Total Current Liabilities | 2,533 | 1,442 | ||
Deferred Credits and Other Liabilities: | ||||
Deferred income taxes, net | 1,866 | 1,703 | ||
Deferred investment tax credits | 28 | 32 | ||
Asset retirement obligations | 563 | 576 | ||
Pension and other postretirement benefits | 315 | 227 | ||
Regulatory liabilities | 814 | 966 | ||
Other | 215 | 159 | ||
Total Deferred Credits and Other Liabilities | 3,801 | 3,663 | ||
Total | 16,852 | 15,164 | ||
SCE&G | ||||
Assets | ||||
Utility Plant In Service | 10,650 | 10,378 | ||
Accumulated Depreciation and Amortization | -3,667 | -3,499 | ||
Construction Work in Progress | 3,302 | 2,682 | ||
Plant to be Retired, net | 169 | 177 | ||
Nuclear Fuel, Net of Accumulated Amortization | 329 | 310 | ||
Utility Plant, Net | 10,783 | 10,048 | ||
Nonutility Property and Investments: | ||||
Nonutility property, net of accumulated depreciation | 67 | 69 | ||
Assets held in trust, net-nuclear decommissioning | 113 | 101 | ||
Other investments | 2 | 3 | ||
Nonutility Property and Investments, Net | 182 | 173 | ||
Current Assets: | ||||
Cash and cash equivalents | 100 | 92 | 51 | 16 |
Receivables, net of allowance for uncollectible accounts | 524 | 486 | ||
Due from Affiliate, Current | 109 | 19 | ||
Inventories (at average cost): | ||||
Fuel | 130 | 131 | ||
Materials and supplies | 129 | 120 | ||
Emission allowances | 1 | 1 | ||
Prepayments | 154 | 65 | ||
Other Assets, Current | 99 | 15 | ||
Total Current Assets | 1,246 | 929 | ||
Deferred Debits and Other Assets: | ||||
Regulatory assets | 1,745 | 1,303 | ||
Defined Benefit Plan, Amounts Recognized in Balance Sheet | 10 | 96 | ||
Other | 141 | 151 | ||
Total | 14,107 | 12,700 | 12,104 | |
Capitalization and Liabilities | ||||
Common Stock, Value, Outstanding | 2,560 | 2,479 | ||
Retained Earnings, Unappropriated | 2,077 | 1,896 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 | ||
Common equity | 4,634 | 4,372 | ||
Stockholders' Equity Attributable to Noncontrolling Interest | 123 | 117 | ||
Total Equity | 4,757 | 4,489 | 4,043 | 3,773 |
Long-term Debt, Excluding Current Maturities | 4,299 | 4,007 | ||
Total Capitalization | 9,056 | 8,496 | ||
Current Liabilities: | ||||
Short-term borrowings | 709 | 251 | ||
Long-term Debt, Current Maturities | 10 | 48 | ||
Accounts payable | 294 | 241 | ||
Due to Affiliate, Current | 180 | 117 | ||
Customer deposits and customer prepayments | 61 | 56 | ||
Taxes accrued | 170 | 223 | ||
Interest accrued | 64 | 64 | ||
Dividends declared | 74 | 62 | ||
Derivative financial instruments | 208 | 1 | ||
Other | 99 | 71 | ||
Total Current Liabilities | 1,869 | 1,134 | ||
Deferred Credits and Other Liabilities: | ||||
Deferred income taxes, net | 1,696 | 1,509 | ||
Deferred investment tax credits | 28 | 32 | ||
Asset retirement obligations | 536 | 547 | ||
Pension and other postretirement benefits | 195 | 173 | ||
Regulatory liabilities | 610 | 732 | ||
Other | 117 | 77 | ||
Total Deferred Credits and Other Liabilities | 3,182 | 3,070 | ||
Commitments and Contingencies (Note 10) | 0 | 0 | ||
Total | $14,107 | $12,700 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Public Utilities, Property, Plant and Equipment, Net | $12,232 | $11,643 |
Regulated Entity, Other Assets, Noncurrent | 2,003 | 1,596 |
Nonutility property, accumulated depreciation | 122 | 150 |
Common Stock, Shares, Outstanding | 142.7 | 140.7 |
Receivables, net of allowance for uncollectible accounts | 7 | 6 |
Assets, Current | 2,145 | 1,421 |
SCE&G | ||
Public Utilities, Property, Plant and Equipment, Net | 10,783 | 10,048 |
Regulated Entity, Other Assets, Noncurrent | 1,896 | 1,550 |
Common Stock, Shares, Outstanding | 40.3 | 40.3 |
Receivables, net of allowance for uncollectible accounts | 4 | 3 |
Assets, Current | 1,246 | 929 |
VIEs | SCE&G | ||
Public Utilities, Property, Plant and Equipment, Net | 675 | 720 |
Regulated Entity, Other Assets, Noncurrent | 50 | 35 |
Assets, Current | $158 | $147 |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating Revenues: | |||
Electric Domestic Regulated Revenue | $2,622 | $2,423 | $2,446 |
Regulated Operating Revenue, Gas | 1,028 | 955 | 774 |
Gas-nonregulated | 1,301 | 1,117 | 956 |
Regulated and Unregulated Operating Revenue | 4,951 | 4,495 | 4,176 |
Operating Expenses [Abstract] | |||
Fuel used in electric generation | 793 | 745 | 838 |
Purchased power | 81 | 43 | 28 |
Gas purchased for resale | 1,729 | 1,491 | 1,198 |
Other operation and maintenance | 728 | 708 | 690 |
Depreciation and amortization | 384 | 378 | 356 |
Other taxes | 229 | 220 | 207 |
Total Operating Expenses | 3,944 | 3,585 | 3,317 |
Operating Income | 1,007 | 910 | 859 |
Other Income (Expense): | |||
Other income | 122 | 100 | 59 |
Other expenses | -64 | -46 | -42 |
Interest charges, net of allowance for borrowed funds used during construction | -312 | -297 | -295 |
Allowance for equity funds used during construction | 33 | 27 | 21 |
Total Other Expense | -221 | -216 | -257 |
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest | 786 | 694 | 602 |
Income Tax Expense (Benefit) | 248 | 223 | 182 |
Income Available to Common Shareholders | 538 | 471 | 420 |
Per Common Share Data | |||
Earnings Per Share, Basic | $3.79 | $3.40 | $3.20 |
Earnings Per Share, Diluted | $3.79 | $3.39 | $3.15 |
Weighted Average Common Shares Outstanding (millions) | |||
Weighted Average Number of Shares Outstanding, Basic | 141.9 | 138.7 | 131.1 |
Weighted Average Number of Shares Outstanding, Diluted | 141.9 | 139.1 | 133.3 |
Dividends Declared Per Share of Common Stock (in dollars per share) | $2.10 | $2.03 | $1.98 |
SCE&G | |||
Operating Revenues: | |||
Electric Domestic Regulated Revenue | 2,629 | 2,431 | 2,453 |
Regulated Operating Revenue, Gas | 462 | 414 | 356 |
Regulated Operating Revenue | 3,091 | 2,845 | 2,809 |
Operating Expenses [Abstract] | |||
Fuel used in electric generation | 799 | 751 | 844 |
Purchased power | 81 | 43 | 28 |
Gas purchased for resale | 283 | 244 | 197 |
Other operation and maintenance | 575 | 557 | 542 |
Depreciation and amortization | 315 | 313 | 293 |
Other taxes | 208 | 200 | 188 |
Total Operating Expenses | 2,261 | 2,108 | 2,092 |
Operating Income | 830 | 737 | 717 |
Other Income (Expense): | |||
Other income | 80 | 53 | 0 |
Other expenses | -34 | -18 | -18 |
Interest charges, net of allowance for borrowed funds used during construction | -228 | -217 | -211 |
Allowance for equity funds used during construction | 28 | 25 | 21 |
Total Other Expense | -154 | -157 | -208 |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | 676 | 580 | 509 |
Income Tax Expense (Benefit) | 218 | 189 | 157 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 458 | 391 | 352 |
Net Income (Loss) Attributable to Noncontrolling Interest | 12 | 11 | 11 |
Earnings Available to Common Shareholder | 446 | 380 | 341 |
Dividends Common Stock Declared | $272 | $257 | $209 |
CONSOLIDATED_STATEMENTS_OF_INC1
CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Interest charges, allowance for borrowed funds used during construction | $16 | $14 | $11 |
SCE&G | |||
Interest charges, allowance for borrowed funds used during construction | $14 | $13 | $11 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Available to Common Shareholders | $538 | $471 | $420 |
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax | -14 | 7 | -8 |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax | -11 | -18 | -11 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax | -5 | 7 | -4 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax | 1 | 1 | 1 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | -4 | 8 | -3 |
Other Comprehensive Income (Loss), Net of Tax | -15 | 26 | 8 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 1 | 1 | 1 |
Total Comprehensive Income (Loss) | 523 | 497 | 428 |
SCE&G | |||
Other Comprehensive Income (Loss), Net of Tax | 0 | 1 | -1 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 458 | 391 | 352 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 1 | -1 |
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | 0 | 0 | 0 |
Total Comprehensive Income (Loss) | 458 | 392 | 351 |
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 458 | 392 | 351 |
Genco | |||
Less comprehensive income attributable to noncontrolling interest | 12 | 11 | 11 |
SCEG excluding VIEs [Member] | |||
Income Available to Common Shareholders | 446 | 380 | 341 |
Total Comprehensive Income (Loss) | 446 | 381 | 340 |
Interest Rate Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 7 | 8 | 6 |
Commodity Contract [Member] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | ($4) | $3 | $13 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | ($9) | $4 | ($5) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 4 | 5 | 4 |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax | ($2) | $2 | $8 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net Income (Loss) Available to Common Stockholders, Basic | $538 | $471 | $420 |
Adjustments to reconcile net income to net cash provided from operating activities: | |||
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions | 5 | 7 | 0 |
Deferred income taxes, net | 235 | 49 | 130 |
Depreciation and amortization | 403 | 393 | 368 |
Amortization of nuclear fuel | 45 | 57 | 44 |
Allowance for equity funds used during construction | -33 | -27 | -21 |
Carrying cost recovery | -9 | -3 | 0 |
Cash provided (used) by changes in certain assets and liabilities: | |||
Receivables | -33 | -38 | 5 |
Inventories | -62 | 21 | -53 |
Increase (Decrease) in Prepaid Expense | 235 | -49 | -26 |
Increase (Decrease) in Other Regulatory Assets | -372 | 113 | -172 |
Regulatory liabilities | -133 | 56 | 62 |
Accounts payable | 36 | 24 | 34 |
Taxes accrued | -24 | 42 | 10 |
Increase (Decrease) in Pension and Postretirement Obligations | 133 | -217 | 89 |
Increase (Decrease) in Derivative Assets and Liabilities | 225 | -72 | 3 |
Changes in other assets | -8 | 17 | -143 |
Changes in other liabilities | 19 | 108 | 37 |
Net Cash Provided from Operating Activities | 730 | 1,050 | 839 |
Cash Flows From Investing Activities | |||
Property additions and construction expenditures | -1,092 | -1,106 | -1,077 |
Proceeds from investments (including derivative collateral posted) | 347 | 222 | 472 |
Purchase of investments (including derivative collateral posted) | -475 | -176 | -414 |
Payments upon interest rate contract settlement | -95 | -49 | -51 |
Payments for (Proceeds from) Hedge, Investing Activities | 0 | 163 | 14 |
Net Cash Used for Investing Activities | -1,315 | -946 | -1,056 |
Cash Flows from Financing Activities | |||
Proceeds from Issuance of Common Stock | 98 | 295 | 97 |
Proceeds from issuance of long-term debt | 294 | 451 | 759 |
Repayments of Long-term Debt | -54 | -258 | -309 |
Dividends | -294 | -281 | -257 |
Short-term borrowings, net | 542 | -247 | -30 |
Net Cash Provided From Financing Activities | 586 | -40 | 260 |
Net (Decrease) Increase in Cash and Cash Equivalents | 1 | 64 | 43 |
Cash and Cash Equivalents, January 1 | 136 | 72 | 29 |
Cash and Cash Equivalents, December 31 | 137 | 136 | 72 |
Supplemental Cash Flow Information | |||
Cash paid for-Interest (net of capitalized interest ) | 301 | 288 | 281 |
Cash paid for-Income taxes | 299 | 104 | 107 |
Cash Flow, Noncash Investing and Financing Activities Disclosure | |||
Accrued construction expenditures | 180 | 111 | 124 |
Capital Lease Obligations Incurred | 5 | 6 | 8 |
Noncash or Part Noncash Acquisition, Fixed Assets Acquired | 98 | ||
SCE&G | |||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 458 | 391 | 352 |
Adjustments to reconcile net income to net cash provided from operating activities: | |||
Income (Loss) from Equity Method Investments | 5 | 3 | 4 |
Deferred income taxes, net | 187 | 29 | 116 |
Depreciation and amortization | 318 | 315 | 294 |
Amortization of nuclear fuel | 45 | 57 | 44 |
Allowance for equity funds used during construction | -28 | -25 | -21 |
Carrying cost recovery | -9 | -2.9 | 0 |
Cash provided (used) by changes in certain assets and liabilities: | |||
Receivables | -39 | -36 | 35 |
Inventories | -52 | 35 | -60 |
Increase (Decrease) in Prepaid Expense | 89 | -8 | -6 |
Increase (Decrease) in Other Regulatory Assets | -350 | 83 | -158 |
Regulatory liabilities | -132 | 54 | 64 |
Accounts payable | 14 | 5 | 27 |
Taxes accrued | -53 | 72 | 1 |
Increase (Decrease) in Pension and Postretirement Obligations | 106 | -186 | 69 |
Increase (Decrease) in Derivative Assets and Liabilities | 207 | -65 | 64 |
Changes in other assets | 12 | 27 | -154 |
Changes in other liabilities | 41 | 88 | -9 |
Net Cash Provided from Operating Activities | 641 | 852 | 674 |
Cash Flows From Investing Activities | |||
Property additions and construction expenditures | -934 | -1,003 | -978 |
Proceeds from investments (including derivative collateral posted) | 275 | 144 | 275 |
Purchase of investments (including derivative collateral posted) | -381 | -116 | -268 |
Payments upon interest rate contract settlement | -95 | -49 | 0 |
Payments for (Proceeds from) Hedge, Investing Activities | 0 | 163 | 14 |
Investment In Affiliate | -80 | 0 | 0 |
Net Cash Used for Investing Activities | -1,215 | -861 | -957 |
Cash Flows from Financing Activities | |||
Proceeds from issuance of long-term debt | 294 | 451 | 513 |
Repayments of Long-term Debt | -48 | -251 | -49 |
Dividends | -260 | -241 | -202 |
Short-term borrowings, net | 458 | -198 | -63 |
Short-term borrowings-affiliate,net | 56 | -22 | -9 |
Contributions from parent | 82 | 311 | 128 |
Net Cash Provided From Financing Activities | 582 | 50 | 318 |
Net (Decrease) Increase in Cash and Cash Equivalents | 8 | 41 | 35 |
Cash and Cash Equivalents, January 1 | 92 | 51 | 16 |
Cash and Cash Equivalents, December 31 | 100 | 92 | 51 |
Supplemental Cash Flow Information | |||
Cash paid for-Interest (net of capitalized interest ) | 210 | 200 | 186 |
Cash paid for-Income taxes | 177 | 92 | 105 |
Cash Flow, Noncash Investing and Financing Activities Disclosure | |||
Accrued construction expenditures | 151 | 100 | 116 |
Capital Lease Obligations Incurred | 5 | 4 | 8 |
Noncash or Part Noncash Acquisition, Fixed Assets Acquired | $98 |
CONSOLIDATED_STATEMENTS_OF_CAS1
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash paid for interest, capitalized interest | $16 | $14 | $11 |
SCE&G | |||
Cash paid for interest, capitalized interest | $14 | $13 | $11 |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMMON EQUITY (USD $) | 3 Months Ended | 12 Months Ended | ||||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax | ($3) | $4 | ($2) | |||
Shares, Outstanding | 143 | 141 | 143 | 141 | 132 | 130 |
Stock Issued During Period, Shares, New Issues | 2 | 9 | 2 | |||
Common stock issued | 98 | 297 | 97 | |||
Dividends, Common Stock | -298 | -284 | -260 | |||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | -63 | -52 | -63 | -52 | -70 | -81 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | -12 | -8 | -12 | -8 | -16 | -13 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -75 | -60 | -75 | -60 | -86 | -94 |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | -11 | 18 | 11 | |||
Other Comprehensive Income (Loss), Net of Tax | -15 | 26 | 8 | |||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | -14 | 7 | -8 | |||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | -5 | 7 | -4 | |||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 3 | 11 | 19 | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax | 1 | 1 | 1 | |||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 523 | 497 | 428 | |||
Retained Earnings, Unappropriated | 2,684 | 2,444 | 2,684 | 2,444 | 2,257 | 2,097 |
Common Stock, Value, Outstanding | 2,378 | 2,280 | 2,378 | 2,280 | 1,983 | 1,886 |
Income Available to Common Shareholders | 105 | 104 | 538 | 471 | 420 | |
Dividends Declared Per Share of Common Stock (in dollars per share) | $2.10 | $2.03 | $1.98 | |||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), Tax | 0 | 0 | 0 | |||
Genco | ||||||
Stockholders' Equity Attributable to Noncontrolling Interest | 123 | 117 | 123 | 117 | 114 | 108 |
Net Income (Loss) Attributable to Noncontrolling Interest | 12 | 11 | 11 | |||
Contributions from parent | -1 | 1 | ||||
Dividends | 7 | 7 | 7 | |||
SCE&G | ||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 | -3 | -3 | ||
Stockholders' Equity Attributable to Noncontrolling Interest | 123 | 117 | 123 | 117 | ||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,757 | 4,489 | 4,757 | 4,489 | 4,043 | 3,773 |
Net Income (Loss) Attributable to Noncontrolling Interest | 12 | 11 | 11 | |||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 76 | 72 | 458 | 391 | 352 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent | 0 | 1 | -1 | |||
Contributions from parent | 82 | 311 | 128 | |||
Dividends | -272 | -257 | -209 | |||
Other Comprehensive Income (Loss), Net of Tax | 0 | 1 | -1 | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Reclassified During Period, Net of Tax | 0 | 1 | -1 | |||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 458 | 392 | 351 | |||
Retained Earnings, Unappropriated | 2,077 | 1,896 | 2,077 | 1,896 | ||
Common Stock, Value, Outstanding | 2,560 | 2,479 | 2,560 | 2,479 | ||
SCEG excluding VIEs [Member] | ||||||
Shares, Outstanding | 40 | 40 | 40 | 40 | 40 | 40 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 | -3 | -3 | -4 | -3 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent | 0 | 1 | -1 | |||
Contributions from parent | 81 | 312 | 126 | |||
Dividends | 265 | 250 | 202 | |||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 446 | 381 | 340 | |||
Retained Earnings, Unappropriated | 1,896 | 1,896 | 1,766 | 1,627 | ||
Common Stock, Value, Outstanding | 2,479 | 2,479 | 2,167 | 2,041 | ||
Income Available to Common Shareholders | $446 | $380 | $341 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Significant Accounting Policies [Text Block] | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||||||
Organization and Principles of Consolidation | |||||||||||||||||
SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina. | |||||||||||||||||
The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries. | |||||||||||||||||
Regulated businesses | Nonregulated businesses | ||||||||||||||||
South Carolina Electric & Gas Company | SCANA Energy Marketing, Inc. | ||||||||||||||||
South Carolina Fuel Company, Inc. | SCANA Communications, Inc. | ||||||||||||||||
South Carolina Generating Company, Inc. | ServiceCare, Inc. | ||||||||||||||||
Public Service Company of North Carolina, Incorporated | SCANA Services, Inc. | ||||||||||||||||
Carolina Gas Transmission Corporation | SCANA Corporate Security Services, Inc. | ||||||||||||||||
CGT and SCI were sold in the first quarter of 2015. Accordingly, the assets and liabilities of these entities are aggregated and shown as Assets held for sale and Liabilities held for sale in the December 31, 2014 consolidated balance sheet. See Note 13. | |||||||||||||||||
The Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. | |||||||||||||||||
Use of Estimates | |||||||||||||||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Utility Plant | |||||||||||||||||
Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. | |||||||||||||||||
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.2% for 2014, 6.9% for 2013 and 6.3% for 2012. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. | |||||||||||||||||
The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows: | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
SCE&G | 2.85 | % | 2.96 | % | 2.93 | % | |||||||||||
GENCO | 2.66 | % | 2.66 | % | 2.66 | % | |||||||||||
CGT | 2.11 | % | 2.19 | % | 2.09 | % | |||||||||||
PSNC Energy | 2.98 | % | 3.01 | % | 3.01 | % | |||||||||||
Weighted average of above | 2.84 | % | 2.93 | % | 2.9 | % | |||||||||||
SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. | |||||||||||||||||
Jointly Owned Utility Plant | |||||||||||||||||
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion | |||||
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. | |||||||||||||||||
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $88.9 million at December 31, 2014 and $75.6 million at December 31, 2013. | |||||||||||||||||
Plant to be Retired | |||||||||||||||||
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |||||||||||||||||
Major Maintenance | |||||||||||||||||
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued to regulatory assets in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the consolidated balance sheet (see Note 2). Other planned major maintenance is expensed when incurred. | |||||||||||||||||
Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2014 and 2013, SCE&G incurred $19.4 million and $18.1 million, respectively, for turbine maintenance. | |||||||||||||||||
Nuclear refueling outages are scheduled 18 months apart. SCE&G accrued $1.2 million per month from July 2011 through December 2012 for its portion of the outages in the fall of 2012. Total costs for the 2012 outage were $32.3 million, of which SCE&G was responsible for $21.5 million. In connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began to accrue $1.4 million per month for its portion of the nuclear refueling outages that are scheduled to occur from the spring of 2014 through the spring of 2020. Total costs for the 2014 outage were $43.7 million, of which SCE&G was responsible for $29.1 million. | |||||||||||||||||
Goodwill | |||||||||||||||||
The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill. At December 31, 2014 and 2013, assets with a carrying value of $210 million (net of writedown of $230 million) for PSNC Energy (Gas Distribution segment) were classified as goodwill. Assets with a carrying value of $20 million for CGT (All Other segment) were classified as assets held for sale as of December 31, 2014 and as goodwill as of December 31, 2013. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is generally a two-step quantitative process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Accounting guidance adopted by the Company gives it the option to first perform a qualitative assessment of impairment. Based on this qualitative ("step zero") assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with the two-step quantitative assessment. | |||||||||||||||||
In evaluations of PSNC Energy, fair value was estimated using the assistance of an independent appraisal. In evaluations of CGT, estimated fair value was obtained from discounted cash flow and other analysis as of January 1, 2014. In all evaluations for the periods presented, step one has indicated no impairment. The estimated fair values of the reporting units are substantially in excess of their carrying values, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense. | |||||||||||||||||
Nuclear Decommissioning | |||||||||||||||||
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million, stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. | |||||||||||||||||
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2014, 2013 and 2012) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis. | |||||||||||||||||
Cash and Cash Equivalents | |||||||||||||||||
The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills. | |||||||||||||||||
Accounts Receivable | |||||||||||||||||
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. | |||||||||||||||||
Inventory | |||||||||||||||||
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC. | |||||||||||||||||
Asset Management and Supply Service Agreements | |||||||||||||||||
PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. Such counterparties held 48% and 48% of PSNC Energy’s natural gas inventory at December 31, 2014 and December 31, 2013, respectively, with a carrying value of $26.1 million and $22.8 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire March 31, 2015. | |||||||||||||||||
Income Taxes | |||||||||||||||||
The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. | |||||||||||||||||
Regulatory Assets and Regulatory Liabilities | |||||||||||||||||
The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs in the ratemaking process. | |||||||||||||||||
Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt | |||||||||||||||||
The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. | |||||||||||||||||
Environmental | |||||||||||||||||
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. | |||||||||||||||||
Income Statement Presentation | |||||||||||||||||
The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). | |||||||||||||||||
Revenue Recognition | |||||||||||||||||
The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $186.4 million at December 31, 2014 and $183.1 million at December 31, 2013. | |||||||||||||||||
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent hearings. | |||||||||||||||||
SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. | |||||||||||||||||
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a pilot basis for its electric customers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC. See Note 2. | |||||||||||||||||
PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. | |||||||||||||||||
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. | |||||||||||||||||
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 Company has issued no securities that would have an antidilutive effect on earnings per share. | |||||||||||||||||
A reconciliation of the weighted average number of common shares for each of the three years ended December 31, for basic and diluted purposes is as follows: | |||||||||||||||||
In Millions | 2014 | 2013 | 2012 | ||||||||||||||
Weighted Average Shares Outstanding—Basic | 141.9 | 138.7 | 131.1 | ||||||||||||||
Net effect of equity forward contracts | — | 0.4 | 2.2 | ||||||||||||||
Weighted Average Shares Outstanding—Diluted | 141.9 | 139.1 | 133.3 | ||||||||||||||
New Accounting Matters | |||||||||||||||||
In April 2014, the Financial Accounting Standards Board issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this new guidance for the period ended December 31, 2014. | |||||||||||||||||
In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position. | |||||||||||||||||
SCE&G | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Significant Accounting Policies [Text Block] | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||||||
Organization and Principles of Consolidation | |||||||||||||||||
SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. | |||||||||||||||||
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), and accordingly, the accompanying 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. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. | |||||||||||||||||
GENCO owns a coal-fired electric generating station with a 605 megawatt 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 $472 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4. | |||||||||||||||||
Use of Estimates | |||||||||||||||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Utility Plant | |||||||||||||||||
Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. | |||||||||||||||||
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. Consolidated SCE&G calculated AFC using average composite rates of 6.5% for 2014, 6.9% for 2013 | |||||||||||||||||
and 6.3% for 2012. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. | |||||||||||||||||
Consolidated SCE&G records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.84% in 2014, 2.94% in 2013 and 2.91% in 2012. | |||||||||||||||||
SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. | |||||||||||||||||
Jointly Owned Utility Plant | |||||||||||||||||
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G's share of the direct expenses is included in the corresponding operating expenses on its income statement. | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion | |||||
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. | |||||||||||||||||
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $88.9 million at December 31, 2014 and $75.6 million at December 31, 2013. | |||||||||||||||||
Plant to be Retired | |||||||||||||||||
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |||||||||||||||||
Major Maintenance | |||||||||||||||||
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued to regulatory assets in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the balance sheet (see Note 2). Other planned major maintenance is expensed when incurred. | |||||||||||||||||
Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2014 and 2013, SCE&G incurred $19.4 million and $18.1 million, respectively, for turbine maintenance. | |||||||||||||||||
Nuclear refueling outages are scheduled 18 months apart. SCE&G accrued $1.2 million per month from July 2011 through December 2012 for its portion of the outages in the fall of 2012. Total costs for the 2012 outage were $32.3 million, of which SCE&G was responsible for $21.5 million. In connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began to accrue $1.4 million per month for its portion of the nuclear refueling outages that are scheduled to occur from the spring of 2014 through the spring of 2020. Total costs for the 2014 outage were $43.7 million, of which SCE&G was responsible for $29.1 million. | |||||||||||||||||
Nuclear Decommissioning | |||||||||||||||||
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million, stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. | |||||||||||||||||
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2014, 2013 and 2012) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis. | |||||||||||||||||
Cash and Cash Equivalents | |||||||||||||||||
Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills. | |||||||||||||||||
Accounts Receivable | |||||||||||||||||
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. | |||||||||||||||||
Inventory | |||||||||||||||||
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC. | |||||||||||||||||
Income Taxes | |||||||||||||||||
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. | |||||||||||||||||
Regulatory Assets and Regulatory Liabilities | |||||||||||||||||
Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs in the ratemaking process. | |||||||||||||||||
Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt | |||||||||||||||||
Consolidated SCE&G records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. | |||||||||||||||||
Environmental | |||||||||||||||||
SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. | |||||||||||||||||
Income Statement Presentation | |||||||||||||||||
Consolidated SCE&G presents the revenues and expenses of its regulated activities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). | |||||||||||||||||
Revenue Recognition | |||||||||||||||||
Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $115.8 million at December 31, 2014 and $111.9 million at December 31, 2013. | |||||||||||||||||
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent hearings. | |||||||||||||||||
Customers subject to the PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. | |||||||||||||||||
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a pilot basis for its electric customers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC. See Note 2. | |||||||||||||||||
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. | |||||||||||||||||
New Accounting Matters | |||||||||||||||||
In April 2014, the Financial Accounting Standards Board issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, Consolidated SCE&G adopted this new guidance for the period ended December 31, 2014. | |||||||||||||||||
In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Consolidated SCE&G will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted. Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position. |
RATE_AND_OTHER_REGULATORY_MATT
RATE AND OTHER REGULATORY MATTERS | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Rate Matters [Line Items] | ||||||||||
Schedule of Regulatory Assets and Liabilities [Text Block] | RATE AND OTHER REGULATORY MATTERS | |||||||||
Rate Matters | ||||||||||
Electric - Cost of Fuel | ||||||||||
SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased. In connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of base fuel costs, and approved SCE&G's total fuel cost component. | ||||||||||
Pursuant to a November 2013 SCPSC accounting order, the Company's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. See also Note 6. | ||||||||||
By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, the Company's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. See also Note 6. | ||||||||||
The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The SCPSC will consider the impact of this action in future cost of fuel rate proceedings. | ||||||||||
In October 2014, the SCPSC initiated its 2015 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 9, 2015. In connection with its January 2015 DSM Programs filing (see Electric-Base Rates herein), SCE&G notified the SCPSC that it anticipates proposing an adjustment to SCE&G's cost of fuel that, if approved, will result in an overall decrease to its base fuel costs beginning with the first billing cycle of May 2015. | ||||||||||
Electric - Base Rates | ||||||||||
In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) 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 borrowing rate, and $5.8 million and $2.9 million of such carrying costs were accrued within other income during 2014 and 2013, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these 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. | ||||||||||
In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed. | ||||||||||
Prior to 2014, certain of SCE&G's electric rates included an adjustment for eWNA. The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition. In connection with the termination of the eWNA effective December 31, 2013, and pursuant to an SCPSC order, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. This revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the settlement of certain interest rate derivatives, which gains had been deferred as a regulatory liability. | ||||||||||
SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. | ||||||||||
SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenues associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below: | ||||||||||
Year | Effective | Amount | ||||||||
2014 | First billing cycle of May | $15.4 million | ||||||||
2013 | First billing cycle of May | $16.9 million | ||||||||
2012 | First billing cycle of May | $19.6 million | ||||||||
Other activity related to SCE&G’s DSM Programs is as follows: | ||||||||||
• | In May 2013, the SCPSC ordered the deferral of one-half of the net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | |||||||||
• | In April 2014, the SCPSC approved SCE&G's request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost revenues component of SCE&G's DSM Program rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. | |||||||||
• | In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year. | |||||||||
• | In January 2015, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved, the filing would, among other things, allow recovery of $33.0 million of costs and net lost revenues associated with the DSM Programs, along with an incentive to invest in such programs. | |||||||||
Electric - BLRA | ||||||||||
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 the March 30, 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 pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. In December 2012, the SCPSC denied separate petitions filed by two parties requesting reconsideration of its order. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | ||||||||||
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: | ||||||||||
Year | Increase | Amount | ||||||||
2014 | 2.80% | $66.2 million | ||||||||
2013 | 2.90% | $67.2 million | ||||||||
2012 | 2.30% | $52.1 million | ||||||||
Gas | ||||||||||
SCE&G | ||||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: | ||||||||||
Year | Action | Amount | ||||||||
2014 | 0.6 | % | Decrease | $2.6 million | ||||||
2013 | No change | |||||||||
2012 | 2.1 | % | Increase | $7.5 million | ||||||
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2014 and 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each review period were reasonable and prudent. | ||||||||||
PSNC Energy | ||||||||||
PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales. | ||||||||||
PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. | ||||||||||
In September 2014, in connection with PSNC Energy's 2014 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2014. | ||||||||||
In 2013, the State of North Carolina passed legislation that changed statutes covering income taxes, among other things. In December 2013, the NCUC issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility's cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014. On May 13, 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate and to file a proposal to refund amounts collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and notwithstanding a subsequent reversal of the NCUC's order, PSNC Energy expects to refund amounts collected on a provisional basis through the normal operation of its Rider D rate mechanism. At December 31, 2014, these amounts were not significant. | ||||||||||
Regulatory Assets and Regulatory Liabilities | ||||||||||
The Company's cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has 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. | ||||||||||
December 31, | ||||||||||
Millions of dollars | 2014 | 2013 | ||||||||
Regulatory Assets: | ||||||||||
Accumulated deferred income taxes | $ | 284 | $ | 259 | ||||||
Under-collections—electric fuel adjustment clause | 20 | 18 | ||||||||
Environmental remediation costs | 40 | 41 | ||||||||
AROs and related funding | 366 | 368 | ||||||||
Franchise agreements | 26 | 31 | ||||||||
Deferred employee benefit plan costs | 350 | 238 | ||||||||
Planned major maintenance | 2 | — | ||||||||
Deferred losses on interest rate derivatives | 453 | 124 | ||||||||
Deferred pollution control costs | 36 | 37 | ||||||||
Unrecovered plant | 137 | 145 | ||||||||
DSM Programs | 56 | 51 | ||||||||
Other | 53 | 48 | ||||||||
Total Regulatory Assets | $ | 1,823 | $ | 1,360 | ||||||
Regulatory Liabilities: | ||||||||||
Accumulated deferred income taxes | $ | 22 | $ | 24 | ||||||
Asset removal costs | 703 | 695 | ||||||||
Storm damage reserve | 6 | 27 | ||||||||
Monetization of bankruptcy claim | — | 29 | ||||||||
Deferred gains on interest rate derivatives | 82 | 181 | ||||||||
Planned major maintenance | — | 10 | ||||||||
Other | 1 | — | ||||||||
Total Regulatory Liabilities | $ | 814 | $ | 966 | ||||||
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 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | ||||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. | ||||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 25 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 90 years. | ||||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2020. | ||||||||||
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent 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. | ||||||||||
Planned major maintenance related to certain fossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil-fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges. | ||||||||||
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 2038. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed above at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost revenues related to DSM Programs. | ||||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. | ||||||||||
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. | ||||||||||
DSM Programs represent deferred costs associated with such programs. As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider. See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs. | ||||||||||
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 non-legal obligation to remove assets in the future. | ||||||||||
The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. In 2014, $16.8 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed above at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost revenues related to DSM Programs. | ||||||||||
The monetization of bankruptcy claim represented proceeds from the sale of a bankruptcy claim which was being amortized into operating revenue through February 2024. The balance at December 31, 2014 has been reclassified to Liabilities held for sale (see Note 13). | ||||||||||
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 received by the Company. 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 could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. | ||||||||||
SCE&G | ||||||||||
Rate Matters [Line Items] | ||||||||||
Schedule of Regulatory Assets and Liabilities [Text Block] | RATE AND OTHER REGULATORY MATTERS | |||||||||
Electric - Cost of Fuel | ||||||||||
SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased. In connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of base fuel costs, and approved SCE&G's total fuel cost component. | ||||||||||
Pursuant to a November 2013 SCPSC accounting order, SCE&G's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. See also Note 6. | ||||||||||
By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, SCE&G's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. See also Note 6. | ||||||||||
The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The SCPSC will consider the impact of this action in future cost of fuel rate proceedings. | ||||||||||
In October 2014, the SCPSC initiated its 2015 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 9, 2015. In connection with its January 2015 DSM Programs filing (see Electric-Base Rates herein), SCE&G notified the SCPSC that it anticipates proposing an adjustment to SCE&G's cost of fuel that, if approved, will result in an overall decrease to its base fuel costs beginning with the first billing cycle of May 2015. | ||||||||||
Electric - Base Rates | ||||||||||
In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) 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 borrowing rate, and $5.8 million and $2.9 million of such carrying costs were accrued within other income during 2014 and 2013, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these 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. | ||||||||||
In December 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates, a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed. | ||||||||||
Prior to 2014, certain of SCE&G's electric rates included an adjustment for eWNA. The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition. In connection with the termination of the eWNA effective December 31, 2013, and pursuant to an SCPSC order, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. This revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the settlement of certain interest rate derivatives, which gains had been deferred as a regulatory liability. | ||||||||||
SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. | ||||||||||
SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenues associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below: | ||||||||||
Year | Effective | Amount | ||||||||
2014 | First billing cycle of May | $15.4 million | ||||||||
2013 | First billing cycle of May | $16.9 million | ||||||||
2012 | First billing cycle of May | $19.6 million | ||||||||
Other activity related to SCE&G’s DSM Programs is as follows: | ||||||||||
• | In May 2013, the SCPSC ordered the deferral of one-half of the net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | |||||||||
• | In April 2014, the SCPSC approved SCE&G's request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost revenues component of SCE&G's DSM Program rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described. | |||||||||
• | In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year. | |||||||||
• | In January 2015, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved, the filing would, among other things, allow recovery of $33.0 million of costs and net lost revenues associated with the DSM Programs, along with an incentive to invest in such programs. | |||||||||
Electric - BLRA | ||||||||||
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 the March 30, 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 pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. In December 2012, the SCPSC denied separate petitions filed by two parties requesting reconsideration of its order. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | ||||||||||
Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G's updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: | ||||||||||
Year | Increase | Amount | ||||||||
2014 | 2.80% | $66.2 million | ||||||||
2013 | 2.90% | $67.2 million | ||||||||
2012 | 2.30% | $52.1 million | ||||||||
Gas | ||||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: | ||||||||||
Year | Action | Amount | ||||||||
2014 | 0.6 | % | Decrease | $ | 2.6 | million | ||||
2013 | No change | |||||||||
2012 | 2.1 | % | Increase | $ | 7.5 | million | ||||
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2014 and 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each review period were reasonable and prudent. | ||||||||||
Regulatory Assets and Regulatory Liabilities | ||||||||||
Consolidated SCE&G has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, Consolidated SCE&G has 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. | ||||||||||
December 31, | ||||||||||
Millions of dollars | 2014 | 2013 | ||||||||
Regulatory Assets: | ||||||||||
Accumulated deferred income taxes | $ | 278 | $ | 256 | ||||||
Under-collections-electric fuel adjustment clause | 20 | 18 | ||||||||
Environmental remediation costs | 36 | 37 | ||||||||
AROs and related funding | 347 | 350 | ||||||||
Franchise agreements | 26 | 31 | ||||||||
Deferred employee benefit plan costs | 310 | 215 | ||||||||
Planned major maintenance | 2 | — | ||||||||
Deferred losses on interest rate derivatives | 453 | 124 | ||||||||
Deferred pollution control costs | 36 | 37 | ||||||||
Unrecovered plant | 137 | 145 | ||||||||
DSM Programs | 56 | 51 | ||||||||
Other | 44 | 39 | ||||||||
Total Regulatory Assets | $ | 1,745 | $ | 1,303 | ||||||
Regulatory Liabilities: | ||||||||||
Accumulated deferred income taxes | $ | 17 | $ | 19 | ||||||
Asset removal costs | 505 | 495 | ||||||||
Storm damage reserve | 6 | 27 | ||||||||
Deferred gains on interest rate derivatives | 82 | 181 | ||||||||
Planned major maintenance | — | 10 | ||||||||
Total Regulatory Liabilities | $ | 610 | $ | 732 | ||||||
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 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | ||||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. | ||||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 25 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 90 years. | ||||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2020. | ||||||||||
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent 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. | ||||||||||
Planned major maintenance related to certain fossil-fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil-fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges. | ||||||||||
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 2038. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed above at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost revenues related to DSM Programs. | ||||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. | ||||||||||
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. | ||||||||||
DSM Programs represent deferred costs associated with such programs. As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider. See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs. | ||||||||||
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 non-legal obligation to remove assets in the future. | ||||||||||
The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. In 2014, $16.8 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed above at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost revenues related to DSM Programs. | ||||||||||
The SCPSC 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 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 received by SCE&G. 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, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded. |
COMMON_EQUITY
COMMON EQUITY | 12 Months Ended |
Dec. 31, 2014 | |
Schedule of Capitalization, Equity [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | COMMON EQUITY |
The Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture and PSNC Energy’s note purchase and debenture purchase agreements each contain provisions that, under certain circumstances, which the Company considers to be remote, could limit the payment of cash dividends on their respective common stock. | |
The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2014 and 2013, retained earnings of approximately $67.7 million and $63.1 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock. | |
Authorized shares of common stock were 200 million as of December 31, 2014 and 2013. | |
SCANA issued common stock valued at $99.3 million, $100.9 million and $97.7 million (when issued) during the years ended December 31, 2014, 2013 and 2012, respectively, to satisfy the requirements of various compensation and dividend reinvestment plans. In addition, in March 2013, SCANA settled all forward sales contracts related to its common stock through the issuance of approximately 6.6 million common shares, resulting in net proceeds of approximately $196.2 million. | |
SCE&G | |
Schedule of Capitalization, Equity [Line Items] | |
Stockholders' Equity Note Disclosure [Text Block] | EQUITY |
Authorized shares of SCE&G common stock were 50 million as of December 31, 2014 and 2013. Authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA as of December 31, 2014 and 2013. | |
SCE&G’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, SCE&G’s bond indenture contains provisions that, under certain circumstances, which SCE&G considers to be remote, could limit the payment of cash dividends on its common stock. | |
The Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At December 31, 2014 and 2013, retained earnings of approximately $67.7 million and $63.1 million, respectively, were restricted by this requirement as to payment of cash dividends on common stock. |
LONGTERM_AND_SHORTTERM_DEBT
LONG-TERM AND SHORT-TERM DEBT | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt Disclosure [Text Block] | LONG-TERM AND SHORT-TERM DEBT | ||||||||||||||||||||||||
Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Dollars in millions | Maturity | Balance | Rate | Balance | Rate | ||||||||||||||||||||
Medium Term Notes (unsecured) | 2020 | - | 2022 | $ | 800 | 5.42 | % | $ | 800 | 5.42 | % | ||||||||||||||
Senior Notes (unsecured) (a) | 2015 | - | 2034 | 88 | 0.93 | % | 92 | 0.94 | % | ||||||||||||||||
First Mortgage Bonds (secured) | 2018 | - | 2064 | 3,840 | 5.56 | % | 3,540 | 5.6 | % | ||||||||||||||||
Junior Subordinated Notes (unsecured) (b) | 2065 | 150 | 7.92 | % | 150 | 7.92 | % | ||||||||||||||||||
GENCO Notes (secured) | 2015 | - | 2024 | 227 | 5.9 | % | 233 | 5.89 | % | ||||||||||||||||
Industrial and Pollution Control Bonds (c) | 2028 | - | 2038 | 122 | 3.51 | % | 158 | 3.83 | % | ||||||||||||||||
Senior Debentures | 2020 | - | 2026 | 350 | 5.93 | % | 350 | 5.93 | % | ||||||||||||||||
Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | 100 | 0.78 | % | ||||||||||||||||||
Other | 2015 | - | 2027 | 17 | 2.9 | % | 20 | 2.73 | % | ||||||||||||||||
Total debt | 5,694 | 5,443 | |||||||||||||||||||||||
Current maturities of long-term debt | (166 | ) | (54 | ) | |||||||||||||||||||||
Unamortized premium | 3 | 6 | |||||||||||||||||||||||
Total long-term debt, net | $ | 5,531 | $ | 5,395 | |||||||||||||||||||||
(a) Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17%) | |||||||||||||||||||||||||
(b) Redeemed at par prior to maturity on February 2, 2015, and included in the current portion of long-term debt on the balance sheet at December 31, 2014. | |||||||||||||||||||||||||
(c) Includes variable rate debt of $67.8 million at December 31, 2014 (rate of 0.04%) and 2013 (rate of 0.11%) which are hedged by fixed swaps. | |||||||||||||||||||||||||
The annual amounts of long-term debt maturities for the next five years are summarized as follows: | |||||||||||||||||||||||||
Year | Millions | ||||||||||||||||||||||||
of dollars | |||||||||||||||||||||||||
2015 | $ | 166 | |||||||||||||||||||||||
2016 | 115 | ||||||||||||||||||||||||
2017 | 14 | ||||||||||||||||||||||||
2018 | 723 | ||||||||||||||||||||||||
2019 | 13 | ||||||||||||||||||||||||
Substantially all of SCE&G's and GENCO's electric utility plant is pledged as collateral in connection with long-term debt. | |||||||||||||||||||||||||
SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2014, the Bond Ratio was 5.41. | |||||||||||||||||||||||||
Lines of Credit and Short-Term Borrowings | |||||||||||||||||||||||||
At December 31, 2014 and 2013, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: | |||||||||||||||||||||||||
SCANA | SCE&G | PSNC Energy | |||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
Lines of Credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | 300 | 1,400 | 1,400 | 100 | 100 | ||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 179 | $ | 125 | $ | 709 | $ | 251 | $ | 30 | — | ||||||||||||||
Weighted average interest rate | 0.54 | % | 0.39 | % | 0.52 | % | 0.27 | % | 0.65 | % | — | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 118 | $ | 172 | $ | 691 | $ | 1,149 | $ | 70 | $ | 100 | |||||||||||||
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million, respectively. In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. These 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. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.8 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9%, and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. | |||||||||||||||||||||||||
On January 29, 2015, SCANA entered into an unsecured, three-month credit agreement in the amount of $150 million. SCANA entered this agreement to ensure sufficient liquidity was available to redeem its junior subordinated notes on February 2, 2015. No borrowings were made under this agreement, and it expired according to its terms on February 6, 2015. | |||||||||||||||||||||||||
The Company 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. The letters of credit expire, subject to renewal, in the fourth quarter of 2019. | |||||||||||||||||||||||||
The Company pays fees to the banks as compensation for maintaining committed lines of credit. Such fees were not material in any period presented. | |||||||||||||||||||||||||
SCE&G | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt Disclosure [Text Block] | LONG-TERM AND SHORT-TERM DEBT | ||||||||||||||||||||||||
Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows: | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Dollars in millions | Maturity | Balance | Rate | Balance | Rate | ||||||||||||||||||||
First Mortgage Bonds (secured) | 2018 | - | 2064 | $ | 3,840 | 5.56 | % | $ | 3,540 | 5.6 | % | ||||||||||||||
GENCO Notes (secured) | 2015 | - | 2024 | 227 | 5.9 | % | 233 | 5.89 | % | ||||||||||||||||
Industrial and Pollution Control Bonds (a) | 2028 | - | 2038 | 122 | 3.51 | % | 158 | 3.83 | % | ||||||||||||||||
Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | 100 | 0.78 | % | ||||||||||||||||||
Other | 2015 | - | 2027 | 14 | 2.63 | % | 16 | 2.26 | % | ||||||||||||||||
Total debt | 4,303 | 4,047 | |||||||||||||||||||||||
Current maturities of long-term debt | (10 | ) | (48 | ) | |||||||||||||||||||||
Unamortized premium | 6 | 8 | |||||||||||||||||||||||
Total long-term debt, net | $ | 4,299 | $ | 4,007 | |||||||||||||||||||||
(a) Includes variable rate debt of $67.8 million at December 31, 2014 (rate of 0.04%) and 2013 (rate of 0.11%), which are hedged by fixed swaps. | |||||||||||||||||||||||||
The annual amounts of long-term debt maturities for the next five years are summarized as follows: | |||||||||||||||||||||||||
Year | Millions of dollars | ||||||||||||||||||||||||
2015 | $ | 10 | |||||||||||||||||||||||
2016 | 109 | ||||||||||||||||||||||||
2017 | 9 | ||||||||||||||||||||||||
2018 | 719 | ||||||||||||||||||||||||
2019 | 8 | ||||||||||||||||||||||||
Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. | |||||||||||||||||||||||||
SCE&G is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be outstanding (Bond Ratio). For the year ended December 31, 2014, the Bond Ratio was 5.41. | |||||||||||||||||||||||||
Lines of Credit and Short-Term Borrowings | |||||||||||||||||||||||||
At December 31, 2014 and 2013, SCE&G (including Fuel Company) had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings: | |||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 709 | $ | 251 | |||||||||||||||||||||
Weighted average interest rate | 0.52 | % | 0.27 | % | |||||||||||||||||||||
Letters of credit supported by an LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 691 | $ | 1,149 | |||||||||||||||||||||
SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company). In addition, SCE&G is party to a three-year credit agreement in the amount of $200 million. In October 2014, the term of the five-year agreements was extended by one year, such that they expire in October 2019. The three-year agreement expires in October 2016. These 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. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%. Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. | |||||||||||||||||||||||||
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 pays fees to the banks as compensation for maintaining committed lines of credit. Such fees were not material in any period presented. | |||||||||||||||||||||||||
Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries 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 December 31, 2014 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83 million and money pool investments due from an affiliate of $80 million. At December 31, 2013 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $27.3 million. On the consolidated 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 | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
income tax [Line Items] | |||||||||||||
Income Tax Disclosure [Text Block] | INCOME TAXES | ||||||||||||
Components of income tax expense are as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Current taxes: | |||||||||||||
Federal | $ | 38 | $ | 161 | $ | 103 | |||||||
State | (4 | ) | 17 | 10 | |||||||||
Total current taxes | 34 | 178 | 113 | ||||||||||
Deferred taxes, net: | |||||||||||||
Federal | 184 | 39 | 72 | ||||||||||
State | 34 | 10 | 14 | ||||||||||
Total deferred taxes | 218 | 49 | 86 | ||||||||||
Investment tax credits: | |||||||||||||
Amortization of amounts deferred-state | (1 | ) | (1 | ) | (14 | ) | |||||||
Amortization of amounts deferred-federal | (3 | ) | (3 | ) | (3 | ) | |||||||
Total investment tax credits | (4 | ) | (4 | ) | (17 | ) | |||||||
Total income tax expense | $ | 248 | $ | 223 | $ | 182 | |||||||
The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Net income | $ | 538 | $ | 471 | $ | 420 | |||||||
Income tax expense | 248 | 223 | 182 | ||||||||||
Total pre-tax income | $ | 786 | $ | 694 | $ | 602 | |||||||
Income taxes on above at statutory federal income tax rate | $ | 275 | $ | 243 | $ | 211 | |||||||
Increases (decreases) attributed to: | |||||||||||||
State income taxes (less federal income tax effect) | 24 | 22 | 19 | ||||||||||
State investment tax credits (less federal income tax effect) | (5 | ) | (5 | ) | (13 | ) | |||||||
Allowance for equity funds used during construction | (11 | ) | (9 | ) | (8 | ) | |||||||
Deductible dividends—Stock Purchase Savings Plan | (10 | ) | (10 | ) | (9 | ) | |||||||
Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | |||||||
Section 41 tax credits | (3 | ) | — | — | |||||||||
Section 45 tax credits | (9 | ) | (5 | ) | (5 | ) | |||||||
Domestic production activities deduction | (7 | ) | (11 | ) | (9 | ) | |||||||
Other differences, net | (3 | ) | 1 | (1 | ) | ||||||||
Total income tax expense | $ | 248 | $ | 223 | $ | 182 | |||||||
The tax effects of significant temporary differences comprising the Company’s net deferred tax liability are as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||
Deferred tax assets: | |||||||||||||
Nondeductible accruals | $ | 127 | $ | 84 | |||||||||
Asset retirement obligation, including nuclear decommissioning | 216 | 220 | |||||||||||
Financial instruments | 40 | 32 | |||||||||||
Unamortized investment tax credits | 17 | 19 | |||||||||||
Regulatory liability, net gain on interest rate derivative contracts settlement | — | 27 | |||||||||||
Monetization of bankruptcy claim | 10 | 11 | |||||||||||
Other | 10 | 13 | |||||||||||
Total deferred tax assets | 420 | 406 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property, plant and equipment | $ | 1,928 | $ | 1,765 | |||||||||
Deferred employee benefit plan costs | 107 | 63 | |||||||||||
Regulatory asset, asset retirement obligation | 122 | 121 | |||||||||||
Deferred fuel costs | 27 | 25 | |||||||||||
Regulatory asset, unrecovered plant | 53 | 55 | |||||||||||
Regulatory asset, net loss on interest rate derivative contracts settlement | 21 | — | |||||||||||
Demand side management costs | 21 | 21 | |||||||||||
Prepayments | 27 | 25 | |||||||||||
Other | 45 | 38 | |||||||||||
Total deferred tax liabilities | 2,351 | 2,113 | |||||||||||
Net deferred tax liability | $ | 1,931 | $ | 1,707 | |||||||||
During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015. In connection with this change in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). Related IRS revenue procedures were then issued on January 24, 2014. These regulations did not and are not expected to, have a material impact on the Company's financial position, results of operations or cash flows. | |||||||||||||
The Company files a consolidated federal income tax return, and the Company and its subsidiaries file various applicable state and local income tax returns. The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2012. With few exceptions, the Company is no longer subject to state and local income tax examinations by tax authorities for years before 2010. | |||||||||||||
Changes to Unrecognized Tax Benefits | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits, January 1 | $ | 3 | — | $ | 38 | ||||||||
Gross increases—uncertain tax positions in prior period | — | — | — | ||||||||||
Gross decreases—uncertain tax positions in prior period | — | — | (38 | ) | |||||||||
Gross increases—current period uncertain tax positions | 13 | $ | 3 | — | |||||||||
Settlements | — | — | — | ||||||||||
Lapse of statute of limitations | — | — | — | ||||||||||
Unrecognized tax benefits, December 31 | $ | 16 | $ | 3 | $ | — | |||||||
In connection with the change in method of tax accounting for certain repair costs in prior years, the Company had previously recorded an unrecognized tax benefit. During the first quarter of 2012, the publication of new administrative guidance from the IRS allowed the Company to recognize this benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Company's effective tax rate. | |||||||||||||
During 2013 and 2014, the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $16 million. If recognized, $13 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through December 31, 2014. | |||||||||||||
As of December 31, 2014, prepayments primarily relates to the late 2014 extension of the 50% bonus depreciation deduction. Further, a current deferred tax liability of $51.3 million related to the sales of CGT and SCI is included within other current liabilities. | |||||||||||||
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of the tax benefit in 2012, during 2012 the Company reversed $2 million of interest expense which had been accrued during 2011. The Company has not recorded interest expense or penalties associated with uncertain tax positions in 2013 or 2014. | |||||||||||||
SCE&G | |||||||||||||
income tax [Line Items] | |||||||||||||
Income Tax Disclosure [Text Block] | INCOME TAXES | ||||||||||||
Components of income tax expense are as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Current taxes: | |||||||||||||
Federal | $ | 39 | $ | 146 | $ | 91 | |||||||
State | (6 | ) | 13 | 8 | |||||||||
Total current taxes | 33 | 159 | 99 | ||||||||||
Deferred taxes, net: | |||||||||||||
Federal | 157 | 25 | 62 | ||||||||||
State | 32 | 9 | 12 | ||||||||||
Total deferred taxes | 189 | 34 | 74 | ||||||||||
Investment tax credits: | |||||||||||||
Amortization of amounts deferred—state | (1 | ) | (1 | ) | (13 | ) | |||||||
Amortization of amounts deferred—federal | (3 | ) | (3 | ) | (3 | ) | |||||||
Total investment tax credits | (4 | ) | (4 | ) | (16 | ) | |||||||
Total income tax expense | $ | 218 | $ | 189 | $ | 157 | |||||||
The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Net income | $ | 446 | $ | 380 | $ | 341 | |||||||
Income tax expense | 218 | 189 | 157 | ||||||||||
Noncontrolling interest | 12 | 11 | 11 | ||||||||||
Total pre-tax income | $ | 676 | $ | 580 | $ | 509 | |||||||
Income taxes on above at statutory federal income tax rate | $ | 237 | $ | 203 | $ | 178 | |||||||
Increases (decreases) attributed to: | |||||||||||||
State income taxes (less federal income tax effect) | 21 | 18 | 17 | ||||||||||
State investment tax credits (less federal income tax effect) | (5 | ) | (5 | ) | (13 | ) | |||||||
Allowance for equity funds used during construction | (10 | ) | (9 | ) | (7 | ) | |||||||
Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | |||||||
Section 41 tax credits | (3 | ) | — | — | |||||||||
Section 45 tax credits | (9 | ) | (5 | ) | (5 | ) | |||||||
Domestic production activities deduction | (7 | ) | (11 | ) | (9 | ) | |||||||
Other differences, net | (3 | ) | 1 | (1 | ) | ||||||||
Total income tax expense | $ | 218 | $ | 189 | $ | 157 | |||||||
The tax effects of significant temporary differences comprising Consolidated SCE&G’s net deferred tax liability are as follows: | |||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||
Deferred tax assets: | |||||||||||||
Nondeductible accruals | $ | 47 | $ | 17 | |||||||||
Asset retirement obligation, including nuclear decommissioning | 205 | 209 | |||||||||||
Unamortized investment tax credits | 17 | 19 | |||||||||||
Regulatory liability, net gain on interest rate derivative contracts settlement | — | 27 | |||||||||||
Other | 6 | 11 | |||||||||||
Total deferred tax assets | 275 | 283 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property, plant and equipment | $ | 1,623 | $ | 1,494 | |||||||||
Regulatory asset, asset retirement obligation | 115 | 114 | |||||||||||
Deferred employee benefit plan costs | 91 | 54 | |||||||||||
Deferred fuel costs | 27 | 26 | |||||||||||
Regulatory asset, unrecovered plant | 53 | 55 | |||||||||||
Regulatory asset, net loss on interest rate derivative contracts settlement | 21 | — | |||||||||||
Demand side management costs | 21 | 21 | |||||||||||
Prepayments | 25 | 23 | |||||||||||
Other | 23 | 18 | |||||||||||
Total deferred tax liabilities | 1,999 | 1,805 | |||||||||||
Net deferred tax liability | $ | 1,724 | $ | 1,522 | |||||||||
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA and files various applicable state and local income tax returns. The IRS has completed examinations of SCANA’s federal returns through 2004, and SCANA’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2012. With few exceptions, Consolidated SCE&G is no longer subject to state and local income tax examinations by tax authorities for years before 2010. | |||||||||||||
Changes to Unrecognized Tax Benefits | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits, January 1 | $ | 3 | — | $ | 38 | ||||||||
Gross increases-uncertain tax positions in prior period | — | — | — | ||||||||||
Gross decreases-uncertain tax positions in prior period | — | — | (38 | ) | |||||||||
Gross increases-current period uncertain tax positions | 13 | $ | 3 | — | |||||||||
Settlements | — | — | — | ||||||||||
Lapse of statute of limitations | — | — | — | ||||||||||
Unrecognized tax benefits, December 31 | $ | 16 | $ | 3 | $ | — | |||||||
In connection with the change in method of tax accounting for certain repair costs in prior years, the Company had previously recorded an unrecognized tax benefit. During the first quarter of 2012, the publication of new administrative guidance from the IRS allowed Consolidated SCE&G to recognize this benefit. Since this change was primarily a temporary difference, the recognition of this benefit did not have a significant effect on the Consolidated SCE&G's effective tax rate. | |||||||||||||
During 2013 and 2014, Consolidated SCE&G amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $16 million. If recognized, $13 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of the Consolidated SCE&G’s tax positions have occurred through December 31, 2014. | |||||||||||||
As of December 31, 2014, prepayments primarily relates to the late 2014 extension of the 50% bonus depreciation deduction. | |||||||||||||
Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. In connection with the resolution of the uncertainty and recognition of the tax benefit in 2012, during 2012 Consolidated SCE&G reversed $2 million of interest expense which had been accrued during 2011. Consolidated SCE&G has not recorded interest expense or penalties associated with uncertain tax positions in 2013 or 2014. |
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended | ||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Text Block] | DERIVATIVE FINANCIAL INSTRUMENTS | ||||||||||||||||||||||
The Company recognizes all derivative instruments as either assets or liabilities in its statements of financial position and measures those instruments at fair value. The Company recognizes changes in the fair value of derivative instruments either in earnings, as a component of other comprehensive income (loss) or, for regulated subsidiaries, 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 assumed by the Company. 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 Company’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. | |||||||||||||||||||||||
Commodity Derivatives | |||||||||||||||||||||||
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the consolidated statement of cash flows. | |||||||||||||||||||||||
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and swaps and NYMEX futures and options. PSNC Energy’s tariffs also 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 over- or under-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 | |||||||||||||||||||||||
The Company may use interest rate swaps to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which the Company synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. | |||||||||||||||||||||||
In anticipation of the issuance of debt, the Company may use treasury rate lock or forward starting swap agreements that are designated as cash flow hedges. 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 the holding company or 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 issued in 2013, interest 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. As discussed in Note 2, the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. As also discussed in Note 2, pursuant to regulatory orders issued in 2014, the SCPSC directed SCE&G to apply $46 million of these deferred gains to reduce under-collected fuel balances in April 2014. The SCPSC also approved SCE&G’s request to utilize approximately $17.8 million of these gains to offset a portion of the net lost revenues component of SCE&G’s DSM Program rider and apply $5.0 million of the gains to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets. | |||||||||||||||||||||||
Cash payments made or received upon settlement of these financial instruments are classified as investing activities for cash flow statement purposes. | |||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | |||||||||||||||||||||||
The Company was party to natural gas derivative contracts outstanding in the following quantities: | |||||||||||||||||||||||
Commodity and Other Energy Management Contracts (in MMBTU) | |||||||||||||||||||||||
Hedge designation | Gas Distribution | Retail Gas | Energy Marketing | Total | |||||||||||||||||||
Marketing | |||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Commodity | 6,840,000 | 7,951,000 | 3,446,720 | 18,237,720 | |||||||||||||||||||
Energy Management (a) | — | — | 37,495,339 | 37,495,339 | |||||||||||||||||||
Total (a) | 6,840,000 | 7,951,000 | 40,942,059 | 55,733,059 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Commodity | 6,070,000 | 6,726,000 | 2,560,000 | 15,356,000 | |||||||||||||||||||
Energy Management (b) | — | — | 27,359,958 | 27,359,958 | |||||||||||||||||||
Total (b) | 6,070,000 | 6,726,000 | 29,919,958 | 42,715,958 | |||||||||||||||||||
(a) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
(b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $124.4 million at December 31, 2014, and $128.8 million at December 31, 2013. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion and $1.3 billion at December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
The fair value of derivatives in the consolidated balance sheets is as follows: | |||||||||||||||||||||||
Fair Values of Derivative Instruments | Asset Derivatives | Liability Derivatives | |||||||||||||||||||||
Millions of dollars | Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||
Location | Value | Location | Value | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 28 | ||||||||||||||||||||||
Commodity contracts | Other current assets | 1 | |||||||||||||||||||||
Derivative financial instruments | 11 | ||||||||||||||||||||||
Total | $ | 45 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | ||||||||||||||||||||
Other deferred credits and other liabilities | 17 | ||||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | ||||||||||||||||||||
Energy management contracts | Other current assets | 15 | Other current assets | 5 | |||||||||||||||||||
Derivative financial instruments | 10 | ||||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | ||||||||||||||||||||
Total | $ | 21 | $ | 244 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 14 | ||||||||||||||||||||||
Commodity contracts | Other current assets | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 19 | |||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other current assets | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Commodity contracts | Other current assets | 2 | |||||||||||||||||||||
Energy management contracts | Other current assets | 4 | Derivative financial instruments | 4 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 42 | $ | 9 | |||||||||||||||||||
Derivatives Designated as Fair Value Hedges | |||||||||||||||||||||||
The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | |||||||||||||||||||||||
The effect of derivative instruments on the consolidated statements of income is as follows: | |||||||||||||||||||||||
Gain or (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | Location | Amount | ||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (9 | ) | Interest expense | $ | (3 | ) | ||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 106 | Interest expense | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | 84 | Interest expense | $ | (3 | ) | |||||||||||||||||
Gain or (Loss) | Gain (Loss) Reclassified from AOCI into Income, | ||||||||||||||||||||||
Recognized in OCI, net of tax | net of tax (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | Location | Amount | ||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (6 | ) | Interest expense | $ | (7 | ) | ||||||||||||||||
Commodity contracts | (8 | ) | Gas purchased for resale | 4 | |||||||||||||||||||
Total | $ | (14 | ) | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 5 | Interest expense | $ | (8 | ) | |||||||||||||||||
Commodity contracts | 2 | Gas purchased for resale | (3 | ) | |||||||||||||||||||
Total | $ | 7 | $ | (11 | ) | ||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | (4 | ) | Interest expense | $ | (6 | ) | ||||||||||||||||
Commodity contracts | (4 | ) | Gas purchased for resale | (13 | ) | ||||||||||||||||||
Total | $ | (8 | ) | $ | (19 | ) | |||||||||||||||||
As of December 31, 2014, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive loss to earnings arising from cash flow hedges will include approximately $10.0 million as an increase to gas cost and approximately $7.1 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of December 31, 2014, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2017. | |||||||||||||||||||||||
As of December 31, 2014, the Company expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense assuming financial markets remain at their current levels. | |||||||||||||||||||||||
Hedge Ineffectiveness | |||||||||||||||||||||||
Other gain (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant for all periods presented. | |||||||||||||||||||||||
Derivatives Not Designated as Hedging Instruments | |||||||||||||||||||||||
Loss Recognized in Income | Year Ended December 31, | ||||||||||||||||||||||
Millions of dollars | Location | 2014 | 2013 | 2012 | |||||||||||||||||||
Commodity contracts | Gas purchased for resale | — | — | $ | (1 | ) | |||||||||||||||||
Gain (Loss) Deferred in Regulatory Accounts | Gain Reclassified from | ||||||||||||||||||||||
Deferred Accounts into Income | |||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (352 | ) | Other income | $ | 64 | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 39 | Other income | $ | 50 | ||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | — | — | |||||||||||||||||||||
Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. | |||||||||||||||||||||||
As of December 31, 2014, the Company expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $5.2 million as an increase to other income. | |||||||||||||||||||||||
Credit Risk Considerations | |||||||||||||||||||||||
The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. The Company uses standardized master agreements which generally include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with the Company's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||||
Certain of the Company’s derivative instruments contain contingent provisions that require the Company to provide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 2014 and 2013, the Company had posted $152.4 million and $26.8 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Other Current Assets on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of December 31, 2014 and 2013, the Company would have been required to post an additional $129.8 million and $- million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2014 and 2013, are $282.2 million and $25.2 million, respectively. | |||||||||||||||||||||||
In addition, as of December 31, 2014 and December 31, 2013, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2014 and December 31, 2013, the Company could request $- million and $34.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2014 and December 31, 2013 is $- million and $34.1 million, respectively. In addition, at December 31, 2014, the Company could have called on letters of credit in the amount of $9.2 million related to $20 million in commodity derivatives that are in a net asset position, compared to letters of credit of $6 million related to derivatives of $6 million at December 31, 2013, if all the contingent features underlying these instruments had been fully triggered. | |||||||||||||||||||||||
Information related to the Company's offsetting derivative assets and liabilities follows: | |||||||||||||||||||||||
Offsetting Derivative Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Commodity | $ | 1 | — | $ | 1 | — | — | $ | 1 | ||||||||||||||
Energy Management | 20 | — | 20 | — | — | 20 | |||||||||||||||||
Total | $ | 21 | — | $ | 21 | — | — | $ | 21 | ||||||||||||||
Balance sheet location | Other current assets | $ | 16 | ||||||||||||||||||||
Other deferred debits and other assets | 5 | ||||||||||||||||||||||
Total | $ | 21 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
Energy Management | 8 | — | 8 | — | — | 8 | |||||||||||||||||
Total | $ | 44 | — | $ | 44 | $ | (1 | ) | — | $ | 43 | ||||||||||||
Balance sheet location | Other current assets | $ | 21 | ||||||||||||||||||||
Other deferred debits and other assets | 23 | ||||||||||||||||||||||
Total | $ | 44 | |||||||||||||||||||||
Offsetting Derivative Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 257 | — | $ | 257 | — | $ | (131 | ) | $ | 126 | ||||||||||||
Commodity | 12 | — | 12 | — | (10 | ) | 2 | ||||||||||||||||
Energy Management | 20 | — | 20 | — | (11 | ) | 9 | ||||||||||||||||
Total | $ | 289 | — | $ | 289 | — | $ | (152 | ) | $ | 137 | ||||||||||||
Balance sheet location | Other current assets | $ | 6 | ||||||||||||||||||||
Derivative financial instruments | 233 | ||||||||||||||||||||||
Other deferred credits and other liabilities | 50 | ||||||||||||||||||||||
Total | $ | 289 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | (19 | ) | — | |||||||||||
Energy Management | 8 | — | 8 | — | (6 | ) | $ | 2 | |||||||||||||||
Total | $ | 28 | — | $ | 28 | $ | (1 | ) | $ | (25 | ) | $ | 2 | ||||||||||
Balance sheet location | Derivative financial instruments | $ | 10 | ||||||||||||||||||||
Other deferred credits and other liabilities | 18 | ||||||||||||||||||||||
Total | $ | 28 | |||||||||||||||||||||
SCE&G | |||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Text Block] | DERIVATIVE FINANCIAL INSTRUMENTS | ||||||||||||||||||||||
Consolidated SCE&G recognizes all derivative instruments as either assets or liabilities in its statements of financial position and measures those instruments at fair value. Consolidated SCE&G recognizes changes in the fair value of derivative instruments either in earnings or 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 assumed by Consolidated SCE&G. 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, including Consolidated SCE&G. The Risk Management Committee, which is comprised of certain officers, including Consolidated SCE&G’s Risk Management Officer and 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. | |||||||||||||||||||||||
Interest Rate Swaps | |||||||||||||||||||||||
Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. | |||||||||||||||||||||||
In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements. Pursuant to regulatory orders issued in 2013, interest 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. As discussed in Note 2, the SCPSC directed SCE&G to recognize $41.6 million and $8.5 million of realized gains (which had been deferred in regulatory liabilities) within other income, fully offsetting revenue reductions related to under-collected fuel balances and under-collected amounts arising under the eWNA program which was terminated at the end of 2013. As also discussed in Note 2, pursuant to regulatory orders issued in 2014, the SCPSC directed SCE&G to apply $46 million of these deferred gains to reduce under-collected fuel balances in April 2014. The SCPSC also approved SCE&G’s request to utilize approximately $17.8 million of these gains to offset a portion of the net lost revenues component of SCE&G’s DSM Program rider and apply $5.0 million of the gains to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets. | |||||||||||||||||||||||
Cash payments made or received upon settlement of these financial instruments are classified as investing activities for cash flow statement purposes. | |||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | |||||||||||||||||||||||
Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $36.4 million and $36.4 million at December 31, 2014 and 2013, respectively. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.1 billion and $1.3 billion at December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
The fair value of derivatives in the consolidated balance sheets is as follows: | |||||||||||||||||||||||
Fair Values of Derivative Instruments | Asset Derivatives | Liability Derivatives | |||||||||||||||||||||
Millions of dollars | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair | |||||||||||||||||||
Value | |||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Other deferred credits and other liabilities | 8 | ||||||||||||||||||||||
Total | $ | 9 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | ||||||||||||||||||||
Other deferred credits and other liabilities | 17 | ||||||||||||||||||||||
Total | $ | 224 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Total | $ | 1 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other current assets | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | $ | 1 | |||||||||||||||||||
The effect of derivative instruments on the consolidated statements of income is as follows: | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Deferred | Gain (Loss) Reclassified from | |||||||||||||||||||||
in Regulatory Accounts (Effective Portion) | Deferred Accounts into Income | ||||||||||||||||||||||
(Effective Portion) | |||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (9 | ) | Interest expense | $ | (3 | ) | ||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 106 | Interest expense | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | 84 | Interest expense | $ | (3 | ) | |||||||||||||||||
As of December 31, 2014, Consolidated SCE&G expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense assuming financial markets remain at their current levels. | |||||||||||||||||||||||
Hedge Ineffectiveness | |||||||||||||||||||||||
Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant for all periods presented. | |||||||||||||||||||||||
Derivatives Not Designated as Hedging Instruments | Loss Recognized in Income | Year Ended December 31, | |||||||||||||||||||||
Millions of dollars | Location | 2014 | 2013 | 2012 | |||||||||||||||||||
Commodity contracts | Gas purchased for resale | — | — | $ | (1 | ) | |||||||||||||||||
Gain or (Loss) Deferred | Gain Reclassified from | ||||||||||||||||||||||
in Regulatory Accounts | Deferred Accounts into Income | ||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (352 | ) | Other income | $ | 64 | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | 39 | Other income | 50 | ||||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | — | Other income | — | ||||||||||||||||||||
The gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. | |||||||||||||||||||||||
As of December 31, 2014, Consolidated SCE&G expects that during the next twelve months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $5.2 million as an increase to other income. | |||||||||||||||||||||||
Credit Risk Considerations | |||||||||||||||||||||||
Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties on an ongoing basis. Consolidated SCE&G uses standardized master agreements which generally include collateral requirements. These master agreements permit the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with Consolidated SCE&G's credit policies and due diligence. In addition, collateral agreements allow for the termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||||
Certain of Consolidated SCE&G’s derivative instruments contain contingent provisions that require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit rating downgrades. As of December 31, 2014 and 2013, Consolidated SCE&G had posted $107.1 million and $1.5 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months are recorded in Other Current Assets on the consolidated balance sheets. Collateral related to the noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of December 31, 2014 and 2013, Consolidated SCE&G would have been required to post an additional $125.9 million and $- million, respectively, of collateral to its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of December 31, 2014 and 2013, are $233.0 million and $1.0 million, respectively. | |||||||||||||||||||||||
In addition, as of December 31, 2014 and December 31, 2013, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments had been fully triggered as of December 31, 2014 and December 31, 2013, Consolidated SCE&G could request $- million and $31.7 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of December 31, 2014 and December 31, 2013 is $- million and $31.7 million, respectively. | |||||||||||||||||||||||
Information related to Consolidated SCE&G's offsetting derivative assets and liabilities follows: | |||||||||||||||||||||||
Offsetting Derivative Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | — | — | — | — | — | — | |||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Balance sheet location | Other current assets | $ | 13 | ||||||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | |||||||||||||||||||||
Offsetting Derivative Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 233 | — | $ | 233 | — | $ | (107 | ) | $ | 126 | ||||||||||||
Balance sheet location | Derivative financial instruments | $ | 208 | ||||||||||||||||||||
Other deferred credits and other liabilities | 25 | ||||||||||||||||||||||
Total | $ | 233 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (1 | ) | $ | (1 | ) | $ | — | ||||||||||
Balance sheet location | Derivative financial instruments | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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 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 December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 13 | — | $ | 9 | — | |||||||||||
Interest rate contracts | — | — | — | $ | 32 | ||||||||||||
Commodity contracts | 1 | — | 2 | 2 | |||||||||||||
Energy management contracts | — | $ | 20 | 1 | 7 | ||||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 257 | — | 20 | |||||||||||||
Commodity contracts | 1 | 11 | — | — | |||||||||||||
Energy management contracts | 5 | 18 | — | 12 | |||||||||||||
There were 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. | |||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,697.20 | $ | 6,592.10 | $ | 5,449.30 | $ | 5,916.30 | |||||||||
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 their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2. | |||||||||||||||||
SCE&G | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||
Fair Value Disclosures [Text Block] | 7. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | ||||||||||||||||
Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value Level 2 measurements were as follows: | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 2 | Level 2 | |||||||||||||||
Assets-Interest rate contracts | — | $ | 32 | ||||||||||||||
Liabilities-Interest rate contracts | $ | 233 | 2 | ||||||||||||||
There were 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 at December 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 4,308.60 | $ | 5,070.90 | $ | 4,054.90 | $ | 4,433.00 | |||||||||
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 their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefits Disclosure [Text Block] | EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN | ||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||
The Company sponsors a noncontributory defined benefit pension plan covering substantially all regular, full-time employees hired before January 1, 2014. Benefits are no longer offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. The Company’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. | |||||||||||||||||||||||||||||
The Company’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. | |||||||||||||||||||||||||||||
In addition to pension benefits, the Company provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. Retirees hired before January 1, 2011 share in a portion of their medical care cost. Employees hired after December 31, 2010 are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. | |||||||||||||||||||||||||||||
Changes in Benefit Obligations | |||||||||||||||||||||||||||||
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Benefit obligation, January 1 | $ | 823 | $ | 931.6 | $ | 238 | $ | 265.3 | |||||||||||||||||||||
Service cost | 20 | 21.8 | 4.6 | 5.9 | |||||||||||||||||||||||||
Interest cost | 40.4 | 38.5 | 12 | 11.1 | |||||||||||||||||||||||||
Plan participants’ contributions | — | — | 2.2 | 2.6 | |||||||||||||||||||||||||
Actuarial (gain) loss | 100.1 | (83.4 | ) | 23.5 | (35.1 | ) | |||||||||||||||||||||||
Benefits paid | (64.0 | ) | (60.0 | ) | (12.1 | ) | (11.8 | ) | |||||||||||||||||||||
Curtailment | — | (25.5 | ) | — | — | ||||||||||||||||||||||||
Benefit obligation, December 31 | $ | 919.5 | $ | 823 | $ | 268.2 | $ | 238 | |||||||||||||||||||||
The accumulated benefit obligation for pension benefits was $888.3 million at the end of 2014 and $796.4 million at the end of 2013. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. | |||||||||||||||||||||||||||||
Significant assumptions used to determine the above benefit obligations are as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||||||
Annual discount rate used to determine benefit obligation | 4.2 | % | 5.03 | % | 4.3 | % | 5.19 | % | |||||||||||||||||||||
Assumed annual rate of future salary increases for projected benefit obligation | 3 | % | 3 | % | 3 | % | 3.75 | % | |||||||||||||||||||||
A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter. | |||||||||||||||||||||||||||||
A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation by $1.1 million at December 31, 2014 and by $1.3 million at December 31, 2013. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation by $1.0 million at December 31, 2014 and by $1.2 million at December 31, 2013. | |||||||||||||||||||||||||||||
Funded Status | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Fair value of plan assets | $ | 861.8 | $ | 870 | — | — | |||||||||||||||||||||||
Benefit obligation | 919.5 | 823 | $ | 268.2 | $ | 238 | |||||||||||||||||||||||
Funded status | $ | (57.7 | ) | $ | 47 | $ | (268.2 | ) | $ | (238.0 | ) | ||||||||||||||||||
Amounts recognized on the consolidated balance sheets were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Current liability | — | — | $ | (11.2 | ) | $ | (11.5 | ) | |||||||||||||||||||||
Noncurrent asset | — | $ | 47 | — | — | ||||||||||||||||||||||||
Noncurrent liability | $ | (57.7 | ) | — | (257.0 | ) | (226.5 | ) | |||||||||||||||||||||
Amounts recognized in accumulated other comprehensive loss (a component of common equity) as of December 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 8.1 | $ | 5.2 | $ | 3 | $ | 1.7 | |||||||||||||||||||||
Prior service cost | 0.3 | 0.5 | 0.1 | 0.1 | |||||||||||||||||||||||||
Total | $ | 8.4 | $ | 5.7 | $ | 3.1 | $ | 1.8 | |||||||||||||||||||||
Amounts recognized in regulatory assets as of December 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 222.1 | $ | 124.8 | $ | 43.8 | $ | 24.4 | |||||||||||||||||||||
Prior service cost | 9.6 | 12.8 | 0.6 | 0.9 | |||||||||||||||||||||||||
Total | $ | 231.7 | $ | 137.6 | $ | 44.4 | $ | 25.3 | |||||||||||||||||||||
In connection with the joint ownership of Summer Station, as of December 31, 2014 and 2013, the Company recorded within deferred debits $17.8 million and $14.1 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2014 and 2013, the Company also recorded within deferred debits $15.1 million and $12.6 million, respectively, from Santee Cooper, representing its portion of the unfunded postretirement benefit obligation. | |||||||||||||||||||||||||||||
Changes in Fair Value of Plan Assets | |||||||||||||||||||||||||||||
Pension Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Fair value of plan assets, January 1 | $ | 870 | $ | 799.1 | |||||||||||||||||||||||||
Actual return on plan assets | 55.8 | 130.9 | |||||||||||||||||||||||||||
Benefits paid | (64.0 | ) | (60.0 | ) | |||||||||||||||||||||||||
Fair value of plan assets, December 31 | $ | 861.8 | $ | 870 | |||||||||||||||||||||||||
Investment Policies and Strategies | |||||||||||||||||||||||||||||
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan is closed to new entrants effective January 1, 2014, and benefit accruals will cease effective January 1, 2024. In addition, during 2013, the Company adopted a dynamic investment strategy for the management of the pension plan assets. The strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs in connection with the amendments to the plan. | |||||||||||||||||||||||||||||
The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. | |||||||||||||||||||||||||||||
Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. | |||||||||||||||||||||||||||||
The Company’s pension plan asset allocation at December 31, 2014 and 2013 and the target allocation for 2015 are as follows: | |||||||||||||||||||||||||||||
Percentage of Plan Assets | |||||||||||||||||||||||||||||
Target | At | ||||||||||||||||||||||||||||
Allocation | December 31, | ||||||||||||||||||||||||||||
Asset Category | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||
Equity Securities | 58 | % | 57 | % | 59 | % | |||||||||||||||||||||||
Fixed Income | 33 | % | 34 | % | 32 | % | |||||||||||||||||||||||
Hedge Funds | 9 | % | 9 | % | 9 | % | |||||||||||||||||||||||
For 2015, the expected long-term rate of return on assets will be 7.50%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active returns across various asset classes and assumes an asset allocation of 58% with equity managers, 33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy adopted for 2013. | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2014 and 2013, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | |||||||||||||||||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||||||
Millions of dollars | Total | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||||||||||||||||
Common stock | — | — | — | $ | 332 | $ | 332 | — | — | ||||||||||||||||||||
Preferred stock | — | — | — | 1 | 1 | — | — | ||||||||||||||||||||||
Mutual funds | $ | 622 | $ | 622 | — | 305 | 20 | $ | 285 | — | |||||||||||||||||||
Short-term investment vehicles | 20 | 20 | — | 19 | — | 19 | — | ||||||||||||||||||||||
US Treasury securities | 6 | 6 | — | 33 | — | 33 | — | ||||||||||||||||||||||
Corporate debt securities | 86 | 86 | — | 53 | — | 53 | — | ||||||||||||||||||||||
Loans secured by mortgages | — | — | — | 12 | — | 12 | — | ||||||||||||||||||||||
Municipals | 15 | 15 | — | 4 | — | 4 | — | ||||||||||||||||||||||
Limited partnerships | 32 | 32 | — | 35 | 1 | 34 | — | ||||||||||||||||||||||
Multi‑strategy hedge funds | 81 | — | $ | 81 | 76 | — | — | $ | 76 | ||||||||||||||||||||
$ | 862 | $ | 781 | $ | 81 | $ | 870 | $ | 354 | $ | 440 | $ | 76 | ||||||||||||||||
At December 31, 2014, assets with fair value measurements classified as Level 1 were insignificant. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2014 or 2013. | |||||||||||||||||||||||||||||
The pension plan values common stock, preferred stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds represent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The fair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur. | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Level 3 | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Beginning Balance | $ | 76 | $ | 70 | |||||||||||||||||||||||||
Unrealized gains included in changes in net assets | 5 | 6 | |||||||||||||||||||||||||||
Purchases, issuances, and settlements | — | — | |||||||||||||||||||||||||||
Ending Balance | $ | 81 | $ | 76 | |||||||||||||||||||||||||
Expected Cash Flows | |||||||||||||||||||||||||||||
The total benefits expected to be paid from the pension plan or from the Company’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: | |||||||||||||||||||||||||||||
Expected Benefit Payments | |||||||||||||||||||||||||||||
Millions of dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
2015 | $ | 63.4 | $ | 11.5 | |||||||||||||||||||||||||
2016 | 64.5 | 12.4 | |||||||||||||||||||||||||||
2017 | 65.6 | 13.1 | |||||||||||||||||||||||||||
2018 | 66.1 | 13.8 | |||||||||||||||||||||||||||
2019 | 65.1 | 14.6 | |||||||||||||||||||||||||||
2020-2024 | 338.4 | 81.8 | |||||||||||||||||||||||||||
Pension Plan Contributions | |||||||||||||||||||||||||||||
The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals in the future, the Company does not anticipate making significant contributions to the pension plan for the foreseeable future. | |||||||||||||||||||||||||||||
Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
The Company records net periodic benefit cost utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. | |||||||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Service cost | $ | 20 | $ | 21.8 | $ | 19.6 | $ | 4.6 | $ | 5.9 | $ | 4.8 | |||||||||||||||||
Interest cost | 40.4 | 38.5 | 43 | 12 | 11.1 | 11.9 | |||||||||||||||||||||||
Expected return on assets | (66.7 | ) | (61.4 | ) | (59.5 | ) | n/a | n/a | n/a | ||||||||||||||||||||
Prior service cost amortization | 4.1 | 6 | 7 | 0.3 | 0.7 | 0.9 | |||||||||||||||||||||||
Amortization of actuarial losses | 4.8 | 16.9 | 18.4 | — | 3.3 | 1.4 | |||||||||||||||||||||||
Transition obligation amortization | — | — | — | — | 0.3 | 0.7 | |||||||||||||||||||||||
Curtailment | — | 9.9 | — | — | — | — | |||||||||||||||||||||||
Net periodic benefit cost | $ | 2.6 | $ | 31.7 | $ | 28.5 | $ | 16.9 | $ | 21.3 | $ | 19.7 | |||||||||||||||||
In connection with regulatory orders, in 2013 SCE&G began recovering current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). SCE&G is amortizing previously deferred pension costs as further described in Note 2. | |||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 3.1 | $ | (5.0 | ) | $ | 1.7 | $ | 1.3 | $ | (1.8 | ) | $ | 2 | |||||||||||||||
Amortization of actuarial losses | (0.2 | ) | (0.5 | ) | (0.6 | ) | — | (0.2 | ) | — | |||||||||||||||||||
Amortization of prior service cost | (0.2 | ) | (0.2 | ) | (0.2 | ) | — | — | — | ||||||||||||||||||||
Prior service cost (credit) | — | (0.3 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.1 | ) | (0.1 | ) | |||||||||||||||||||||
Total recognized in OCI | $ | 2.7 | $ | (6.0 | ) | $ | 0.9 | $ | 1.3 | $ | (2.1 | ) | $ | 1.9 | |||||||||||||||
Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 101.3 | $ | (157.5 | ) | $ | 45 | $ | 19.4 | $ | (29.9 | ) | $ | 31.4 | |||||||||||||||
Amortization of actuarial losses | (4.0 | ) | (14.7 | ) | (16.0 | ) | — | (2.7 | ) | (1.2 | ) | ||||||||||||||||||
Amortization of prior service cost | (3.2 | ) | (5.2 | ) | (6.4 | ) | (0.3 | ) | (0.6 | ) | (0.8 | ) | |||||||||||||||||
Prior service cost (credit) | — | (8.9 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.2 | ) | (0.5 | ) | |||||||||||||||||||||
Total recognized in regulatory assets | $ | 94.1 | $ | (186.3 | ) | $ | 22.6 | $ | 19.1 | $ | (33.4 | ) | $ | 28.9 | |||||||||||||||
Significant Assumptions Used in Determining Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
Discount rate | 5.03 | % | 4.10%/5.07% | 5.25 | % | 5.19 | % | 4.19 | % | 5.35 | % | ||||||||||||||||||
Expected return on plan assets | 8 | % | 8 | % | 8.25 | % | n/a | n/a | n/a | ||||||||||||||||||||
Rate of compensation increase | 3 | % | 3.75%/3.00% | 4 | % | 3.75 | % | 3.75 | % | 4 | % | ||||||||||||||||||
Health care cost trend rate | n/a | n/a | n/a | 7.4 | % | 7.8 | % | 8.2 | % | ||||||||||||||||||||
Ultimate health care cost trend rate | n/a | n/a | n/a | 5 | % | 5 | % | 5 | % | ||||||||||||||||||||
Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2020 | |||||||||||||||||||||||
Net periodic benefit cost for the period through September 1, 2013 was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of compensation increase were changed in connection with the September 1, 2013 remeasurement. | |||||||||||||||||||||||||||||
The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 are as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 0.5 | $ | 0.1 | |||||||||||||||||||||||||
Prior service cost | 0.1 | — | |||||||||||||||||||||||||||
Total | $ | 0.6 | $ | 0.1 | |||||||||||||||||||||||||
The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2015 are as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 12.3 | $ | 1.9 | |||||||||||||||||||||||||
Prior service cost | 3.6 | 0.3 | |||||||||||||||||||||||||||
Total | $ | 15.9 | $ | 2.2 | |||||||||||||||||||||||||
Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. | |||||||||||||||||||||||||||||
Stock Purchase Savings Plan | |||||||||||||||||||||||||||||
The Company sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. The Company provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan were $25.8 million in 2014, $23.4 million in 2013 and $22.3 million in 2012 and were made in the form of SCANA common stock. | |||||||||||||||||||||||||||||
SCE&G | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefits Disclosure [Text Block] | EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN | ||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||
SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees hired before January 1, 2014. Benefits are no longer offered to employees hired or rehired after December 31, 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after December 31, 2023. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. | |||||||||||||||||||||||||||||
SCANA’s pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and for all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. | |||||||||||||||||||||||||||||
In addition to pension benefits, SCE&G participates in SCANA’s unfunded postretirement health care and life insurance programs which provide benefits to certain active and retired employees. Retirees hired before January 1, 2011 share in a portion of their medical care cost. Employees hired after December 31, 2010 are responsible for the full costs of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits. | |||||||||||||||||||||||||||||
The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans. The information presented below reflects Consolidated SCE&G's portion of the obligations, assets, funded status, net periodic benefit costs, and other information reported for the parent sponsored plans as a whole. The tabular data presented reflects the use of various cost assignment methodologies and participation assumptions based on Consolidated SCE&G's past and current employees and its share of plan assets. | |||||||||||||||||||||||||||||
Changes in Benefit Obligations | |||||||||||||||||||||||||||||
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Benefit obligation, January 1 | $ | 695.7 | $ | 788.4 | $ | 181.7 | $ | 206 | |||||||||||||||||||||
Service cost | 16 | 17.6 | 3.6 | 4.6 | |||||||||||||||||||||||||
Interest cost | 34.1 | 32.6 | 9.4 | 8.7 | |||||||||||||||||||||||||
Plan participants’ contributions | — | — | 1.8 | 2 | |||||||||||||||||||||||||
Actuarial (gain) loss | 82.7 | (70.7 | ) | 18.6 | (27.3 | ) | |||||||||||||||||||||||
Benefits paid | (54.8 | ) | (50.6 | ) | (9.6 | ) | (9.3 | ) | |||||||||||||||||||||
Curtailment | — | (21.6 | ) | — | — | ||||||||||||||||||||||||
Amounts funded to parent | — | — | (1.4 | ) | (3.0 | ) | |||||||||||||||||||||||
Benefit obligation, December 31 | $ | 773.7 | $ | 695.7 | $ | 204.1 | $ | 181.7 | |||||||||||||||||||||
The accumulated benefit obligation for pension benefits was $747.6 million at the end of 2014 and $673.2 million at the end of 2013. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. | |||||||||||||||||||||||||||||
Significant assumptions used to determine the above benefit obligations are as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||||||
Annual discount rate used to determine benefit obligation | 4.2 | % | 5.03 | % | 4.3 | % | 5.19 | % | |||||||||||||||||||||
Assumed annual rate of future salary increases for projected benefit obligation | 3 | % | 3 | % | 3 | % | 3.75 | % | |||||||||||||||||||||
A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014. The rate was assumed to decrease gradually to 5.0% for 2020 and to remain at that level thereafter. | |||||||||||||||||||||||||||||
A one percent increase in the assumed health care cost trend rate would increase the postretirement benefit obligation by $0.9 million at December 31, 2014 and by $1.0 million at December 31, 2013. A one percent decrease in the assumed health care cost trend rate would decrease the postretirement benefit obligation by $0.8 million at December 31, 2014 and by $0.9 million at December 31, 2013. | |||||||||||||||||||||||||||||
Funded Status | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Fair value of plan assets | $ | 783.6 | $ | 792.1 | — | — | |||||||||||||||||||||||
Benefit obligation | 773.7 | 695.7 | $ | 204.1 | $ | 181.7 | |||||||||||||||||||||||
Funded status | $ | 9.9 | $ | 96.4 | $ | (204.1 | ) | $ | (181.7 | ) | |||||||||||||||||||
Amounts recognized on the consolidated balance sheets were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Current liability | — | — | $ | (8.5 | ) | $ | (7.8 | ) | |||||||||||||||||||||
Noncurrent asset | $ | 9.9 | $ | 96.4 | — | — | |||||||||||||||||||||||
Noncurrent liability | — | — | (195.6 | ) | (173.9 | ) | |||||||||||||||||||||||
Amounts recognized in accumulated other comprehensive loss (a component of common equity) as of December 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 1.9 | $ | 1.8 | $ | 1 | $ | 0.6 | |||||||||||||||||||||
Prior service cost | 0.1 | 0.2 | — | — | |||||||||||||||||||||||||
Total | $ | 2 | $ | 2 | $ | 1 | $ | 0.6 | |||||||||||||||||||||
Amounts recognized in regulatory assets as of December 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 191.9 | $ | 107.7 | $ | 35.9 | $ | 20.1 | |||||||||||||||||||||
Prior service cost | 8.3 | 11.1 | 0.5 | 0.7 | |||||||||||||||||||||||||
Total | $ | 200.2 | $ | 118.8 | $ | 36.4 | $ | 20.8 | |||||||||||||||||||||
In connection with the joint ownership of Summer Station, as of December 31, 2014 and 2013, SCE&G recorded within deferred debits $17.8 million and $14.1 million, respectively, attributable to Santee Cooper’s portion of shared pension costs. As of December 31, 2014 and 2013, SCE&G also recorded within deferred debits $15.1 million and $12.6 million, respectively, from Santee Cooper, representing its portion of the unfunded postretirement benefit obligation. | |||||||||||||||||||||||||||||
Changes in Fair Value of Plan Assets | |||||||||||||||||||||||||||||
Pension Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Fair value of plan assets, January 1 | $ | 792.1 | $ | 732 | |||||||||||||||||||||||||
Actual return on plan assets | 46.3 | 110.7 | |||||||||||||||||||||||||||
Benefits paid | (54.8 | ) | (50.6 | ) | |||||||||||||||||||||||||
Fair value of plan assets, December 31 | $ | 783.6 | $ | 792.1 | |||||||||||||||||||||||||
Investment Policies and Strategies | |||||||||||||||||||||||||||||
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. The pension plan is closed to new entrants effective January 1, 2014, and benefit accruals will cease effective January 1, 2024. In addition, during 2013, SCANA adopted a dynamic investment strategy for the management of the pension plan assets. The strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs in connection with the amendments to the plan. | |||||||||||||||||||||||||||||
The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries. | |||||||||||||||||||||||||||||
Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited. | |||||||||||||||||||||||||||||
The pension plan asset allocation at December 31, 2014 and 2013 and the target allocation for 2015 are as follows: | |||||||||||||||||||||||||||||
Percentage of Plan Assets | |||||||||||||||||||||||||||||
Target | At | ||||||||||||||||||||||||||||
Allocation | December 31, | ||||||||||||||||||||||||||||
Asset Category | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||
Equity Securities | 58 | % | 57 | % | 59 | % | |||||||||||||||||||||||
Fixed Income | 33 | % | 34 | % | 32 | % | |||||||||||||||||||||||
Hedge Funds | 9 | % | 9 | % | 9 | % | |||||||||||||||||||||||
For 2015, the expected long-term rate of return on assets will be 7.50%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active returns across various asset classes and assumes an asset allocation of 58% with equity managers, 33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy adopted for 2013. | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2014 and 2013, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | |||||||||||||||||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||||||
Millions of dollars | Total | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
31-Dec-14 | December 31, 2013 | ||||||||||||||||||||||||||||
Common stock | — | — | — | $ | 302 | $ | 302 | — | — | ||||||||||||||||||||
Preferred stock | — | — | — | 1 | 1 | — | — | ||||||||||||||||||||||
Mutual funds | $ | 566 | $ | 566 | — | 278 | 18 | $ | 260 | — | |||||||||||||||||||
Short-term investment vehicles | 18 | 18 | — | 18 | — | 18 | — | ||||||||||||||||||||||
US Treasury securities | 6 | 6 | — | 30 | — | 30 | — | ||||||||||||||||||||||
Corporate debt securities | 78 | 78 | — | 48 | — | 48 | — | ||||||||||||||||||||||
Loans secured by mortgages | — | — | — | 11 | — | 11 | — | ||||||||||||||||||||||
Municipals | 14 | 14 | — | 3 | — | 3 | — | ||||||||||||||||||||||
Limited partnerships | 29 | 29 | — | 32 | 1 | 31 | — | ||||||||||||||||||||||
Multi-strategy hedge funds | 73 | — | $ | 73 | 69 | — | — | $ | 69 | ||||||||||||||||||||
$ | 784 | $ | 711 | $ | 73 | $ | 792 | $ | 322 | $ | 401 | $ | 69 | ||||||||||||||||
At December 31, 2014, assets with fair value measurements classified as Level 1 were insignificant. There were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2014 or 2013. | |||||||||||||||||||||||||||||
The pension plan values common stock, preferred stock and certain mutual funds, where applicable, using unadjusted quoted prices from a national stock exchange, such as NYSE and NASDAQ, where the securities are actively traded. Other mutual funds, common collective trusts and limited partnerships are valued using the observable prices of the underlying fund assets based on trade data for identical or similar securities or from a national stock exchange for similar assets or broker quotes. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. Government agency securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt securities and municipals are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Loans secured by mortgages are valued using observable prices based on trade data for identical or comparable instruments. Hedge funds represent investments in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and do not trade on a daily basis. The fair value of this multi-strategy hedge fund is estimated based on the net asset value of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may impact their fair value. The estimated fair value is the price at which redemptions and subscriptions occur. | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Level 3 | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Beginning Balance | $ | 69 | $ | 64 | |||||||||||||||||||||||||
Unrealized gains included in changes in net assets | 4 | 5 | |||||||||||||||||||||||||||
Purchases, issuances, and settlements | — | — | |||||||||||||||||||||||||||
Ending Balance | $ | 73 | $ | 69 | |||||||||||||||||||||||||
Expected Cash Flows | |||||||||||||||||||||||||||||
The total benefits expected to be paid from the pension plan or from SCE&G’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: | |||||||||||||||||||||||||||||
Expected Benefit Payments | |||||||||||||||||||||||||||||
Millions of dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
2015 | $ | 63.4 | $ | 9.1 | |||||||||||||||||||||||||
2016 | 64.5 | 9.8 | |||||||||||||||||||||||||||
2017 | 65.6 | 10.4 | |||||||||||||||||||||||||||
2018 | 66.1 | 10.9 | |||||||||||||||||||||||||||
2019 | 65.1 | 11.5 | |||||||||||||||||||||||||||
2020 - 2024 | 338.4 | 64.6 | |||||||||||||||||||||||||||
Pension Plan Contributions | |||||||||||||||||||||||||||||
The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals in the future, SCE&G does not anticipate making significant contributions to the pension plan for the foreseeable future. | |||||||||||||||||||||||||||||
Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
SCE&G records net periodic benefit cost utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. | |||||||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Service cost | $ | 16 | $ | 17.6 | $ | 15.7 | $ | 3.6 | $ | 4.6 | $ | 3.7 | |||||||||||||||||
Interest cost | 34.1 | 32.6 | 36.4 | 9.4 | 8.7 | 9.4 | |||||||||||||||||||||||
Expected return on assets | (56.3 | ) | (51.9 | ) | (50.4 | ) | n/a | n/a | n/a | ||||||||||||||||||||
Prior service cost amortization | 3.5 | 5 | 6 | 0.3 | 0.6 | 0.7 | |||||||||||||||||||||||
Amortization of actuarial losses | 4 | 14.3 | 15.6 | — | 2.6 | 1.1 | |||||||||||||||||||||||
Curtailment | — | 8.4 | — | — | — | — | |||||||||||||||||||||||
Net periodic benefit cost | $ | 1.3 | $ | 26 | $ | 23.3 | $ | 13.3 | $ | 16.5 | $ | 14.9 | |||||||||||||||||
In connection with regulatory orders, in 2013 SCE&G began recovering current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). SCE&G is amortizing previously deferred pension costs as further described in Note 2. | |||||||||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 0.2 | $ | (0.8 | ) | $ | 0.4 | $ | 0.4 | $ | (0.4 | ) | $ | 0.7 | |||||||||||||||
Amortization of actuarial losses | (0.1 | ) | (0.1 | ) | (0.1 | ) | — | (0.1 | ) | — | |||||||||||||||||||
Amortization of prior service cost | (0.1 | ) | — | (0.1 | ) | — | — | (0.1 | ) | ||||||||||||||||||||
Total recognized in OCI | $ | — | $ | (0.9 | ) | $ | 0.2 | $ | 0.4 | $ | (0.5 | ) | $ | 0.6 | |||||||||||||||
Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 87.7 | $ | (137.1 | ) | $ | 37.9 | $ | 15.8 | $ | (24.4 | ) | $ | 25.7 | |||||||||||||||
Amortization of actuarial losses | (3.5 | ) | (12.7 | ) | (14.0 | ) | — | (2.2 | ) | (1.0 | ) | ||||||||||||||||||
Amortization of prior service cost | (2.8 | ) | (4.5 | ) | (5.7 | ) | (0.2 | ) | (0.5 | ) | (0.7 | ) | |||||||||||||||||
Prior service cost (credit) | — | (7.7 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.1 | ) | (0.2 | ) | |||||||||||||||||||||
Total recognized in regulatory assets | $ | 81.4 | $ | (162.0 | ) | $ | 18.2 | $ | 15.6 | $ | (27.2 | ) | $ | 23.8 | |||||||||||||||
Significant Assumptions Used in Determining Net Periodic Benefit Cost | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
Discount rate | 5.03 | % | 4.10%/5.07% | 5.25 | % | 5.19 | % | 4.19 | % | 5.35 | % | ||||||||||||||||||
Expected return on plan assets | 8 | % | 8 | % | 8.25 | % | n/a | n/a | n/a | ||||||||||||||||||||
Rate of compensation increase | 3 | % | 3.75%/3.00% | 4 | % | 3.75 | % | 3.75 | % | 4 | % | ||||||||||||||||||
Health care cost trend rate | n/a | n/a | n/a | 7.4 | % | 7.8 | % | 8.2 | % | ||||||||||||||||||||
Ultimate health care cost trend rate | n/a | n/a | n/a | 5 | % | 5 | % | 5 | % | ||||||||||||||||||||
Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2020 | |||||||||||||||||||||||
Net periodic benefit cost for the period through September 1, 2013, was determined using a 4.10% discount rate, and net periodic benefit cost after that date was determined using a 5.07% discount rate. Similarly, estimated rates of compensation increase were changed in connection with the September 1, 2013 remeasurement. | |||||||||||||||||||||||||||||
The actuarial loss and prior service cost to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 are insignificant. | |||||||||||||||||||||||||||||
The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2015 are as follows: | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 10.6 | $ | 1.6 | |||||||||||||||||||||||||
Prior service cost | 3.1 | 0.2 | |||||||||||||||||||||||||||
Total | $ | 13.7 | $ | 1.8 | |||||||||||||||||||||||||
Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. | |||||||||||||||||||||||||||||
Stock Purchase Savings Plan | |||||||||||||||||||||||||||||
SCE&G participates in a SCANA-sponsored defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. Employee deferrals are fully vested and nonforfeitable at all times. SCE&G provides 100% matching contributions up to 6% of an employee’s eligible earnings. Total matching contributions made to the plan were $20.7 million in 2014, $18.7 million in 2013 and $17.7 million in 2012 and were made in the form of SCANA common stock. |
SHAREBASED_COMPENSATION
SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2014 | |
Share-Based Compensation | |
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | SHARE-BASED COMPENSATION |
The LTECP provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock. | |
Compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest. | |
Liability Awards | |
The 2012-2014, 2013-2015 and 2014-2016 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. In each performance cycle, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to exceptions for retirement, death, disability or change in control. The remaining 80% of the award was granted in performance shares, which are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to exceptions for retirement, death or disability. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock. Dividend equivalents are accrued on the performance shares and the restricted share units. Payouts of performance share awards are determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). | |
Compensation cost of liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Awards under the 2012-2014 performance cycle were paid in cash at SCANA’s discretion in February 2015. Cash-settled liabilities related to the performance cycles were paid totaling approximately $11.8 million in 2014, $12.2 million in 2013, and $11.8 million in 2012. | |
Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling approximately $20.3 million in 2014, $8.7 million in 2013 and $15.0 million in 2012. Fair value adjustments resulted in capitalized compensation costs of $3.1 million in 2014, $1.4 million in 2013 and $2.7 million in 2012. | |
SCE&G | |
Share-Based Compensation | |
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | SHARE-BASED COMPENSATION |
SCE&G participates in the LTECP which provides for grants of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock. | |
Compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest. | |
Liability Awards | |
The 2012-2014, 2013-2015, and 2014-2016 performance cycles provide for performance measurement and award determination on an annual basis, with payment of awards being deferred until after the end of the three-year performance cycle. In each performance cycle, 20% of the performance award was granted in the form of restricted share units, which are liability awards payable in cash and are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to exceptions for retirement, death, disability or change in control. The remaining 80% of the award was granted in performance shares, which are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to exceptions for retirement, death or disability. Each performance share has a value that is equal to, and changes with, the value of a share of SCANA common stock. Dividend equivalents are accrued on the performance shares and the restricted share units. Payouts of performance share awards are determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%) and growth in “GAAP-adjusted net earnings per share from operations” (weighted 50%). | |
Compensation cost of liability awards is recognized over their respective three-year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Awards under the 2012-2014 performance cycle were paid in cash at SCANA’s discretion in February 2015. Cash-settled liabilities related to the performance cycles were paid totaling approximately $1.9 million in 2014, $3.2 million in 2013 and $8.7 million in 2012. | |
Fair value adjustments for performance awards resulted in compensation expense recognized in the statements of income totaling approximately $12.6 million in 2014, $5.5 million in 2013 and $9.5 million in 2012. Fair value adjustments resulted in capitalized compensation costs of $0.6 million in 2014, $0.5 million in 2013 and $2.1 million in 2012. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Commitment [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 the company’s nuclear power plant. Price-Anderson provides funds up to $13.6 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. 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 in limits of 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 premiums, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million. | |||||||||
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear 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 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 incident. However, if such an incident were to occur, it likely would have a material impact on the Company’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, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), 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. Such annual rate changes are described in Note 2. As of December 31, 2014, SCE&G’s investment in the New Units totaled $2.7 billion, for which the financing costs on $2.425 billion have been reflected in rates under the BLRA. | |||||||||
The SCPSC granted initial approval of the construction schedule, including 146 milestones within that 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 December 2012, the SCPSC denied separate petitions filed by two parties requesting reconsideration of its order. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | |||||||||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule. | |||||||||
Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015. | |||||||||
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 intended result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit 2 was expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. | |||||||||
During the third quarter of 2014, the Consortium also provided preliminary cost estimates for Units 2 and 3, principally related to delays for non-firm and non-fixed scopes of work to achieve a late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million, excluding any owner's cost amounts associated with the delays, which could be $10 million per month for delays beyond the current SCPSC-approved substantial completion dates. This figure is presented in 2007 dollars and would be subject to escalation, which could be material. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review, and SCE&G cannot predict when a revised schedule and cost estimate will be resolved with the Consortium. | |||||||||
Since receiving the August 2014 preliminary information, SCE&G has worked with Consortium executive management to evaluate this information. Based upon this evaluation, the Consortium now indicates that the substantial completion date of Unit 2 is expected to occur by June 2019 and that the substantial completion date of Unit 3 may be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. SCE&G is continuing discussions with Consortium executive management in order to identify potential mitigation strategies to possibly accelerate the substantial completion date of Unit 2 to a time earlier in the first half of 2019 or to the end of 2018, with Unit 3 following approximately 12 months later. | |||||||||
As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of December 31, 2014, 101 milestones have been completed. Three of the remaining milestones have not been or will not be completed within their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are now projected to exceed amounts currently approved by the SCPSC of $4.548 billion and $5.755 billion, respectively. As such, in 2015 SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition is expected to include certain updated owner's costs and other capital costs, including amounts within the Consortium's preliminary cost estimate which may be the subject of dispute. As such, the petition is not expected to reflect the resolution of the above described negotiations. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G. | |||||||||
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 (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, 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, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire 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 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 current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure could be higher in light of the delays and related costs discussed above. | |||||||||
Nuclear Production Tax Credits | |||||||||
In August 2014, the IRS 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. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, 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. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized. | |||||||||
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, as well as a request for information related to emergency plant staffing. SCE&G fulfilled the request related to emergency plant staffing in 2012. In addition, SCE&G prepared and submitted an integrated response 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 | |||||||||
The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions. | |||||||||
SCE&G | |||||||||
The EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The proposed rule was issued on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are to be made final no later than June 1, 2015, and include state-specific rate based goals for carbon dioxide emissions. | |||||||||
From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. | |||||||||
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, thus delaying 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 or 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. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR. | |||||||||
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at the Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. | |||||||||
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 was published in the Federal Register on June 7, 2013, and is expected to be finalized no later than September 30, 2015. Once the rule becomes effective, 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. Based on the proposed rule, the Company expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. | |||||||||
The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 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 to ensure compliance with this rule. 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. | |||||||||
On December 19, 2014, the EPA issued a final rule for CCR, which is expected to become effective in 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds. | |||||||||
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. The Nuclear Waste Act also 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, 2014, 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 is constructing a dry cask storage facility 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. | |||||||||
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | |||||||||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 2017 and will cost an additional $19.3 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 December 31, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.5 million and are included in regulatory assets. | |||||||||
PSNC Energy | |||||||||
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. Actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $1.0 million, the estimated remaining liability at December 31, 2014. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites. | |||||||||
Claims and Litigation | |||||||||
The Company is subject to various claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on the Company’s results of operations, cash flows or financial condition. | |||||||||
Operating Lease Commitments | |||||||||
The Company is obligated under various operating leases for vehicles, office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $12.3 million in 2014, $14.8 million in 2013 and $14.8 million in 2012. Future minimum rental payments under such leases are as follows: | |||||||||
Millions of dollars | |||||||||
2015 | $ | 8 | |||||||
2016 | 5 | ||||||||
2017 | 2 | ||||||||
2018 | 1 | ||||||||
2019 | 2 | ||||||||
Thereafter | 20 | ||||||||
Total | $ | 38 | |||||||
Guarantees | |||||||||
SCANA issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is remote; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability is included in the consolidated financial statements. At December 31, 2014, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $1.7 billion. | |||||||||
Asset Retirement Obligations | |||||||||
The Company recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition. | |||||||||
The legal obligations associated with the retirement of long-lived tangible assets that results from their acquisition, construction, development and normal operation relate primarily to the Company’s regulated utility operations. As of December 31, 2014, the Company has recorded AROs of approximately $201 million for nuclear plant decommissioning (see Note 1) and AROs of approximately $362 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. | |||||||||
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows: | |||||||||
Millions of dollars | 2014 | 2013 | |||||||
Beginning balance | $ | 576 | $ | 561 | |||||
Liabilities incurred | 3 | 6 | |||||||
Liabilities settled | (6 | ) | (4 | ) | |||||
Accretion expense | 26 | 25 | |||||||
Revisions in estimated cash flows | (36 | ) | (12 | ) | |||||
Ending balance | $ | 563 | $ | 576 | |||||
Revisions in estimated cash flows for 2014 primarily relate to lower estimates for certain environmental clean up obligations at generation facilities. | |||||||||
SCE&G | |||||||||
Commitment [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 the company’s nuclear power plant. Price-Anderson provides funds up to $13.6 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. 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 in limits of 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 premiums, SCE&G’s portion of the retrospective premium assessment would not exceed $43.5 million | |||||||||
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear 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 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 incident. However, if such an incident were to occur, it likely would have a material impact on the 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, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), 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. Such annual rate changes are described in Note 2. As of December 31, 2014, SCE&G’s investment in the New Units totaled $2.7 billion, for which the financing costs on $2.425 billion have been reflected in rates under the BLRA. | |||||||||
The SCPSC granted initial approval of the construction schedule, including 146 milestones within that 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 December 2012, the SCPSC denied separate petitions filed by two parties requesting reconsideration of its order. On October 22, 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | |||||||||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule. | |||||||||
Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01, as well as shield building modules, are considered critical path items for both New Units. CA20 was placed on the nuclear island of Unit 2 in May 2014. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the first half of 2015. | |||||||||
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 intended result will be a revised fully integrated project schedule with timing of specific construction activities along with detailed information on budget, cost and cash flow requirements. While this detailed re-baselining of construction schedules has not been completed, in August 2014, SCE&G received preliminary information in which the Consortium has indicated that the substantial completion of Unit 2 was expected to occur in late 2018 or the first half of 2019 and that the substantial completion of Unit 3 may be approximately 12 months later. | |||||||||
During the third quarter of 2014, the Consortium also provided preliminary cost estimates for Units 2 and 3, principally related to delays for non-firm and non-fixed scopes of work to achieve a late 2018 substantial completion date for Unit 2 and a substantial completion date for Unit 3 approximately 12 months later. SCE&G's 55% portion of this preliminary estimate is approximately $660 million, excluding any owner's cost amounts associated with the delays, which could be $10 million per month for delays beyond the current SCPSC-approved substantial completion dates. This figure is presented in 2007 dollars and would be subject to escalation, which could be material. Further, this figure does not reflect consideration of the liquidated damages provisions of the EPC Contract which would partly mitigate any such delay-related costs. The Consortium's preliminary schedule and the cost estimate information have not been accepted by SCE&G and are under review, and SCE&G cannot predict when a revised schedule and cost estimate will be resolved with the Consortium. | |||||||||
Since receiving the August 2014 preliminary information, SCE&G has worked with Consortium executive management to evaluate this information. Based upon this evaluation, the Consortium now indicates that the substantial completion date of Unit 2 is expected to occur by June 2019 and that the substantial completion date of Unit 3 may be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. SCE&G is continuing discussions with Consortium executive management in order to identify potential mitigation strategies to possibly accelerate the substantial completion date of Unit 2 to a time earlier in the first half of 2019 or to the end of 2018, with Unit 3 following approximately 12 months later. | |||||||||
As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of December 31, 2014, 101 milestones have been completed. Three of the remaining milestones have not been or will not be completed within their 18-month contingency periods, and it is anticipated that the completion dates for a number of the other remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are now projected to exceed amounts currently approved by the SCPSC of $4.548 billion and $5.755 billion, respectively. As such, in 2015 SCE&G, as provided for under the BLRA, expects to petition the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition is expected to include certain updated owner's costs and other capital costs, including amounts within the Consortium's preliminary cost estimate which may be the subject of dispute. As such, the petition is not expected to reflect the resolution of the above described negotiations. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G. | |||||||||
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 (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, 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, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire 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 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 current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure could be higher in light of the delays and related costs discussed above. | |||||||||
Nuclear Production Tax Credits | |||||||||
In August 2014, the IRS 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. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, 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. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized. | |||||||||
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, as well as a request for information related to emergency plant staffing. SCE&G fulfilled the request related to emergency plant staffing in 2012. In addition, SCE&G prepared and submitted an integrated response 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 | |||||||||
Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions. | |||||||||
The EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The proposed rule was issued on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are to be made final no later than June 1, 2015, and include state-specific rate based goals for carbon dioxide emissions. | |||||||||
From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. | |||||||||
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, thus delaying 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 or 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. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR. | |||||||||
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in 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. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at the Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. | |||||||||
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 was published in the Federal Register on June 7, 2013, and is expected to be finalized no later than September 30, 2015. Once the rule becomes effective, 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. Based on the proposed rule, Consolidated SCE&G expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. | |||||||||
The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 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 to ensure compliance with this rule. 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. | |||||||||
On December 19, 2014, the EPA issued a final rule for CCR, which is expected to become effective in 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds. | |||||||||
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. The Nuclear Waste Act also 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, 2014, 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 is constructing a dry cask storage facility 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. | |||||||||
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | |||||||||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 2017 and will cost an additional $19.3 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 December 31, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.5 million and are included in regulatory assets. | |||||||||
Claims and Litigation | |||||||||
Consolidated SCE&G is subject to various claims and litigation incidental to its business operations which management anticipates will be resolved without a material impact on Consolidated SCE&G’s results of operations, cash flows or financial condition. | |||||||||
Operating Lease Commitments | |||||||||
Consolidated SCE&G is obligated under various operating leases for vehicles, office space, furniture and equipment. Leases expire at various dates through 2057. Rent expense totaled approximately $12.1 million in 2014, $13.6 million in 2013 and $9.6 million in 2012. Future minimum rental payments under such leases are as follows: | |||||||||
Millions of dollars | |||||||||
2015 | $ | 6 | |||||||
2016 | 3 | ||||||||
2017 | 1 | ||||||||
2018 | — | ||||||||
2019 | 1 | ||||||||
Thereafter | 18 | ||||||||
Total | $ | 29 | |||||||
Asset Retirement Obligations | |||||||||
Consolidated SCE&G recognizes a liability for the present value of an ARO when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition. | |||||||||
The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to Consolidated SCE&G’s regulated utility operations. As of December 31, 2014, Consolidated SCE&G has recorded AROs of approximately $201 million for nuclear plant decommissioning (see Note 1) and AROs of approximately $335 million for other conditional obligations primarily related to generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of imprecision, particularly since such payments will be made many years in the future. | |||||||||
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows: | |||||||||
Millions of dollars | 2014 | 2013 | |||||||
Beginning balance | $ | 547 | $ | 535 | |||||
Liabilities incurred | 3 | 5 | |||||||
Liabilities settled | (6 | ) | (4 | ) | |||||
Accretion expense | 25 | 24 | |||||||
Revisions in estimated cash flows | (33 | ) | (13 | ) | |||||
Ending Balance | $ | 536 | $ | 547 | |||||
Revisions in estimated cash flows for 2014 primarily relate to lower estimates for certain environmental clean up obligations at generation facilities. |
AFFILIATED_TRANSACTIONS
AFFILIATED TRANSACTIONS | 12 Months Ended |
Dec. 31, 2014 | |
Affiliated Transaction [Line Items] | |
AFFILIATED TRANSACTIONS | AFFILIATED TRANSACTIONS |
The Company received cash distributions from equity-method investees of $7.8 million in 2014, $10.4 million in 2013 and $12.5 million in 2012. The Company made investments in equity-method investees of $5.7 million in 2014, $5.2 million in 2013 and $10.6 million in 2012. | |
SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. SCE&G’s receivable from this affiliate was $27.8 million at December 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s payable to this affiliate was $27.9 million at December 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s total purchases from this affiliate were $260.3 million in 2014 and $134.2 million in 2013. SCE&G’s total sales to this affiliate were $259.0 million in 2014 and $133.6 million in 2013. | |
SCE&G | |
Affiliated Transaction [Line Items] | |
AFFILIATED TRANSACTIONS | AFFILIATED TRANSACTIONS |
CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. Such purchases totaled approximately $30.0 million in 2014, $33.3 million in 2013 and $35.9 million in 2012. SCE&G had approximately $3.3 million and $3.3 million payable to CGT for transportation services at December 31, 2014 and December 31, 2013, respectively. SCE&G had approximately $1.2 million and $1.3 million receivable from CGT for transportation services at December 31, 2014 and December 31, 2013, respectively. | |
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 $195.7 million in 2014, $166.9 million in 2013 and $125.5 million in 2012. SCE&G’s payables to SEMI for such purposes were $12.6 million and $12.5 million as of December 31, 2014 and 2013, respectively. | |
SCE&G owns 40% of Canadys Refined Coal, LLC which is involved in the manufacturing and selling of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. SCE&G’s receivable from this affiliate was $27.8 million at December 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s payable to this affiliate was $27.9 million at December 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s total purchases from this affiliate were $260.3 million in 2014 and $134.2 million in 2013. SCE&G’s total sales to this affiliate were $259.0 million in 2014 and $133.6 million in 2013. | |
SCANA Services 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 totaled $292.2 million in 2014, $285.6 million in 2013 and $305.6 million in 2012. Consolidated SCE&G's payables to SCANA Services for these services were $47.3 million and $49.1 million at December 31, 2014 and 2013, respectively. | |
Borrowings from and investments in an affiliated money pool are described in Note 4. |
SEGMENT_OF_BUSINESS_INFORMATIO
SEGMENT OF BUSINESS INFORMATION | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||||||||
Segment Reporting Disclosure [Text Block] | SEGMENT OF BUSINESS INFORMATION | |||||||||||||||||||||||||||
Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices. | ||||||||||||||||||||||||||||
Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. | ||||||||||||||||||||||||||||
Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. | ||||||||||||||||||||||||||||
Retail Gas Marketing markets natural gas in Georgia and is regulated as a marketer by the GPSC. Energy Marketing markets natural gas to industrial and large commercial customers and municipalities, primarily in the Southeast. | ||||||||||||||||||||||||||||
All Other is comprised of the holding company and its other direct and indirect wholly-owned subsidiaries. One of these subsidiaries operates a FERC-regulated interstate pipeline company and the other subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met the quantitative thresholds for determining reportable segments during any period reported. See Note 13. | ||||||||||||||||||||||||||||
Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Marketing segments differ from each other in their respective markets and customer type. | ||||||||||||||||||||||||||||
Management uses operating income to measure segment profitability for SCE&G and other regulated operations and evaluates utility plant, net, for segments attributable to SCE&G. As a result, the Company does not allocate interest charges, income tax expense or assets other than utility plant to its segments. For nonregulated operations, management uses net income as the measure of segment profitability and evaluates total assets for financial position. Interest income is not reported by segment and is not material. The Company’s deferred tax assets are netted with deferred tax liabilities for reporting purposes. | ||||||||||||||||||||||||||||
The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income consist of the unallocated net income of the Company's regulated reportable segments. | ||||||||||||||||||||||||||||
Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G. | ||||||||||||||||||||||||||||
Adjustments to Interest Expense, Income Tax Expense, Expenditures for Assets and Deferred Tax Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to asset retirement obligations. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis. | ||||||||||||||||||||||||||||
Disclosure of Reportable Segments (Millions of dollars) | ||||||||||||||||||||||||||||
Electric | Gas | Retail Gas | Energy | All | Adjustments/ | Consolidated | ||||||||||||||||||||||
Operations | Distribution | Marketing | Marketing | Other | Eliminations | Total | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,622 | $ | 1,012 | $ | 515 | $ | 786 | $ | 37 | $ | (21 | ) | $ | 4,951 | |||||||||||||
Intersegment Revenue | 7 | 2 | — | 196 | 437 | (642 | ) | — | ||||||||||||||||||||
Operating Income | 768 | 159 | n/a | n/a | 27 | 53 | 1,007 | |||||||||||||||||||||
Interest Expense | 19 | 22 | 1 | — | 5 | 265 | 312 | |||||||||||||||||||||
Depreciation and Amortization | 300 | 72 | 2 | — | 24 | (14 | ) | 384 | ||||||||||||||||||||
Income Tax Expense | 7 | 33 | 16 | 3 | 12 | 177 | 248 | |||||||||||||||||||||
Net Income | n/a | n/a | 26 | 5 | (6 | ) | 513 | 538 | ||||||||||||||||||||
Segment Assets | 10,182 | 2,487 | 140 | 150 | 1,474 | 2,419 | 16,852 | |||||||||||||||||||||
Expenditures for Assets | 936 | 200 | — | 2 | 52 | (98 | ) | 1,092 | ||||||||||||||||||||
Deferred Tax Assets | 11 | 29 | 11 | 9 | 15 | (75 | ) | — | ||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,423 | $ | 942 | $ | 465 | $ | 652 | $ | 40 | $ | (27 | ) | $ | 4,495 | |||||||||||||
Intersegment Revenue | 6 | 1 | — | 167 | 416 | (590 | ) | — | ||||||||||||||||||||
Operating Income | 679 | 153 | n/a | n/a | 27 | 51 | 910 | |||||||||||||||||||||
Interest Expense | 19 | 22 | 1 | — | 4 | 251 | 297 | |||||||||||||||||||||
Depreciation and Amortization | 297 | 70 | 3 | — | 26 | (18 | ) | 378 | ||||||||||||||||||||
Income Tax Expense | 6 | 33 | 15 | 4 | 14 | 151 | 223 | |||||||||||||||||||||
Net Income | n/a | n/a | 24 | 6 | (2 | ) | 443 | 471 | ||||||||||||||||||||
Segment Assets | 9,488 | 2,340 | 172 | 133 | 1,378 | 1,653 | 15,164 | |||||||||||||||||||||
Expenditures for Assets | 907 | 140 | — | 1 | 31 | 27 | 1,106 | |||||||||||||||||||||
Deferred Tax Assets | 10 | 27 | 8 | 2 | 14 | (61 | ) | — | ||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,446 | $ | 764 | $ | 413 | $ | 543 | $ | 45 | $ | (35 | ) | $ | 4,176 | |||||||||||||
Intersegment Revenue | 7 | 1 | — | 125 | 416 | (549 | ) | — | ||||||||||||||||||||
Operating Income | 668 | 141 | n/a | n/a | 22 | 28 | 859 | |||||||||||||||||||||
Interest Expense | 21 | 23 | 1 | — | 3 | 247 | 295 | |||||||||||||||||||||
Depreciation and Amortization | 278 | 67 | 3 | — | 25 | (17 | ) | 356 | ||||||||||||||||||||
Income Tax Expense | 7 | 32 | 7 | 3 | 15 | 118 | 182 | |||||||||||||||||||||
Net Income | n/a | n/a | 11 | 5 | 1 | 403 | 420 | |||||||||||||||||||||
Segment Assets | 8,989 | 2,292 | 153 | 122 | 1,415 | 1,645 | 14,616 | |||||||||||||||||||||
Expenditures for Assets | 999 | 123 | — | 1 | 14 | (60 | ) | 1,077 | ||||||||||||||||||||
Deferred Tax Assets | 9 | 26 | 10 | 4 | 17 | (55 | ) | 11 | ||||||||||||||||||||
SCE&G | ||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||||||||
Segment Reporting Disclosure [Text Block] | SEGMENT OF BUSINESS INFORMATION | |||||||||||||||||||||||||||
Consolidated SCE&G’s reportable segments follow the same accounting policies as those described in Note 1. | ||||||||||||||||||||||||||||
Electric Operations primarily generates, transmits, and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution purchases and sells natural gas, primarily at retail, and is regulated by the SCPSC. | ||||||||||||||||||||||||||||
Disclosure of Reportable Segments (Millions of dollars) | ||||||||||||||||||||||||||||
Electric | Gas | Adjustments/ | Consolidated | |||||||||||||||||||||||||
Operations | Distribution | Eliminations | Total | |||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,629 | $ | 462 | — | $ | 3,091 | |||||||||||||||||||||
Operating Income | 768 | 62 | — | 830 | ||||||||||||||||||||||||
Interest Expense | 19 | — | $ | 209 | 228 | |||||||||||||||||||||||
Depreciation and Amortization | 300 | 27 | (12 | ) | 315 | |||||||||||||||||||||||
Segment Assets | 10,182 | 721 | 3,204 | 14,107 | ||||||||||||||||||||||||
Expenditures for Assets | 936 | 55 | (57 | ) | 934 | |||||||||||||||||||||||
Deferred Tax Assets | 11 | n/a | (11 | ) | — | |||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,431 | $ | 414 | — | $ | 2,845 | |||||||||||||||||||||
Operating Income | 679 | 58 | — | 737 | ||||||||||||||||||||||||
Interest Expense | 19 | — | $ | 198 | 217 | |||||||||||||||||||||||
Depreciation and Amortization | 294 | 26 | (7 | ) | 313 | |||||||||||||||||||||||
Segment Assets | 9,488 | 686 | 2,526 | 12,700 | ||||||||||||||||||||||||
Expenditures for Assets | 907 | 45 | 51 | 1,003 | ||||||||||||||||||||||||
Deferred Tax Assets | 10 | n/a | (10 | ) | — | |||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,453 | $ | 356 | — | $ | 2,809 | |||||||||||||||||||||
Operating Income | 668 | 49 | — | 717 | ||||||||||||||||||||||||
Interest Expense | 21 | — | $ | 190 | 211 | |||||||||||||||||||||||
Depreciation and Amortization | 278 | 25 | (10 | ) | 293 | |||||||||||||||||||||||
Segment Assets | 8,989 | 659 | 2,456 | 12,104 | ||||||||||||||||||||||||
Expenditures for Assets | 999 | 56 | (77 | ) | 978 | |||||||||||||||||||||||
Deferred Tax Assets | 9 | n/a | (9 | ) | — | |||||||||||||||||||||||
Management uses operating income to measure segment profitability for regulated operations and evaluates utility plant, net, for its segments. As a result, Consolidated SCE&G does not allocate interest charges, income tax expense, earnings available to common shareholder or assets other than utility plant to its segments. Intersegment revenue and interest income were not significant. Consolidated SCE&G’s deferred tax assets are netted with deferred tax liabilities for reporting purposes. | ||||||||||||||||||||||||||||
The consolidated financial statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Segment Assets include utility plant, net for all reportable segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for the segments. Adjustments to Interest Expense and Deferred Tax Assets include amounts that are not allocated to the segments. Expenditures for Assets are adjusted for revisions to estimated cash flows related to asset retirement obligations, and totals not allocated to other segments. |
DISPOSITIONS_Notes
DISPOSITIONS (Notes) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Dispositions [Abstract] | |||||||||||||
Disposal Group [Text Block] | DISPOSITIONS | ||||||||||||
In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to Spirit Communications. These sales closed in the first quarter of 2015. Proceeds from these sales, net of transaction costs, were approximately $625 million, and the estimated pre-tax gain on the sales to be recognized during the first quarter of 2015 is approximately $350 million. | |||||||||||||
CGT and SCI operate 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 meet accounting criteria for disclosure as a reportable segment. Accordingly, segment disclosures related to them are included within All Other in Note 12. As a result, the Company has determined that the sales of CGT and SCI do not represent a strategic shift that will have a major effect on its operations, and therefore, these sales do not meet the criteria for classification as discontinued operations. | |||||||||||||
The carrying values of the major classes of assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows: | |||||||||||||
Millions of dollars | CGT | SCI | Total | ||||||||||
Assets Held for Sale | |||||||||||||
Utility Plant, Net | $ | 288.4 | — | $ | 288.4 | ||||||||
Nonutility Property and Investments, Net | 0.6 | $ | 40.1 | 40.7 | |||||||||
Current Assets | 6.5 | 3.9 | 10.4 | ||||||||||
Deferred Debits and Other Assets | 0.9 | 0.2 | 1.1 | ||||||||||
Total Assets Held for Sale | $ | 296.4 | $ | 44.2 | $ | 340.6 | |||||||
Liabilities Held for Sale | |||||||||||||
Current Liabilities | $ | 3.5 | $ | 2.2 | $ | 5.7 | |||||||
Deferred Credits and Other Liabilities | 42.9 | 3.1 | 46 | ||||||||||
Total Liabilities Held for Sale | $ | 46.4 | $ | 5.3 | $ | 51.7 | |||||||
QUARTERLY_FINANCIAL_INFORMATIO
QUARTERLY FINANCIAL INFORMATION QUARTERLY FINANCIAL INFORMATION (Notes) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Entity Information [Line Items] | |||||||||||||||||||||
Quarterly Financial Information [Text Block] | QUARTERLY FINANCIAL DATA (UNAUDITED) | ||||||||||||||||||||
Millions of dollars, except per share amounts | First | Second | Third | Fourth | Annual | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||
2014 | |||||||||||||||||||||
Total operating revenues | $ | 1,590 | $ | 1,026 | $ | 1,121 | $ | 1,214 | $ | 4,951 | |||||||||||
Operating income | 350 | 154 | 269 | 234 | 1,007 | ||||||||||||||||
Net income | 193 | 96 | 144 | 105 | 538 | ||||||||||||||||
Basic earnings per share | 1.37 | 0.68 | 1.01 | 0.73 | 3.79 | ||||||||||||||||
Diluted earnings per share | 1.37 | 0.68 | 1.01 | 0.73 | 3.79 | ||||||||||||||||
2013 | |||||||||||||||||||||
Total operating revenues | $ | 1,311 | $ | 1,016 | $ | 1,051 | $ | 1,117 | $ | 4,495 | |||||||||||
Operating income | 293 | 189 | 255 | 173 | 910 | ||||||||||||||||
Net income | 151 | 85 | 131 | 104 | 471 | ||||||||||||||||
Basic earnings per share | 1.13 | 0.6 | 0.94 | 0.73 | 3.4 | ||||||||||||||||
Diluted earnings per share | 1.11 | 0.6 | 0.94 | 0.73 | 3.39 | ||||||||||||||||
SCE&G | |||||||||||||||||||||
Entity Information [Line Items] | |||||||||||||||||||||
Quarterly Financial Information [Text Block] | QUARTERLY FINANCIAL DATA (UNAUDITED) | ||||||||||||||||||||
Millions of dollars | First | Second | Third | Fourth | Annual | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||
2014 | |||||||||||||||||||||
Total operating revenues | $ | 859 | $ | 698 | $ | 812 | $ | 722 | $ | 3,091 | |||||||||||
Operating income | 239 | 145 | 272 | 174 | 830 | ||||||||||||||||
Net Income | 126 | 99 | 157 | 76 | 458 | ||||||||||||||||
Earnings Available to Common Shareholder | 123 | 96 | 154 | 73 | 446 | ||||||||||||||||
2013 | |||||||||||||||||||||
Total operating revenues | $ | 728 | $ | 696 | $ | 776 | $ | 645 | $ | 2,845 | |||||||||||
Operating income | 191 | 180 | 255 | 111 | 737 | ||||||||||||||||
Net Income | 92 | 88 | 139 | 72 | 391 | ||||||||||||||||
Earnings Available to Common Shareholder | 89 | 85 | 136 | 70 | 380 | ||||||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Consolidation, Policy [Policy Text Block] | Organization and Principles of Consolidation | ||||||||||||||||
SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina. | |||||||||||||||||
The accompanying consolidated financial statements reflect the accounts of SCANA and the following wholly-owned subsidiaries. | |||||||||||||||||
Regulated businesses | Nonregulated businesses | ||||||||||||||||
South Carolina Electric & Gas Company | SCANA Energy Marketing, Inc. | ||||||||||||||||
South Carolina Fuel Company, Inc. | SCANA Communications, Inc. | ||||||||||||||||
South Carolina Generating Company, Inc. | ServiceCare, Inc. | ||||||||||||||||
Public Service Company of North Carolina, Incorporated | SCANA Services, Inc. | ||||||||||||||||
Carolina Gas Transmission Corporation | SCANA Corporate Security Services, Inc. | ||||||||||||||||
CGT and SCI were sold in the first quarter of 2015. Accordingly, the assets and liabilities of these entities are aggregated and shown as Assets held for sale and Liabilities held for sale in the December 31, 2014 consolidated balance sheet. See Note 13. | |||||||||||||||||
The Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. | |||||||||||||||||
Use of Estimates, Policy [Policy Text Block] | Use of Estimates | ||||||||||||||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Property, Plant and Equipment, Policy [Policy Text Block] | Utility Plant | ||||||||||||||||
Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. | |||||||||||||||||
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 7.2% for 2014, 6.9% for 2013 and 6.3% for 2012. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. | |||||||||||||||||
The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows: | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
SCE&G | 2.85 | % | 2.96 | % | 2.93 | % | |||||||||||
GENCO | 2.66 | % | 2.66 | % | 2.66 | % | |||||||||||
CGT | 2.11 | % | 2.19 | % | 2.09 | % | |||||||||||
PSNC Energy | 2.98 | % | 3.01 | % | 3.01 | % | |||||||||||
Weighted average of above | 2.84 | % | 2.93 | % | 2.9 | % | |||||||||||
SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. | |||||||||||||||||
Jointly Owned Plant Policy [Policy Text Block] | Jointly Owned Utility Plant | ||||||||||||||||
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion | |||||
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. | |||||||||||||||||
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $88.9 million at December 31, 2014 and $75.6 million at December 31, 2013. | |||||||||||||||||
Plant to be retired [Policy Text Block] | Plant to be Retired | ||||||||||||||||
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |||||||||||||||||
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block] | Major Maintenance | ||||||||||||||||
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued to regulatory assets in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the consolidated balance sheet (see Note 2). Other planned major maintenance is expensed when incurred. | |||||||||||||||||
Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2014 and 2013, SCE&G incurred $19.4 million and $18.1 million, respectively, for turbine maintenance. | |||||||||||||||||
Nuclear refueling outages are scheduled 18 months apart. SCE&G accrued $1.2 million per month from July 2011 through December 2012 for its portion of the outages in the fall of 2012. Total costs for the 2012 outage were $32.3 million, of which SCE&G was responsible for $21.5 million. In connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began to accrue $1.4 million per month for its portion of the nuclear refueling outages that are scheduled to occur from the spring of 2014 through the spring of 2020. Total costs for the 2014 outage were $43.7 million, of which SCE&G was responsible for $29.1 million. | |||||||||||||||||
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block] | Goodwill | ||||||||||||||||
The Company considers amounts categorized by FERC as “acquisition adjustments” to be goodwill. At December 31, 2014 and 2013, assets with a carrying value of $210 million (net of writedown of $230 million) for PSNC Energy (Gas Distribution segment) were classified as goodwill. Assets with a carrying value of $20 million for CGT (All Other segment) were classified as assets held for sale as of December 31, 2014 and as goodwill as of December 31, 2013. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. The goodwill impairment testing is generally a two-step quantitative process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Accounting guidance adopted by the Company gives it the option to first perform a qualitative assessment of impairment. Based on this qualitative ("step zero") assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with the two-step quantitative assessment. | |||||||||||||||||
In evaluations of PSNC Energy, fair value was estimated using the assistance of an independent appraisal. In evaluations of CGT, estimated fair value was obtained from discounted cash flow and other analysis as of January 1, 2014. In all evaluations for the periods presented, step one has indicated no impairment. The estimated fair values of the reporting units are substantially in excess of their carrying values, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense. | |||||||||||||||||
Nuclear Decommissiong [Policy Text Block] | Nuclear Decommissioning | ||||||||||||||||
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million, stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. | |||||||||||||||||
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2014, 2013 and 2012) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis. | |||||||||||||||||
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and Cash Equivalents | ||||||||||||||||
The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills. | |||||||||||||||||
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block] | Accounts Receivable | ||||||||||||||||
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. | |||||||||||||||||
Inventory, Policy [Policy Text Block] | Inventory | ||||||||||||||||
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC. | |||||||||||||||||
Asset Management and Supply Service Agreements [Policy Text Block] | Asset Management and Supply Service Agreements | ||||||||||||||||
PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. Such counterparties held 48% and 48% of PSNC Energy’s natural gas inventory at December 31, 2014 and December 31, 2013, respectively, with a carrying value of $26.1 million and $22.8 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. No fees are received under supply service agreements. The agreements expire March 31, 201 | |||||||||||||||||
Income Tax, Policy [Policy Text Block] | Income Taxes | ||||||||||||||||
The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense. | |||||||||||||||||
regulatory assets and regulatory liabilities [Policy Text Block] | Regulatory Assets and Regulatory Liabilities | ||||||||||||||||
The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs in the ratemaking process. | |||||||||||||||||
Debt Premium, Discount, and Expense [Policy Text Block] | Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt | ||||||||||||||||
The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. | |||||||||||||||||
Environmental Costs, Policy [Policy Text Block] | Environmental | ||||||||||||||||
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. | |||||||||||||||||
Income Statement policy [Policy Text Block] | Income Statement Presentation | ||||||||||||||||
The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). | |||||||||||||||||
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition | ||||||||||||||||
The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $186.4 million at December 31, 2014 and $183.1 million at December 31, 2013. | |||||||||||||||||
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent hearings. | |||||||||||||||||
SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. | |||||||||||||||||
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a pilot basis for its electric customers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC. See Note 2. | |||||||||||||||||
PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors. | |||||||||||||||||
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. | |||||||||||||||||
Earnings Per Share, Policy [Policy 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 Company has issued no securities that would have an antidilutive effect on earnings per share. | |||||||||||||||||
A reconciliation of the weighted average number of common shares for each of the three years ended December 31, for basic and diluted purposes is as follows: | |||||||||||||||||
In Millions | 2014 | 2013 | 2012 | ||||||||||||||
Weighted Average Shares Outstanding—Basic | 141.9 | 138.7 | 131.1 | ||||||||||||||
Net effect of equity forward contracts | — | 0.4 | 2.2 | ||||||||||||||
Weighted Average Shares Outstanding—Diluted | 141.9 | 139.1 | 133.3 | ||||||||||||||
New Accounting Matters [Policy Text Block] | New Accounting Matters | ||||||||||||||||
In April 2014, the Financial Accounting Standards Board issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this new guidance for the period ended December 31, 2014. | |||||||||||||||||
In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Company will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position. | |||||||||||||||||
SCE&G | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Consolidation, Policy [Policy Text Block] | Organization and Principles of Consolidation | ||||||||||||||||
SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA, a South Carolina corporation. Consolidated SCE&G engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. | |||||||||||||||||
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs), and accordingly, the accompanying 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. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements. Intercompany balances and transactions between SCE&G, Fuel Company and GENCO have been eliminated in consolidation. | |||||||||||||||||
GENCO owns a coal-fired electric generating station with a 605 megawatt 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 $472 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4. | |||||||||||||||||
Use of Estimates, Policy [Policy Text Block] | Use of Estimates | ||||||||||||||||
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. | |||||||||||||||||
Property, Plant and Equipment, Policy [Policy Text Block] | Utility Plant | ||||||||||||||||
Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. | |||||||||||||||||
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. Consolidated SCE&G calculated AFC using average composite rates of 6.5% for 2014, 6.9% for 2013 | |||||||||||||||||
and 6.3% for 2012. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred. | |||||||||||||||||
Consolidated SCE&G records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.84% in 2014, 2.94% in 2013 and 2.91% in 2012. | |||||||||||||||||
SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel. | |||||||||||||||||
Jointly Owned Plant Policy [Policy Text Block] | Jointly Owned Utility Plant | ||||||||||||||||
SCE&G jointly owns and is the operator of Summer Station Unit 1. In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit. SCE&G's share of the direct expenses is included in the corresponding operating expenses on its income statement. | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion | |||||
SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. For a discussion of expected cash outlays and expected in-service dates for the New Units and a description of SCE&G's agreement to acquire an additional 5% ownership in the New Units, see Note 10. | |||||||||||||||||
Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $88.9 million at December 31, 2014 and $75.6 million at December 31, 2013. | |||||||||||||||||
Plant to be retired [Policy Text Block] | Plant to be Retired | ||||||||||||||||
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |||||||||||||||||
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block] | Major Maintenance | ||||||||||||||||
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued to regulatory assets in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections are classified as a regulatory asset or regulatory liability on the balance sheet (see Note 2). Other planned major maintenance is expensed when incurred. | |||||||||||||||||
Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2014 and 2013, SCE&G incurred $19.4 million and $18.1 million, respectively, for turbine maintenance. | |||||||||||||||||
Nuclear refueling outages are scheduled 18 months apart. SCE&G accrued $1.2 million per month from July 2011 through December 2012 for its portion of the outages in the fall of 2012. Total costs for the 2012 outage were $32.3 million, of which SCE&G was responsible for $21.5 million. In connection with the SCPSC's December 2012 approval of SCE&G's retail electric rates (see Note 2), effective January 1, 2013, SCE&G began to accrue $1.4 million per month for its portion of the nuclear refueling outages that are scheduled to occur from the spring of 2014 through the spring of 2020. Total costs for the 2014 outage were $43.7 million, of which SCE&G was responsible for $29.1 million. | |||||||||||||||||
Nuclear Decommissiong [Policy Text Block] | Nuclear Decommissioning | ||||||||||||||||
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $696.8 million, stated in 2012 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. | |||||||||||||||||
Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2014, 2013 and 2012) are invested in insurance policies on the lives of certain SCE&G and affiliate personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis. | |||||||||||||||||
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and Cash Equivalents | ||||||||||||||||
Consolidated SCE&G considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements and treasury bills. | |||||||||||||||||
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block] | Accounts Receivable | ||||||||||||||||
Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. | |||||||||||||||||
Inventory, Policy [Policy Text Block] | Inventory | ||||||||||||||||
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas and fuel oil. Fuel is charged to inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC. Emission allowances are included in inventory at average cost. Emission allowances are expensed at weighted average cost as used and recovered through fuel cost recovery rates approved by the SCPSC. | |||||||||||||||||
Income tax presentation policy [Policy Text Block] | Income Taxes | ||||||||||||||||
Consolidated SCE&G is included in the consolidated federal income tax return of SCANA. Under a joint consolidated income tax allocation agreement, each SCANA subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. | |||||||||||||||||
regulatory assets and regulatory liabilities [Policy Text Block] | Regulatory Assets and Regulatory Liabilities | ||||||||||||||||
Consolidated SCE&G records costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense or revenues would be recognized by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (see Note 2) and are amortized consistent with the treatment of the related costs in the ratemaking process. | |||||||||||||||||
Debt Premium, Discount, and Expense [Policy Text Block] | Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt | ||||||||||||||||
Consolidated SCE&G records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges. | |||||||||||||||||
Environmental Costs, Policy [Policy Text Block] | Environmental | ||||||||||||||||
SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred. | |||||||||||||||||
Income Statement policy [Policy Text Block] | Income Statement Presentation | ||||||||||||||||
Consolidated SCE&G presents the revenues and expenses of its regulated activities (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense). | |||||||||||||||||
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition | ||||||||||||||||
Consolidated SCE&G records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered but not billed. Unbilled revenues totaled $115.8 million at December 31, 2014 and $111.9 million at December 31, 2013. | |||||||||||||||||
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent hearings. | |||||||||||||||||
Customers subject to the PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. | |||||||||||||||||
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a pilot basis for its electric customers; effective with the first billing cycle of 2014, the eWNA was discontinued as approved by the SCPSC. See Note 2. | |||||||||||||||||
Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of income. | |||||||||||||||||
New Accounting Matters [Policy Text Block] | New Accounting Matters | ||||||||||||||||
In April 2014, the Financial Accounting Standards Board issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, Consolidated SCE&G adopted this new guidance for the period ended December 31, 2014. | |||||||||||||||||
In May 2014, the Financial Accounting Standards Board issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Consolidated SCE&G will be required to adopt the new guidance in the first quarter of 2017, and early adoption is not permitted. Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Schedule of weighted avg depreciation rates [Table Text Block] | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
SCE&G | 2.85 | % | 2.96 | % | 2.93 | % | |||||||||||
GENCO | 2.66 | % | 2.66 | % | 2.66 | % | |||||||||||
CGT | 2.11 | % | 2.19 | % | 2.09 | % | |||||||||||
PSNC Energy | 2.98 | % | 3.01 | % | 3.01 | % | |||||||||||
Weighted average of above | 2.84 | % | 2.93 | % | 2.9 | % | |||||||||||
Schedule of Jointly Owned Utility Plants [Table Text Block] | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion | |||||
Schedule of Weighted Average Number of Shares [Table Text Block] | |||||||||||||||||
In Millions | 2014 | 2013 | 2012 | ||||||||||||||
Weighted Average Shares Outstanding—Basic | 141.9 | 138.7 | 131.1 | ||||||||||||||
Net effect of equity forward contracts | — | 0.4 | 2.2 | ||||||||||||||
Weighted Average Shares Outstanding—Diluted | 141.9 | 139.1 | 133.3 | ||||||||||||||
SCE&G | |||||||||||||||||
Significant Accounting Policies | |||||||||||||||||
Schedule of Jointly Owned Utility Plants [Table Text Block] | |||||||||||||||||
As of December 31, | 2014 | 2013 | |||||||||||||||
Unit 1 | New Units | Unit 1 | New Units | ||||||||||||||
Percent owned | 66.70% | 55.00% | 66.70% | 55.00% | |||||||||||||
Plant in service | $ | 1.2 | billion | — | $ | 1.1 | billion | — | |||||||||
Accumulated depreciation | $ | 578.3 | million | — | $ | 566.9 | million | — | |||||||||
Construction work in progress | $ | 199.3 | million | $ | 2.7 | billion | $ | 127.1 | million | $ | 2.3 | billion |
RATE_AND_OTHER_REGULATORY_MATT1
RATE AND OTHER REGULATORY MATTERS (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Public Utilities, General Disclosures | ||||||||||
Demand reduction programs [Table Text Block] | ||||||||||
Year | Effective | Amount | ||||||||
2014 | First billing cycle of May | $15.4 million | ||||||||
2013 | First billing cycle of May | $16.9 million | ||||||||
2012 | First billing cycle of May | $19.6 million | ||||||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | : | |||||||||
Year | Increase | Amount | ||||||||
2014 | 2.80% | $66.2 million | ||||||||
2013 | 2.90% | $67.2 million | ||||||||
2012 | 2.30% | $52.1 million | ||||||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | : | |||||||||
Year | Action | Amount | ||||||||
2014 | 0.6 | % | Decrease | $2.6 million | ||||||
2013 | No change | |||||||||
2012 | 2.1 | % | Increase | $7.5 million | ||||||
Schedule of Regulatory Assets [Table Text Block] | . | |||||||||
December 31, | ||||||||||
Millions of dollars | 2014 | 2013 | ||||||||
Regulatory Assets: | ||||||||||
Accumulated deferred income taxes | $ | 284 | $ | 259 | ||||||
Under-collections—electric fuel adjustment clause | 20 | 18 | ||||||||
Environmental remediation costs | 40 | 41 | ||||||||
AROs and related funding | 366 | 368 | ||||||||
Franchise agreements | 26 | 31 | ||||||||
Deferred employee benefit plan costs | 350 | 238 | ||||||||
Planned major maintenance | 2 | — | ||||||||
Deferred losses on interest rate derivatives | 453 | 124 | ||||||||
Deferred pollution control costs | 36 | 37 | ||||||||
Unrecovered plant | 137 | 145 | ||||||||
DSM Programs | 56 | 51 | ||||||||
Other | 53 | 48 | ||||||||
Total Regulatory Assets | $ | 1,823 | $ | 1,360 | ||||||
Schedule of Regulatory Liabilities [Table Text Block] | ||||||||||
Regulatory Liabilities: | ||||||||||
Accumulated deferred income taxes | $ | 22 | $ | 24 | ||||||
Asset removal costs | 703 | 695 | ||||||||
Storm damage reserve | 6 | 27 | ||||||||
Monetization of bankruptcy claim | — | 29 | ||||||||
Deferred gains on interest rate derivatives | 82 | 181 | ||||||||
Planned major maintenance | — | 10 | ||||||||
Other | 1 | — | ||||||||
Total Regulatory Liabilities | $ | 814 | $ | 966 | ||||||
SCE&G | ||||||||||
Public Utilities, General Disclosures | ||||||||||
Demand reduction programs [Table Text Block] | ||||||||||
Year | Effective | Amount | ||||||||
2014 | First billing cycle of May | $15.4 million | ||||||||
2013 | First billing cycle of May | $16.9 million | ||||||||
2012 | First billing cycle of May | $19.6 million | ||||||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | ||||||||||
Year | Increase | Amount | ||||||||
2014 | 2.80% | $66.2 million | ||||||||
2013 | 2.90% | $67.2 million | ||||||||
2012 | 2.30% | $52.1 million | ||||||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | ||||||||||
Year | Action | Amount | ||||||||
2014 | 0.6 | % | Decrease | $ | 2.6 | million | ||||
2013 | No change | |||||||||
2012 | 2.1 | % | Increase | $ | 7.5 | million | ||||
Schedule of Regulatory Assets [Table Text Block] | . | |||||||||
December 31, | ||||||||||
Millions of dollars | 2014 | 2013 | ||||||||
Regulatory Assets: | ||||||||||
Accumulated deferred income taxes | $ | 278 | $ | 256 | ||||||
Under-collections-electric fuel adjustment clause | 20 | 18 | ||||||||
Environmental remediation costs | 36 | 37 | ||||||||
AROs and related funding | 347 | 350 | ||||||||
Franchise agreements | 26 | 31 | ||||||||
Deferred employee benefit plan costs | 310 | 215 | ||||||||
Planned major maintenance | 2 | — | ||||||||
Deferred losses on interest rate derivatives | 453 | 124 | ||||||||
Deferred pollution control costs | 36 | 37 | ||||||||
Unrecovered plant | 137 | 145 | ||||||||
DSM Programs | 56 | 51 | ||||||||
Other | 44 | 39 | ||||||||
Total Regulatory Assets | $ | 1,745 | $ | 1,303 | ||||||
Schedule of Regulatory Liabilities [Table Text Block] | ||||||||||
Regulatory Liabilities: | ||||||||||
Accumulated deferred income taxes | $ | 17 | $ | 19 | ||||||
Asset removal costs | 505 | 495 | ||||||||
Storm damage reserve | 6 | 27 | ||||||||
Deferred gains on interest rate derivatives | 82 | 181 | ||||||||
Planned major maintenance | — | 10 | ||||||||
Total Regulatory Liabilities | $ | 610 | $ | 732 | ||||||
LONGTERM_AND_SHORTTERM_DEBT_Ta
LONG-TERM AND SHORT-TERM DEBT (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Schedule of Debt [Table Text Block] | : | ||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Dollars in millions | Maturity | Balance | Rate | Balance | Rate | ||||||||||||||||||||
Medium Term Notes (unsecured) | 2020 | - | 2022 | $ | 800 | 5.42 | % | $ | 800 | 5.42 | % | ||||||||||||||
Senior Notes (unsecured) (a) | 2015 | - | 2034 | 88 | 0.93 | % | 92 | 0.94 | % | ||||||||||||||||
First Mortgage Bonds (secured) | 2018 | - | 2064 | 3,840 | 5.56 | % | 3,540 | 5.6 | % | ||||||||||||||||
Junior Subordinated Notes (unsecured) (b) | 2065 | 150 | 7.92 | % | 150 | 7.92 | % | ||||||||||||||||||
GENCO Notes (secured) | 2015 | - | 2024 | 227 | 5.9 | % | 233 | 5.89 | % | ||||||||||||||||
Industrial and Pollution Control Bonds (c) | 2028 | - | 2038 | 122 | 3.51 | % | 158 | 3.83 | % | ||||||||||||||||
Senior Debentures | 2020 | - | 2026 | 350 | 5.93 | % | 350 | 5.93 | % | ||||||||||||||||
Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | 100 | 0.78 | % | ||||||||||||||||||
Other | 2015 | - | 2027 | 17 | 2.9 | % | 20 | 2.73 | % | ||||||||||||||||
Total debt | 5,694 | 5,443 | |||||||||||||||||||||||
Current maturities of long-term debt | (166 | ) | (54 | ) | |||||||||||||||||||||
Unamortized premium | 3 | 6 | |||||||||||||||||||||||
Total long-term debt, net | $ | 5,531 | $ | 5,395 | |||||||||||||||||||||
Schedule of Maturities of Long-term Debt [Table Text Block] | The annual amounts of long-term debt maturities for the next five years are summarized as follows: | ||||||||||||||||||||||||
Year | Millions | ||||||||||||||||||||||||
of dollars | |||||||||||||||||||||||||
2015 | $ | 166 | |||||||||||||||||||||||
2016 | 115 | ||||||||||||||||||||||||
2017 | 14 | ||||||||||||||||||||||||
2018 | 723 | ||||||||||||||||||||||||
2019 | 13 | ||||||||||||||||||||||||
Schedule of Line of Credit Facilities [Text Block] | |||||||||||||||||||||||||
SCANA | SCE&G | PSNC Energy | |||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
Lines of Credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | 300 | 1,400 | 1,400 | 100 | 100 | ||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 179 | $ | 125 | $ | 709 | $ | 251 | $ | 30 | — | ||||||||||||||
Weighted average interest rate | 0.54 | % | 0.39 | % | 0.52 | % | 0.27 | % | 0.65 | % | — | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 118 | $ | 172 | $ | 691 | $ | 1,149 | $ | 70 | $ | 100 | |||||||||||||
SCE&G | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Schedule of Debt [Table Text Block] | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Dollars in millions | Maturity | Balance | Rate | Balance | Rate | ||||||||||||||||||||
First Mortgage Bonds (secured) | 2018 | - | 2064 | $ | 3,840 | 5.56 | % | $ | 3,540 | 5.6 | % | ||||||||||||||
GENCO Notes (secured) | 2015 | - | 2024 | 227 | 5.9 | % | 233 | 5.89 | % | ||||||||||||||||
Industrial and Pollution Control Bonds (a) | 2028 | - | 2038 | 122 | 3.51 | % | 158 | 3.83 | % | ||||||||||||||||
Nuclear Fuel Financing | 2016 | 100 | 0.78 | % | 100 | 0.78 | % | ||||||||||||||||||
Other | 2015 | - | 2027 | 14 | 2.63 | % | 16 | 2.26 | % | ||||||||||||||||
Total debt | 4,303 | 4,047 | |||||||||||||||||||||||
Current maturities of long-term debt | (10 | ) | (48 | ) | |||||||||||||||||||||
Unamortized premium | 6 | 8 | |||||||||||||||||||||||
Total long-term debt, net | $ | 4,299 | $ | 4,007 | |||||||||||||||||||||
Schedule of Maturities of Long-term Debt [Table Text Block] | : | ||||||||||||||||||||||||
Year | Millions of dollars | ||||||||||||||||||||||||
2015 | $ | 10 | |||||||||||||||||||||||
2016 | 109 | ||||||||||||||||||||||||
2017 | 9 | ||||||||||||||||||||||||
2018 | 719 | ||||||||||||||||||||||||
2019 | 8 | ||||||||||||||||||||||||
Schedule of Line of Credit Facilities [Text Block] | : | ||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 709 | $ | 251 | |||||||||||||||||||||
Weighted average interest rate | 0.52 | % | 0.27 | % | |||||||||||||||||||||
Letters of credit supported by an LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 691 | $ | 1,149 | |||||||||||||||||||||
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | : | ||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Current taxes: | |||||||||||||
Federal | $ | 38 | $ | 161 | $ | 103 | |||||||
State | (4 | ) | 17 | 10 | |||||||||
Total current taxes | 34 | 178 | 113 | ||||||||||
Deferred taxes, net: | |||||||||||||
Federal | 184 | 39 | 72 | ||||||||||
State | 34 | 10 | 14 | ||||||||||
Total deferred taxes | 218 | 49 | 86 | ||||||||||
Investment tax credits: | |||||||||||||
Amortization of amounts deferred-state | (1 | ) | (1 | ) | (14 | ) | |||||||
Amortization of amounts deferred-federal | (3 | ) | (3 | ) | (3 | ) | |||||||
Total investment tax credits | (4 | ) | (4 | ) | (17 | ) | |||||||
Total income tax expense | $ | 248 | $ | 223 | $ | 182 | |||||||
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | : | ||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Net income | $ | 538 | $ | 471 | $ | 420 | |||||||
Income tax expense | 248 | 223 | 182 | ||||||||||
Total pre-tax income | $ | 786 | $ | 694 | $ | 602 | |||||||
Income taxes on above at statutory federal income tax rate | $ | 275 | $ | 243 | $ | 211 | |||||||
Increases (decreases) attributed to: | |||||||||||||
State income taxes (less federal income tax effect) | 24 | 22 | 19 | ||||||||||
State investment tax credits (less federal income tax effect) | (5 | ) | (5 | ) | (13 | ) | |||||||
Allowance for equity funds used during construction | (11 | ) | (9 | ) | (8 | ) | |||||||
Deductible dividends—Stock Purchase Savings Plan | (10 | ) | (10 | ) | (9 | ) | |||||||
Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | |||||||
Section 41 tax credits | (3 | ) | — | — | |||||||||
Section 45 tax credits | (9 | ) | (5 | ) | (5 | ) | |||||||
Domestic production activities deduction | (7 | ) | (11 | ) | (9 | ) | |||||||
Other differences, net | (3 | ) | 1 | (1 | ) | ||||||||
Total income tax expense | $ | 248 | $ | 223 | $ | 182 | |||||||
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | : | ||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||
Deferred tax assets: | |||||||||||||
Nondeductible accruals | $ | 127 | $ | 84 | |||||||||
Asset retirement obligation, including nuclear decommissioning | 216 | 220 | |||||||||||
Financial instruments | 40 | 32 | |||||||||||
Unamortized investment tax credits | 17 | 19 | |||||||||||
Regulatory liability, net gain on interest rate derivative contracts settlement | — | 27 | |||||||||||
Monetization of bankruptcy claim | 10 | 11 | |||||||||||
Other | 10 | 13 | |||||||||||
Total deferred tax assets | 420 | 406 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property, plant and equipment | $ | 1,928 | $ | 1,765 | |||||||||
Deferred employee benefit plan costs | 107 | 63 | |||||||||||
Regulatory asset, asset retirement obligation | 122 | 121 | |||||||||||
Deferred fuel costs | 27 | 25 | |||||||||||
Regulatory asset, unrecovered plant | 53 | 55 | |||||||||||
Regulatory asset, net loss on interest rate derivative contracts settlement | 21 | — | |||||||||||
Demand side management costs | 21 | 21 | |||||||||||
Prepayments | 27 | 25 | |||||||||||
Other | 45 | 38 | |||||||||||
Total deferred tax liabilities | 2,351 | 2,113 | |||||||||||
Net deferred tax liability | $ | 1,931 | $ | 1,707 | |||||||||
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits, January 1 | $ | 3 | — | $ | 38 | ||||||||
Gross increases—uncertain tax positions in prior period | — | — | — | ||||||||||
Gross decreases—uncertain tax positions in prior period | — | — | (38 | ) | |||||||||
Gross increases—current period uncertain tax positions | 13 | $ | 3 | — | |||||||||
Settlements | — | — | — | ||||||||||
Lapse of statute of limitations | — | — | — | ||||||||||
Unrecognized tax benefits, December 31 | $ | 16 | $ | 3 | $ | — | |||||||
SCE&G | |||||||||||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Current taxes: | |||||||||||||
Federal | $ | 39 | $ | 146 | $ | 91 | |||||||
State | (6 | ) | 13 | 8 | |||||||||
Total current taxes | 33 | 159 | 99 | ||||||||||
Deferred taxes, net: | |||||||||||||
Federal | 157 | 25 | 62 | ||||||||||
State | 32 | 9 | 12 | ||||||||||
Total deferred taxes | 189 | 34 | 74 | ||||||||||
Investment tax credits: | |||||||||||||
Amortization of amounts deferred—state | (1 | ) | (1 | ) | (13 | ) | |||||||
Amortization of amounts deferred—federal | (3 | ) | (3 | ) | (3 | ) | |||||||
Total investment tax credits | (4 | ) | (4 | ) | (16 | ) | |||||||
Total income tax expense | $ | 218 | $ | 189 | $ | 157 | |||||||
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Net income | $ | 446 | $ | 380 | $ | 341 | |||||||
Income tax expense | 218 | 189 | 157 | ||||||||||
Noncontrolling interest | 12 | 11 | 11 | ||||||||||
Total pre-tax income | $ | 676 | $ | 580 | $ | 509 | |||||||
Income taxes on above at statutory federal income tax rate | $ | 237 | $ | 203 | $ | 178 | |||||||
Increases (decreases) attributed to: | |||||||||||||
State income taxes (less federal income tax effect) | 21 | 18 | 17 | ||||||||||
State investment tax credits (less federal income tax effect) | (5 | ) | (5 | ) | (13 | ) | |||||||
Allowance for equity funds used during construction | (10 | ) | (9 | ) | (7 | ) | |||||||
Amortization of federal investment tax credits | (3 | ) | (3 | ) | (3 | ) | |||||||
Section 41 tax credits | (3 | ) | — | — | |||||||||
Section 45 tax credits | (9 | ) | (5 | ) | (5 | ) | |||||||
Domestic production activities deduction | (7 | ) | (11 | ) | (9 | ) | |||||||
Other differences, net | (3 | ) | 1 | (1 | ) | ||||||||
Total income tax expense | $ | 218 | $ | 189 | $ | 157 | |||||||
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | |||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||
Deferred tax assets: | |||||||||||||
Nondeductible accruals | $ | 47 | $ | 17 | |||||||||
Asset retirement obligation, including nuclear decommissioning | 205 | 209 | |||||||||||
Unamortized investment tax credits | 17 | 19 | |||||||||||
Regulatory liability, net gain on interest rate derivative contracts settlement | — | 27 | |||||||||||
Other | 6 | 11 | |||||||||||
Total deferred tax assets | 275 | 283 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Property, plant and equipment | $ | 1,623 | $ | 1,494 | |||||||||
Regulatory asset, asset retirement obligation | 115 | 114 | |||||||||||
Deferred employee benefit plan costs | 91 | 54 | |||||||||||
Deferred fuel costs | 27 | 26 | |||||||||||
Regulatory asset, unrecovered plant | 53 | 55 | |||||||||||
Regulatory asset, net loss on interest rate derivative contracts settlement | 21 | — | |||||||||||
Demand side management costs | 21 | 21 | |||||||||||
Prepayments | 25 | 23 | |||||||||||
Other | 23 | 18 | |||||||||||
Total deferred tax liabilities | 1,999 | 1,805 | |||||||||||
Net deferred tax liability | $ | 1,724 | $ | 1,522 | |||||||||
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | |||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | ||||||||||
Unrecognized tax benefits, January 1 | $ | 3 | — | $ | 38 | ||||||||
Gross increases-uncertain tax positions in prior period | — | — | — | ||||||||||
Gross decreases-uncertain tax positions in prior period | — | — | (38 | ) | |||||||||
Gross increases-current period uncertain tax positions | 13 | $ | 3 | — | |||||||||
Settlements | — | — | — | ||||||||||
Lapse of statute of limitations | — | — | — | ||||||||||
Unrecognized tax benefits, December 31 | $ | 16 | $ | 3 | $ | — | |||||||
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended | ||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||
Schedule of Derivative Instruments [Table Text Block] | The Company was party to natural gas derivative contracts outstanding in the following quantities: | ||||||||||||||||||||||
Commodity and Other Energy Management Contracts (in MMBTU) | |||||||||||||||||||||||
Hedge designation | Gas Distribution | Retail Gas | Energy Marketing | Total | |||||||||||||||||||
Marketing | |||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Commodity | 6,840,000 | 7,951,000 | 3,446,720 | 18,237,720 | |||||||||||||||||||
Energy Management (a) | — | — | 37,495,339 | 37,495,339 | |||||||||||||||||||
Total (a) | 6,840,000 | 7,951,000 | 40,942,059 | 55,733,059 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Commodity | 6,070,000 | 6,726,000 | 2,560,000 | 15,356,000 | |||||||||||||||||||
Energy Management (b) | — | — | 27,359,958 | 27,359,958 | |||||||||||||||||||
Total (b) | 6,070,000 | 6,726,000 | 29,919,958 | 42,715,958 | |||||||||||||||||||
(a) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
(b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The fair value of derivatives in the consolidated balance sheets is as follows: | ||||||||||||||||||||||
Fair Values of Derivative Instruments | Asset Derivatives | Liability Derivatives | |||||||||||||||||||||
Millions of dollars | Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||
Location | Value | Location | Value | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 28 | ||||||||||||||||||||||
Commodity contracts | Other current assets | 1 | |||||||||||||||||||||
Derivative financial instruments | 11 | ||||||||||||||||||||||
Total | $ | 45 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | ||||||||||||||||||||
Other deferred credits and other liabilities | 17 | ||||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | ||||||||||||||||||||
Energy management contracts | Other current assets | 15 | Other current assets | 5 | |||||||||||||||||||
Derivative financial instruments | 10 | ||||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | ||||||||||||||||||||
Total | $ | 21 | $ | 244 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 14 | ||||||||||||||||||||||
Commodity contracts | Other current assets | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 19 | |||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other current assets | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Commodity contracts | Other current assets | 2 | |||||||||||||||||||||
Energy management contracts | Other current assets | 4 | Derivative financial instruments | 4 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 42 | $ | 9 | |||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The effect of derivative instruments on the consolidated statements of income is as follows: | ||||||||||||||||||||||
Gain or (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | Location | Amount | ||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (9 | ) | Interest expense | $ | (3 | ) | ||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 106 | Interest expense | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | 84 | Interest expense | $ | (3 | ) | |||||||||||||||||
Gain or (Loss) | Gain (Loss) Reclassified from AOCI into Income, | ||||||||||||||||||||||
Recognized in OCI, net of tax | net of tax (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | Location | Amount | ||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (6 | ) | Interest expense | $ | (7 | ) | ||||||||||||||||
Commodity contracts | (8 | ) | Gas purchased for resale | 4 | |||||||||||||||||||
Total | $ | (14 | ) | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 5 | Interest expense | $ | (8 | ) | |||||||||||||||||
Commodity contracts | 2 | Gas purchased for resale | (3 | ) | |||||||||||||||||||
Total | $ | 7 | $ | (11 | ) | ||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | (4 | ) | Interest expense | $ | (6 | ) | ||||||||||||||||
Commodity contracts | (4 | ) | Gas purchased for resale | (13 | ) | ||||||||||||||||||
Total | $ | (8 | ) | $ | (19 | ) | |||||||||||||||||
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 | ||||||||||||||||||||||
Loss Recognized in Income | Year Ended December 31, | ||||||||||||||||||||||
Millions of dollars | Location | 2014 | 2013 | 2012 | |||||||||||||||||||
Commodity contracts | Gas purchased for resale | — | — | $ | (1 | ) | |||||||||||||||||
Gain (Loss) Deferred in Regulatory Accounts | Gain Reclassified from | ||||||||||||||||||||||
Deferred Accounts into Income | |||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (352 | ) | Other income | $ | 64 | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 39 | Other income | $ | 50 | ||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | — | — | |||||||||||||||||||||
Offsetting Assets [Table Text Block] | Information related to the Company's offsetting derivative assets and liabilities follows: | ||||||||||||||||||||||
Offsetting Derivative Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Commodity | $ | 1 | — | $ | 1 | — | — | $ | 1 | ||||||||||||||
Energy Management | 20 | — | 20 | — | — | 20 | |||||||||||||||||
Total | $ | 21 | — | $ | 21 | — | — | $ | 21 | ||||||||||||||
Balance sheet location | Other current assets | $ | 16 | ||||||||||||||||||||
Other deferred debits and other assets | 5 | ||||||||||||||||||||||
Total | $ | 21 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
Energy Management | 8 | — | 8 | — | — | 8 | |||||||||||||||||
Total | $ | 44 | — | $ | 44 | $ | (1 | ) | — | $ | 43 | ||||||||||||
Balance sheet location | Other current assets | $ | 21 | ||||||||||||||||||||
Other deferred debits and other assets | 23 | ||||||||||||||||||||||
Total | $ | 44 | |||||||||||||||||||||
Offsetting Derivative Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 257 | — | $ | 257 | — | $ | (131 | ) | $ | 126 | ||||||||||||
Commodity | 12 | — | 12 | — | (10 | ) | 2 | ||||||||||||||||
Energy Management | 20 | — | 20 | — | (11 | ) | 9 | ||||||||||||||||
Total | $ | 289 | — | $ | 289 | — | $ | (152 | ) | $ | 137 | ||||||||||||
Balance sheet location | Other current assets | $ | 6 | ||||||||||||||||||||
Derivative financial instruments | 233 | ||||||||||||||||||||||
Other deferred credits and other liabilities | 50 | ||||||||||||||||||||||
Total | $ | 289 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | (19 | ) | — | |||||||||||
Energy Management | 8 | — | 8 | — | (6 | ) | $ | 2 | |||||||||||||||
Total | $ | 28 | — | $ | 28 | $ | (1 | ) | $ | (25 | ) | $ | 2 | ||||||||||
Balance sheet location | Derivative financial instruments | $ | 10 | ||||||||||||||||||||
Other deferred credits and other liabilities | 18 | ||||||||||||||||||||||
Total | $ | 28 | |||||||||||||||||||||
Offsetting Liabilities [Table Text Block] | |||||||||||||||||||||||
Offsetting Derivative Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 257 | — | $ | 257 | — | $ | (131 | ) | $ | 126 | ||||||||||||
Commodity | 12 | — | 12 | — | (10 | ) | 2 | ||||||||||||||||
Energy Management | 20 | — | 20 | — | (11 | ) | 9 | ||||||||||||||||
Total | $ | 289 | — | $ | 289 | — | $ | (152 | ) | $ | 137 | ||||||||||||
Balance sheet location | Other current assets | $ | 6 | ||||||||||||||||||||
Derivative financial instruments | 233 | ||||||||||||||||||||||
Other deferred credits and other liabilities | 50 | ||||||||||||||||||||||
Total | $ | 289 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | (19 | ) | — | |||||||||||
Energy Management | 8 | — | 8 | — | (6 | ) | $ | 2 | |||||||||||||||
Total | $ | 28 | — | $ | 28 | $ | (1 | ) | $ | (25 | ) | $ | 2 | ||||||||||
Balance sheet location | Derivative financial instruments | $ | 10 | ||||||||||||||||||||
Other deferred credits and other liabilities | 18 | ||||||||||||||||||||||
Total | $ | 28 | |||||||||||||||||||||
SCE&G | |||||||||||||||||||||||
Derivative [Line Items] | |||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The fair value of derivatives in the consolidated balance sheets is as follows: | ||||||||||||||||||||||
Fair Values of Derivative Instruments | Asset Derivatives | Liability Derivatives | |||||||||||||||||||||
Millions of dollars | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair | |||||||||||||||||||
Value | |||||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Other deferred credits and other liabilities | 8 | ||||||||||||||||||||||
Total | $ | 9 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | ||||||||||||||||||||
Other deferred credits and other liabilities | 17 | ||||||||||||||||||||||
Total | $ | 224 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Total | $ | 1 | |||||||||||||||||||||
Not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other current assets | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | $ | 1 | |||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The effect of derivative instruments on the consolidated statements of income is as follows: | ||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Deferred | Gain (Loss) Reclassified from | |||||||||||||||||||||
in Regulatory Accounts (Effective Portion) | Deferred Accounts into Income | ||||||||||||||||||||||
(Effective Portion) | |||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (9 | ) | Interest expense | $ | (3 | ) | ||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | $ | 106 | Interest expense | $ | (3 | ) | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | $ | 84 | Interest expense | $ | (3 | ) | |||||||||||||||||
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 | Loss Recognized in Income | Year Ended December 31, | |||||||||||||||||||||
Millions of dollars | Location | 2014 | 2013 | 2012 | |||||||||||||||||||
Commodity contracts | Gas purchased for resale | — | — | $ | (1 | ) | |||||||||||||||||
Gain or (Loss) Deferred | Gain Reclassified from | ||||||||||||||||||||||
in Regulatory Accounts | Deferred Accounts into Income | ||||||||||||||||||||||
Millions of dollars | Location | Amount | |||||||||||||||||||||
Year Ended December 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (352 | ) | Other income | $ | 64 | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||||||||
Interest rate contracts | 39 | Other income | 50 | ||||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||
Interest rate contracts | — | Other income | — | ||||||||||||||||||||
Offsetting Assets [Table Text Block] | Information related to Consolidated SCE&G's offsetting derivative assets and liabilities follows: | ||||||||||||||||||||||
Offsetting Derivative Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | — | — | — | — | — | — | |||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Balance sheet location | Other current assets | $ | 13 | ||||||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | |||||||||||||||||||||
Offsetting Liabilities [Table Text Block] | |||||||||||||||||||||||
Offsetting Derivative Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | |||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of December 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 233 | — | $ | 233 | — | $ | (107 | ) | $ | 126 | ||||||||||||
Balance sheet location | Derivative financial instruments | $ | 208 | ||||||||||||||||||||
Other deferred credits and other liabilities | 25 | ||||||||||||||||||||||
Total | $ | 233 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (1 | ) | $ | (1 | ) | $ | — | ||||||||||
Balance sheet location | Derivative financial instruments | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD1
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Table Text Block] | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 13 | — | $ | 9 | — | |||||||||||
Interest rate contracts | — | — | — | $ | 32 | ||||||||||||
Commodity contracts | 1 | — | 2 | 2 | |||||||||||||
Energy management contracts | — | $ | 20 | 1 | 7 | ||||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 257 | — | 20 | |||||||||||||
Commodity contracts | 1 | 11 | — | — | |||||||||||||
Energy management contracts | 5 | 18 | — | 12 | |||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,697.20 | $ | 6,592.10 | $ | 5,449.30 | $ | 5,916.30 | |||||||||
SCE&G | |||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Table Text Block] | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 2 | Level 2 | |||||||||||||||
Assets-Interest rate contracts | — | $ | 32 | ||||||||||||||
Liabilities-Interest rate contracts | $ | 233 | 2 | ||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | |||||||||||||||||
As of December 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 4,308.60 | $ | 5,070.90 | $ | 4,054.90 | $ | 4,433.00 | |||||||||
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||
Schedule of Changes in Projected Benefit Obligations [Table Text Block] | The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Benefit obligation, January 1 | $ | 823 | $ | 931.6 | $ | 238 | $ | 265.3 | |||||||||||||||||||||
Service cost | 20 | 21.8 | 4.6 | 5.9 | |||||||||||||||||||||||||
Interest cost | 40.4 | 38.5 | 12 | 11.1 | |||||||||||||||||||||||||
Plan participants’ contributions | — | — | 2.2 | 2.6 | |||||||||||||||||||||||||
Actuarial (gain) loss | 100.1 | (83.4 | ) | 23.5 | (35.1 | ) | |||||||||||||||||||||||
Benefits paid | (64.0 | ) | (60.0 | ) | (12.1 | ) | (11.8 | ) | |||||||||||||||||||||
Curtailment | — | (25.5 | ) | — | — | ||||||||||||||||||||||||
Benefit obligation, December 31 | $ | 919.5 | $ | 823 | $ | 268.2 | $ | 238 | |||||||||||||||||||||
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block] | Significant assumptions used to determine the above benefit obligations are as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||||||
Annual discount rate used to determine benefit obligation | 4.2 | % | 5.03 | % | 4.3 | % | 5.19 | % | |||||||||||||||||||||
Assumed annual rate of future salary increases for projected benefit obligation | 3 | % | 3 | % | 3 | % | 3.75 | % | |||||||||||||||||||||
Schedule of Net Funded Status [Table Text Block] | |||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Fair value of plan assets | $ | 861.8 | $ | 870 | — | — | |||||||||||||||||||||||
Benefit obligation | 919.5 | 823 | $ | 268.2 | $ | 238 | |||||||||||||||||||||||
Funded status | $ | (57.7 | ) | $ | 47 | $ | (268.2 | ) | $ | (238.0 | ) | ||||||||||||||||||
Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | Amounts recognized on the consolidated balance sheets were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Current liability | — | — | $ | (11.2 | ) | $ | (11.5 | ) | |||||||||||||||||||||
Noncurrent asset | — | $ | 47 | — | — | ||||||||||||||||||||||||
Noncurrent liability | $ | (57.7 | ) | — | (257.0 | ) | (226.5 | ) | |||||||||||||||||||||
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Amounts recognized in accumulated other comprehensive loss (a component of common equity) as of December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 8.1 | $ | 5.2 | $ | 3 | $ | 1.7 | |||||||||||||||||||||
Prior service cost | 0.3 | 0.5 | 0.1 | 0.1 | |||||||||||||||||||||||||
Total | $ | 8.4 | $ | 5.7 | $ | 3.1 | $ | 1.8 | |||||||||||||||||||||
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block] | Amounts recognized in regulatory assets as of December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 222.1 | $ | 124.8 | $ | 43.8 | $ | 24.4 | |||||||||||||||||||||
Prior service cost | 9.6 | 12.8 | 0.6 | 0.9 | |||||||||||||||||||||||||
Total | $ | 231.7 | $ | 137.6 | $ | 44.4 | $ | 25.3 | |||||||||||||||||||||
Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | |||||||||||||||||||||||||||||
Pension Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Fair value of plan assets, January 1 | $ | 870 | $ | 799.1 | |||||||||||||||||||||||||
Actual return on plan assets | 55.8 | 130.9 | |||||||||||||||||||||||||||
Benefits paid | (64.0 | ) | (60.0 | ) | |||||||||||||||||||||||||
Fair value of plan assets, December 31 | $ | 861.8 | $ | 870 | |||||||||||||||||||||||||
Schedule of Allocation of Plan Assets [Table Text Block] | The Company’s pension plan asset allocation at December 31, 2014 and 2013 and the target allocation for 2015 are as follows: | ||||||||||||||||||||||||||||
Percentage of Plan Assets | |||||||||||||||||||||||||||||
Target | At | ||||||||||||||||||||||||||||
Allocation | December 31, | ||||||||||||||||||||||||||||
Asset Category | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||
Equity Securities | 58 | % | 57 | % | 59 | % | |||||||||||||||||||||||
Fixed Income | 33 | % | 34 | % | 32 | % | |||||||||||||||||||||||
Hedge Funds | 9 | % | 9 | % | 9 | % | |||||||||||||||||||||||
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block] | Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2014 and 2013, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | ||||||||||||||||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||||||
Millions of dollars | Total | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||||||||||||||||
Common stock | — | — | — | $ | 332 | $ | 332 | — | — | ||||||||||||||||||||
Preferred stock | — | — | — | 1 | 1 | — | — | ||||||||||||||||||||||
Mutual funds | $ | 622 | $ | 622 | — | 305 | 20 | $ | 285 | — | |||||||||||||||||||
Short-term investment vehicles | 20 | 20 | — | 19 | — | 19 | — | ||||||||||||||||||||||
US Treasury securities | 6 | 6 | — | 33 | — | 33 | — | ||||||||||||||||||||||
Corporate debt securities | 86 | 86 | — | 53 | — | 53 | — | ||||||||||||||||||||||
Loans secured by mortgages | — | — | — | 12 | — | 12 | — | ||||||||||||||||||||||
Municipals | 15 | 15 | — | 4 | — | 4 | — | ||||||||||||||||||||||
Limited partnerships | 32 | 32 | — | 35 | 1 | 34 | — | ||||||||||||||||||||||
Multi‑strategy hedge funds | 81 | — | $ | 81 | 76 | — | — | $ | 76 | ||||||||||||||||||||
$ | 862 | $ | 781 | $ | 81 | $ | 870 | $ | 354 | $ | 440 | $ | 76 | ||||||||||||||||
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block] | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Level 3 | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Beginning Balance | $ | 76 | $ | 70 | |||||||||||||||||||||||||
Unrealized gains included in changes in net assets | 5 | 6 | |||||||||||||||||||||||||||
Purchases, issuances, and settlements | — | — | |||||||||||||||||||||||||||
Ending Balance | $ | 81 | $ | 76 | |||||||||||||||||||||||||
Schedule of Expected Benefit Payments [Table Text Block] | |||||||||||||||||||||||||||||
Millions of dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
2015 | $ | 63.4 | $ | 11.5 | |||||||||||||||||||||||||
2016 | 64.5 | 12.4 | |||||||||||||||||||||||||||
2017 | 65.6 | 13.1 | |||||||||||||||||||||||||||
2018 | 66.1 | 13.8 | |||||||||||||||||||||||||||
2019 | 65.1 | 14.6 | |||||||||||||||||||||||||||
2020-2024 | 338.4 | 81.8 | |||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Service cost | $ | 20 | $ | 21.8 | $ | 19.6 | $ | 4.6 | $ | 5.9 | $ | 4.8 | |||||||||||||||||
Interest cost | 40.4 | 38.5 | 43 | 12 | 11.1 | 11.9 | |||||||||||||||||||||||
Expected return on assets | (66.7 | ) | (61.4 | ) | (59.5 | ) | n/a | n/a | n/a | ||||||||||||||||||||
Prior service cost amortization | 4.1 | 6 | 7 | 0.3 | 0.7 | 0.9 | |||||||||||||||||||||||
Amortization of actuarial losses | 4.8 | 16.9 | 18.4 | — | 3.3 | 1.4 | |||||||||||||||||||||||
Transition obligation amortization | — | — | — | — | 0.3 | 0.7 | |||||||||||||||||||||||
Curtailment | — | 9.9 | — | — | — | — | |||||||||||||||||||||||
Net periodic benefit cost | $ | 2.6 | $ | 31.7 | $ | 28.5 | $ | 16.9 | $ | 21.3 | $ | 19.7 | |||||||||||||||||
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block] | Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 3.1 | $ | (5.0 | ) | $ | 1.7 | $ | 1.3 | $ | (1.8 | ) | $ | 2 | |||||||||||||||
Amortization of actuarial losses | (0.2 | ) | (0.5 | ) | (0.6 | ) | — | (0.2 | ) | — | |||||||||||||||||||
Amortization of prior service cost | (0.2 | ) | (0.2 | ) | (0.2 | ) | — | — | — | ||||||||||||||||||||
Prior service cost (credit) | — | (0.3 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.1 | ) | (0.1 | ) | |||||||||||||||||||||
Total recognized in OCI | $ | 2.7 | $ | (6.0 | ) | $ | 0.9 | $ | 1.3 | $ | (2.1 | ) | $ | 1.9 | |||||||||||||||
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block] | Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 101.3 | $ | (157.5 | ) | $ | 45 | $ | 19.4 | $ | (29.9 | ) | $ | 31.4 | |||||||||||||||
Amortization of actuarial losses | (4.0 | ) | (14.7 | ) | (16.0 | ) | — | (2.7 | ) | (1.2 | ) | ||||||||||||||||||
Amortization of prior service cost | (3.2 | ) | (5.2 | ) | (6.4 | ) | (0.3 | ) | (0.6 | ) | (0.8 | ) | |||||||||||||||||
Prior service cost (credit) | — | (8.9 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.2 | ) | (0.5 | ) | |||||||||||||||||||||
Total recognized in regulatory assets | $ | 94.1 | $ | (186.3 | ) | $ | 22.6 | $ | 19.1 | $ | (33.4 | ) | $ | 28.9 | |||||||||||||||
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block] | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
Discount rate | 5.03 | % | 4.10%/5.07% | 5.25 | % | 5.19 | % | 4.19 | % | 5.35 | % | ||||||||||||||||||
Expected return on plan assets | 8 | % | 8 | % | 8.25 | % | n/a | n/a | n/a | ||||||||||||||||||||
Rate of compensation increase | 3 | % | 3.75%/3.00% | 4 | % | 3.75 | % | 3.75 | % | 4 | % | ||||||||||||||||||
Health care cost trend rate | n/a | n/a | n/a | 7.4 | % | 7.8 | % | 8.2 | % | ||||||||||||||||||||
Ultimate health care cost trend rate | n/a | n/a | n/a | 5 | % | 5 | % | 5 | % | ||||||||||||||||||||
Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2020 | |||||||||||||||||||||||
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block] | The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015 are as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 0.5 | $ | 0.1 | |||||||||||||||||||||||||
Prior service cost | 0.1 | — | |||||||||||||||||||||||||||
Total | $ | 0.6 | $ | 0.1 | |||||||||||||||||||||||||
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block] | The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2015 are as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 12.3 | $ | 1.9 | |||||||||||||||||||||||||
Prior service cost | 3.6 | 0.3 | |||||||||||||||||||||||||||
Total | $ | 15.9 | $ | 2.2 | |||||||||||||||||||||||||
SCE&G | |||||||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||
Schedule of Changes in Projected Benefit Obligations [Table Text Block] | |||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Benefit obligation, January 1 | $ | 695.7 | $ | 788.4 | $ | 181.7 | $ | 206 | |||||||||||||||||||||
Service cost | 16 | 17.6 | 3.6 | 4.6 | |||||||||||||||||||||||||
Interest cost | 34.1 | 32.6 | 9.4 | 8.7 | |||||||||||||||||||||||||
Plan participants’ contributions | — | — | 1.8 | 2 | |||||||||||||||||||||||||
Actuarial (gain) loss | 82.7 | (70.7 | ) | 18.6 | (27.3 | ) | |||||||||||||||||||||||
Benefits paid | (54.8 | ) | (50.6 | ) | (9.6 | ) | (9.3 | ) | |||||||||||||||||||||
Curtailment | — | (21.6 | ) | — | — | ||||||||||||||||||||||||
Amounts funded to parent | — | — | (1.4 | ) | (3.0 | ) | |||||||||||||||||||||||
Benefit obligation, December 31 | $ | 773.7 | $ | 695.7 | $ | 204.1 | $ | 181.7 | |||||||||||||||||||||
Schedule of Assumptions Used to Determine Benefit Obligations [Table Text Block] | Significant assumptions used to determine the above benefit obligations are as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||||||||
Annual discount rate used to determine benefit obligation | 4.2 | % | 5.03 | % | 4.3 | % | 5.19 | % | |||||||||||||||||||||
Assumed annual rate of future salary increases for projected benefit obligation | 3 | % | 3 | % | 3 | % | 3.75 | % | |||||||||||||||||||||
Schedule of Net Funded Status [Table Text Block] | Funded Status | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Fair value of plan assets | $ | 783.6 | $ | 792.1 | — | — | |||||||||||||||||||||||
Benefit obligation | 773.7 | 695.7 | $ | 204.1 | $ | 181.7 | |||||||||||||||||||||||
Funded status | $ | 9.9 | $ | 96.4 | $ | (204.1 | ) | $ | (181.7 | ) | |||||||||||||||||||
Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | Amounts recognized on the consolidated balance sheets were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Current liability | — | — | $ | (8.5 | ) | $ | (7.8 | ) | |||||||||||||||||||||
Noncurrent asset | $ | 9.9 | $ | 96.4 | — | — | |||||||||||||||||||||||
Noncurrent liability | — | — | (195.6 | ) | (173.9 | ) | |||||||||||||||||||||||
Schedule of Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Amounts recognized in accumulated other comprehensive loss (a component of common equity) as of December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 1.9 | $ | 1.8 | $ | 1 | $ | 0.6 | |||||||||||||||||||||
Prior service cost | 0.1 | 0.2 | — | — | |||||||||||||||||||||||||
Total | $ | 2 | $ | 2 | $ | 1 | $ | 0.6 | |||||||||||||||||||||
Schedule of defined benefit plan, amounts recognized in regulatory assets [Table Text Block] | Amounts recognized in regulatory assets as of December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
December 31, | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Net actuarial loss | $ | 191.9 | $ | 107.7 | $ | 35.9 | $ | 20.1 | |||||||||||||||||||||
Prior service cost | 8.3 | 11.1 | 0.5 | 0.7 | |||||||||||||||||||||||||
Total | $ | 200.2 | $ | 118.8 | $ | 36.4 | $ | 20.8 | |||||||||||||||||||||
Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | Changes in Fair Value of Plan Assets | ||||||||||||||||||||||||||||
Pension Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Fair value of plan assets, January 1 | $ | 792.1 | $ | 732 | |||||||||||||||||||||||||
Actual return on plan assets | 46.3 | 110.7 | |||||||||||||||||||||||||||
Benefits paid | (54.8 | ) | (50.6 | ) | |||||||||||||||||||||||||
Fair value of plan assets, December 31 | $ | 783.6 | $ | 792.1 | |||||||||||||||||||||||||
Schedule of Allocation of Plan Assets [Table Text Block] | The pension plan asset allocation at December 31, 2014 and 2013 and the target allocation for 2015 are as follows: | ||||||||||||||||||||||||||||
Percentage of Plan Assets | |||||||||||||||||||||||||||||
Target | At | ||||||||||||||||||||||||||||
Allocation | December 31, | ||||||||||||||||||||||||||||
Asset Category | 2015 | 2014 | 2013 | ||||||||||||||||||||||||||
Equity Securities | 58 | % | 57 | % | 59 | % | |||||||||||||||||||||||
Fixed Income | 33 | % | 34 | % | 32 | % | |||||||||||||||||||||||
Hedge Funds | 9 | % | 9 | % | 9 | % | |||||||||||||||||||||||
Schedule of Fair Value of Plan, Assets by Measurement Levels [Table Text Block] | Assets held by the pension plan are measured at fair value as described below. Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 2014 and 2013, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | ||||||||||||||||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||||||
Millions of dollars | Total | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||
31-Dec-14 | December 31, 2013 | ||||||||||||||||||||||||||||
Common stock | — | — | — | $ | 302 | $ | 302 | — | — | ||||||||||||||||||||
Preferred stock | — | — | — | 1 | 1 | — | — | ||||||||||||||||||||||
Mutual funds | $ | 566 | $ | 566 | — | 278 | 18 | $ | 260 | — | |||||||||||||||||||
Short-term investment vehicles | 18 | 18 | — | 18 | — | 18 | — | ||||||||||||||||||||||
US Treasury securities | 6 | 6 | — | 30 | — | 30 | — | ||||||||||||||||||||||
Corporate debt securities | 78 | 78 | — | 48 | — | 48 | — | ||||||||||||||||||||||
Loans secured by mortgages | — | — | — | 11 | — | 11 | — | ||||||||||||||||||||||
Municipals | 14 | 14 | — | 3 | — | 3 | — | ||||||||||||||||||||||
Limited partnerships | 29 | 29 | — | 32 | 1 | 31 | — | ||||||||||||||||||||||
Multi-strategy hedge funds | 73 | — | $ | 73 | 69 | — | — | $ | 69 | ||||||||||||||||||||
$ | 784 | $ | 711 | $ | 73 | $ | 792 | $ | 322 | $ | 401 | $ | 69 | ||||||||||||||||
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block] | |||||||||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
Level 3 | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | |||||||||||||||||||||||||||
Beginning Balance | $ | 69 | $ | 64 | |||||||||||||||||||||||||
Unrealized gains included in changes in net assets | 4 | 5 | |||||||||||||||||||||||||||
Purchases, issuances, and settlements | — | — | |||||||||||||||||||||||||||
Ending Balance | $ | 73 | $ | 69 | |||||||||||||||||||||||||
Schedule of Expected Benefit Payments [Table Text Block] | The total benefits expected to be paid from the pension plan or from SCE&G’s assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows: | ||||||||||||||||||||||||||||
Expected Benefit Payments | |||||||||||||||||||||||||||||
Millions of dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
2015 | $ | 63.4 | $ | 9.1 | |||||||||||||||||||||||||
2016 | 64.5 | 9.8 | |||||||||||||||||||||||||||
2017 | 65.6 | 10.4 | |||||||||||||||||||||||||||
2018 | 66.1 | 10.9 | |||||||||||||||||||||||||||
2019 | 65.1 | 11.5 | |||||||||||||||||||||||||||
2020 - 2024 | 338.4 | 64.6 | |||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | Components of Net Periodic Benefit Cost | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Service cost | $ | 16 | $ | 17.6 | $ | 15.7 | $ | 3.6 | $ | 4.6 | $ | 3.7 | |||||||||||||||||
Interest cost | 34.1 | 32.6 | 36.4 | 9.4 | 8.7 | 9.4 | |||||||||||||||||||||||
Expected return on assets | (56.3 | ) | (51.9 | ) | (50.4 | ) | n/a | n/a | n/a | ||||||||||||||||||||
Prior service cost amortization | 3.5 | 5 | 6 | 0.3 | 0.6 | 0.7 | |||||||||||||||||||||||
Amortization of actuarial losses | 4 | 14.3 | 15.6 | — | 2.6 | 1.1 | |||||||||||||||||||||||
Curtailment | — | 8.4 | — | — | — | — | |||||||||||||||||||||||
Net periodic benefit cost | $ | 1.3 | $ | 26 | $ | 23.3 | $ | 13.3 | $ | 16.5 | $ | 14.9 | |||||||||||||||||
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block] | Other changes in plan assets and benefit obligations recognized in other comprehensive income (net of tax) were as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 0.2 | $ | (0.8 | ) | $ | 0.4 | $ | 0.4 | $ | (0.4 | ) | $ | 0.7 | |||||||||||||||
Amortization of actuarial losses | (0.1 | ) | (0.1 | ) | (0.1 | ) | — | (0.1 | ) | — | |||||||||||||||||||
Amortization of prior service cost | (0.1 | ) | — | (0.1 | ) | — | — | (0.1 | ) | ||||||||||||||||||||
Total recognized in OCI | $ | — | $ | (0.9 | ) | $ | 0.2 | $ | 0.4 | $ | (0.5 | ) | $ | 0.6 | |||||||||||||||
Schedule of defined benefit plan, Other changes in plan assets recognized in regulatory assets [Table Text Block] | Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 87.7 | $ | (137.1 | ) | $ | 37.9 | $ | 15.8 | $ | (24.4 | ) | $ | 25.7 | |||||||||||||||
Amortization of actuarial losses | (3.5 | ) | (12.7 | ) | (14.0 | ) | — | (2.2 | ) | (1.0 | ) | ||||||||||||||||||
Amortization of prior service cost | (2.8 | ) | (4.5 | ) | (5.7 | ) | (0.2 | ) | (0.5 | ) | (0.7 | ) | |||||||||||||||||
Prior service cost (credit) | — | (7.7 | ) | — | — | — | — | ||||||||||||||||||||||
Amortization of transition obligation | — | — | — | — | (0.1 | ) | (0.2 | ) | |||||||||||||||||||||
Total recognized in regulatory assets | $ | 81.4 | $ | (162.0 | ) | $ | 18.2 | $ | 15.6 | $ | (27.2 | ) | $ | 23.8 | |||||||||||||||
Schedule of Assumptions Used in Determining Net Periodic Benefit Cost [Table Text Block] | Significant Assumptions Used in Determining Net Periodic Benefit Cost | ||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement | ||||||||||||||||||||||||||||
Benefits | |||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||
Discount rate | 5.03 | % | 4.10%/5.07% | 5.25 | % | 5.19 | % | 4.19 | % | 5.35 | % | ||||||||||||||||||
Expected return on plan assets | 8 | % | 8 | % | 8.25 | % | n/a | n/a | n/a | ||||||||||||||||||||
Rate of compensation increase | 3 | % | 3.75%/3.00% | 4 | % | 3.75 | % | 3.75 | % | 4 | % | ||||||||||||||||||
Health care cost trend rate | n/a | n/a | n/a | 7.4 | % | 7.8 | % | 8.2 | % | ||||||||||||||||||||
Ultimate health care cost trend rate | n/a | n/a | n/a | 5 | % | 5 | % | 5 | % | ||||||||||||||||||||
Year achieved | n/a | n/a | n/a | 2020 | 2020 | 2020 | |||||||||||||||||||||||
Schedule of amounts in regulatory assets to be recognized over the next fiscal year [Table Text Block] | The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2015 are as follows: | ||||||||||||||||||||||||||||
Millions of Dollars | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||
Actuarial loss | $ | 10.6 | $ | 1.6 | |||||||||||||||||||||||||
Prior service cost | 3.1 | 0.2 | |||||||||||||||||||||||||||
Total | $ | 13.7 | $ | 1.8 | |||||||||||||||||||||||||
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES ARO (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Change in Asset Retirement Obligations [Line Items] | |||||||||
Change in Asset Retirement Obligations [Table Text Block] | |||||||||
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations is as follows: | |||||||||
Millions of dollars | 2014 | 2013 | |||||||
Beginning balance | $ | 576 | $ | 561 | |||||
Liabilities incurred | 3 | 6 | |||||||
Liabilities settled | (6 | ) | (4 | ) | |||||
Accretion expense | 26 | 25 | |||||||
Revisions in estimated cash flows | (36 | ) | (12 | ) | |||||
Ending balance | $ | 563 | $ | 576 | |||||
SCE&G | |||||||||
Change in Asset Retirement Obligations [Line Items] | |||||||||
Change in Asset Retirement Obligations [Table Text Block] | follows: | ||||||||
Millions of dollars | 2014 | 2013 | |||||||
Beginning balance | $ | 547 | $ | 535 | |||||
Liabilities incurred | 3 | 5 | |||||||
Liabilities settled | (6 | ) | (4 | ) | |||||
Accretion expense | 25 | 24 | |||||||
Revisions in estimated cash flows | (33 | ) | (13 | ) | |||||
Ending Balance | $ | 536 | $ | 547 | |||||
COMMITMENTS_AND_CONTINGENCIES_1
COMMITMENTS AND CONTINGENCIES Operating Leases Tables (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Operating Leased Assets [Line Items] | ||||
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] | ||||
Millions of dollars | ||||
2015 | $ | 8 | ||
2016 | 5 | |||
2017 | 2 | |||
2018 | 1 | |||
2019 | 2 | |||
Thereafter | 20 | |||
Total | $ | 38 | ||
SCE&G | ||||
Operating Leased Assets [Line Items] | ||||
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] | ||||
Millions of dollars | ||||
2015 | $ | 6 | ||
2016 | 3 | |||
2017 | 1 | |||
2018 | — | |||
2019 | 1 | |||
Thereafter | 18 | |||
Total | $ | 29 | ||
COMMITMENTS_AND_CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES Nuclear (Tables) | 12 Months Ended |
Dec. 31, 2014 | |
ForecastedCapitalCosts | |
SCE&G | |
ForecastedCapitalCosts |
SEGMENT_OF_BUSINESS_INFORMATIO1
SEGMENT OF BUSINESS INFORMATION (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ||||||||||||||||||||||||||||
Electric | Gas | Retail Gas | Energy | All | Adjustments/ | Consolidated | ||||||||||||||||||||||
Operations | Distribution | Marketing | Marketing | Other | Eliminations | Total | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,622 | $ | 1,012 | $ | 515 | $ | 786 | $ | 37 | $ | (21 | ) | $ | 4,951 | |||||||||||||
Intersegment Revenue | 7 | 2 | — | 196 | 437 | (642 | ) | — | ||||||||||||||||||||
Operating Income | 768 | 159 | n/a | n/a | 27 | 53 | 1,007 | |||||||||||||||||||||
Interest Expense | 19 | 22 | 1 | — | 5 | 265 | 312 | |||||||||||||||||||||
Depreciation and Amortization | 300 | 72 | 2 | — | 24 | (14 | ) | 384 | ||||||||||||||||||||
Income Tax Expense | 7 | 33 | 16 | 3 | 12 | 177 | 248 | |||||||||||||||||||||
Net Income | n/a | n/a | 26 | 5 | (6 | ) | 513 | 538 | ||||||||||||||||||||
Segment Assets | 10,182 | 2,487 | 140 | 150 | 1,474 | 2,419 | 16,852 | |||||||||||||||||||||
Expenditures for Assets | 936 | 200 | — | 2 | 52 | (98 | ) | 1,092 | ||||||||||||||||||||
Deferred Tax Assets | 11 | 29 | 11 | 9 | 15 | (75 | ) | — | ||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,423 | $ | 942 | $ | 465 | $ | 652 | $ | 40 | $ | (27 | ) | $ | 4,495 | |||||||||||||
Intersegment Revenue | 6 | 1 | — | 167 | 416 | (590 | ) | — | ||||||||||||||||||||
Operating Income | 679 | 153 | n/a | n/a | 27 | 51 | 910 | |||||||||||||||||||||
Interest Expense | 19 | 22 | 1 | — | 4 | 251 | 297 | |||||||||||||||||||||
Depreciation and Amortization | 297 | 70 | 3 | — | 26 | (18 | ) | 378 | ||||||||||||||||||||
Income Tax Expense | 6 | 33 | 15 | 4 | 14 | 151 | 223 | |||||||||||||||||||||
Net Income | n/a | n/a | 24 | 6 | (2 | ) | 443 | 471 | ||||||||||||||||||||
Segment Assets | 9,488 | 2,340 | 172 | 133 | 1,378 | 1,653 | 15,164 | |||||||||||||||||||||
Expenditures for Assets | 907 | 140 | — | 1 | 31 | 27 | 1,106 | |||||||||||||||||||||
Deferred Tax Assets | 10 | 27 | 8 | 2 | 14 | (61 | ) | — | ||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,446 | $ | 764 | $ | 413 | $ | 543 | $ | 45 | $ | (35 | ) | $ | 4,176 | |||||||||||||
Intersegment Revenue | 7 | 1 | — | 125 | 416 | (549 | ) | — | ||||||||||||||||||||
Operating Income | 668 | 141 | n/a | n/a | 22 | 28 | 859 | |||||||||||||||||||||
Interest Expense | 21 | 23 | 1 | — | 3 | 247 | 295 | |||||||||||||||||||||
Depreciation and Amortization | 278 | 67 | 3 | — | 25 | (17 | ) | 356 | ||||||||||||||||||||
Income Tax Expense | 7 | 32 | 7 | 3 | 15 | 118 | 182 | |||||||||||||||||||||
Net Income | n/a | n/a | 11 | 5 | 1 | 403 | 420 | |||||||||||||||||||||
Segment Assets | 8,989 | 2,292 | 153 | 122 | 1,415 | 1,645 | 14,616 | |||||||||||||||||||||
Expenditures for Assets | 999 | 123 | — | 1 | 14 | (60 | ) | 1,077 | ||||||||||||||||||||
Deferred Tax Assets | 9 | 26 | 10 | 4 | 17 | (55 | ) | 11 | ||||||||||||||||||||
SCE&G | ||||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Disclosure of Reportable Segments (Millions of dollars) | |||||||||||||||||||||||||||
Electric | Gas | Adjustments/ | Consolidated | |||||||||||||||||||||||||
Operations | Distribution | Eliminations | Total | |||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,629 | $ | 462 | — | $ | 3,091 | |||||||||||||||||||||
Operating Income | 768 | 62 | — | 830 | ||||||||||||||||||||||||
Interest Expense | 19 | — | $ | 209 | 228 | |||||||||||||||||||||||
Depreciation and Amortization | 300 | 27 | (12 | ) | 315 | |||||||||||||||||||||||
Segment Assets | 10,182 | 721 | 3,204 | 14,107 | ||||||||||||||||||||||||
Expenditures for Assets | 936 | 55 | (57 | ) | 934 | |||||||||||||||||||||||
Deferred Tax Assets | 11 | n/a | (11 | ) | — | |||||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,431 | $ | 414 | — | $ | 2,845 | |||||||||||||||||||||
Operating Income | 679 | 58 | — | 737 | ||||||||||||||||||||||||
Interest Expense | 19 | — | $ | 198 | 217 | |||||||||||||||||||||||
Depreciation and Amortization | 294 | 26 | (7 | ) | 313 | |||||||||||||||||||||||
Segment Assets | 9,488 | 686 | 2,526 | 12,700 | ||||||||||||||||||||||||
Expenditures for Assets | 907 | 45 | 51 | 1,003 | ||||||||||||||||||||||||
Deferred Tax Assets | 10 | n/a | (10 | ) | — | |||||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
External Revenue | $ | 2,453 | $ | 356 | — | $ | 2,809 | |||||||||||||||||||||
Operating Income | 668 | 49 | — | 717 | ||||||||||||||||||||||||
Interest Expense | 21 | — | $ | 190 | 211 | |||||||||||||||||||||||
Depreciation and Amortization | 278 | 25 | (10 | ) | 293 | |||||||||||||||||||||||
Segment Assets | 8,989 | 659 | 2,456 | 12,104 | ||||||||||||||||||||||||
Expenditures for Assets | 999 | 56 | (77 | ) | 978 | |||||||||||||||||||||||
Deferred Tax Assets | 9 | n/a | (9 | ) | — | |||||||||||||||||||||||
DISPOSITIONS_Tables
DISPOSITIONS (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Dispositions [Abstract] | |||||||||||||
Schedule of Disposal Groups [Table Text Block] | |||||||||||||
Millions of dollars | CGT | SCI | Total | ||||||||||
Assets Held for Sale | |||||||||||||
Utility Plant, Net | $ | 288.4 | — | $ | 288.4 | ||||||||
Nonutility Property and Investments, Net | 0.6 | $ | 40.1 | 40.7 | |||||||||
Current Assets | 6.5 | 3.9 | 10.4 | ||||||||||
Deferred Debits and Other Assets | 0.9 | 0.2 | 1.1 | ||||||||||
Total Assets Held for Sale | $ | 296.4 | $ | 44.2 | $ | 340.6 | |||||||
Liabilities Held for Sale | |||||||||||||
Current Liabilities | $ | 3.5 | $ | 2.2 | $ | 5.7 | |||||||
Deferred Credits and Other Liabilities | 42.9 | 3.1 | 46 | ||||||||||
Total Liabilities Held for Sale | $ | 46.4 | $ | 5.3 | $ | 51.7 | |||||||
QUARTERLY_FINANCIAL_INFORMATIO1
QUARTERLY FINANCIAL INFORMATION (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Statement [Line Items] | |||||||||||||||||||||
Schedule of Quarterly Financial Information [Table Text Block] | |||||||||||||||||||||
Millions of dollars, except per share amounts | First | Second | Third | Fourth | Annual | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||
2014 | |||||||||||||||||||||
Total operating revenues | $ | 1,590 | $ | 1,026 | $ | 1,121 | $ | 1,214 | $ | 4,951 | |||||||||||
Operating income | 350 | 154 | 269 | 234 | 1,007 | ||||||||||||||||
Net income | 193 | 96 | 144 | 105 | 538 | ||||||||||||||||
Basic earnings per share | 1.37 | 0.68 | 1.01 | 0.73 | 3.79 | ||||||||||||||||
Diluted earnings per share | 1.37 | 0.68 | 1.01 | 0.73 | 3.79 | ||||||||||||||||
2013 | |||||||||||||||||||||
Total operating revenues | $ | 1,311 | $ | 1,016 | $ | 1,051 | $ | 1,117 | $ | 4,495 | |||||||||||
Operating income | 293 | 189 | 255 | 173 | 910 | ||||||||||||||||
Net income | 151 | 85 | 131 | 104 | 471 | ||||||||||||||||
Basic earnings per share | 1.13 | 0.6 | 0.94 | 0.73 | 3.4 | ||||||||||||||||
Diluted earnings per share | 1.11 | 0.6 | 0.94 | 0.73 | 3.39 | ||||||||||||||||
SCE&G | |||||||||||||||||||||
Statement [Line Items] | |||||||||||||||||||||
Schedule of Quarterly Financial Information [Table Text Block] | |||||||||||||||||||||
Millions of dollars | First | Second | Third | Fourth | Annual | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||
2014 | |||||||||||||||||||||
Total operating revenues | $ | 859 | $ | 698 | $ | 812 | $ | 722 | $ | 3,091 | |||||||||||
Operating income | 239 | 145 | 272 | 174 | 830 | ||||||||||||||||
Net Income | 126 | 99 | 157 | 76 | 458 | ||||||||||||||||
Earnings Available to Common Shareholder | 123 | 96 | 154 | 73 | 446 | ||||||||||||||||
2013 | |||||||||||||||||||||
Total operating revenues | $ | 728 | $ | 696 | $ | 776 | $ | 645 | $ | 2,845 | |||||||||||
Operating income | 191 | 180 | 255 | 111 | 737 | ||||||||||||||||
Net Income | 92 | 88 | 139 | 72 | 391 | ||||||||||||||||
Earnings Available to Common Shareholder | 89 | 85 | 136 | 70 | 380 | ||||||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 12 Months Ended | ||
Share data in Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Significant Accounting Policies | |||
Undercollected balance fuel | $46,000,000 | ||
Unbilled Receivables, Current | 186,400,000 | 183,100,000 | |
Goodwill | 210,000,000 | 230,000,000 | |
Number of coal fired units to be retired | 6 | ||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.84% | 2.93% | 2.90% |
Public Utilities, Allowance for Funds Used During Construction, Additions | 7.20% | 6.90% | 6.30% |
Asset Management and Supply Service Agreements | |||
Natural gas inventory, carrying amount | 22,800,000 | ||
Property, Plant and Equipment, Net | 284,000,000 | 317,000,000 | |
Accrual period of nuclear refueling charges (in months) | 18 | ||
Earnings Per Share | |||
Weighted Average Shares Outstanding - Basic | 141.9 | 138.7 | 131.1 |
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements | 0 | 0.4 | 2.2 |
Weighted Average Number of Shares Outstanding, Diluted | 141.9 | 139.1 | 133.3 |
SCEG and GENCO [Member] | |||
Significant Accounting Policies | |||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.84% | 2.94% | 2.91% |
SCE&G | |||
Significant Accounting Policies | |||
Maintenance Costs | 18,400,000 | ||
Environmental Remediation Costs Recognized in Regulatory Assets | 35,500,000 | ||
Undercollected balance fuel | 46,000,000 | ||
Decommissioning Liability, Noncurrent | 696,800,000 | ||
Decommissioning safe storage | 60 | ||
Unbilled Receivables, Current | 115,800,000 | 111,900,000 | |
Utilities Operating Expense, Maintenance | 19,400,000 | 18,100,000 | |
Anount accrued monthly for nuclear fuel outages | 1,400,000 | 1,200,000 | |
Number of coal fired units to be retired | 6 | ||
Nuclear refueling outage cost | 43,700,000 | 32,300,000 | |
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.85% | 2.96% | 2.93% |
Public Utilities, Allowance for Funds Used During Construction, Additions | 6.50% | 6.90% | 6.30% |
Asset Management and Supply Service Agreements | |||
Property, Plant and Equipment, Net | 67,000,000 | 69,000,000 | |
Payments to Acquire Investments to be Held in Decommissioning Trust Fund | 3,200,000 | ||
Genco | |||
Significant Accounting Policies | |||
Power Generation Capacity Megawatts | 605 | ||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.66% | 2.66% | 2.66% |
Asset Management and Supply Service Agreements | |||
Property, Plant and Equipment, Net | 472,000,000 | ||
CGT [Member] | |||
Significant Accounting Policies | |||
Goodwill | 20,000,000 | ||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.11% | 2.19% | 2.09% |
PSNC Energy | |||
Significant Accounting Policies | |||
Goodwill | 210,000,000 | ||
Accumulated Amortization and Write-down, Goodwill | 230,000,000 | ||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.98% | 3.01% | 3.01% |
Asset Management and Supply Service Agreements | |||
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent) | 48.00% | 48.00% | |
Natural gas inventory, carrying amount | 26,100,000 | ||
Summer Station Unit 1 [Domain] | |||
Significant Accounting Policies | |||
Jointly Owned Utility Plant, Proportionate Ownership Share | 66.70% | 66.70% | |
Asset Management and Supply Service Agreements | |||
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | 1,200,000,000 | 1,100,000,000 | |
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | 578,300,000 | 566,900,000 | |
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 199,300,000 | 127,100,000 | |
Summer Station Unit 1 [Domain] | SCE&G | |||
Asset Management and Supply Service Agreements | |||
Accounts Receivable, Net | 88,900,000 | 75,600,000 | |
Summer Station New Units [Domain] | |||
Significant Accounting Policies | |||
Jointly Owned Utility Plant, Proportionate Ownership Share | 55.00% | 55.00% | |
Asset Management and Supply Service Agreements | |||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 2,700,000,000 | 2,300,000,000 | |
SCE&G | |||
Significant Accounting Policies | |||
Nuclear refueling outage cost | $29,100,000 | 21,500,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 5.00% |
RATE_AND_OTHER_REGULATORY_MATT2
RATE AND OTHER REGULATORY MATTERS RATE AND OTHER REGULATORY MATTERS (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 |
Derivative, Gain on Derivative | $17.80 | ||||
Undercollected balance fuel | 46 | ||||
Carrying cost recovery | 5.8 | 2.9 | |||
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | 4.23% | ||||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 10.25% | ||||
Prior accrual of under collected fuel | 8.5 | ||||
Gain (Loss) on Sale of Derivatives | 8.5 | ||||
Number of coal fired units to be retired | 6 | 6 | |||
Number of coal fired units retired | 3 | ||||
Demand Side Management Program Costs, Noncurrent | 15.4 | 16.9 | 19.6 | 19.6 | |
Storm Damage Reserve Cost Applied | 5 | ||||
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net | 5 | ||||
Reduction to Net Lost Revenues from DSM Programs Percent | 25.00% | ||||
Net Lost Revenues associated with DSM Programs Dollars | 33 | 6.6 | |||
SCE&G | |||||
Derivative, Gain on Derivative | 17.8 | ||||
Fuel Cost Increase To Base Fuel Costs | 10.3 | ||||
Undercollected balance fuel | 46 | ||||
Carrying cost recovery | 5.8 | 2.9 | |||
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | 4.23% | ||||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 10.25% | ||||
Prior accrual of under collected fuel | 8.5 | ||||
Gain (Loss) on Sale of Derivatives | 8.5 | ||||
Number of coal fired units to be retired | 6 | 6 | |||
Number of coal fired units retired | 3 | ||||
Demand Side Management Program Costs, Noncurrent | 15.4 | 16.9 | 19.6 | 19.6 | |
Storm Damage Reserve Cost Applied | 5 | ||||
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net | 5 | ||||
Reduction to Net Lost Revenues from DSM Programs Percent | 25.00% | ||||
Net Lost Revenues associated with DSM Programs Dollars | $33 | $6.60 |
RATE_AND_OTHER_REGULATORY_MATT3
RATE AND OTHER REGULATORY MATTERS ELECTRIC-BLRA (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Entity Information [Line Items] | |||
Undercollected balance fuel | $46 | ||
Public Utilities, Allowed Return on Common Equity under Base Load Review Act | 11.00% | ||
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA | 2.80% | 2.90% | 2.30% |
Public Utilties increase (decrease) in retail electric rates | 66.2 | 67.2 | 52.1 |
Carrying cost recovery | 5.8 | 2.9 | |
SCE&G | |||
Entity Information [Line Items] | |||
Undercollected balance fuel | 46 | ||
Public Utilities, Allowed Return on Common Equity under Base Load Review Act | 11.00% | ||
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA | 2.80% | 2.90% | 2.30% |
Public Utilties increase (decrease) in retail electric rates | 66.2 | 67.2 | 52.1 |
Carrying cost recovery | $5.80 | $2.90 |
RATE_AND_OTHER_REGULATORY_MATT4
RATE AND OTHER REGULATORY MATTERS GAS (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2012 |
Entity Information [Line Items] | ||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 0.60% | 2.10% |
Public Utilities changes in Retail Natural Gas Rates Approved under RSA | $2.60 | $7.50 |
Public Utilities, Rate Calculation Basis | 12 | |
SCE&G | ||
Entity Information [Line Items] | ||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 0.60% | 2.10% |
Public Utilities changes in Retail Natural Gas Rates Approved under RSA | $2.60 | $7.50 |
Public Utilities, Rate Calculation Basis | 12 |
RATE_AND_OTHER_REGULATORY_MATT5
RATE AND OTHER REGULATORY MATTERS REGULATORY ASSETS AND LIABILITIES(Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Regulatory Assets, Noncurrent | $1,823 | $1,360 | |
Regulatory Liability, Noncurrent | 814 | 966 | |
Other Regulatory Liability [Member] | |||
Regulatory Liability, Noncurrent | 1 | ||
Planned major maintenance [Member] | |||
Regulatory Liability, Noncurrent | 0 | 10 | |
Amounts Recovered through Electric Rates to offset Turbine Expense | 18.4 | ||
Storm damage reserve [Member] | |||
Regulatory Liability, Noncurrent | 6 | 27 | |
Asset Retirement Obligation Costs [Member] | |||
Regulatory Liability, Noncurrent | 703 | 695 | |
Deferred Income Tax Charge [Member] | |||
Regulatory Liability, Noncurrent | 22 | 24 | |
Monetization bankruptcy claim [Member] | |||
Regulatory Liability, Noncurrent | 0 | 29 | |
Deferred gains on interest rate derivatives [Member] | |||
Regulatory Liability, Noncurrent | 82 | 181 | |
Deferred Income Tax Charge [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 70 | ||
Regulatory Assets, Noncurrent | 284 | 259 | |
Regulatory Clause Revenues, under-recovered [Member] | |||
Regulatory Assets, Noncurrent | 20 | 18 | |
Environmental Restoration Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 25 | ||
Regulatory Assets, Noncurrent | 40 | 41 | |
Asset Retirement Obligation Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 90 | ||
Regulatory Assets, Noncurrent | 366 | 368 | |
Franchise agreement Costs [Member] | |||
Regulatory Assets, Noncurrent | 26 | 31 | |
Pension Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | 14 | 30 |
Regulatory Assets, Noncurrent | 350 | 238 | |
Planned major maintenance [Member] | |||
Regulatory Assets, Noncurrent | 2 | 0 | |
Deferred Losses On Interest Rate Derivatives [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | P50Y | ||
Regulatory Assets, Noncurrent | 453 | 124 | |
Deferred Pollution Control Cost [Member] | |||
Regulatory Assets, Noncurrent | 36 | 37 | |
Canadys Refined Coal [Member] | |||
Regulatory Assets, Noncurrent | 137 | ||
Demand Side Management programs [Member] | |||
Regulatory Assets, Noncurrent | 56 | 51 | |
Other Regulatory Assets [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | P30Y | ||
Regulatory Assets, Noncurrent | 53 | 48 | |
SCE&G | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | ||
Regulatory Assets, Noncurrent | 1,745 | 1,303 | |
Regulatory Liability, Noncurrent | 610 | 732 | |
SCE&G | Planned major maintenance [Member] | |||
Regulatory Liability, Noncurrent | 0 | ||
Amounts Recovered through Electric Rates to offset Turbine Expense | 18.4 | ||
SCE&G | Storm damage reserve [Member] | |||
Regulatory Liability, Noncurrent | 6 | 27 | |
SCE&G | Asset Retirement Obligation Costs [Member] | |||
Regulatory Liability, Noncurrent | 505 | 495 | |
SCE&G | Deferred Income Tax Charge [Member] | |||
Regulatory Liability, Noncurrent | 17 | ||
SCE&G | Deferred gains on interest rate derivatives [Member] | |||
Regulatory Liability, Noncurrent | 82 | 181 | |
SCE&G | Deferred Income Tax Charge [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 70 | ||
Regulatory Assets, Noncurrent | 278 | 256 | |
SCE&G | Regulatory Clause Revenues, under-recovered [Member] | |||
Regulatory Assets, Noncurrent | 20 | 18 | |
SCE&G | Environmental Restoration Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 25 | ||
Regulatory Assets, Noncurrent | 36 | 37 | |
SCE&G | Asset Retirement Obligation Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 90 | ||
Regulatory Assets, Noncurrent | 347 | 350 | |
SCE&G | Franchise agreement Costs [Member] | |||
Regulatory Assets, Noncurrent | 26 | 31 | |
SCE&G | Pension Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | 14 | |
Regulatory Assets, Noncurrent | 310 | 215 | |
SCE&G | Planned major maintenance [Member] | |||
Regulatory Assets, Noncurrent | 2 | 0 | |
SCE&G | Deferred Losses On Interest Rate Derivatives [Member] | |||
Regulatory Assets, Noncurrent | 453 | 124 | |
SCE&G | Deferred Pollution Control Cost [Member] | |||
Regulatory Assets, Noncurrent | 36 | 37 | |
SCE&G | Canadys Refined Coal [Member] | |||
Regulatory Assets, Noncurrent | 137 | 145 | |
SCE&G | Demand Side Management programs [Member] | |||
Regulatory Assets, Noncurrent | 56 | 51 | |
SCE&G | Other Regulatory Assets [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 50 | ||
Regulatory Assets, Noncurrent | $44 | $39 | |
Pension Plan, Defined Benefit | SCE&G | Other Regulatory Assets [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 30 |
RATE_AND_OTHER_REGULATORY_MATT6
RATE AND OTHER REGULATORY MATTERS NARRATIVE (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | ||
Demand side management recovery period | 10 | ||
Planned major maintenance [Member] | |||
Maintenance Costs | $18.40 | ||
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs | 17.2 | ||
Storm damage reserve [Member] | |||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | ||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | ||
Storm reserve applied to offset storm damage costs | 16.8 | ||
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM | 5 | ||
Deferred Income Tax Charge [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 70 | ||
Environmental Restoration Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 25 | ||
Asset Retirement Obligation Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 90 | ||
Pension Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | 14 | 30 |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | 14 | 63 | |
Deferred Losses On Interest Rate Derivatives [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | P50Y | ||
Other Regulatory Assets [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | P30Y | ||
SCE&G | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | ||
Demand side management recovery period | 10 | ||
SCE&G | Planned major maintenance [Member] | |||
Maintenance Costs | 18.4 | ||
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs | 17.2 | ||
SCE&G | Storm damage reserve [Member] | |||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | ||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | ||
Storm reserve applied to offset storm damage costs | 16.8 | ||
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM | 5 | ||
SCE&G | Deferred Income Tax Charge [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 70 | ||
SCE&G | Environmental Restoration Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 25 | ||
SCE&G | Asset Retirement Obligation Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 90 | ||
SCE&G | Pension Costs [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 12 | 14 | |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | $14 | $63 | |
SCE&G | Other Regulatory Assets [Member] | |||
Regulatory Noncurrent Asset, Amortization Period | 50 |
COMMON_EQUITY_Details
COMMON EQUITY (Details) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Schedule of Capitalization, Equity [Line Items] | |||
Retained Earnings, Appropriated | $67.70 | $63.10 | |
Common Stock, Shares Authorized | 200,000,000 | 200,000,000 | |
Proceeds from exercise of equity forward sales agreements | 196.2 | ||
Common stock issued through various compensation and dividend reinvestment plans, including the Stock Purchase Savings Plan | 99.3 | 100.9 | 97.7 |
Number of shares underlying forward sales contracts (in shares) | 6,600,000 | ||
SCE&G | |||
Schedule of Capitalization, Equity [Line Items] | |||
Retained Earnings, Appropriated | $67.70 | $63.10 | |
Common Stock, Shares Authorized | 50,000,000 | 50,000,000 | |
Preferred Stock, Shares Authorized | 20,000,000 | 20,000,000 | |
Preferred Stock, Shares Outstanding | 1,000 | 1,000 |
LONGTERM_AND_SHORTTERM_DEBT_De
LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Debt Instrument [Line Items] | ||
Medium-term Notes | 800 | 800 |
Senior Notes | 88 | 92 |
First Mortgage Bonds | 3,840 | 3,540 |
Junior Subordinated Notes | 150 | 150 |
GENCO Notes | 227 | 233 |
Industrial and Pollution Control Bonds | 122 | 158 |
Senior Notes, Noncurrent | 350 | 350 |
Long Term Contract for Nuclear Fuel Purchase | 100 | 100 |
Other Long-term Debt | 17 | 20 |
Long-term Debt, Gross | 5,694 | 5,443 |
Long-term Debt, Current Maturities | -166 | -54 |
Debt Instrument, Unamortized Discount | 3 | 6 |
Long-term Debt | 5,531 | 5,395 |
Medium-term Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.42% | 5.42% |
Debt Instrument, Redemption Period, Start Date | 1-Apr-20 | |
Debt Instrument, Redemption Period, End Date | 1-Feb-22 | |
Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 0.93% | 0.94% |
Debt Instrument, Redemption Period, Start Date | 1-Jun-15 | |
Debt Instrument, Redemption Period, End Date | 1-Jun-34 | |
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate | 6.17% | |
First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.56% | 5.60% |
Debt Instrument, Redemption Period, Start Date | 1-Nov-18 | |
Debt Instrument, Redemption Period, End Date | 1-Jun-64 | |
Junior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 7.92% | 7.92% |
Debt Instrument, Redemption Period, End Date | 30-Jan-65 | |
Genco Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.90% | 5.89% |
Debt Instrument, Redemption Period, Start Date | 1-Feb-15 | |
Debt Instrument, Redemption Period, End Date | 1-Feb-24 | |
Industrial and Pollution Control Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 3.51% | 3.83% |
Debt Instrument, Redemption Period, Start Date | 1-Feb-28 | |
Debt Instrument, Redemption Period, End Date | 1-Dec-38 | |
Long-term Debt, Percentage Bearing Variable Interest, Amount | 67.8 | |
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.04% | 0.11% |
Senior Debentures [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.93% | 5.93% |
Debt Instrument, Redemption Period, Start Date | 30-Mar-20 | |
Debt Instrument, Redemption Period, End Date | 15-Dec-26 | |
Nuclear fuel purchase contract [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 0.78% | 0.78% |
Debt Instrument, Redemption Period, End Date | 1-Nov-16 | |
Other Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 2.90% | 2.73% |
Debt Instrument, Redemption Period, Start Date | 1-Jan-15 | |
Debt Instrument, Redemption Period, End Date | 30-Sep-27 | |
SCE&G | ||
Debt Instrument [Line Items] | ||
First Mortgage Bonds | 3,840 | 3,540 |
GENCO Notes | 227 | 233 |
Industrial and Pollution Control Bonds | 122 | 158 |
Long Term Contract for Nuclear Fuel Purchase | 100 | 100 |
Other Long-term Debt | 14 | 16 |
Long-term Debt, Gross | 4,303 | 4,047 |
Long-term Debt, Current Maturities | -10 | -48 |
Debt Instrument, Unamortized Discount | 6 | 8 |
Long-term Debt | 4,299 | 4,007 |
SCE&G | First Mortgage Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.56% | 5.60% |
Debt Instrument, Redemption Period, Start Date | 1-Nov-18 | |
Debt Instrument, Redemption Period, End Date | 1-Jun-64 | |
SCE&G | Genco Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 5.90% | 5.89% |
Debt Instrument, Redemption Period, Start Date | 1-Feb-15 | |
Debt Instrument, Redemption Period, End Date | 1-Feb-24 | |
SCE&G | Industrial and Pollution Control Bonds [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 3.51% | 3.83% |
Debt Instrument, Redemption Period, Start Date | 1-Feb-28 | |
Debt Instrument, Redemption Period, End Date | 1-Dec-38 | |
Long-term Debt, Percentage Bearing Variable Interest, Amount | 67.8 | |
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.11% | |
SCE&G | Nuclear fuel purchase contract [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 0.78% | 0.78% |
Debt Instrument, Redemption Period, End Date | 1-Nov-16 | |
SCE&G | Other Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 2.63% | 2.26% |
Debt Instrument, Redemption Period, Start Date | 31-Jan-15 | |
Debt Instrument, Redemption Period, End Date | 30-Sep-27 |
LONGTERM_AND_SHORTTERM_DEBT_De1
LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Debt Instrument, Redemption [Line Items] | |
Long-term Debt Current Maturities in Next Twelve Months | $166 |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 115 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 14 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 723 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 13 |
SCE&G | |
Debt Instrument, Redemption [Line Items] | |
Long-term Debt Current Maturities in Next Twelve Months | 10 |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 109 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 9 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 719 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | $8 |
LONGTERM_AND_SHORTTERM_DEBT_NA
LONG-TERM AND SHORT-TERM DEBT (NARRATIVE) (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Debt Instrument [Line Items] | ||
Line of Credit, Current | $150 | |
months preceding issuance of bonds | 18 | |
Unfunded property additions | 70.00% | |
Consecutive months for bond ratio | 12 | |
Bond Ratio | 5.41 | |
SCE&G | ||
Debt Instrument [Line Items] | ||
Due to Related Parties | 83 | 27.3 |
Related Party Transaction, Due from (to) Related Party, Current | $80 | |
months preceding issuance of bonds | 18 | |
Unfunded property additions | 70.00% | |
Consecutive months for bond ratio | 12 | |
Bond Ratio | 5.41 |
Recovered_Sheet1
LONG-TERM AND SHORT-TERM DEBT (DETAILS 4) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $1,800,000,000 | |
Other Long-Term Debt Lenders | 2 | |
Wells Fargo, National Assoc, BOA and Morgan Stanley[Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
JP Morgan Chase, Mizuho, TD Bank, Credit Suisse AG,Cayman Islands Branch and UBS Loan [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
Branch Banking Trust Co, Union Bank and US Bank National Assoc [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
TD Bank [Domain] | ||
Line of Credit Facility [Line Items] | ||
Industrial Revenue Bonds | 67,800,000 | |
Expires October 2019 [Domain] | ||
Line of Credit Facility [Line Items] | ||
Long-Term Line of Credit - Parent Co | 300,000,000 | |
Long-Term Line of Credit - SCE&G (including SC Fuel Co) | 1,200,000,000 | |
Duration of Long-Term Credit Agreement | 5 | |
Long-Term Line of Credit - SC Fuel Co only | 500,000,000 | |
Long-Term Line of Credit - PSNC | 100,000,000 | |
Expires October 2016 [Domain] | ||
Line of Credit Facility [Line Items] | ||
Long-term Line of Credit - SCE&G only | 200,000,000 | |
Duration of Long-Term Credit Agreement | 3 | |
Parent Company [Member] | ||
Line of Credit Facility [Line Items] | ||
Commercial Paper | 179,000,000 | 125,000,000 |
Debt, Weighted Average Interest Rate | 0.54% | 0.39% |
Letters of Credit Outstanding, Amount | 3,000,000 | 3,000,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 118,000,000 | 172,000,000 |
SCE&G (including Fuel Company) | ||
Line of Credit Facility [Line Items] | ||
Commercial Paper | 709,000,000 | 251,000,000 |
Debt, Weighted Average Interest Rate | 0.52% | 0.27% |
Letters of Credit Outstanding, Amount | 300,000 | 300,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 691,000,000 | 1,149,000,000 |
PSNC Energy | ||
Line of Credit Facility [Line Items] | ||
Commercial Paper | 30,000,000 | |
Debt, Weighted Average Interest Rate | 0.65% | |
Line of Credit Facility, Remaining Borrowing Capacity | 70,000,000 | 100,000,000 |
SCE&G (including Fuel Company) | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400,000,000 | 1,400,000,000 |
SCE&G | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400,000,000 | 1,400,000,000 |
Commercial Paper | 709,000,000 | 251,000,000 |
Debt, Weighted Average Interest Rate | 0.52% | 0.27% |
Letters of Credit Outstanding, Amount | 300,000 | 300,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 691,000,000 | 1,149,000,000 |
Other Long-Term Debt Lenders | 2 | |
Related Party Transaction, Due from (to) Related Party, Current | 80,000,000 | |
Due to Related Parties | 83,000,000 | 27,300,000 |
SCE&G | Wells Fargo, National Assoc, BOA and Morgan Stanley[Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
SCE&G | JP Morgan Chase, Mizuho, TD Bank, Credit Suisse AG,Cayman Islands Branch and UBS Loan [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCE&G | Branch Banking Trust Co, Union Bank and US Bank National Assoc [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
SCE&G | TD Bank [Domain] | ||
Line of Credit Facility [Line Items] | ||
Industrial Revenue Bonds | 67,800,000 | |
SCE&G | Expires October 2019 [Domain] | ||
Line of Credit Facility [Line Items] | ||
Long-Term Line of Credit - SCE&G (including SC Fuel Co) | 1,200,000,000 | |
Duration of Long-Term Credit Agreement | 5 | |
Long-Term Line of Credit - SC Fuel Co only | 500,000,000 | |
SCE&G | Expires October 2016 [Domain] | ||
Line of Credit Facility [Line Items] | ||
Long-term Line of Credit - SCE&G only | 200,000,000 | |
Duration of Long-Term Credit Agreement | 3 | |
PSNC Energy | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 100,000,000 | 100,000,000 |
Parent Company [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $300,000,000 | $300,000,000 |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Investments, Owned, Federal Income Tax Note [Line Items] | |||||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 6.00% | 6.90% | 5.00% | ||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | ||||||
Current Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Current Federal Tax Expense (Benefit) | $38,000,000 | $161,000,000 | $103,000,000 | ||||
Current State and Local Tax Expense (Benefit) | -4,000,000 | 17,000,000 | 10,000,000 | ||||
Current Income Tax Expense (Benefit) | 34,000,000 | 178,000,000 | 113,000,000 | ||||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Deferred Federal Income Tax Expense (Benefit) | 184,000,000 | 39,000,000 | 72,000,000 | ||||
Deferred State and Local Income Tax Expense (Benefit) | 34,000,000 | 10,000,000 | 14,000,000 | ||||
Deferred Income Tax Expense (Benefit) | 218,000,000 | 49,000,000 | 86,000,000 | ||||
Income Tax Reconciliation, Tax Credits, Investment [Abstract] | |||||||
Balance at the beginning of the period | -1,000,000 | -1,000,000 | -14,000,000 | ||||
Investment Tax Credit | -4,000,000 | -4,000,000 | -17,000,000 | ||||
Income Tax Expense (Benefit) | 248,000,000 | 223,000,000 | 182,000,000 | ||||
Income (Loss) from Continuing Operations before Income Taxes, Domestic | 786,000,000 | 694,000,000 | 602,000,000 | ||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 275,000,000 | 243,000,000 | 211,000,000 | ||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | 24,000,000 | 22,000,000 | 19,000,000 | ||||
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits | -5,000,000 | -5,000,000 | -13,000,000 | ||||
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction | -11,000,000 | -9,000,000 | -8,000,000 | ||||
Effective Income Tax Rate Reconciliation, Deduction, Dividends, Amount | -10,000,000 | -10,000,000 | -9,000,000 | ||||
Amortization of Amounts Deferred under Federal Investment Tax Credits | -3,000,000 | -3,000,000 | -3,000,000 | ||||
Section41TaxCredit | -3,000,000 | 0 | 0 | ||||
Section 45 tax credit | -9,000,000 | -5,000,000 | -5,000,000 | ||||
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent | -7,000,000 | -11,000,000 | -9,000,000 | ||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | -3,000,000 | 1,000,000 | -1,000,000 | ||||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | 127,000,000 | 127,000,000 | 84,000,000 | ||||
Deferred tax Nuclear Decommissioning | 216,000,000 | 216,000,000 | 220,000,000 | ||||
Deferred Tax Assets, Financial Instruments | 40,000,000 | 40,000,000 | 32,000,000 | ||||
Deferred Tax Asset, Unamortized Investment, Tax Credits | 17,000,000 | 17,000,000 | 19,000,000 | ||||
Deferred Tax Assets, Derivative Instruments | 0 | 0 | 27,000,000 | ||||
Deferred Tax Assets, Monetization of Bankruptcy Claims | 10,000,000 | 10,000,000 | 11,000,000 | ||||
Deferred Tax Assets, Other | 10,000,000 | 10,000,000 | 13,000,000 | ||||
Deferred Tax Assets, Net | 420,000,000 | 420,000,000 | 406,000,000 | ||||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,928,000,000 | 1,928,000,000 | 1,765,000,000 | ||||
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits | 107,000,000 | 107,000,000 | 63,000,000 | ||||
Deferred Tax Liabilities, Asset Retirement Obligation | 122,000,000 | 122,000,000 | 121,000,000 | ||||
Deferred Tax Liabilities, Deferred Expense Fuel Costs | 27,000,000 | 27,000,000 | 25,000,000 | ||||
Deferred tax asset unrecovered plant | 53,000,000 | 53,000,000 | 55,000,000 | ||||
Deferred Tax Liabilities, Derivatives | 21,000,000 | 21,000,000 | 0 | ||||
Deferred Tax Liability, Demand Side Management | 21,000,000 | 21,000,000 | 21,000,000 | ||||
deferred tax liability, prepayments | 27,000,000 | 27,000,000 | 25,000,000 | ||||
Deferred Tax Liabilities, Other | 45,000,000 | 45,000,000 | 38,000,000 | ||||
Deferred Tax Liabilities, Net | 2,351,000,000 | 2,351,000,000 | 2,113,000,000 | ||||
Deferred Tax Liabilities, Net, Noncurrent | 1,931,000,000 | 1,931,000,000 | 1,707,000,000 | ||||
Unrecognized Tax Benefits | 16,000,000 | 16,000,000 | 3,000,000 | 0 | |||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 13,000,000 | ||||||
SCE&G | |||||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||||
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound | 7,000,000 | 7,000,000 | |||||
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 13,000,000 | 13,000,000 | |||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | ||||||
Current Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Current Federal Tax Expense (Benefit) | 39,000,000 | 146,000,000 | 91,000,000 | ||||
Current State and Local Tax Expense (Benefit) | -6,000,000 | 13,000,000 | 8,000,000 | ||||
Current Income Tax Expense (Benefit) | 33,000,000 | 159,000,000 | 99,000,000 | ||||
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract] | |||||||
Deferred Federal Income Tax Expense (Benefit) | 157,000,000 | 25,000,000 | 62,000,000 | ||||
Deferred State and Local Income Tax Expense (Benefit) | 32,000,000 | 9,000,000 | 12,000,000 | ||||
Deferred Income Tax Expense (Benefit) | 189,000,000 | 34,000,000 | 74,000,000 | ||||
Income Tax Reconciliation, Tax Credits, Investment [Abstract] | |||||||
Balance at the beginning of the period | -1,000,000 | -1,000,000 | -13,000,000 | ||||
Investment Tax Credit | -4,000,000 | -4,000,000 | -16,000,000 | ||||
Income Tax Expense (Benefit) | 218,000,000 | 189,000,000 | 157,000,000 | ||||
Net Income (Loss) Attributable to Noncontrolling Interest | 12,000,000 | 11,000,000 | 11,000,000 | ||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 237,000,000 | 203,000,000 | 178,000,000 | ||||
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | 21,000,000 | 18,000,000 | 17,000,000 | ||||
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits | -5,000,000 | -5,000,000 | -13,000,000 | ||||
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction | -10,000,000 | -9,000,000 | -7,000,000 | ||||
Amortization of Amounts Deferred under Federal Investment Tax Credits | -3,000,000 | -3,000,000 | -3,000,000 | ||||
Section 45 tax credit | -9,000,000 | -5,000,000 | -5,000,000 | ||||
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent | -7,000,000 | -11,000,000 | -9,000,000 | ||||
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | -3,000,000 | 1,000,000 | -1,000,000 | ||||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | 47,000,000 | 47,000,000 | 17,000,000 | ||||
Deferred tax Nuclear Decommissioning | 205,000,000 | 205,000,000 | 209,000,000 | ||||
Deferred Tax Asset, Unamortized Investment, Tax Credits | 17,000,000 | 17,000,000 | 19,000,000 | ||||
Deferred Tax Assets, Derivative Instruments | 0 | 0 | 27,000,000 | ||||
Deferred Tax Assets, Other | 6,000,000 | 6,000,000 | 11,000,000 | ||||
Deferred Tax Assets, Net | 275,000,000 | 275,000,000 | 283,000,000 | ||||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,623,000,000 | 1,623,000,000 | 1,494,000,000 | ||||
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits | 91,000,000 | 91,000,000 | 54,000,000 | ||||
Deferred Tax Liabilities, Asset Retirement Obligation | 115,000,000 | 115,000,000 | 114,000,000 | ||||
Deferred Tax Liabilities, Deferred Expense Fuel Costs | 27,000,000 | 27,000,000 | 26,000,000 | ||||
Deferred tax asset unrecovered plant | 53,000,000 | 53,000,000 | 55,000,000 | ||||
Deferred Tax Liabilities, Derivatives | 21,000,000 | 21,000,000 | 0 | ||||
Deferred Tax Liability, Demand Side Management | 21,000,000 | 21,000,000 | 21,000,000 | ||||
deferred tax liability, prepayments | 25,000,000 | 25,000,000 | 23,000,000 | ||||
Deferred Tax Liabilities, Other | 23,000,000 | 23,000,000 | 18,000,000 | ||||
Deferred Tax Liabilities, Net | 1,999,000,000 | 1,999,000,000 | 1,805,000,000 | ||||
Deferred Tax Liabilities, Net, Noncurrent | 1,724,000,000 | 1,724,000,000 | 1,522,000,000 | ||||
Unrecognized Tax Benefits | 16,000,000 | 16,000,000 | 3,000,000 | 0 | 38,000,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions | 0 | -38,000,000 | |||||
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 13,000,000 | 3,000,000 | 0 | ||||
Held for Sale, CGT and SCI [Member] | |||||||
Income Tax Reconciliation, Tax Credits, Investment [Abstract] | |||||||
Deferred Tax Liabilities, Net, Current | $51,300,000 | $51,300,000 |
INCOME_TAXES_INCOME_TAXES_Deta
INCOME TAXES INCOME TAXES (Details 2) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2015 | |
income tax [Line Items] | ||||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | $127,000,000 | $84,000,000 | ||
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate | 275,000,000 | 243,000,000 | 211,000,000 | |
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract] | ||||
Income Tax Reconciliation, State and Local Income Taxes | 24,000,000 | 22,000,000 | 19,000,000 | |
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits | -5,000,000 | -5,000,000 | -13,000,000 | |
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction | -11,000,000 | -9,000,000 | -8,000,000 | |
Income Tax Reconciliation, Deductions, Dividends | -10,000,000 | -10,000,000 | -9,000,000 | |
Amortization of Amounts Deferred under Federal Investment Tax Credits | -3,000,000 | -3,000,000 | -3,000,000 | |
Section 45 tax credit | -9,000,000 | -5,000,000 | -5,000,000 | |
Income Tax Reconciliation, Other Adjustments | -3,000,000 | 1,000,000 | -1,000,000 | |
Income Tax Expense (Benefit) | 248,000,000 | 223,000,000 | 182,000,000 | |
Income (Loss) from Continuing Operations before Income Taxes, Domestic | 786,000,000 | 694,000,000 | 602,000,000 | |
SCE&G | ||||
income tax [Line Items] | ||||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 16,000,000 | 2,000,000 | ||
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 2,000,000 | |||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | 47,000,000 | 17,000,000 | ||
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate | 237,000,000 | 203,000,000 | 178,000,000 | |
Income Tax Expense (Benefit) Continuing Operations, Income Tax Reconciliation, Changes [Abstract] | ||||
Income Tax Reconciliation, State and Local Income Taxes | 21,000,000 | 18,000,000 | 17,000,000 | |
Income Tax Reconciliation, Amortization of State and Local Investment Tax Credits | -5,000,000 | -5,000,000 | -13,000,000 | |
Income Tax Reconciliation, Allowance for Cost of Equity Funds Used During Construction | -10,000,000 | -9,000,000 | -7,000,000 | |
Amortization of Amounts Deferred under Federal Investment Tax Credits | -3,000,000 | -3,000,000 | -3,000,000 | |
Section 45 tax credit | -9,000,000 | -5,000,000 | -5,000,000 | |
Income Tax Reconciliation, Other Adjustments | -3,000,000 | 1,000,000 | -1,000,000 | |
Income Tax Expense (Benefit) | 218,000,000 | 189,000,000 | 157,000,000 | |
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest | $676,000,000 | $580,000,000 | $509,000,000 |
INCOME_TAXES_INCOME_TAXES_Deta1
INCOME TAXES INCOME TAXES (Details 3) (USD $) | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2015 | Dec. 31, 2011 |
Deferred Tax Assets, Net [Abstract] | |||||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | $127 | $84 | |||
Deferred tax Nuclear Decommissioning | 216 | 220 | |||
Deferred Tax Assets, Financial Instruments | 40 | 32 | |||
Deferred Tax Asset, Unamortized Investment, Tax Credits | 17 | 19 | |||
Deferred Tax Assets, Derivative Instruments | 0 | 27 | |||
Deferred Tax Assets, Monetization of Bankruptcy Claims | 10 | 11 | |||
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits | 107 | 63 | |||
Deferred Tax Assets, Other | 10 | 13 | |||
Deferred Tax Assets, Net | 420 | 406 | |||
Deferred Tax Liabilities, Gross [Abstract] | |||||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,928 | 1,765 | |||
Deferred Tax Liabilities, Asset Retirement Obligation | 122 | 121 | |||
Deferred Tax Liabilities, Deferred Expense Fuel Costs | 27 | 25 | |||
Deferred tax asset unrecovered plant | 53 | 55 | |||
Deferred Tax Liabilities, Derivatives | 21 | 0 | |||
Deferred Tax Liability, Demand Side Management | 21 | 21 | |||
deferred tax liability, prepayments | 27 | 25 | |||
Deferred Tax Liabilities, Other | 45 | 38 | |||
Deferred Tax Liabilities, Gross | 2,351 | 2,113 | |||
Deferred Tax Liabilities, Net, Noncurrent | 1,931 | 1,707 | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||||
Gross increases current period tax positions | 13 | ||||
Balance at the end of the period | 16 | 3 | 0 | ||
SCE&G | |||||
Investments, Owned, Federal Income Tax Note [Line Items] | |||||
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 2 | ||||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 16 | 2 | |||
Deferred Tax Assets, Net [Abstract] | |||||
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities | 47 | 17 | |||
Deferred tax Nuclear Decommissioning | 205 | 209 | |||
Deferred Tax Asset, Unamortized Investment, Tax Credits | 17 | 19 | |||
Deferred Tax Assets, Derivative Instruments | 0 | 27 | |||
Deferred Tax Liabilities, Tax Deferred Expense Compensation and Benefits, Employee Benefits | 91 | 54 | |||
Deferred Tax Assets, Other | 6 | 11 | |||
Deferred Tax Assets, Net | 275 | 283 | |||
Deferred Tax Liabilities, Gross [Abstract] | |||||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,623 | 1,494 | |||
Deferred Tax Liabilities, Asset Retirement Obligation | 115 | 114 | |||
Deferred Tax Liabilities, Deferred Expense Fuel Costs | 27 | 26 | |||
Deferred tax asset unrecovered plant | 53 | 55 | |||
Deferred Tax Liabilities, Derivatives | 21 | 0 | |||
Deferred Tax Liability, Demand Side Management | 21 | 21 | |||
deferred tax liability, prepayments | 25 | 23 | |||
Deferred Tax Liabilities, Other | 23 | 18 | |||
Deferred Tax Liabilities, Gross | 1,999 | 1,805 | |||
Deferred Tax Liabilities, Net, Noncurrent | 1,724 | 1,522 | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||||
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions | 0 | ||||
Gross decreases tax positions in prior period | 0 | 38 | |||
Gross increases current period tax positions | 13 | 3 | 0 | ||
Balance at the end of the period | $16 | $3 | $0 | $38 |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
MMBTU | MMBTU | |||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 55,733,059 | [1] | 42,715,958 | [2] |
Gas Distribution | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 6,840,000 | 6,070,000 | ||
Retail Gas Marketing | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 7,951,000 | 6,726,000 | ||
Energy Marketing [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 40,942,059 | [1] | 29,919,958 | [2] |
Energy Related Derivative [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 37,495,339 | [1] | 27,359,958 | [2] |
Energy Related Derivative [Member] | Gas Distribution | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 0 | 0 | ||
Energy Related Derivative [Member] | Retail Gas Marketing | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 0 | 0 | ||
Energy Related Derivative [Member] | Energy Marketing [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 37,495,339 | 27,359,958 | ||
Commodity Contracts | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 18,237,720 | 15,356,000 | ||
Commodity Contracts | Gas Distribution | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 6,840,000 | 6,070,000 | ||
Commodity Contracts | Retail Gas Marketing | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 7,951,000 | 6,726,000 | ||
Commodity Contracts | Energy Marketing [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 3,446,720 | 2,560,000 | ||
Basis Swap [Member] | Energy Related Derivative [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount, Energy Measure | 933,893 | 348,453 | ||
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | 1,100 | 1,300 | ||
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | 124.4 | 128.8 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | 1,100 | 1,300 | ||
SCE&G | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | 36.4 | 36.4 | ||
[1] | (a) Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing. | |||
[2] | (b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS FAIR VALUE ON BALANCE SHEET (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative [Line Items] | |||
Derivative Liability | $289 | $28 | |
Derivative Asset | 21 | 44 | |
Other Deferred Debits and Other Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 5 | 23 | |
Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 50 | 18 | |
Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 6 | ||
Derivative Asset | 16 | 21 | |
Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Liability | 257 | 20 | |
Derivative Asset | 32 | ||
Commodity Contracts | |||
Derivative [Line Items] | |||
Derivative Liability | 12 | ||
Derivative Asset | 1 | 4 | |
Other Energy Management Contract [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 20 | 8 | |
Derivative Asset | 20 | 8 | |
Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 45 | 19 | |
Derivative Asset | 2 | ||
Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 5 | 5 | |
Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 28 | 14 | |
Designated as Hedging Instrument [Member] | Commodity Contracts | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 11 | ||
Designated as Hedging Instrument [Member] | Commodity Contracts | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 1 | ||
Derivative Asset | 2 | ||
Not Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 244 | 9 | |
Derivative Asset | 21 | 42 | |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -352 | 39 | |
Derivative, Notional Amount | 1,100 | 1,300 | |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 207 | 1 | |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Debits and Other Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 19 | ||
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 17 | ||
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 13 | ||
Not Designated as Hedging Instrument [Member] | Commodity Contracts | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 1 | 2 | |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 10 | 4 | |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 5 | 4 | |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 5 | 4 | |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 5 | ||
Derivative Asset | 15 | 4 | |
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | 124.4 | 128.8 | |
SCE&G | |||
Derivative [Line Items] | |||
Derivative Liability | 233 | 2 | |
Derivative Asset | 32 | ||
SCE&G | Other Deferred Debits and Other Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 19 | ||
SCE&G | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 25 | ||
SCE&G | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 13 | ||
SCE&G | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Liability | 233 | 2 | |
Derivative Asset | 0 | 32 | |
SCE&G | Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 9 | 1 | |
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 1 | 1 | |
SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 8 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 224 | 1 | |
Derivative Asset | 32 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -352 | 39 | |
Derivative, Notional Amount | 1,100 | 1,300 | |
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Derivative Financial Instruments, Liabilities [Member] | |||
Derivative [Line Items] | |||
Derivative Liability | 207 | 1 | |
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Debits and Other Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 19 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Deferred Credits and Other Liabilities | |||
Derivative [Line Items] | |||
Derivative Liability | 17 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Current Assets [Member] | |||
Derivative [Line Items] | |||
Derivative Asset | 13 | ||
SCE&G | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | 36.4 | 36.4 | |
Interest Expense [Member] | Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -9 | 106 | 84 |
Interest Expense [Member] | SCE&G | Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | ($9) | $106 | $84 |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS ON INCOME STATEMENT (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative [Line Items] | |||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | ($14) | $7 | ($8) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | -3 | -11 | -19 |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant | insignificant |
Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 7 | 8 | 6 |
Interest Rate Contract | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | -7.1 | ||
Commodity Contracts | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -4 | 3 | 13 |
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | -1 | ||
Commodity Contracts | Gas Purchased for Resale [Member] [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | -10 | ||
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | 1,100 | 1,300 | |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -352 | 39 | |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 64 | 50 | |
SCE&G | |||
Derivative [Line Items] | |||
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant | insignificant |
SCE&G | Commodity Contracts | |||
Derivative [Line Items] | |||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | -1 | ||
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | 1,100 | 1,300 | |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -352 | 39 | |
SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 64 | 50 | |
Cash Flow Hedging [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | -6 | 5 | -4 |
Cash Flow Hedging [Member] | Interest Rate Contract | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -3 | -3 | -3 |
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -7 | -8 | -6 |
Cash Flow Hedging [Member] | Commodity Contracts | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | -8 | 2 | -4 |
Cash Flow Hedging [Member] | Commodity Contracts | Gas Purchased for Resale [Member] [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -4 | 3 | 13 |
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | 124.4 | 128.8 | |
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -9 | 106 | 84 |
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 2.3 | ||
Cash Flow Hedging [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 5.2 | ||
Cash Flow Hedging [Member] | SCE&G | Interest Rate Contract | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -3 | -3 | -3 |
Cash Flow Hedging [Member] | SCE&G | Designated as Hedging Instrument [Member] | Interest Rate Contract | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -9 | 106 | 84 |
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 2.3 | ||
Cash Flow Hedging [Member] | SCE&G | Not Designated as Hedging Instrument [Member] | Interest Rate Contract | Other Nonoperating Income (Expense) [Member] | |||
Derivative [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | $5.20 |
DERIVATIVE_FINANCIAL_INSTRUMEN5
DERIVATIVE FINANCIAL INSTRUMENTS (CREDIT RISK) (Details 3) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Derivative, Credit Risk Related Contingent Features [Abstract] | ||
Collateral Already Posted, Aggregate Fair Value | $152.40 | $26.80 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | 129.8 | |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 282.2 | 25.2 |
Cash collateral requested from counterparty | 0 | 34.1 |
Derivative, net asset position | 34.1 | |
Letter of Credit Available Commodity Derivatives,asset position | 9.2 | 20 |
Commodity Derivative, net asset position | 6 | 6 |
SCE&G | ||
Derivative, Credit Risk Related Contingent Features [Abstract] | ||
Collateral Already Posted, Aggregate Fair Value | 107.1 | 1.5 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | 125.9 | |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 233 | 1 |
Cash collateral requested from counterparty | 31.7 | |
Commodity Derivative, net asset position | $0 | $31.70 |
DERIVATIVE_FINANCIAL_INSTRUMEN6
DERIVATIVE FINANCIAL INSTRUMENTS OFFSETTING ASSETS AND LIABILITIES (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Derivative [Line Items] | ||
Derivative Liability | $289 | $28 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 21 | 44 |
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | -1 |
Derivative Asset, Fair Value, Gross Asset | 21 | 44 |
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liabilities, Net Amount | 137 | 2 |
Derivative Liability, Fair Value, Gross Liability | 289 | 28 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | -1 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted | 152 | 25 |
Derivative Assets, Net Amount | 21 | 43 |
Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 5 | 23 |
Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 6 | |
Derivative Asset | 16 | 21 |
Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 233 | 10 |
Other Deferred Credits and Other Liabilities | ||
Derivative [Line Items] | ||
Derivative Liability | 50 | 18 |
Interest Rate Contract | ||
Derivative [Line Items] | ||
Derivative Liability | 257 | 20 |
Derivative Asset | 32 | |
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | -1 | |
Derivative Asset, Fair Value, Gross Asset | 32 | |
Derivative Liabilities, Net Amount | 126 | 0 |
Derivative Liability, Fair Value, Gross Liability | 257 | 20 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | -1 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted | 131 | 19 |
Derivative Assets, Net Amount | 31 | |
Commodity Contracts | ||
Derivative [Line Items] | ||
Derivative Liability | 12 | |
Derivative Asset, Fair Value, Gross Liability | 0 | |
Derivative Asset | 1 | 4 |
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | |
Derivative Asset, Fair Value, Gross Asset | 1 | 4 |
Derivative Liability, Fair Value, Gross Asset | 0 | |
Derivative Liabilities, Net Amount | 2 | |
Derivative Liability, Fair Value, Gross Liability | 12 | |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted | 10 | |
Derivative Assets, Net Amount | 1 | 4 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 20 | 8 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 20 | 8 |
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | |
Derivative Asset, Fair Value, Gross Asset | 20 | 8 |
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liabilities, Net Amount | 9 | 2 |
Derivative Liability, Fair Value, Gross Liability | 20 | 8 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | 0 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted | 11 | 6 |
Derivative Assets, Net Amount | 20 | 8 |
SCE&G | ||
Derivative [Line Items] | ||
Derivative Liability | 233 | 2 |
Derivative Asset | 32 | |
SCE&G | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 19 | |
SCE&G | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 13 | |
SCE&G | Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 208 | 2 |
SCE&G | Other Deferred Credits and Other Liabilities | ||
Derivative [Line Items] | ||
Derivative Liability | 25 | |
SCE&G | Interest Rate Contract | ||
Derivative [Line Items] | ||
Derivative Liability | 233 | 2 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 0 | 32 |
Derivative Assets, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | -1 |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Gross Asset | 0 | 32 |
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liabilities, Net Amount | 126 | 0 |
Derivative Liability, Fair Value, Gross Liability | 233 | 2 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Financial Instruments | 0 | -1 |
Derivative Liabilities, Gross Amounts Not Offset in the Statement of Financial Position - Cash Collateral Posted | 107 | 1 |
Derivative Assets, Net Amount | $0 | $31 |
FAIR_VALUE_MEASUREMENTS_INCLUD2
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $21 | $44 |
Derivative Liability | 289 | 28 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no |
Level 3 Fair Value Measurements | no | no |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Available-for-sale Securities | 13 | 9 |
Interest Rate Contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 32 | |
Derivative Liability | 257 | 20 |
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 32 | |
Derivative Liability | 257 | 20 |
Commodity Contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 1 | 4 |
Derivative Liability | 12 | |
Commodity Contracts | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 1 | 2 |
Derivative Liability | 1 | |
Commodity Contracts | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 2 | |
Derivative Liability | 11 | |
Other Energy Management Contract [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 20 | 8 |
Derivative Liability | 20 | 8 |
Other Energy Management Contract [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 1 | |
Derivative Liability | 5 | |
Other Energy Management Contract [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 20 | 7 |
Derivative Liability | 18 | 12 |
SCE&G | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 32 | |
Derivative Liability | 233 | 2 |
Liabilities, Fair Value Disclosure [Abstract] | ||
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no |
Level 3 Fair Value Measurements | no | no |
SCE&G | Interest Rate Contract | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 0 | 32 |
Derivative Liability | 233 | 2 |
SCE&G | Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 32 | |
Derivative Liability | $233 | $2 |
FAIR_VALUE_MEASUREMENTS_INCLUD3
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Other Long-term Debt, Noncurrent | $5,697.20 | $5,449.30 |
Long-term debt, Fair Value | 6,592.10 | 5,916.30 |
SCE&G | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Other Long-term Debt, Noncurrent | 4,308.60 | 4,054.90 |
Long-term debt, Fair Value | $5,070.90 | $4,433 |
EMPLOYEE_BENEFIT_PLANS_Details
EMPLOYEE BENEFIT PLANS (Details) (USD $) | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
Dec. 31, 2013 | Aug. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Curtailments | $0 | ($25,500,000) | ||||
Defined Benefit Plan, Accumulated Benefit Obligation | 796,400,000 | 888,300,000 | 796,400,000 | |||
Defined Benefit Plan Health Care Cost Trend Rate, Assumed | 7.00% | |||||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | |||||
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation | 1,100,000 | 1,300,000 | ||||
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation | 1,000,000 | 1,200,000 | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 870,000,000 | 862,000,000 | 870,000,000 | |||
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no | ||||
Defined Benefit Plan Allocation, Equity Securities | 58.00% | |||||
Defined Benefit Plan, Debt Securies | 33.00% | |||||
Defined Contribution Plan, Cost Recognized | 25,800,000 | 23,400,000 | 22,300,000 | |||
defined benefit plan, hedge funds | 0.00% | |||||
Other Postretirement Benefits | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Benefit Obligation | 238,000,000 | 268,200,000 | 238,000,000 | 265,300,000 | ||
Service cost | 4,600,000 | 5,900,000 | 4,800,000 | |||
Interest cost | 12,000,000 | 11,100,000 | 11,900,000 | |||
Defined Benefit Plan, Contributions by Plan Participants | 2,200,000 | 2,600,000 | ||||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -23,500,000 | 35,100,000 | ||||
Defined Benefit Plan, Benefits Paid | -12,100,000 | -11,800,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 5.19% | 4.30% | 5.19% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.75% | 3.00% | 3.75% | |||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | 5.00% | 5.00% | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 | |||
Defined Benefit Plan, Funded Status of Plan | -238,000,000 | -268,200,000 | -238,000,000 | |||
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities | -11,500,000 | -11,200,000 | -11,500,000 | |||
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent | -226,500,000 | -257,000,000 | -226,500,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 1,700,000 | 3,000,000 | 1,700,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 100,000 | 100,000 | 100,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax | 1,800,000 | 3,100,000 | 1,800,000 | |||
pension and other postretirement benefit plans, regulated assets, net gains, before tax | 43,800,000 | 24,400,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax | 600,000 | 900,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, before tax | 44,400,000 | 25,300,000 | ||||
Defined Benefit Plan, Shared Costs Deferred | 12.6 | 15.1 | 12.6 | |||
Defined benefit plan, future amortization of gain or loss from regulatory assets | 1,900,000 | |||||
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax | 19,400,000 | -29,900,000 | 31,400,000 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.19% | 4.19% | 5.35% | |||
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 300,000 | 700,000 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 4.00% | |||
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax | 0 | -2,700,000 | -1,200,000 | |||
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax | -300,000 | -600,000 | -800,000 | |||
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax | 0 | 0 | 0 | |||
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax | 0 | -200,000 | -500,000 | |||
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax | 19,100,000 | -33,400,000 | 28,900,000 | |||
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets | 300,000 | |||||
Defined benefit plan, amount to be amortized from regulatory assets next year | 2,200,000 | |||||
Pension Plan, Defined Benefit | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Benefit Obligation | 823,000,000 | 919,500,000 | 823,000,000 | 931,600,000 | ||
Service cost | 20,000,000 | 21,800,000 | 19,600,000 | |||
Interest cost | 40,400,000 | 38,500,000 | 43,000,000 | |||
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 | ||||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -100,100,000 | 83,400,000 | ||||
Defined Benefit Plan, Benefits Paid | -64,000,000 | -60,000,000 | ||||
Defined Benefit Plan, Curtailments | 0 | 9,900,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 5.03% | 4.20% | 5.03% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.00% | 3.00% | 3.00% | |||
Defined Benefit Plan, Fair Value of Plan Assets | 870,000,000 | 861,800,000 | 870,000,000 | 799,100,000 | ||
Defined Benefit Plan, Funded Status of Plan | 47,000,000 | -57,700,000 | 47,000,000 | |||
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 47,000,000 | 0 | 47,000,000 | |||
Defined Benefit Pension Plan, Liabilities, Noncurrent | 0 | -57,700,000 | 0 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 5,200,000 | 8,100,000 | 5,200,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 500,000 | 300,000 | 500,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax | 5,700,000 | 8,400,000 | 5,700,000 | |||
pension and other postretirement benefit plans, regulated assets, net gains, before tax | 222,100,000 | 124,800,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax | 9,600,000 | 12,800,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, before tax | 231,700,000 | 137,600,000 | ||||
Defined Benefit Plan, Shared Costs Deferred | 14.1 | 17.8 | 14.1 | |||
Defined benefit plan, future amortization of gain or loss from regulatory assets | 12,300,000 | |||||
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax | 101,300,000 | -157,500,000 | 45,000,000 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.07% | 4.10% | 5.03% | 5.25% | ||
Expected return on assets | 66,700,000 | 61,400,000 | 59,500,000 | |||
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 0 | 0 | |||
Defined Benefit Plan, Actual Return on Plan Assets | 55,800,000 | 130,900,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.00% | 3.75% | 3.00% | 4.00% | ||
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax | -4,000,000 | -14,700,000 | -16,000,000 | |||
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax | -3,200,000 | -5,200,000 | -6,400,000 | |||
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax | 0 | -8,900,000 | 0 | |||
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax | 0 | 0 | 0 | |||
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax | 94,100,000 | -186,300,000 | 22,600,000 | |||
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets | 3,600,000 | |||||
Defined benefit plan, amount to be amortized from regulatory assets next year | 15,900,000 | |||||
SCE&G | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Period for which Annual Base Earnings are Considered Under Average Pay Formula | 3 | |||||
Defined Benefit Plan, Curtailments | 0 | -21,600,000 | ||||
Defined Benefit Plan, Accumulated Benefit Obligation | 0 | 0 | 0 | |||
Defined Benefit Plan Health Care Cost Trend Rate, Assumed | 7.00% | |||||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | |||||
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation | 0 | 0 | ||||
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation | 0 | 0 | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 792,000,000 | 784,000,000 | 792,000,000 | |||
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no | ||||
Defined Contribution Plan, Cost Recognized | 20,700,000 | 18,700,000 | 17,700,000 | |||
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | insignificant | |||||
Regulatory assets, expected recovery period (in years) | 12 | |||||
SCE&G | Other Postretirement Benefits | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Benefit Obligation | 181,700,000 | 204,100,000 | 181,700,000 | 206,000,000 | ||
Service cost | 3,600,000 | 4,600,000 | 3,700,000 | |||
Interest cost | 9,400,000 | 8,700,000 | 9,400,000 | |||
Defined Benefit Plan, Contributions by Plan Participants | 1,800,000 | 2,000,000 | ||||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -18,600,000 | 27,300,000 | ||||
Defined Benefit Plan, Benefits Paid | -9,600,000 | -9,300,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 5.19% | 4.30% | 5.19% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.75% | 3.00% | 3.75% | |||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | 5.00% | 5.00% | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 | |||
Defined Benefit Plan, Funded Status of Plan | -181,700,000 | -204,100,000 | -181,700,000 | |||
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities | -7,800,000 | -8,500,000 | -7,800,000 | |||
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 0 | 0 | 0 | |||
Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent | -173,900,000 | -195,600,000 | -173,900,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 600,000 | 1,000,000 | 600,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 0 | 0 | 0 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax | 600,000 | 1,000,000 | 600,000 | |||
pension and other postretirement benefit plans, regulated assets, net gains, before tax | 35,900,000 | 20,100,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax | 500,000 | 700,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, before tax | 36,400,000 | 20,800,000 | ||||
Defined Benefit Plan, Shared Costs Deferred | 12.6 | 15.1 | 12.6 | |||
Defined benefit plan, future amortization of gain or loss from regulatory assets | 1,600,000 | |||||
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax | 15,800,000 | -24,400,000 | 25,700,000 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.19% | 4.19% | 5.35% | |||
Defined Benefit Plan, Amounts Funded to Parent | -1,400,000 | -3,000,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 4.00% | |||
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax | 0 | -2,200,000 | -1,000,000 | |||
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax | -200,000 | -500,000 | -700,000 | |||
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax | 0 | 0 | 0 | |||
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax | 0 | -100,000 | -200,000 | |||
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax | 15,600,000 | -27,200,000 | 23,800,000 | |||
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets | 200,000 | |||||
Defined benefit plan, amount to be amortized from regulatory assets next year | 1,800,000 | |||||
SCE&G | Pension Plan, Defined Benefit | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Benefit Obligation | 695,700,000 | 773,700,000 | 695,700,000 | 788,400,000 | ||
Service cost | 16,000,000 | 17,600,000 | 15,700,000 | |||
Interest cost | 34,100,000 | 32,600,000 | 36,400,000 | |||
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 | ||||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -82,700,000 | 70,700,000 | ||||
Defined Benefit Plan, Benefits Paid | -54,800,000 | -50,600,000 | ||||
Defined Benefit Plan, Curtailments | 0 | 8,400,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 5.03% | 4.20% | 5.03% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 3.00% | 3.00% | 3.00% | |||
Defined Benefit Plan, Fair Value of Plan Assets | 792,100,000 | 783,600,000 | 792,100,000 | 732,000,000 | ||
Defined Benefit Plan, Funded Status of Plan | 96,400,000 | 9,900,000 | 96,400,000 | |||
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 96,400,000 | 9,900,000 | 96,400,000 | |||
Defined Benefit Pension Plan, Liabilities, Noncurrent | 0 | 0 | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 1,800,000 | 1,900,000 | 1,800,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 200,000 | 100,000 | 200,000 | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax | 2,000,000 | 2,000,000 | 2,000,000 | |||
pension and other postretirement benefit plans, regulated assets, net gains, before tax | 191,900,000 | 107,700,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, net prior service costs (credit), before tax | 8,300,000 | 11,100,000 | ||||
Pension and other postretirement benefit plans, regulatory assets, before tax | 200,200,000 | 118,800,000 | ||||
Defined Benefit Plan, Shared Costs Deferred | 14.1 | 17.8 | 14.1 | |||
Defined benefit plan, future amortization of gain or loss from regulatory assets | 10,600,000 | |||||
Regulatory assets, pension and other postretirement benefit plans, net unamortized gain (loss) arising during the period, net of tax | 87,700,000 | -137,100,000 | 37,900,000 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.07% | 4.10% | 5.03% | 5.25% | ||
Defined Benefit Plan, Amounts Funded to Parent | 0 | 0 | ||||
Expected return on assets | 56,300,000 | 51,900,000 | 50,400,000 | |||
Defined Benefit Plan, Actual Return on Plan Assets | 46,300,000 | 110,700,000 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.00% | 3.75% | 3.00% | 4.00% | ||
Regulatory assets, amortization of actuarial losses, pension and other postretirement benefit plans, net of tax | -3,500,000 | -12,700,000 | -14,000,000 | |||
Regulatory assets, amortization of prior service cost, pension and other postretirement benefit plans, net of tax | -2,800,000 | -4,500,000 | -5,700,000 | |||
Regulatory assets, prior service cost (credit), pension and other postretirement benefit plans, net of tax | 0 | -7,700,000 | 0 | |||
Regulatory assets, amortization of transition obligation, pension and other postretirement benefit plans, net of tax | 0 | 0 | 0 | |||
Regulatory assets, total recognized in regulatory assets, pension and other postretirement benefit plans, net of tax | 81,400,000 | -162,000,000 | 18,200,000 | |||
Defined benefit plan, future amortization of prior service cost (credit) from regulatory assets | 3,100,000 | |||||
Defined benefit plan, amount to be amortized from regulatory assets next year | 13,700,000 | |||||
Pension Costs [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | 14,000,000 | 14,000,000 | 63,000,000 | |||
Regulatory assets, expected recovery period (in years) | 12 | 14 | 30 | |||
Pension Costs [Member] | SCE&G | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | $14,000,000 | $14,000,000 | $63,000,000 | |||
Regulatory assets, expected recovery period (in years) | 12 | 14 |
EMPLOYEE_BENEFIT_PLANS_EMPLOYE
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 2) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Target Allocation, Equity Securities | 58.00% | 57.00% | 59.00% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | ||
Defined Benefit Plan, Target Plan Asset Allocations | 33.00% | 34.00% | 32.00% |
Defined Benefit Plan Allocation, Equity Securities | 58.00% | ||
Defined Benefit Plan, Debt Securies | 33.00% | ||
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds | 9.00% | 9.00% | 9.00% |
SCE&G | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Target Allocation, Equity Securities | 58.00% | 57.00% | 59.00% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | ||
Defined Benefit Plan, Target Plan Asset Allocations | 33.00% | 34.00% | 32.00% |
Defined Benefit Plan, Target Plan Asset Allocation, Hedge Funds | 9.00% | 9.00% | 9.00% |
EMPLOYEE_BENEFIT_PLANS_EMPLOYE1
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 3) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $862 | $870 | |
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no | |
Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 332 | |
Preferred Stock [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 1 | |
Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 622 | 305 | |
Short-term Investments [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 20 | 19 | |
Agency Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 6 | 33 | |
Corporate Debt Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 86 | 53 | |
Loans Secured by Mortgage [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 12 | |
Municipal Bonds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 15 | 4 | |
Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 32 | 35 | |
Hedge Funds, Multi-strategy [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 81 | 76 | |
Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 354 | ||
Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 332 | ||
Fair Value, Inputs, Level 1 [Member] | Preferred Stock [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | ||
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 20 | ||
Fair Value, Inputs, Level 1 [Member] | Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | ||
Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 781 | 440 | |
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 622 | 285 | |
Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 20 | 19 | |
Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 6 | 33 | |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 86 | 53 | |
Fair Value, Inputs, Level 2 [Member] | Loans Secured by Mortgage [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 12 | |
Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 15 | 4 | |
Fair Value, Inputs, Level 2 [Member] | Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 32 | 34 | |
Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 81 | 76 | 70 |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unobservable Input, Unrealized Gains (Losses), Changes in Assets and Liabilities, Net | 5 | 6 | |
Defined Benefit Plan, Purchases, Sales, and Settlements | 0 | 0 | |
Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 81 | 76 | |
SCE&G | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 784 | 792 | |
Transfers of fair value amounts into or out of Levels 1, 2 or 3 | no | no | |
SCE&G | Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 302 | |
SCE&G | Preferred Stock [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 1 | |
SCE&G | Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 566 | 278 | |
SCE&G | Short-term Investments [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 18 | 18 | |
SCE&G | Agency Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 6 | 30 | |
SCE&G | Corporate Debt Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 78 | 48 | |
SCE&G | Loans Secured by Mortgage [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 11 | |
SCE&G | Municipal Bonds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 14 | 3 | |
SCE&G | Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 29 | 32 | |
SCE&G | Hedge Funds, Multi-strategy [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 73 | 69 | |
SCE&G | Fair Value, Inputs, Level 1 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 322 | ||
SCE&G | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 302 | ||
SCE&G | Fair Value, Inputs, Level 1 [Member] | Preferred Stock [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | ||
SCE&G | Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 18 | ||
SCE&G | Fair Value, Inputs, Level 1 [Member] | Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | ||
SCE&G | Fair Value, Inputs, Level 2 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 711 | 401 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 566 | 260 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Short-term Investments [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 18 | 18 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Agency Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 6 | 30 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 78 | 48 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Loans Secured by Mortgage [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 11 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Municipal Bonds [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 14 | 3 | |
SCE&G | Fair Value, Inputs, Level 2 [Member] | Limited Partner [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 29 | 31 | |
SCE&G | Fair Value, Inputs, Level 3 [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 73 | 69 | 64 |
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unobservable Input, Unrealized Gains (Losses), Changes in Assets and Liabilities, Net | 4 | 5 | |
Defined Benefit Plan, Purchases, Sales, and Settlements | 0 | 0 | |
SCE&G | Fair Value, Inputs, Level 3 [Member] | Hedge Funds, Multi-strategy [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $73 | $69 |
EMPLOYEE_BENEFIT_PLANS_EMPLOYE2
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 4) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Pension Plan, Defined Benefit | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $63.40 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 64.5 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 65.6 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 66.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 65.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 338.4 |
Other Postretirement Benefit Plans, Defined Benefit [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 11.5 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 12.4 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 13.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 13.8 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 14.6 |
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 81.8 |
SCE&G | Pension Plan, Defined Benefit | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 63.4 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 64.5 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 65.6 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 66.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 65.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | 338.4 |
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 9.1 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Two | 9.8 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Three | 10.4 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Four | 10.9 |
Defined Benefit Plan, Expected Future Benefit Payments, Year Five | 11.5 |
Defined Benefit Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter | $64.60 |
EMPLOYEE_BENEFIT_PLANS_EMPLOYE3
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS (Details 5) (USD $) | 4 Months Ended | 8 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2013 | Aug. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | |||||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | $1 | $1 | $1 | |||
Defined Benefit Plan, Curtailments | 0 | -25.5 | ||||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 4 | -8 | 3 | |||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | |||||
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution | 100.00% | |||||
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match | 6.00% | |||||
Defined Contribution Plan, Cost Recognized | 25.8 | 23.4 | 22.3 | |||
Pension Plan, Defined Benefit | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Pension Plan, Liabilities, Noncurrent | 0 | -57.7 | 0 | |||
Defined Benefit Plan, Amortization of Net Gains (Losses) | 0.5 | |||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.07% | 4.10% | 5.03% | 5.25% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 8.00% | 8.00% | 8.25% | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 3.1 | -5 | 1.7 | |||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | -0.2 | -0.5 | -0.6 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | -0.2 | -0.2 | -0.2 | |||
Other Comprehensive Income, Other Adjustments to Defined Benefit Plan, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | 0 | -0.3 | 0 | |||
Defined Benefit Plan, Amortization of Net Transition Asset (Obligation) | 0 | 0 | 0 | |||
Defined Benefit Plan, Service Cost | 20 | 21.8 | 19.6 | |||
Defined Benefit Plan, Interest Cost | 40.4 | 38.5 | 43 | |||
Defined Benefit Plan, Expected Return on Plan Assets | -66.7 | -61.4 | -59.5 | |||
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 4.1 | 6 | 7 | |||
Defined Benefit Plan, Amortization of Gains (Losses) | 4.8 | 16.9 | 18.4 | |||
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 0 | 0 | |||
Defined Benefit Plan, Curtailments | 0 | 9.9 | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | 2.6 | 31.7 | 28.5 | |||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 2.7 | -6 | 0.9 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.00% | 3.75% | 3.00% | 4.00% | ||
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit) | 0.1 | |||||
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | 0.6 | |||||
Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Amortization of Net Gains (Losses) | 0.1 | |||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.19% | 4.19% | 5.35% | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 1.3 | -1.8 | 2 | |||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | 0 | -0.2 | 0 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | 0 | 0 | 0 | |||
Other Comprehensive Income, Other Adjustments to Defined Benefit Plan, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | 0 | 0 | 0 | |||
Defined Benefit Plan, Amortization of Net Transition Asset (Obligation) | 0 | -0.1 | -0.1 | |||
Defined Benefit Plan, Service Cost | 4.6 | 5.9 | 4.8 | |||
Defined Benefit Plan, Interest Cost | 12 | 11.1 | 11.9 | |||
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0.3 | 0.7 | 0.9 | |||
Defined Benefit Plan, Amortization of Gains (Losses) | 0 | 3.3 | 1.4 | |||
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 0.3 | 0.7 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 16.9 | 21.3 | 19.7 | |||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 1.3 | -2.1 | 1.9 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 4.00% | |||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 7.40% | 7.80% | 8.20% | |||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | 5.00% | 5.00% | |||
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit) | 0 | |||||
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | 0.1 | |||||
SCE&G | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | |||||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 1 | -1 | |||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | 0 | 0 | 0 | |||
Defined Benefit Plan, Curtailments | 0 | -21.6 | ||||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | |||||
Defined Contribution Plan, Maximum Percentage of Employer Contribution for up to Six Percent of Participant Contribution | 100.00% | |||||
Defined Contribution Plan, Maximum Percentage of Participant Contribution Eligible for Employer Contribution Match | 6.00% | |||||
Defined Contribution Plan, Cost Recognized | 20.7 | 18.7 | 17.7 | |||
SCE&G | Pension Plan, Defined Benefit | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Pension Plan, Liabilities, Noncurrent | 0 | 0 | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.07% | 4.10% | 5.03% | 5.25% | ||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 8.00% | 8.00% | 8.25% | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0.2 | -0.8 | 0.4 | |||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | -0.1 | -0.1 | -0.1 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | -0.1 | 0 | -0.1 | |||
Defined Benefit Plan, Service Cost | 16 | 17.6 | 15.7 | |||
Defined Benefit Plan, Interest Cost | 34.1 | 32.6 | 36.4 | |||
Defined Benefit Plan, Expected Return on Plan Assets | -56.3 | -51.9 | -50.4 | |||
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 3.5 | 5 | 6 | |||
Defined Benefit Plan, Amortization of Gains (Losses) | 4 | 14.3 | 15.6 | |||
Defined Benefit Plan, Curtailments | 0 | 8.4 | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | 1.3 | 26 | 23.3 | |||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 0 | -0.9 | 0.2 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.00% | 3.75% | 3.00% | 4.00% | ||
SCE&G | Other Postretirement Benefit Plans, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.19% | 4.19% | 5.35% | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0.4 | -0.4 | 0.7 | |||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax | 0 | -0.1 | 0 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Pension Cost, Net of Tax | 0 | 0 | -0.1 | |||
Defined Benefit Plan, Service Cost | 3.6 | 4.6 | 3.7 | |||
Defined Benefit Plan, Interest Cost | 9.4 | 8.7 | 9.4 | |||
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 0.3 | 0.6 | 0.7 | |||
Defined Benefit Plan, Amortization of Gains (Losses) | 0 | 2.6 | 1.1 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 13.3 | 16.5 | 14.9 | |||
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | $0.40 | ($0.50) | $0.60 | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.75% | 3.75% | 4.00% | |||
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year | 7.40% | 7.80% | 8.20% | |||
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate | 5.00% | 5.00% | 5.00% |
SHAREBASED_COMPENSATION_Detail
SHARE-BASED COMPENSATION (Details) | Dec. 31, 2014 |
Share-Based Compensation | |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 5,000,000 |
Restricted Stock Units | |
Share-Based Compensation | |
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 1,000,000 |
SHAREBASED_COMPENSATION_Liabil
SHARE-BASED COMPENSATION Liability Awards (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Liability Awards | |||
Cash-Settled Liabilities | $11.80 | $12.20 | $11.80 |
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards | 20.3 | 8.7 | 15 |
Capitalized Compensation Expense | 3.1 | 1.4 | 2.7 |
Restricted Stock Units | |||
Liability Awards | |||
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent) | 20.00% | ||
Performance Shares [Member] | |||
Liability Awards | |||
Percentage of Performance Award Granted in Form of Performance Shares (as a percent) | 80.00% | ||
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage | 50.00% | ||
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent | 50.00% | ||
SCE&G | |||
Liability Awards | |||
Cash-Settled Liabilities | 1.9 | 3.2 | 8.7 |
Compensation Expenses Recognized Resulting From Fair Value Adjustments of Performance Awards | 12.6 | 5.5 | 9.5 |
Capitalized Compensation Expense | $0.60 | $0.50 | $2.10 |
SCE&G | Restricted Stock Units | |||
Liability Awards | |||
Performance cycle (in years) | 3 years | ||
Percentage of Performance Award Granted in Form of Restricted Stock Units (as a percent) | 20.00% | ||
SCE&G | Performance Shares [Member] | |||
Liability Awards | |||
Percentage of Performance Award Granted in Form of Performance Shares (as a percent) | 80.00% | ||
Weight of Entity's Performance Against Pre-Determined Measures of Total Stockholder Return As Compared to Peer Groups of Utilities to Determine Payout of Performance Shares as a Percentage | 50.00% | ||
Weight of Growth in GAAP-adjusted net earnings per share from operations to determine payout of performance shares as a percent | 50.00% |
COMMITMENTS_AND_CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Commitments and contingencies | |||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $8 | ||
Asset Retirement Obligation, Liabilities Incurred | 3,000,000 | 6,000,000 | |
Asset Retirement Obligation, Liabilities Settled | -6,000,000 | -4,000,000 | |
Environmental | |||
Regulatory assets | 1,823,000,000 | 1,360,000,000 | |
Operating Leases, Rent Expense | 12.3 | 14.8 | 14.8 |
Guarantor Obligations, Maximum Exposure, Undiscounted | 1,700,000,000 | ||
Asset Retirement Obligation, Accretion Expense | 26,000,000 | 25,000,000 | |
Asset Retirement Obligation, Revision of Estimate | -36,000,000 | -12,000,000 | |
Asset Retirement Obligation | 563,000,000 | 576,000,000 | 561,000,000 |
Operating Leases, Future Minimum Payments, Due in Two Years | 5 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 2 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | 1 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | 2 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | 20 | ||
Operating Leases, Future Minimum Payments Due | 38 | ||
Asset Retirement Obligation Other Conditional Obligations | 362,000,000 | ||
Jointly Owned Nuclear Power Plant [Member] | |||
Nuclear Insurance | |||
Maximum liability assessment per reactor for each nuclear incident | 127,300,000 | ||
SCE&G | |||
Commitments and contingencies | |||
Federal Limit on Public Liability Claims from Nuclear Incident Approximate | 13,600,000,000 | ||
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 6 | ||
Asset Retirement Obligation, Liabilities Incurred | 3,000,000 | 5,000,000 | |
Asset Retirement Obligation, Liabilities Settled | -6,000,000 | -4,000,000 | |
Nuclear Insurance | |||
scg_Maximum Insurance Coverage for each Nuclear Plant by ANI | 375,000,000 | ||
Maximum liability assessment per reactor for each nuclear incident | 84,800,000 | ||
Maximum yearly assessment per reactor | 18,900,000 | ||
Maximum prosepective insurance premium per nuclear incident | 43,500,000 | ||
Maximum amount of coverage to nuclear facility for property damage and outage costs | 2,750,000,000 | ||
Maximum amount of coverage for accidental property damage | 500,000,000 | ||
Environmental | |||
Environmental Remediation Expense | 19,300,000 | ||
Deferred costs, net of costs previously recovered through rates and insurance settlements included in regulatory assets | 35,500,000 | ||
Number of MGP Sites Requiring Clean Up [Member] | 4 | ||
Regulatory assets | 1,745,000,000 | 1,303,000,000 | |
Operating Leases, Rent Expense | 12.1 | 13.6 | 9.6 |
NPDES permit number of years | 5 | ||
Asset Retirement Obligation Nuclear Decommissioning | 201,000,000 | ||
Asset Retirement Obligation, Accretion Expense | 25,000,000 | 24,000,000 | |
Asset Retirement Obligation, Revision of Estimate | -33,000,000 | -13,000,000 | |
Asset Retirement Obligation | 536,000,000 | 547,000,000 | 535,000,000 |
Operating Leases, Future Minimum Payments, Due in Two Years | 3 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 1 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | 0 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | 1 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | 18 | ||
Operating Leases, Future Minimum Payments Due | 29 | ||
Asset Retirement Obligation Other Conditional Obligations | 335,000,000 | ||
PSNC Energy | |||
Environmental | |||
Number of MGP Sites Requiring Clean Up [Member] | 5 | ||
Regulatory assets | 1,000,000 | ||
SCE&G | SCE&G | |||
Nuclear Insurance | |||
Maximum yearly assessment per reactor | $12,600,000 |
COMMITMENTS_AND_CONTINGENCIES_4
COMMITMENTS AND CONTINGENCIES Nuclear (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
CapitalCosts [Member] | ||||
ForecastedCapitalCostsApproved2012Order | $4,548 | |||
Grossconstructioncosts [Member] | ||||
ForecastedCapitalCostsApproved2012Order | 5,755 | |||
SCE&G | ||||
Additional ownership in new units | 0.00% | 0.00% | 0.00% | |
Total Construction Milestones | 146 | |||
Milestone Schedule Contingency Period | 18 | |||
Completed Construction Milestones | 101 | |||
MIlestones Extended | Three | |||
Additional ownership in new units, dollars | 500 | |||
Summer Station New Units [Domain] | ||||
jointly owned utility plant ownership, construction financing cost | 2,425 | |||
Jointly Owned Utility Plant, Construction Delay, Preliminary Cost Estimate | 660 | |||
Jointly Owned Utility Plant, Owner's Cost Per Month Caused by Delays, Estimated | $10 |
AFFILIATED_TRANSACTIONS_SCEG_A
AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Affiliated Transaction [Line Items] | |||
Proceeds from Equity Method Investment, Dividends or Distributions | $7.80 | $10.40 | $12.50 |
Equity Method Investments | 5.7 | 5.2 | 10.6 |
Related Party Transaction, Expenses from Transactions with Related Party | 292.2 | 285.6 | 305.6 |
Canadys Refined Coal LLC [Member] | |||
Affiliated Transaction [Line Items] | |||
Related Party Transaction Purchases from Related Party | 260.3 | 134.2 | |
Sales to Affiliate | 259 | 133.6 | |
Equity Method Investment, Ownership Percentage | 40.00% | ||
Related Party Tax Expense, Due from Affiliates, Current | 27.8 | 18 | |
Related Party Tax Expense, Due to Affiliates, Current | 27.9 | 18 | |
SCE&G | |||
Affiliated Transaction [Line Items] | |||
Due to Affiliate, Current | 180 | 117 | |
Due from Affiliate, Current | 109 | 19 | |
Related Party Transaction, Due from (to) Related Party, Current | 80 | ||
Accounts Payable, Related Parties, Current | 47.3 | 49.1 | |
CGT [Member] | |||
Affiliated Transaction [Line Items] | |||
due from affiliate | insignificant | ||
Related Party Transaction Purchases from Related Party | 30 | 33.3 | 35.9 |
Due to Affiliate, Current | 3.3 | 3.3 | |
Due from Affiliate, Current | 1.2 | 1.3 | |
Retail Gas and Energy Marketing Segment [Member] | |||
Affiliated Transaction [Line Items] | |||
Due to Affiliate, Current | 12.6 | 12.5 | |
Cost of Natural Gas Purchases | $195.70 | $166.90 | $125.50 |
SEGMENT_OF_BUSINESS_INFORMATIO2
SEGMENT OF BUSINESS INFORMATION (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||||||||||
Total | $16,852 | $15,164 | $16,852 | $15,164 | $14,616 | ||||||
Additions to Other Assets, Amount | 1,092 | 1,106 | 1,077 | ||||||||
Deferred Tax Assets, Gross | 0 | 0 | 0 | 0 | -11 | ||||||
Electric Domestic Regulated Revenue | 2,622 | 2,423 | 2,446 | ||||||||
Regulated and Unregulated Operating Revenue | 1,214 | 1,121 | 1,026 | 1,590 | 1,117 | 1,051 | 1,016 | 1,311 | 4,951 | 4,495 | 4,176 |
Intersegment Revenue | 0 | 0 | 0 | ||||||||
Operating Income | 234 | 269 | 154 | 350 | 173 | 255 | 189 | 293 | 1,007 | 910 | 859 |
Interest Expense | 312 | 297 | 295 | ||||||||
Depreciation, Depletion and Amortization | 384 | 378 | 356 | ||||||||
Income Tax Expense (Benefit) | 248 | 223 | 182 | ||||||||
Income Available to Common Shareholders | 105 | 144 | 96 | 193 | 104 | 131 | 85 | 151 | 538 | 471 | 420 |
Regulated Operating Revenue, Gas | 1,028 | 955 | 774 | ||||||||
Electric Operations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 10,182 | 9,488 | 10,182 | 9,488 | 8,989 | ||||||
Additions to Other Assets, Amount | 936 | 907 | 999 | ||||||||
Deferred Tax Assets, Gross | -11 | -10 | -11 | -10 | -9 | ||||||
Intersegment Revenue | 7 | 6 | 7 | ||||||||
Operating Income | 768 | 679 | 668 | ||||||||
Interest Expense | 19 | 19 | 21 | ||||||||
Depreciation, Depletion and Amortization | 300 | 297 | 278 | ||||||||
Income Tax Expense (Benefit) | 7 | 6 | 7 | ||||||||
Gas Distribution | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 2,487 | 2,340 | 2,487 | 2,340 | 2,292 | ||||||
Additions to Other Assets, Amount | 200 | 140 | 123 | ||||||||
Deferred Tax Assets, Gross | -29 | -27 | -29 | -27 | -26 | ||||||
Regulated and Unregulated Operating Revenue | 1,012 | 942 | 764 | ||||||||
Intersegment Revenue | 2 | 1 | 1 | ||||||||
Operating Income | 159 | 153 | 141 | ||||||||
Interest Expense | 22 | 22 | 23 | ||||||||
Depreciation, Depletion and Amortization | 72 | 70 | 67 | ||||||||
Income Tax Expense (Benefit) | 33 | 33 | 32 | ||||||||
Retail Gas and Energy Marketing Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 150 | 133 | 150 | 133 | 122 | ||||||
Additions to Other Assets, Amount | 2 | 1 | 1 | ||||||||
Deferred Tax Assets, Gross | -9 | -2 | -9 | -2 | -4 | ||||||
Regulated and Unregulated Operating Revenue | 786 | 652 | 543 | ||||||||
Intersegment Revenue | 196 | 167 | 125 | ||||||||
Income Tax Expense (Benefit) | 3 | 4 | 3 | ||||||||
Income Available to Common Shareholders | 5 | 6 | 5 | ||||||||
All Other [member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 1,474 | 1,378 | 1,474 | 1,378 | 1,415 | ||||||
Additions to Other Assets, Amount | 52 | 31 | 14 | ||||||||
Deferred Tax Assets, Gross | -15 | -14 | -15 | -14 | -17 | ||||||
Regulated and Unregulated Operating Revenue | 37 | 40 | 45 | ||||||||
Intersegment Revenue | 437 | 416 | 416 | ||||||||
Operating Income | 27 | 27 | 22 | ||||||||
Interest Expense | 5 | 4 | 3 | ||||||||
Depreciation, Depletion and Amortization | 24 | 26 | 25 | ||||||||
Income Tax Expense (Benefit) | 12 | 14 | 15 | ||||||||
Income Available to Common Shareholders | -6 | -2 | 1 | ||||||||
Retail Gas Marketing | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 140 | 172 | 140 | 172 | 153 | ||||||
Additions to Other Assets, Amount | 0 | 0 | 0 | ||||||||
Deferred Tax Assets, Gross | -11 | -8 | -11 | -8 | -10 | ||||||
Regulated and Unregulated Operating Revenue | 515 | 465 | 413 | ||||||||
Intersegment Revenue | 0 | 0 | 0 | ||||||||
Interest Expense | 1 | 1 | 1 | ||||||||
Depreciation, Depletion and Amortization | 2 | 3 | 3 | ||||||||
Income Tax Expense (Benefit) | 16 | 15 | 7 | ||||||||
Income Available to Common Shareholders | 26 | 24 | 11 | ||||||||
Adjustments/Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 2,419 | 1,653 | 2,419 | 1,653 | 1,645 | ||||||
Additions to Other Assets, Amount | -98 | 27 | -60 | ||||||||
Deferred Tax Assets, Gross | 75 | 61 | 75 | 61 | 55 | ||||||
Regulated and Unregulated Operating Revenue | -21 | -27 | -35 | ||||||||
Intersegment Revenue | -642 | -590 | -549 | ||||||||
Operating Income | 53 | 51 | 28 | ||||||||
Interest Expense | 265 | 251 | 247 | ||||||||
Depreciation, Depletion and Amortization | -14 | -18 | -17 | ||||||||
Income Tax Expense (Benefit) | 177 | 151 | 118 | ||||||||
Income Available to Common Shareholders | 513 | 443 | 403 | ||||||||
SCE&G | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 14,107 | 12,700 | 14,107 | 12,700 | 12,104 | ||||||
Additions to Other Assets, Amount | 934 | 1,003 | 978 | ||||||||
Deferred Tax Assets, Gross | 0 | 0 | 0 | 0 | 0 | ||||||
Electric Domestic Regulated Revenue | 2,629 | 2,431 | 2,453 | ||||||||
Regulated Operating Revenue | 722 | 812 | 698 | 859 | 645 | 776 | 696 | 728 | 3,091 | 2,845 | 2,809 |
Operating Income | 174 | 272 | 145 | 239 | 111 | 255 | 180 | 191 | 830 | 737 | 717 |
Interest Expense | 228 | 217 | 211 | ||||||||
Depreciation, Depletion and Amortization | 315 | 313 | 293 | ||||||||
Income Tax Expense (Benefit) | 218 | 189 | 157 | ||||||||
Regulated Operating Revenue, Gas | 462 | 414 | 356 | ||||||||
SCE&G | Electric Operations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 10,182 | 10,182 | 8,989 | ||||||||
Additions to Other Assets, Amount | 936 | 999 | |||||||||
Deferred Tax Assets, Gross | -11 | -11 | -9 | ||||||||
Operating Income | 768 | 668 | |||||||||
Interest Expense | 19 | 19 | 21 | ||||||||
Depreciation, Depletion and Amortization | 300 | 294 | 278 | ||||||||
SCE&G | Gas Distribution | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 721 | 686 | 721 | 686 | 659 | ||||||
Additions to Other Assets, Amount | 55 | 45 | 56 | ||||||||
Regulated and Unregulated Operating Revenue | 462 | 414 | 356 | ||||||||
Operating Income | 62 | 58 | 49 | ||||||||
Interest Expense | 0 | 0 | 0 | ||||||||
Depreciation, Depletion and Amortization | 27 | 26 | 25 | ||||||||
SCE&G | Adjustments/Eliminations | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total | 3,204 | 2,526 | 3,204 | 2,526 | 2,456 | ||||||
Additions to Other Assets, Amount | -57 | 51 | -77 | ||||||||
Deferred Tax Assets, Gross | -11 | -10 | -11 | -10 | -9 | ||||||
Operating Income | 0 | ||||||||||
Interest Expense | 209 | 198 | 190 | ||||||||
Depreciation, Depletion and Amortization | ($12) | ($7) | ($10) |
DISPOSITIONS_Details
DISPOSITIONS (Details) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Proceeds from sale of CGT and SCI net of transaction costs | $625 | ||
Public Utilities, Property, Plant and Equipment, Net | 12,232 | 11,643 | |
Nonutility Property and Investments, Net | 472 | 504 | |
Assets, Current | 2,145 | 1,421 | |
Regulated Entity, Other Assets, Noncurrent | 2,003 | 1,596 | |
Disposal group current assets held for sale | 341 | 0 | |
Liabilities, Current | 2,533 | 1,442 | |
Liabilities, Noncurrent | 3,801 | 3,663 | |
Liabilities held for sale | 52 | 0 | |
Estimated pre-tax gain on sale of CGT and SCI | 350 | ||
Liabilities, Held for Sale [Member] | CGT [Member] | |||
Liabilities, Current | 3.5 | ||
Liabilities, Noncurrent | 42.9 | ||
Liabilities held for sale | 46.4 | ||
Liabilities, Held for Sale [Member] | SCANA Communications [Member] | |||
Liabilities, Current | 2.2 | ||
Liabilities, Noncurrent | 3.1 | ||
Liabilities held for sale | 5.3 | ||
Liabilities, Held for Sale [Member] | Held for Sale, CGT and SCI [Member] | |||
Liabilities, Current | 5.7 | ||
Liabilities, Noncurrent | 46 | ||
Liabilities held for sale | 51.7 | ||
Assets Held-for-sale [Member] | CGT [Member] | |||
Public Utilities, Property, Plant and Equipment, Net | 288.4 | ||
Nonutility Property and Investments, Net | 0.6 | ||
Assets, Current | 6.5 | ||
Regulated Entity, Other Assets, Noncurrent | 0.9 | ||
Disposal group current assets held for sale | 296.4 | ||
Assets Held-for-sale [Member] | SCANA Communications [Member] | |||
Public Utilities, Property, Plant and Equipment, Net | 0 | ||
Nonutility Property and Investments, Net | 40.1 | ||
Assets, Current | 3.9 | ||
Regulated Entity, Other Assets, Noncurrent | 0.2 | ||
Disposal group current assets held for sale | 44.2 | ||
Assets Held-for-sale [Member] | Held for Sale, CGT and SCI [Member] | |||
Public Utilities, Property, Plant and Equipment, Net | 288.4 | ||
Nonutility Property and Investments, Net | 40.7 | ||
Assets, Current | 10.4 | ||
Regulated Entity, Other Assets, Noncurrent | 1.1 | ||
Disposal group current assets held for sale | $340.60 |
QUARTERLY_FINANCIAL_INFORMATIO2
QUARTERLY FINANCIAL INFORMATION (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Regulated and Unregulated Operating Revenue | $1,214 | $1,121 | $1,026 | $1,590 | $1,117 | $1,051 | $1,016 | $1,311 | $4,951 | $4,495 | $4,176 |
Operating Income (Loss) | 234 | 269 | 154 | 350 | 173 | 255 | 189 | 293 | 1,007 | 910 | 859 |
Income (Loss) Available to Common Shareholders, Basic | 105 | 144 | 96 | 193 | 104 | 131 | 85 | 151 | 538 | 471 | 420 |
Earnings Per Share, Basic | $0.73 | $1.01 | $0.68 | $1.37 | $0.73 | $0.94 | $0.60 | $1.13 | $3.79 | $3.40 | $3.20 |
Earnings Per Share, Diluted | $0.73 | $1.01 | $0.68 | $1.37 | $0.73 | $0.94 | $0.60 | $1.11 | $3.79 | $3.39 | $3.15 |
SCE&G | |||||||||||
Regulated Operating Revenue | 722 | 812 | 698 | 859 | 645 | 776 | 696 | 728 | 3,091 | 2,845 | 2,809 |
Operating Income (Loss) | 174 | 272 | 145 | 239 | 111 | 255 | 180 | 191 | 830 | 737 | 717 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 76 | 157 | 99 | 126 | 72 | 139 | 88 | 92 | 458 | 391 | 352 |
Net Income (Loss) Attributable to Parent | $73 | $154 | $96 | $123 | $70 | $136 | $85 | $89 | $446 | $380 | $341 |
Schedule_II_Details
Schedule II (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Valuation Allowances and Reserves, Balance | $7 | $6 | $7 | $6 |
Valuation Allowances and Reserves, Charged to Cost and Expense | 16 | 13 | 14 | |
Valuation Allowances and Reserves, Charged to Other Accounts | 0 | 0 | 0 | |
Valuation Allowances and Reserves, Deductions | 15 | 14 | 13 | |
General Liability [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Valuation Allowances and Reserves, Balance | 5 | 6 | 6 | 6 |
Valuation Allowances and Reserves, Charged to Cost and Expense | 7 | 4 | 4 | |
Valuation Allowances and Reserves, Charged to Other Accounts | 0 | 0 | 0 | |
Valuation Allowances and Reserves, Deductions | 8 | 4 | 4 | |
SCE&G | Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Valuation Allowances and Reserves, Balance | 4 | 3 | 3 | 3 |
Valuation Allowances and Reserves, Charged to Cost and Expense | 8 | 7 | 6 | |
Valuation Allowances and Reserves, Charged to Other Accounts | 0 | 0 | 0 | |
Valuation Allowances and Reserves, Deductions | 7 | 7 | 6 | |
SCE&G | General Liability [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Valuation Allowances and Reserves, Balance | 3 | 5 | 5 | 4 |
Valuation Allowances and Reserves, Charged to Cost and Expense | 1 | 3 | 3 | |
Valuation Allowances and Reserves, Charged to Other Accounts | 0 | 0 | 0 | |
Valuation Allowances and Reserves, Deductions | $3 | $3 | $2 |