Document_and_Entity_Informatio
Document and Entity Information Document | 9 Months Ended | |
Sep. 30, 2013 | Oct. 31, 2013 | |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'SCANA Corporation | ' |
Entity Central Index Key | '0000754737 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 140,548,894 |
SCEG | ' | ' |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'SOUTH CAROLINA ELECTRIC & GAS CO | ' |
Entity Central Index Key | '0000091882 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 40,296,147 |
CONDENSED_CONSOLIDATED_BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Assets | ' | ' |
Utility Plant In Service | $12,119 | $11,865 |
Accumulated Depreciation and Amortization | -3,965 | -3,811 |
Construction Work in Progress | 2,558 | 2,084 |
Plant to be Retired, Net | 344 | 362 |
Nuclear Fuel, Net of Accumulated Amortization | 296 | 166 |
Goodwill, Net of Writedown of $230 | 230 | 230 |
Utility Plant, Net | 11,582 | 10,896 |
Nonutility Property and Investments: | ' | ' |
Nonutility property, net of accumulated depreciation | 315 | 306 |
Assets held in trust, net-nuclear decommissioning | 98 | 94 |
Other investments | 91 | 87 |
Nonutility Property and Investments, Net | 504 | 487 |
Current Assets: | ' | ' |
Cash and cash equivalents | 30 | 72 |
Receivables, net of allowance for uncollectible accounts | 710 | 780 |
Inventories (at average cost): | ' | ' |
Fuel | 263 | 305 |
Materials and supplies | 145 | 136 |
Prepayments and other | 194 | 223 |
Deferred income taxes | 9 | 11 |
Total Current Assets | 1,351 | 1,527 |
Deferred Debits and Other Assets: | ' | ' |
Regulatory Assets, Noncurrent | 1,333 | 1,464 |
Other | 227 | 242 |
Total Deferred Debits and Other Assets | 1,560 | 1,706 |
Total | 14,997 | 14,616 |
Capitalization and Liabilities | ' | ' |
Common equity | 4,598 | 4,154 |
Long-Term Debt, Net | 5,431 | 4,949 |
Total Capitalization | 10,029 | 9,103 |
Current Liabilities: | ' | ' |
Short-term borrowings | 378 | 623 |
Current portion of long-term debt | 19 | 172 |
Accounts payable | 340 | 428 |
Customer deposits and customer prepayments | 83 | 86 |
Taxes accrued | 137 | 164 |
Interest accrued | 75 | 82 |
Dividends declared | 71 | 66 |
Derivative financial instruments | 12 | 80 |
Other | 88 | 110 |
Total Current Liabilities | 1,203 | 1,811 |
Deferred Credits and Other Liabilities: | ' | ' |
Deferred income taxes, net | 1,723 | 1,653 |
Deferred investment tax credits | 33 | 36 |
Asset retirement obligations | 576 | 561 |
Pension and other postretirement benefits | 263 | 387 |
Regulatory liabilities | 1,007 | 882 |
Other | 163 | 183 |
Total Deferred Credits and Other Liabilities | 3,765 | 3,702 |
Commitments and Contingencies (Note 9) | ' | ' |
Total | 14,997 | 14,616 |
SCEG | ' | ' |
Assets | ' | ' |
Utility Plant In Service | 10,310 | 10,096 |
Accumulated Depreciation and Amortization | -3,456 | -3,322 |
Construction Work in Progress | 2,521 | 2,073 |
Plant to be Retired, Net | 344 | 362 |
Nuclear Fuel, Net of Accumulated Amortization | 296 | 166 |
Utility Plant, Net | 10,015 | 9,375 |
Nonutility Property and Investments: | ' | ' |
Nonutility property, net of accumulated depreciation | 68 | 57 |
Assets held in trust, net-nuclear decommissioning | 98 | 94 |
Other investments | 2 | 3 |
Nonutility Property and Investments, Net | 168 | 154 |
Current Assets: | ' | ' |
Cash and cash equivalents | 17 | 51 |
Receivables, net of allowance for uncollectible accounts | 523 | 483 |
Due from Affiliate, Current | 20 | 2 |
Inventories (at average cost): | ' | ' |
Fuel | 161 | 204 |
Materials and supplies | 130 | 126 |
Prepayments and other | 164 | 143 |
Total Current Assets | 1,015 | 1,009 |
Deferred Debits and Other Assets: | ' | ' |
Regulatory Assets, Noncurrent | 1,259 | 1,377 |
Other | 237 | 189 |
Total Deferred Debits and Other Assets | 1,496 | 1,566 |
Total | 12,694 | 12,104 |
Capitalization and Liabilities | ' | ' |
Common equity | 4,336 | 3,929 |
Stockholders' Equity Attributable to Noncontrolling Interest | 117 | 114 |
Long-Term Debt, Net | 4,043 | 3,557 |
Total Capitalization | 8,496 | 7,600 |
Current Liabilities: | ' | ' |
Short-term borrowings | 310 | 449 |
Current portion of long-term debt | 14 | 165 |
Accounts payable | 210 | 281 |
Due to Affiliate, Current | 122 | 124 |
Customer deposits and customer prepayments | 53 | 51 |
Taxes accrued | 158 | 151 |
Interest accrued | 53 | 63 |
Dividends declared | 67 | 46 |
Derivative financial instruments | 2 | 66 |
Other | 41 | 50 |
Total Current Liabilities | 1,030 | 1,446 |
Deferred Credits and Other Liabilities: | ' | ' |
Deferred income taxes, net | 1,529 | 1,479 |
Deferred investment tax credits | 33 | 36 |
Asset retirement obligations | 549 | 535 |
Pension and other postretirement benefits | 198 | 254 |
Regulatory liabilities | 781 | 665 |
Other | 78 | 89 |
Total Deferred Credits and Other Liabilities | 3,168 | 3,058 |
Commitments and Contingencies (Note 9) | ' | ' |
Total | $12,694 | $12,104 |
CONDENSED_CONSOLIDATED_BALANCE1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Public Utilities, Property, Plant and Equipment, Net | $11,582 | $10,896 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 148 | 139 |
Allowance for Doubtful Accounts Receivable, Current | 5 | 7 |
Assets, Current | 1,351 | 1,527 |
Regulated Entity, Other Assets, Noncurrent | 1,560 | 1,706 |
SCEG | ' | ' |
Public Utilities, Property, Plant and Equipment, Net | 10,015 | 9,375 |
Allowance for Doubtful Accounts Receivable, Current | 3 | 3 |
Assets, Current | 1,015 | 1,009 |
Regulated Entity, Other Assets, Noncurrent | 1,496 | 1,566 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ' | ' |
Public Utilities, Property, Plant and Equipment, Net | 708 | 640 |
Assets, Current | 162 | 206 |
Regulated Entity, Other Assets, Noncurrent | $43 | $54 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Operating Revenues: | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | $704 | $714 | $1,898 | $1,851 |
Regulated Operating Revenue, Gas | 128 | 109 | 667 | 513 |
Gas-nonregulated | 219 | 215 | 813 | 690 |
Regulated and Unregulated Operating Revenue | 1,051 | 1,038 | 3,378 | 3,054 |
Operating Expenses [Abstract] | ' | ' | ' | ' |
Fuel used in electric generation | 196 | 239 | 570 | 617 |
Purchased power | 19 | 9 | 35 | 20 |
Gas purchased for resale | 265 | 248 | 1,076 | 837 |
Other operation and maintenance | 167 | 165 | 513 | 510 |
Depreciation and amortization | 95 | 89 | 282 | 267 |
Other taxes | 54 | 50 | 164 | 156 |
Total Operating Expenses | 796 | 800 | 2,640 | 2,407 |
Operating Income | 255 | 238 | 738 | 647 |
Other Income (Expense): | ' | ' | ' | ' |
Interest Expense | -74 | -75 | -223 | -219 |
Other income | 10 | 13 | 36 | 39 |
Other expenses | -10 | -9 | -32 | -29 |
Allowance for equity funds used during construction | 9 | 6 | 19 | 13 |
Total Other Expense | -65 | -65 | -200 | -196 |
Income Before Income Tax Expense | 190 | 173 | 538 | 451 |
Income Tax Expense | 59 | 51 | 170 | 136 |
Income Available to Common Shareholders | 131 | 122 | 368 | 315 |
Per Common Share Data | ' | ' | ' | ' |
Basic Earnings Per Share of Common Stock (in dollars per share) | $0.94 | $0.93 | $2.67 | $2.41 |
Diluted Earnings Per Share of Common Stock (in dollars per share) | $0.94 | $0.91 | $2.66 | $2.37 |
Weighted Average Common Shares Outstanding (millions) | ' | ' | ' | ' |
Weighted Average Number of Shares Outstanding, Basic | 140.1 | 131.4 | 138 | 130.8 |
Weighted Average Number of Shares Outstanding, Diluted | 140.1 | 133.8 | 138.6 | 133.1 |
Dividends Declared Per Share of Common Stock (in dollars per share) | $0.51 | $0.50 | $1.52 | $1.49 |
SCEG | ' | ' | ' | ' |
Operating Revenues: | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | 706 | 716 | 1,903 | 1,857 |
Regulated Operating Revenue, Gas | 70 | 61 | 297 | 244 |
Regulated Operating Revenue | 776 | 777 | 2,200 | 2,101 |
Operating Expenses [Abstract] | ' | ' | ' | ' |
Fuel used in electric generation | 197 | 240 | 575 | 622 |
Purchased power | 19 | 9 | 34 | 20 |
Gas purchased for resale | 45 | 38 | 177 | 134 |
Other operation and maintenance | 132 | 130 | 406 | 402 |
Depreciation and amortization | 78 | 73 | 234 | 220 |
Other taxes | 50 | 46 | 149 | 142 |
Total Operating Expenses | 521 | 536 | 1,575 | 1,540 |
Operating Income | 255 | 241 | 625 | 561 |
Other Income (Expense): | ' | ' | ' | ' |
Interest Expense | -54 | -53 | -163 | -157 |
Other expenses | -4 | -3 | -11 | -9 |
Allowance for equity funds used during construction | 8 | 5 | 18 | 12 |
Total Other Expense | -50 | -51 | -156 | -154 |
Income Before Income Tax Expense | 205 | 190 | 469 | 407 |
Income Tax Expense | 66 | 58 | 150 | 126 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 139 | 132 | 319 | 281 |
Net Income (Loss) Attributable to Noncontrolling Interest | -3 | -3 | -8 | -9 |
Net Income (Loss) Attributable to Parent | 136 | 129 | 311 | 272 |
Weighted Average Common Shares Outstanding (millions) | ' | ' | ' | ' |
Dividends, Common Stock, Cash | $67 | $56 | $195 | $163 |
CONDENSED_CONSOLIDATED_STATEME1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Allowance for Funds Used During Construction, Capitalized Interest | $4 | $3 | $10 | $8 |
SCEG | ' | ' | ' | ' |
Allowance for Funds Used During Construction, Capitalized Interest | $4 | $3 | $9 | $7 |
CONDENSED_CONSOLIDATED_STATEME2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Net Income (Loss) Attributable to Parent [Abstract] | ' | ' | ' | ' |
Income Available to Common Shareholders | $131 | $122 | $368 | $315 |
Other Comprehensive Income (Loss) | ' | ' | ' | ' |
Unrealized gains (losses) on cash flow hedging activities arising during period | -1 | 1 | 3 | -6 |
Losses on cash flow hedging activities reclassified to net income | 2 | 3 | 7 | 17 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 4 | 0 | 4 | 0 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | 1 | 0 | 1 | 1 |
Other Comprehensive Income | -6 | -4 | -15 | -12 |
Total Comprehensive Income (Loss) | 137 | 126 | 383 | 327 |
SCEG | ' | ' | ' | ' |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 139 | 132 | 319 | 281 |
Other Comprehensive Income (Loss) | ' | ' | ' | ' |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Remeasurement and Curtailment Adjustement, Net of Tax | 1 | 0 | 1 | 0 |
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 140 | 132 | 320 | 281 |
Total Comprehensive Income (Loss) | ' | ' | 320 | 281 |
Genco | ' | ' | ' | ' |
Other Comprehensive Income (Loss) | ' | ' | ' | ' |
Less comprehensive income attributable to noncontrolling interest | -3 | -3 | -8 | -9 |
Total Comprehensive Income (Loss) | ' | ' | 8 | 9 |
SCE&G (including Fuel Company) | ' | ' | ' | ' |
Other Comprehensive Income (Loss) | ' | ' | ' | ' |
Total Comprehensive Income (Loss) | $137 | $129 | $312 | $272 |
CONDENSED_CONSOLIDATED_STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | $69.90 | ' | $69.90 | ' | $85.60 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | 0 | 0 | 2 | -4 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax | 1 | 2 | 4 | 11 | ' |
Other Comprehensive (Income) Loss, Pension and Other Postretirment Benefit Plans, Remeasurement and Curtailment Adjustment, Tax | 2 | 0 | 2 | 0 | ' |
SCEG | ' | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax | $2.70 | ' | $2.70 | ' | $4 |
CONDENSED_CONSOLIDATED_STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Cash Flows From Operating Activities: | ' | ' |
Income Available to Common Shareholders of SCANA | $368 | $315 |
Adjustments to reconcile net income to net cash provided from operating activities: | ' | ' |
Deferred income taxes, net | 62 | 74 |
Depreciation and amortization | 294 | 277 |
Amortization of nuclear fuel | 42 | 38 |
Allowance for equity funds used during construction | -19 | -13 |
Cash provided (used) by changes in certain assets and liabilities: | ' | ' |
Receivables | 70 | 46 |
Inventories | -8 | -34 |
Prepayments and other | 8 | 58 |
Regulatory liabilities | 78 | 47 |
Accounts payable | -32 | -7 |
Taxes accrued | -27 | -21 |
Interest accrued | -7 | 4 |
Regulatory assets | 142 | -2 |
Pension and Postretirement Obligations | -133 | 3 |
Changes in other assets | -46 | 4 |
Changes in other liabilities | -13 | -21 |
Net Cash Provided From Operating Activities | 779 | 768 |
Cash Flows From Investing Activities: | ' | ' |
Property additions and construction expenditures | -868 | -868 |
Proceeds from investments (including derivative collateral posted) | 199 | 364 |
Purchase of investments (including derivative collateral posted) | -161 | -326 |
Proceeds from Hedge, Investing Activities | 43 | 14 |
Payments for interest rate contract settlements | -49 | -51 |
Net Cash Used in Investing Activities | -836 | -867 |
Cash Flows From Financing Activities: | ' | ' |
Proceeds from Issuance of Common Stock | 272 | 73 |
Proceeds from issuance of long-term debt | 451 | 763 |
Repayments of Long-term Debt | -256 | -274 |
Dividends | -207 | -192 |
Short-term borrowings, net | -245 | -259 |
Net Cash Provided From Financing Activities | 15 | 111 |
Net (Decrease) Increase in Cash and Cash Equivalents | -42 | 12 |
Cash and Cash Equivalents, January 1 | 72 | 29 |
Cash and Cash Equivalents, September 30 | 30 | 41 |
Supplemental Cash Flow Information: | ' | ' |
Cash paid for-Interest (net of capitalized interest ) | 222 | 212 |
Cash paid for-Income taxes | 70 | 67 |
Noncash Investing and Financing Activities: | ' | ' |
Accrued construction expenditures | 97 | 79 |
Capital Lease Obligations Incurred | 5 | 4 |
Noncash or Part Noncash Acquisition, Value of Assets Acquired | 98 | 0 |
SCEG | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 319 | 281 |
Adjustments to reconcile net income to net cash provided from operating activities: | ' | ' |
Deferred income taxes, net | 49 | 74 |
Depreciation and amortization | 237 | 221 |
Amortization of nuclear fuel | 42 | 38 |
Allowance for equity funds used during construction | -18 | -12 |
Cash provided (used) by changes in certain assets and liabilities: | ' | ' |
Receivables | -58 | -22 |
Inventories | 5 | -49 |
Prepayments and other | -51 | -57 |
Regulatory liabilities | 80 | 49 |
Accounts payable | -7 | 13 |
Taxes accrued | 7 | -8 |
Interest accrued | -10 | -1 |
Regulatory assets | 129 | -1 |
Pension and Postretirement Obligations | -117 | 0 |
Changes in other assets | -30 | 47 |
Changes in other liabilities | -3 | -20 |
Net Cash Provided From Operating Activities | 574 | 553 |
Cash Flows From Investing Activities: | ' | ' |
Property additions and construction expenditures | -794 | -793 |
Proceeds from investments (including derivative collateral posted) | 139 | 196 |
Purchase of investments (including derivative collateral posted) | -112 | -199 |
Proceeds from Hedge, Investing Activities | 43 | 14 |
Payments for interest rate contract settlements | -49 | 0 |
Net Cash Used in Investing Activities | -773 | -782 |
Cash Flows From Financing Activities: | ' | ' |
Proceeds from issuance of long-term debt | 451 | 517 |
Repayments of Long-term Debt | -248 | -13 |
Dividends | -174 | -146 |
Contributions from parent | 285 | 84 |
Short-term borrowings, net | -139 | -185 |
Short-term borrowings- affiliate,net | -10 | -9 |
Net Cash Provided From Financing Activities | 165 | 248 |
Net (Decrease) Increase in Cash and Cash Equivalents | -34 | 19 |
Cash and Cash Equivalents, January 1 | 51 | 16 |
Cash and Cash Equivalents, September 30 | 17 | 35 |
Supplemental Cash Flow Information: | ' | ' |
Cash paid for-Interest (net of capitalized interest ) | 160 | 147 |
Cash paid for-Income taxes | 67 | 81 |
Noncash Investing and Financing Activities: | ' | ' |
Accrued construction expenditures | 89 | 66 |
Capital Lease Obligations Incurred | 3 | 4 |
Noncash or Part Noncash Acquisition, Value of Assets Acquired | $98 | $0 |
CONDENSED_CONSOLIDATED_STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
Interest Paid, Capitalized | $10 | $8 |
SCEG | ' | ' |
Interest Paid, Capitalized | $9 | $7 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Significant Accounting Policies | ' | |||||||||||||
Significant Accounting Policies [Text Block] | ' | |||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||||
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. | ||||||||||||||
Plant to be Retired | ||||||||||||||
In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the 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. | ||||||||||||||
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. | ||||||||||||||
Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows: | ||||||||||||||
Third Quarter | Year to Date | |||||||||||||
Millions | 2013 | 2012 | 2013 | 2012 | ||||||||||
Weighted Average Shares Outstanding - Basic | 140.1 | 131.4 | 138 | 130.8 | ||||||||||
Effect of dilutive equity forward shares | — | 2.4 | 0.6 | 2.3 | ||||||||||
Weighted Average Shares - Diluted | 140.1 | 133.8 | 138.6 | 133.1 | ||||||||||
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 47% and 44% of PSNC Energy’s natural gas inventory at September 30, 2013 | ||||||||||||||
and December 31, 2012, respectively, with a carrying value of $23.2 million and $19.6 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015. | ||||||||||||||
SCEG | ' | |||||||||||||
Significant Accounting Policies | ' | |||||||||||||
Significant Accounting Policies [Text Block] | ' | |||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||||||
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. | ||||||||||||||
Variable Interest Entities | ||||||||||||||
SCE&G has determined that it is the primary beneficiary of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. | ||||||||||||||
GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $478 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4. | ||||||||||||||
Plant to be Retired | ||||||||||||||
In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013, and in the third quarter SCE&G received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired and to amortize such costs over the units' previously estimated remaining useful lives. The net carrying value of the remaining units to be retired (including these two units) is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of the 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. |
RATE_AND_OTHER_REGULATORY_MATT
RATE AND OTHER REGULATORY MATTERS | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Rate Matters [Line Items] | ' | ||||||||
Public Utilities Disclosure [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 by SCE&G. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012. | |||||||||
This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions. In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. Consistent with the December 2012 rate order, SCE&G did not request any adjustment to its base fuel cost component. On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. | |||||||||
Electric - Base Rates | |||||||||
On December 19, 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 (as discussed above), 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. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed. | |||||||||
The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any. | |||||||||
In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. 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. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired. | |||||||||
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 revenue 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 has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated: | |||||||||
Year | Effective | Amount | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | |||||||||
SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs. SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers. SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013. | |||||||||
On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC. Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G. As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things. The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement. A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending. | |||||||||
Electric – BLRA | |||||||||
In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order 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 claims 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. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9. | |||||||||
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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
2012 | 2.3 | % | Increase | $52.1 million | |||||
Gas | |||||||||
SCE&G | |||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | No change | - | |||||||
2012 | 2.1 | % | Increase | $7.5 million | |||||
On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates. | |||||||||
SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling is pending. | |||||||||
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 2013, in connection with PSNC Energy's 2013 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, 2013. | |||||||||
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. Substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. | |||||||||
Millions of dollars | September 30, | December 31, | |||||||
2013 | 2012 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 254 | $ | 254 | |||||
Under-collections - electric fuel adjustment clause | 52 | 66 | |||||||
Environmental remediation costs | 42 | 44 | |||||||
AROs and related funding | 359 | 319 | |||||||
Franchise agreements | 32 | 36 | |||||||
Deferred employee benefit plan costs | 319 | 460 | |||||||
Planned major maintenance | — | 6 | |||||||
Deferred losses on interest rate derivatives | 126 | 151 | |||||||
Deferred pollution control costs | 37 | 38 | |||||||
Unrecovered plant | 19 | 20 | |||||||
Other | 93 | 70 | |||||||
Total Regulatory Assets | $ | 1,333 | $ | 1,464 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 19 | $ | 21 | |||||
Asset removal costs | 718 | 692 | |||||||
Storm damage reserve | 27 | 27 | |||||||
Monetization of bankruptcy claim | 30 | 32 | |||||||
Deferred gains on interest rate derivatives | 203 | 110 | |||||||
Planned major maintenance | 10 | — | |||||||
Total Regulatory Liabilities | $ | 1,007 | $ | 882 | |||||
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 during annual hearings which are not expected to be recovered in retail electric rates within 12 months. | |||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 26 years. | |||||||||
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs. 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years. | |||||||||
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 amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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 $18.4 million annually for fossil fueled turbine/generation equipment maintenance. Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives generally represent the unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators. | |||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs are being recovered through utility rates over periods up to approximately 30 years. | |||||||||
Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base. | |||||||||
Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. | |||||||||
Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. | |||||||||
The 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. | |||||||||
The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are being amortized into operating revenue through February 2024. | |||||||||
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 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. | |||||||||
SCEG | ' | ||||||||
Rate Matters [Line Items] | ' | ||||||||
Public Utilities Disclosure [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 by SCE&G. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012. | |||||||||
This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions. In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. Consistent with the December 2012 rate order, SCE&G did not request any adjustment to its base fuel cost component. On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. | |||||||||
Electric - Base Rates | |||||||||
On December 19, 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 (as discussed above), 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. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order and the order was not appealed. | |||||||||
The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any. | |||||||||
In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. 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. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired. | |||||||||
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 revenue 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 has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated: | |||||||||
Year | Effective | Amount | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | |||||||||
SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs. SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers. SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013. | |||||||||
On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC. Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G. As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things. The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement. A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending. | |||||||||
Electric – BLRA | |||||||||
In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order 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 claims 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. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. For further discussion of new nuclear construction matters, see Note 9. | |||||||||
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 the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
2012 | 2.3 | % | Increase | $52.1 million | |||||
Gas | |||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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 years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | No change | - | |||||||
2012 | 2.1 | % | Increase | $7.5 million | |||||
On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates. | |||||||||
SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. 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. The 2012 annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling is pending. | |||||||||
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. Substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. | |||||||||
Millions of dollars | September 30, | December 31, | |||||||
2013 | 2012 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 248 | $ | 248 | |||||
Under collections – electric fuel adjustment clause | 52 | 66 | |||||||
Environmental remediation costs | 37 | 39 | |||||||
AROs and related funding | 342 | 304 | |||||||
Franchise agreements | 32 | 36 | |||||||
Deferred employee benefit plan costs | 284 | 405 | |||||||
Planned major maintenance | — | 6 | |||||||
Deferred losses on interest rate derivatives | 126 | 151 | |||||||
Deferred pollution control costs | 37 | 38 | |||||||
Unrecovered plant | 19 | 20 | |||||||
Other | 82 | 64 | |||||||
Total Regulatory Assets | $ | 1,259 | $ | 1,377 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 19 | $ | 21 | |||||
Asset removal costs | 522 | 507 | |||||||
Storm damage reserve | 27 | 27 | |||||||
Deferred gains on interest rate derivatives | 203 | 110 | |||||||
Planned major maintenance | 10 | — | |||||||
Total Regulatory Liabilities | $ | 781 | $ | 665 | |||||
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 during annual hearings which are not expected to be recovered in retail electric rates within 12 months. | |||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G. These regulatory assets are expected to be recovered over periods of up to approximately 26 years. | |||||||||
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs. 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 began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years. | |||||||||
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 amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates 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 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 $18.4 million annually for fossil fueled turbine/generation equipment maintenance. Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives generally represent unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators. | |||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs are being recovered through utility rates over periods up to approximately 30 years. | |||||||||
Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's previously estimated remaining useful life of approximately 14 years. Unamortized amounts are included in rate base. | |||||||||
Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. | |||||||||
Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. | |||||||||
The 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. | |||||||||
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 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 | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||
COMMON EQUITY | ' | ||||||||||||
COMMON EQUITY | |||||||||||||
Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows: | |||||||||||||
Millions of dollars | 2013 | 2012 | |||||||||||
Balance at January 1, | $ | 4,154 | $ | 3,889 | |||||||||
Common stock issued | 273 | 73 | |||||||||||
Dividends declared | (212 | ) | (194 | ) | |||||||||
Comprehensive income | 383 | 327 | |||||||||||
Balance as of September 30, | $ | 4,598 | $ | 4,095 | |||||||||
SCANA had 200 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 140.2 million and 132.0 million were issued and outstanding at September 30, 2013 and December 31, 2012, respectively. | |||||||||||||
On March 5, 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. | |||||||||||||
Reclassifications of gains (losses) from AOCI into earnings, net of taxes, were as follows: | |||||||||||||
Millions of dollars | 2013 | 2012 | Income Statement Line Item Affected | ||||||||||
Three months ended September 30, | |||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (2 | ) | Increase in interest expense | ||||||
Commodity contracts | — | (1 | ) | Increase in gas purchased for resale | |||||||||
Deferred employee benefit plan costs | (1 | ) | — | ||||||||||
Total reclassifications | $ | (3 | ) | $ | (3 | ) | |||||||
Nine months ended September 30, | |||||||||||||
Interest rate contracts | $ | (5 | ) | $ | (5 | ) | Increase in interest expense | ||||||
Commodity contracts | (2 | ) | (12 | ) | Increase in gas purchased for resale | ||||||||
Deferred employee benefit plan costs | (1 | ) | (1 | ) | |||||||||
Total reclassifications | $ | (8 | ) | $ | (18 | ) | |||||||
For information related to the reclassification of deferred employee benefit amounts from AOCI, see Note 8. | |||||||||||||
SCEG | ' | ||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||
COMMON EQUITY | ' | ||||||||||||
EQUITY | |||||||||||||
Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows: | |||||||||||||
Millions of dollars | Common | Noncontrolling | Total | ||||||||||
Equity | Interest | Equity | |||||||||||
Balance at January 1, 2013 | $ | 3,929 | $ | 114 | $ | 4,043 | |||||||
Capital contribution from parent | 285 | — | 285 | ||||||||||
Dividends declared | (190 | ) | (5 | ) | (195 | ) | |||||||
Comprehensive income | 312 | 8 | 320 | ||||||||||
Balance as of September 30, 2013 | $ | 4,336 | $ | 117 | $ | 4,453 | |||||||
Balance at January 1, 2012 | $ | 3,665 | $ | 108 | $ | 3,773 | |||||||
Capital contribution from parent | 84 | — | 84 | ||||||||||
Dividends declared | (157 | ) | (5 | ) | (162 | ) | |||||||
Comprehensive income | 272 | 9 | 281 | ||||||||||
Balance as of September 30, 2012 | $ | 3,864 | $ | 112 | $ | 3,976 | |||||||
SCE&G had 50 million shares of common stock authorized as of September 30, 2013 and December 31, 2012, of which 40.3 million were issued and outstanding during all periods presented. SCE&G had 20 million shares of preferred stock authorized as of September 30, 2013 and December 31, 2012, of which 1,000 shares were issued and outstanding during all periods presented. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA. | |||||||||||||
Reclassifications from AOCI into earnings of the amortization of deferred employee benefit costs were not significant for any period presented. |
LONGTERM_AND_SHORTTERM_DEBT
LONG-TERM AND SHORT-TERM DEBT | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||||||||
Long-term Debt [Text Block] | ' | ||||||||||||||||||||||||
LONG-TERM DEBT AND LIQUIDITY | |||||||||||||||||||||||||
Long-term Debt | |||||||||||||||||||||||||
In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes. | |||||||||||||||||||||||||
In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027. | |||||||||||||||||||||||||
Substantially all of SCE&G’s and GENCO’s electric utility plant is pledged as collateral in connection with long-term debt. The Company is in compliance with all debt covenants. | |||||||||||||||||||||||||
Liquidity | |||||||||||||||||||||||||
SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: | |||||||||||||||||||||||||
SCANA | SCE&G | PSNC Energy | |||||||||||||||||||||||
Millions of dollars | September 30, | December 31, | September 30, | December 31, | September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
LOC advances | — | — | — | — | — | — | |||||||||||||||||||
Weighted average interest rate | — | — | — | — | — | — | |||||||||||||||||||
Outstanding commercial paper | $ | 68 | $ | 142 | $ | 310 | $ | 449 | — | $ | 32 | ||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.43 | % | 0.58 | % | 0.3 | % | 0.42 | % | — | 0.44 | % | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 229 | $ | 155 | $ | 1,090 | $ | 951 | $ | 100 | $ | 68 | |||||||||||||
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 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements expire in October 2018, and 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 Island 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. | |||||||||||||||||||||||||
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 Branch Banking and Trust Company. The letters of credit expire, subject to renewal, in the fourth quarter of 2014. | |||||||||||||||||||||||||
SCEG | ' | ||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||||||||
Long-term Debt [Text Block] | ' | ||||||||||||||||||||||||
LONG-TERM DEBT AND LIQUIDITY | |||||||||||||||||||||||||
Long-term Debt | |||||||||||||||||||||||||
In June 2013, SCE&G issued $400 million of 4.60% first mortgage bonds due June 15, 2043. Proceeds from this sale were used to pay at maturity $150 million of its 7.125% first mortgage bonds due June 15, 2013, to repay short-term debt primarily incurred as a result of SCE&G's construction program, to finance capital expenditures, and for general corporate purposes. | |||||||||||||||||||||||||
In January 2013, JEDA issued at a premium, for the benefit of SCE&G, $39.5 million of 4.0% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of 3.63% tax-exempt industrial revenue bonds due February 1, 2033. Proceeds from these sales were loaned by JEDA to SCE&G and, together with other available funds, were used to redeem prior to maturity $56.9 million of 5.2% industrial revenue bonds due November 1, 2027. | |||||||||||||||||||||||||
Substantially all of Consolidated SCE&G’s electric utility plant is pledged as collateral in connection with long-term debt. Consolidated SCE&G is in compliance with all debt covenants. | |||||||||||||||||||||||||
Liquidity | |||||||||||||||||||||||||
SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: | |||||||||||||||||||||||||
Millions of dollars | September 30, | December 31, | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
LOC advances | — | — | |||||||||||||||||||||||
Weighted average interest rate | — | — | |||||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 310 | $ | 449 | |||||||||||||||||||||
Weighted average interest rate | 0.3 | % | 0.42 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 1,090 | $ | 951 | |||||||||||||||||||||
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 2013, the term of each of these credit agreements was extended by one year, such that the five-year agreements will expire in October 2018, and 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 Branch Banking and Trust Company. The letters of credit expire, subject to renewal, in the fourth quarter of 2014. | |||||||||||||||||||||||||
Consolidated SCE&G participates in a utility money pool. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions was not significant for any period presented. At September 30, 2013 and December 31, 2012, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $39.6 million and $49.4 million, respectively. |
INCOME_TAXES
INCOME TAXES | 9 Months Ended |
Sep. 30, 2013 | |
income tax [Line Items] | ' |
Income Tax Disclosure [Text Block] | ' |
INCOME TAXES | |
No material changes in the status of the Company's tax positions have occurred through September 30, 2013. | |
During the third quarter of 2013, the State of North Carolina passed legislation that will lower the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015. The change in income tax rates 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). These regulations did not have a material impact on the Company's financial position, results of operations or cash flows. | |
SCEG | ' |
income tax [Line Items] | ' |
Income Tax Disclosure [Text Block] | ' |
INCOME TAXES | |
No material changes in the status of Consolidated SCE&G's tax positions have occurred through September 30, 2013. | |
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). These regulations did not have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows. |
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||
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 the statement 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 the Audit Committee's attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. | ||||||||||||||||||||||||
Commodity Derivatives | ||||||||||||||||||||||||
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the condensed consolidated statements of cash flows. | ||||||||||||||||||||||||
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes. | ||||||||||||||||||||||||
Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. | ||||||||||||||||||||||||
As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. | ||||||||||||||||||||||||
Interest Rate Swaps | ||||||||||||||||||||||||
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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as directed by the SCPSC. | ||||||||||||||||||||||||
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. | ||||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | ||||||||||||||||||||||||
The Company was party to natural gas derivative contracts outstanding in the following quantities: | ||||||||||||||||||||||||
Commodity and Other Energy Management Contracts (in MMBTU) | ||||||||||||||||||||||||
Hedge designation | Gas Distribution | Retail Gas | Energy Marketing | Total | ||||||||||||||||||||
Marketing | ||||||||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Commodity | 8,820,000 | 10,407,000 | 3,078,500 | 22,305,500 | ||||||||||||||||||||
Energy Management (a) | — | — | 30,908,058 | 30,908,058 | ||||||||||||||||||||
Total (a) | 8,820,000 | 10,407,000 | 33,986,558 | 53,213,558 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Commodity | 5,170,000 | 6,490,000 | 4,877,000 | 16,537,000 | ||||||||||||||||||||
Energy Management (b) | — | — | 31,763,275 | 31,763,275 | ||||||||||||||||||||
Total (b) | 5,170,000 | 6,490,000 | 36,640,275 | 48,300,275 | ||||||||||||||||||||
(a) Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing. | ||||||||||||||||||||||||
(b) Includes an aggregate 3,500,000 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 $663.8 million at September 30, 2013 and $1.1 billion at December 31, 2012. | ||||||||||||||||||||||||
The fair value of energy-related derivatives and interest rate derivatives was reflected in the condensed consolidated balance sheet as follows: | ||||||||||||||||||||||||
Fair Values of Derivative Instruments | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 83 | Other current liabilities | $ | 5 | ||||||||||||||||||
Other deferred debits and other assets | 41 | Other deferred credits and other liabilities | 19 | |||||||||||||||||||||
Commodity | Other current liabilities | 3 | ||||||||||||||||||||||
Total | $ | 124 | $ | 27 | ||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||||||||||||||
Energy Management | Prepayments and other | 5 | Prepayments and other | $ | 1 | |||||||||||||||||||
Other current liabilities | 4 | |||||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | |||||||||||||||||||||
Total | $ | 11 | $ | 10 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 70 | ||||||||||||||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 36 | |||||||||||||||||||||
Commodity | Prepayments and other | 1 | Other current liabilities | 4 | ||||||||||||||||||||
Total | $ | 74 | $ | 110 | ||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||||||||||||||
Energy management | Prepayments and other | 7 | Prepayments and other | $ | 1 | |||||||||||||||||||
Other deferred debits and other assets | 6 | Other current liabilities | 6 | |||||||||||||||||||||
Other deferred debits and other assets | 6 | |||||||||||||||||||||||
Total | $ | 14 | $ | 13 | ||||||||||||||||||||
The effect of derivative instruments on the condensed consolidated statements of income is as follows: | ||||||||||||||||||||||||
Fair Value Hedges | ||||||||||||||||||||||||
With regard to the Company's interest rate swaps designated as fair value hedges, any gains or losses related to the swaps or the fixed rate debt are recognized in current earnings and included in interest expense. The Company had no interest rate swaps designated as fair value hedges for any period presented, and the amortization of deferred gains on previously terminated swaps were not significant during any period presented. | ||||||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | ||||||||||||||||||||||||
Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
September 30, | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 19 | $ | 23 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||||
Nine Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 115 | $ | 51 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
Gain (Loss) Recognized in OCI, net of tax | Loss Reclassified from AOCI into Income, net of tax | |||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
September 30, | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||
Interest rate | — | $ | (1 | ) | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
Commodity | $ | (1 | ) | 2 | Gas purchased for resale | — | (1 | ) | ||||||||||||||||
Total | $ | (1 | ) | $ | 1 | $ | (2 | ) | $ | (3 | ) | |||||||||||||
Nine Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 4 | $ | (5 | ) | Interest expense | $ | (5 | ) | $ | (5 | ) | ||||||||||||
Commodity | (1 | ) | (1 | ) | Gas purchased for resale | (2 | ) | (12 | ) | |||||||||||||||
Total | $ | 3 | $ | (6 | ) | $ | (7 | ) | $ | (17 | ) | |||||||||||||
As of September 30, 2013, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $2.0 million as an increase to gas cost and approximately $6.2 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels. As of September 30, 2013, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2015. | ||||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | Loss Recognized in Income | |||||||||||||||||||||||
Millions of dollars | Location | 2013 | 2012 | |||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | — | |||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) | |||||||||||||||||||
Hedge Ineffectiveness | ||||||||||||||||||||||||
Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively. | ||||||||||||||||||||||||
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 may 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 permit the secured party to demand the posting of 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 may require the Company to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2013 and December 31, 2012, the Company has posted $35.4 million and $78.3 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 Prepayments and other on the consolidated balance sheets. Collateral related to 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 September 30, 2013 and December 31, 2012, the Company could have been required to post an additional $- million and $26.2 million, respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2013 and December 31, 2012 is $35.3 million and $104.5 million, respectively. | ||||||||||||||||||||||||
In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, the Company could request $78.6 million and $32.1 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 September 30, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively. In addition, at September 30, 2013, the Company could have called on letters of credit in the amount of $9 million related to $10 million in commodity derivatives that are in a net asset position, compared to letters of credit of $10 million related to derivatives of $13 million at December 31, 2012, if all the contingent features underlying these instruments had been fully triggered. | ||||||||||||||||||||||||
Information related to the Company's offsetting of derivative assets follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 124 | — | $ | 124 | $ | (3 | ) | — | $ | 121 | |||||||||||||
Commodity | 1 | — | 1 | — | — | 1 | ||||||||||||||||||
Energy Management | 10 | — | 10 | — | — | 10 | ||||||||||||||||||
Total | $ | 135 | — | $ | 135 | $ | (3 | ) | — | $ | 132 | |||||||||||||
Balance sheet location | Prepayments and other | $ | 89 | |||||||||||||||||||||
Other deferred debits and other assets | 46 | |||||||||||||||||||||||
Total | $ | 135 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||||
Commodity | 2 | — | 2 | — | — | 2 | ||||||||||||||||||
Energy Management | 13 | $ | (1 | ) | 12 | — | — | 12 | ||||||||||||||||
Total | $ | 88 | $ | (1 | ) | $ | 87 | $ | (17 | ) | — | $ | 70 | |||||||||||
Balance sheet location | Prepayments and other | $ | 50 | |||||||||||||||||||||
Other deferred debits and other assets | 37 | |||||||||||||||||||||||
Total | $ | 87 | ||||||||||||||||||||||
Information related to the Company's offsetting of derivative liabilities follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 24 | — | $ | 24 | $ | (3 | ) | $ | (21 | ) | — | ||||||||||||
Commodity | 3 | — | 3 | — | (1 | ) | $ | 2 | ||||||||||||||||
Energy Management | 10 | — | 10 | — | (8 | ) | 2 | |||||||||||||||||
$ | 37 | — | $ | 37 | $ | (3 | ) | $ | (30 | ) | $ | 4 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 1 | |||||||||||||||||||||
Other current liabilities | 12 | |||||||||||||||||||||||
Other deferred credits and other liabilities | 24 | |||||||||||||||||||||||
Total | $ | 37 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (17 | ) | $ | (67 | ) | $ | 22 | |||||||||||
Commodity | 4 | — | 4 | — | — | 4 | ||||||||||||||||||
Energy Management | 13 | $ | (1 | ) | 12 | — | (11 | ) | 1 | |||||||||||||||
$ | 123 | $ | (1 | ) | $ | 122 | $ | (17 | ) | $ | (78 | ) | $ | 27 | ||||||||||
Balance sheet location | Other current liabilities | $ | 80 | |||||||||||||||||||||
Other deferred credits and other liabilities | 42 | |||||||||||||||||||||||
Total | $ | 122 | ||||||||||||||||||||||
SCEG | ' | |||||||||||||||||||||||
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 the statement 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 the 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 the Audit Committee’s 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 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 are recorded in regulatory assets or regulatory liabilities. 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 authorization granted in October 2013, certain interest rate derivatives entered into by SCE&G will no longer be designated as cash flow hedges, and fair value changes and settlement amounts are to be recorded in its regulatory asset and liability accounts. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to undercollected fuel amounts or may be amortized to interest expense as directed by the SCPSC. | ||||||||||||||||||||||||
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. | ||||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | ||||||||||||||||||||||||
Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $571.4 million at September 30, 2013 and $971.4 million at December 31, 2012. | ||||||||||||||||||||||||
The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows: | ||||||||||||||||||||||||
Fair Values of Derivative Instruments | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 83 | Other current liabilities | $ | 2 | ||||||||||||||||||
Other deferred debits and other assets | 41 | Other deferred credits and other liabilities | 1 | |||||||||||||||||||||
Total | $ | 124 | $ | 3 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 66 | ||||||||||||||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 9 | |||||||||||||||||||||
Total | $ | 73 | $ | 75 | ||||||||||||||||||||
The effect of derivative instruments on the condensed consolidated statement of income is as follows: | ||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||||
Millions of dollars | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Interest rate | $ | 19 | $ | 23 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Interest rate | $ | 115 | $ | 51 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
Derivatives not designated as Hedging Instruments | Loss Recognized in Income | |||||||||||||||||||||||
Millions of dollars | Location | 2013 | 2012 | |||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | — | |||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) | |||||||||||||||||||
Hedge Ineffectiveness | ||||||||||||||||||||||||
Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three and nine months ended September 30, 2013 and 2012, respectively. | ||||||||||||||||||||||||
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 may 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 permit the secured party to demand the posting of 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 may require Consolidated SCE&G to provide collateral upon the occurrence of specific events, primarily credit downgrades. As of September 30, 2013 and December 31, 2012, Consolidated SCE&G has posted $3.3 million and $35.2 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 Prepayments and other on the consolidated balance sheets. Collateral related to 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 September 30, 2013 and December 31, 2012, Consolidated SCE&G could have been required to post an additional $- million and $22.7 million, respectively, of collateral with its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position as of September 30, 2013 and December 31, 2012 is $2.6 million and $57.9 million, respectively. | ||||||||||||||||||||||||
In addition, as of September 30, 2013 and December 31, 2012, 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 were fully triggered as of September 30, 2013 and December 31, 2012, Consolidated SCE&G could request $78.6 million and $32.1 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 September 30, 2013 and December 31, 2012 is $78.6 million and $32.1 million, respectively. | ||||||||||||||||||||||||
Information related to Consolidated SCE&G's derivative assets follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 124 | — | $ | 124 | $ | (3 | ) | — | $ | 121 | |||||||||||||
Balance Sheet Location | Prepayments and other | $ | 83 | |||||||||||||||||||||
Other deferred debits and other assets | 41 | |||||||||||||||||||||||
Total | $ | 124 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||||
Balance Sheet Location | Prepayments and other | $ | 42 | |||||||||||||||||||||
Other deferred debits and other assets | 31 | |||||||||||||||||||||||
Total | $ | 73 | ||||||||||||||||||||||
Information related to Consolidated SCE&G's derivative liabilities follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 3 | — | $ | 3 | $ | (3 | ) | $ | — | $ | — | ||||||||||||
Balance Sheet Location | Other current liabilities | $ | 2 | |||||||||||||||||||||
Other deferred credits and other liabilities | 1 | |||||||||||||||||||||||
Total | $ | 3 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 75 | — | $ | 75 | $ | (17 | ) | $ | (35 | ) | $ | 23 | |||||||||||
Balance Sheet Location | Other current liabilities | $ | 66 | |||||||||||||||||||||
Other deferred credits and other liabilities | 9 | |||||||||||||||||||||||
Total | $ | 75 | ||||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ||||||||||||||||
Fair Value Disclosures [Text Block] | ' | ||||||||||||||||
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | |||||||||||||||||
The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced market data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | |||||||||||||||||
Fair Value Measurements Using | |||||||||||||||||
Quoted Prices in | |||||||||||||||||
Active Markets for | Significant Other | ||||||||||||||||
Identical Assets | Observable Inputs | ||||||||||||||||
Millions of dollars | (Level 1) | (Level 2) | |||||||||||||||
As of September 30, 2013 | |||||||||||||||||
Assets - | Available for sale securities | $ | 9 | — | |||||||||||||
Interest rate contracts | — | $ | 124 | ||||||||||||||
Commodity contracts | 1 | — | |||||||||||||||
Energy management contracts | — | 10 | |||||||||||||||
Liabilities - | Interest rate contracts | — | 24 | ||||||||||||||
Commodity contracts | — | 3 | |||||||||||||||
Energy management contracts | — | 13 | |||||||||||||||
As of December 31, 2012 | |||||||||||||||||
Assets - | Available for sale securities | $ | 6 | — | |||||||||||||
Interest rate contracts | — | $ | 73 | ||||||||||||||
Commodity contracts | 1 | 1 | |||||||||||||||
Energy management contracts | — | 13 | |||||||||||||||
Liabilities - | Interest rate contracts | — | 106 | ||||||||||||||
Commodity contracts | — | 4 | |||||||||||||||
Energy management contracts | 1 | 15 | |||||||||||||||
There were no fair value measurements based on significant unobservable inputs (Level 3) for either period presented. In addition, 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 September 30, 2013 and December 31, 2012 were as follows: | |||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,450.90 | $ | 5,936.70 | $ | 5,121.00 | $ | 6,115.00 | |||||||||
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 fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. | |||||||||||||||||
SCEG | ' | ||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ||||||||||||||||
Fair Value Disclosures [Text Block] | ' | ||||||||||||||||
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | |||||||||||||||||
Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements based on significant other observable inputs (level 2) were as follows: | |||||||||||||||||
Fair Value Measurements Using Significant | |||||||||||||||||
Other Observable Inputs (Level 2) | |||||||||||||||||
Millions of dollars | 30-Sep-13 | 31-Dec-12 | |||||||||||||||
Assets - | Interest rate contracts | $ | 124 | $ | 73 | ||||||||||||
Liabilities - | Interest rate contracts | 3 | 75 | ||||||||||||||
There were no fair value measurements based on quoted prices in active markets for identical assets (Level 1) or significant unobservable inputs (Level 3) for either period presented. In addition, 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 September 30, 2013 and December 31, 2012 were as follows: | |||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,056.40 | $ | 4,454.40 | $ | 3,722.00 | $ | 4,543.10 | |||||||||
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. | |||||||||||||||||
Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
EMPLOYEE BENEFIT PLANS | ' | ||||||||||||||||
EMPLOYEE BENEFIT PLANS | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||
Components of net periodic benefit cost recorded by the Company were as follows: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Three months ended September 30, | |||||||||||||||||
Service cost | $ | 5.1 | $ | 5 | $ | 1.2 | $ | 1.1 | |||||||||
Interest cost | 9.5 | 10.9 | 2.8 | 2.9 | |||||||||||||
Expected return on assets | (15.1 | ) | (15.0 | ) | — | — | |||||||||||
Prior service cost amortization | 1.5 | 1.8 | 0.1 | 0.2 | |||||||||||||
Charge due to curtailment | 9.9 | — | — | — | |||||||||||||
Transition obligation amortization | — | — | — | 0.2 | |||||||||||||
Amortization of actuarial losses | 3.5 | 4.5 | 0.8 | — | |||||||||||||
Net periodic benefit cost | $ | 14.4 | $ | 7.2 | $ | 4.9 | $ | 4.4 | |||||||||
Nine months ended September 30, | |||||||||||||||||
Service cost | $ | 16.9 | $ | 14.7 | $ | 4.4 | $ | 3.6 | |||||||||
Interest cost | 28.4 | 32.2 | 8.3 | 8.9 | |||||||||||||
Expected return on assets | (45.8 | ) | (44.6 | ) | — | — | |||||||||||
Prior service cost amortization | 4.9 | 5.3 | 0.5 | 0.7 | |||||||||||||
Charge due to curtailment | 9.9 | — | — | — | |||||||||||||
Transition obligation amortization | — | — | 0.3 | 0.5 | |||||||||||||
Amortization of actuarial losses | 14.4 | 13.8 | 2.5 | 0.4 | |||||||||||||
Net periodic benefit cost | $ | 28.7 | $ | 21.4 | $ | 16 | $ | 14.1 | |||||||||
No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G also began recovering previously deferred pension expense as described in Note 2. Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2. | |||||||||||||||||
In the third quarter 2013, the Company amended its pension plan, such that pension benefits will no longer be 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. As a result, the Company recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $6.3 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. The Company expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings. | |||||||||||||||||
In connection with the pension plan amendment, the Company remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in the Company's pension obligation of approximately $128 million. | |||||||||||||||||
SCEG | ' | ||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
EMPLOYEE BENEFIT PLANS | ' | ||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||
Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to active and retired employees. Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Three months ended September 30, | |||||||||||||||||
Service cost | $ | 4.1 | $ | 4.1 | $ | 1 | $ | 0.8 | |||||||||
Interest cost | 8 | 9.1 | 2.1 | 2.3 | |||||||||||||
Expected return on assets | (12.7 | ) | (12.6 | ) | — | — | |||||||||||
Prior service cost amortization | 1.3 | 1.6 | 0.1 | 0.1 | |||||||||||||
Charge due to curtailment | 8.4 | — | — | — | |||||||||||||
Amortization of actuarial losses | 3 | 3.7 | 0.7 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 12.1 | $ | 5.9 | $ | 3.9 | $ | 3.3 | |||||||||
Nine months ended September 30, | |||||||||||||||||
Service cost | $ | 13.7 | $ | 11.8 | $ | 3.5 | $ | 2.8 | |||||||||
Interest cost | 24 | 27.3 | 6.5 | 7 | |||||||||||||
Expected return on assets | (38.7 | ) | (37.8 | ) | — | — | |||||||||||
Prior service cost amortization | 4.1 | 4.5 | 0.4 | 0.5 | |||||||||||||
Charge due to curtailment | 8.4 | — | — | — | |||||||||||||
Amortization of actuarial losses | 12.2 | 11.7 | 2 | 0.3 | |||||||||||||
Net periodic benefit cost | $ | 23.7 | $ | 17.5 | $ | 12.4 | $ | 10.6 | |||||||||
No significant contribution to the pension trust is expected until after 2016, nor is a limitation on benefits payments expected to apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering current pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G also began recovering previously deferred pension expense as described in Note 2. Costs totaling $1.2 million and $2.4 million related to gas operations were deferred for the three and nine months ended September 30, 2013, respectively. Costs totaling $4.0 million and $11.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. In connection with the October 2013 RSA order, beginning in November 2013, SCE&G will begin recovering current pension expense related to gas operations through cost of service rates and will begin recovering previously deferred costs as described in Note 2. | |||||||||||||||||
In the third quarter 2013, SCANA amended its pension plan, such that pension benefits will no longer be 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. As a result, SCE&G recorded a curtailment charge due to the accelerated amortization of prior service cost. Approximately $5.4 million of the curtailment charge was applicable to regulated operations and was deferred within regulatory assets. SCE&G expects to recover such deferred amounts through existing regulatory orders or to request recovery in future proceedings. | |||||||||||||||||
In connection with the pension plan amendment, SCANA remeasured its pension obligation in the third quarter of 2013 using current assumptions for the discount rate and future salary increases. The pension plan amendment and remeasurement resulted in a reduction in SCE&G's pension obligation of approximately $108 million. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 9 Months Ended | |
Sep. 30, 2013 | ||
Statement [Line Items] | ' | |
Commitments and Contingencies Disclosure [Text Block] | ' | |
COMMITMENTS AND CONTINGENCIES | ||
Nuclear Insurance | ||
Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at 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 premium, SCE&G’s portion of the retrospective premium assessment would not exceed $40.6 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's rates would not recover the cost of any purchased replacement power or other costs and expenses, 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. | ||
Environmental | ||
As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units.The Company is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. The Company also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates. | ||
In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with such regulations are expected to be recoverable through rates. | ||
In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 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 the EPA's rule. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates. | ||
The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates. | ||
The Company maintains an environmental assessment program to identify and evaluate its 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 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. 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 recorded to expense. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 $21.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets. | ||
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s 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 $2.9 million, the estimated remaining liability at September 30, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites. | ||
New Nuclear Construction | ||
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. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. | ||
The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island to the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered. | ||
In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project. The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses. Any disruptions could impact the project's schedule or costs, and such impacts could be material. | ||
Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification. | ||
The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays, | ||
design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock | ||
conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution | ||
of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. | ||
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. These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.” This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units. | ||
SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units. Any such project cost increase or delay could be material. | ||
SCEG | ' | |
Statement [Line Items] | ' | |
Commitments and Contingencies Disclosure [Text Block] | ' | |
COMMITMENTS AND CONTINGENCIES | ||
Nuclear Insurance | ||
Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at 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 premium, SCE&G’s portion of the retrospective premium assessment would not exceed $40.6 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's rates would not recover the cost of any purchased replacement power or other cost and expenses, 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. | ||
Environmental | ||
As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. On September 20, 2013, EPA re-proposed NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when it will become final, if at all, or what conditions it may impose on the Company, if any. Consolidated SCE&G also cannot predict when rules will become final for existing units, if at all, or what conditions they may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates. | ||
In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order was denied. In June, 2013, the U.S. Supreme Court agreed to review the Court of Appeals' decision and has scheduled oral arguments for December 10, 2013. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR. Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with such regulations are expected to be recoverable through rates. | ||
In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 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 Consolidated SCE&G's compliance with the EPA's rule. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates. | ||
The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates. | ||
Consolidated SCE&G maintains an environmental assessment program to identify and evaluate its 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 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. 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 recorded to expense. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct 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 $21.2 million, which is accrued in Other within Deferred Credits and Other Liabilities on the condensed consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At September 30, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.1 million and are included in regulatory assets. | ||
New Nuclear Construction | ||
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. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.7 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. | ||
The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules are a focus area of the Consortium. The delivery schedule of sub-modules for structural module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel, is now expected to support completion of on-site fabrication to allow them to be set on the nuclear island for the first New Unit during the first and third quarters of 2014, respectively. With this schedule, the Consortium continues to indicate that the substantial completion of the first New Unit is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be approximately twelve months after that of the first New Unit. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G has not accepted responsibility for any of these delay-related costs and expects to have further discussions with the Consortium regarding such responsibility. Additionally, the EPC Contract provides for liquidated damages in the event of a delay in the completion of the facility, which will also be included in discussions with the Consortium. SCE&G believes its responsibility for any portion of the $200 million estimate should ultimately be substantially less, once all of the relevant factors are considered. | ||
In addition to the above-described project delays, SCE&G is also aware of financial difficulties at a supplier responsible for certain significant components of the project. The Consortium is monitoring the potential for disruptions in such equipment fabrication and possible responses. Any disruptions could impact the project's schedule or costs, and such impacts could be material. | ||
Subject to a national megawatt capacity limitation, the electricity to be produced by the New Units (advanced nuclear units, as defined) is expected to qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code. Following the pouring of safety-related concrete for each of the Units’ reactor buildings (March 2013 for the first New Unit and November 2013 for the second New Unit), the Company has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the United States Department of Energy for appropriate certification. | ||
The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays, | ||
design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock | ||
conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution | ||
of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. | ||
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. These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.” This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units. | ||
SCE&G understands that Santee Cooper continues to evaluate reduction of its level of participation in the New Units through potential sales of portions of its interest therein to third parties. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the substantial completion dates of the New Units. Any such project cost increase or delay could be material. |
SEGMENT_OF_BUSINESS_INFORMATIO
SEGMENT OF BUSINESS INFORMATION | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||
Segment Reporting Disclosure [Text Block] | ' | ||||||||||||||||
SEGMENT OF BUSINESS INFORMATION | |||||||||||||||||
The Company’s reportable segments are listed in the following table. The Company uses operating income to measure profitability for its regulated operations; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Company uses net income to measure profitability for its Retail Gas Marketing and Energy Marketing segments. Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes equity method investments and other nonreportable segments. Nonreportable segments include a FERC-regulated interstate pipeline company and other companies that conduct nonregulated operations in energy-related and telecommunications industries. | |||||||||||||||||
Millions of dollars | External | Intersegment | Operating | Net | |||||||||||||
Revenue | Revenue | Income | Income | ||||||||||||||
Three Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 704 | $ | 2 | $ | 257 | n/a | ||||||||||
Gas Distribution | 123 | — | (6 | ) | n/a | ||||||||||||
Retail Gas Marketing | 67 | — | n/a | $ | (2 | ) | |||||||||||
Energy Marketing | 152 | 44 | n/a | 1 | |||||||||||||
All Other | 11 | 95 | 8 | (3 | ) | ||||||||||||
Adjustments/Eliminations | (6 | ) | (141 | ) | (4 | ) | 135 | ||||||||||
Consolidated Total | $ | 1,051 | $ | — | $ | 255 | $ | 131 | |||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 1,898 | $ | 6 | $ | 588 | n/a | ||||||||||
Gas Distribution | 657 | — | 94 | n/a | |||||||||||||
Retail Gas Marketing | 325 | — | n/a | $ | 16 | ||||||||||||
Energy Marketing | 488 | 133 | n/a | 5 | |||||||||||||
All Other | 30 | 303 | 22 | (2 | ) | ||||||||||||
Adjustments/Eliminations | (20 | ) | (442 | ) | 34 | 349 | |||||||||||
Consolidated Total | $ | 3,378 | $ | — | $ | 738 | $ | 368 | |||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 714 | $ | 2 | $ | 243 | n/a | ||||||||||
Gas Distribution | 107 | — | (7 | ) | n/a | ||||||||||||
Retail Gas Marketing | 64 | — | n/a | $ | (5 | ) | |||||||||||
Energy Marketing | 151 | 35 | n/a | 1 | |||||||||||||
All Other | 11 | 100 | 6 | (3 | ) | ||||||||||||
Adjustments/Eliminations | (9 | ) | (137 | ) | (4 | ) | 129 | ||||||||||
Consolidated Total | $ | 1,038 | $ | — | $ | 238 | $ | 122 | |||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 1,851 | $ | 7 | $ | 534 | n/a | ||||||||||
Gas Distribution | 507 | — | 81 | n/a | |||||||||||||
Retail Gas Marketing | 288 | — | n/a | $ | 3 | ||||||||||||
Energy Marketing | 402 | 84 | n/a | 5 | |||||||||||||
All Other | 32 | 309 | 17 | (2 | ) | ||||||||||||
Adjustments/Eliminations | (26 | ) | (400 | ) | 15 | 309 | |||||||||||
Consolidated Total | $ | 3,054 | $ | — | $ | 647 | $ | 315 | |||||||||
September 30, | December 31, | ||||||||||||||||
Segment Assets | 2013 | 2012 | |||||||||||||||
Electric Operations | $ | 9,430 | $ | 8,989 | |||||||||||||
Gas Distribution | 2,286 | 2,292 | |||||||||||||||
Retail Gas Marketing | 131 | 153 | |||||||||||||||
Energy Marketing | 124 | 122 | |||||||||||||||
All Other | 1,287 | 1,415 | |||||||||||||||
Adjustments/Eliminations | 1,739 | 1,645 | |||||||||||||||
Consolidated Total | $ | 14,997 | $ | 14,616 | |||||||||||||
SCEG | ' | ||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||
Segment Reporting Disclosure [Text Block] | ' | ||||||||||||||||
SEGMENT OF BUSINESS INFORMATION | |||||||||||||||||
Consolidated SCE&G’s reportable segments are listed in the following table. Consolidated SCE&G uses operating income to measure profitability for its regulated operations. Therefore, earnings available to common shareholder are not allocated to the Electric Operations and Gas Distribution segments. Intersegment revenues were not significant. | |||||||||||||||||
External | Operating | Earnings Available to | |||||||||||||||
Millions of dollars | Revenue | Income | Common Shareholder | ||||||||||||||
Three Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 706 | $ | 257 | n/a | ||||||||||||
Gas Distribution | 70 | (2 | ) | n/a | |||||||||||||
Adjustments/Eliminations | — | — | $ | 136 | |||||||||||||
Consolidated Total | $ | 776 | $ | 255 | $ | 136 | |||||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 1,903 | $ | 588 | n/a | ||||||||||||
Gas Distribution | 297 | 37 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 311 | |||||||||||||
Consolidated Total | $ | 2,200 | $ | 625 | $ | 311 | |||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 716 | $ | 244 | n/a | ||||||||||||
Gas Distribution | 61 | (3 | ) | n/a | |||||||||||||
Adjustments/Eliminations | — | — | $ | 129 | |||||||||||||
Consolidated Total | $ | 777 | $ | 241 | $ | 129 | |||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 1,857 | $ | 534 | n/a | ||||||||||||
Gas Distribution | 244 | 27 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 272 | |||||||||||||
Consolidated Total | $ | 2,101 | $ | 561 | $ | 272 | |||||||||||
September 30, | December 31, | ||||||||||||||||
Segment Assets | 2013 | 2012 | |||||||||||||||
Electric Operations | $ | 9,430 | $ | 8,989 | |||||||||||||
Gas Distribution | 681 | 659 | |||||||||||||||
Adjustments/Eliminations | 2,583 | 2,456 | |||||||||||||||
Consolidated Total | $ | 12,694 | $ | 12,104 | |||||||||||||
AFFILIATED_TRANSACTIONS_SCEG
AFFILIATED TRANSACTIONS - SCEG | 9 Months Ended |
Sep. 30, 2013 | |
AFFILIATED TRANSACTIONS | ' |
AFFILIATED TRANSACTIONS | |
CGT transports natural gas to SCE&G to serve SCE&G’s retail gas customers and certain electric generation requirements. Transportation services totaled approximately $25.3 million and $27.1 million for the nine months ended September 30, 2013 and 2012, respectively. SCE&G had approximately $3.0 million and $3.4 million payable to CGT for transportation services at September 30, 2013 and December 31, 2012, 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 $132.7 million and $84.0 million for the nine months ended September 30, 2013 and 2012, respectively. SCE&G’s payables to SEMI for such purposes were $13.2 million and $13.1 million as of September 30, 2013 and December 31, 2012, respectively. | |
SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G owned 10% of Cope Refined Coal, LLC through December 31, 2012. SCE&G accounts for these investments using the equity method. SCE&G’s receivables from these affiliates were $19.7 million at September 30, 2013 and $1.8 million at December 31, 2012. SCE&G’s payables to these affiliates were $19.8 million at September 30, 2013 and $1.8 million at December 31, 2012. SCE&G’s total purchases from these affiliates were $73.7 million and $87.3 million for the nine months ended September 30, 2013 and 2012, respectively. SCE&G’s total sales to these affiliates were $73.4 million and $86.9 million for the nine months ended September 30, 2013 and 2012, respectively. | |
Consolidated SCE&G receives the following services from SCANA Services and its parent company, which are rendered at direct or allocated cost: information systems 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. Consolidated SCE&G’s payables for such purposes were $40.3 million and $45.8 million as of September 30, 2013 and December 31, 2012, respectively. | |
Money pool borrowings from an affiliate are described at Note 4. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Significant Accounting Policies | ' |
Use of Estimates | ' |
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. | |
Asset Management and Supply Service Agreements | ' |
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 47% and 44% of PSNC Energy’s natural gas inventory at September 30, 2013 | |
and December 31, 2012, respectively, with a carrying value of $23.2 million and $19.6 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015. | |
Earnings Per Share | ' |
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. | |
SCEG | ' |
Significant Accounting Policies | ' |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | ' |
Variable Interest Entities | |
SCE&G has determined that it is the primary beneficiary of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. | |
GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $478 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4. | |
Use of Estimates | ' |
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. | |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | ||||||||||||||
Accounting Policies [Abstract] | ' | |||||||||||||
Reconciliation of the weighted average number of common shares | ' | |||||||||||||
Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows: | ||||||||||||||
Third Quarter | Year to Date | |||||||||||||
Millions | 2013 | 2012 | 2013 | 2012 | ||||||||||
Weighted Average Shares Outstanding - Basic | 140.1 | 131.4 | 138 | 130.8 | ||||||||||
Effect of dilutive equity forward shares | — | 2.4 | 0.6 | 2.3 | ||||||||||
Weighted Average Shares - Diluted | 140.1 | 133.8 | 138.6 | 133.1 | ||||||||||
RATE_AND_OTHER_REGULATORY_MATT1
RATE AND OTHER REGULATORY MATTERS (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Regulatory Assets | ' | ||||||||
Demand reduction programs [Table Text Block] | ' | ||||||||
: | |||||||||
Year | Effective | Amount | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Schedule of Regulatory Assets [Table Text Block] | ' | ||||||||
. | |||||||||
Millions of dollars | September 30, | December 31, | |||||||
2013 | 2012 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 254 | $ | 254 | |||||
Under-collections - electric fuel adjustment clause | 52 | 66 | |||||||
Environmental remediation costs | 42 | 44 | |||||||
AROs and related funding | 359 | 319 | |||||||
Franchise agreements | 32 | 36 | |||||||
Deferred employee benefit plan costs | 319 | 460 | |||||||
Planned major maintenance | — | 6 | |||||||
Deferred losses on interest rate derivatives | 126 | 151 | |||||||
Deferred pollution control costs | 37 | 38 | |||||||
Unrecovered plant | 19 | 20 | |||||||
Other | 93 | 70 | |||||||
Total Regulatory Assets | $ | 1,333 | $ | 1,464 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | ' | ||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 19 | $ | 21 | |||||
Asset removal costs | 718 | 692 | |||||||
Storm damage reserve | 27 | 27 | |||||||
Monetization of bankruptcy claim | 30 | 32 | |||||||
Deferred gains on interest rate derivatives | 203 | 110 | |||||||
Planned major maintenance | 10 | — | |||||||
Total Regulatory Liabilities | $ | 1,007 | $ | 882 | |||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | ' | ||||||||
: | |||||||||
Year | Action | Amount | |||||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
2012 | 2.3 | % | Increase | $52.1 million | |||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | ' | ||||||||
: | |||||||||
Year | Action | Amount | |||||||
2013 | No change | - | |||||||
2012 | 2.1 | % | Increase | $7.5 million | |||||
SCEG | ' | ||||||||
Regulatory Assets | ' | ||||||||
Demand reduction programs [Table Text Block] | ' | ||||||||
Year | Effective | Amount | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Schedule of Regulatory Assets [Table Text Block] | ' | ||||||||
Millions of dollars | September 30, | December 31, | |||||||
2013 | 2012 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 248 | $ | 248 | |||||
Under collections – electric fuel adjustment clause | 52 | 66 | |||||||
Environmental remediation costs | 37 | 39 | |||||||
AROs and related funding | 342 | 304 | |||||||
Franchise agreements | 32 | 36 | |||||||
Deferred employee benefit plan costs | 284 | 405 | |||||||
Planned major maintenance | — | 6 | |||||||
Deferred losses on interest rate derivatives | 126 | 151 | |||||||
Deferred pollution control costs | 37 | 38 | |||||||
Unrecovered plant | 19 | 20 | |||||||
Other | 82 | 64 | |||||||
Total Regulatory Assets | $ | 1,259 | $ | 1,377 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | ' | ||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 19 | $ | 21 | |||||
Asset removal costs | 522 | 507 | |||||||
Storm damage reserve | 27 | 27 | |||||||
Deferred gains on interest rate derivatives | 203 | 110 | |||||||
Planned major maintenance | 10 | — | |||||||
Total Regulatory Liabilities | $ | 781 | $ | 665 | |||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | ' | ||||||||
years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
2012 | 2.3 | % | Increase | $52.1 million | |||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | ' | ||||||||
e years indicated: | |||||||||
Year | Action | Amount | |||||||
2013 | No change | - | |||||||
2012 | 2.1 | % | Increase | $7.5 million |
COMMON_EQUITY_Tables
COMMON EQUITY (Tables) | 9 Months Ended | ||||||||||||
Sep. 30, 2013 | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | ' | ||||||||||||
Schedule of Stockholders Equity [Table Text Block] | ' | ||||||||||||
Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows: | |||||||||||||
Millions of dollars | 2013 | 2012 | |||||||||||
Balance at January 1, | $ | 4,154 | $ | 3,889 | |||||||||
Common stock issued | 273 | 73 | |||||||||||
Dividends declared | (212 | ) | (194 | ) | |||||||||
Comprehensive income | 383 | 327 | |||||||||||
Balance as of September 30, | $ | 4,598 | $ | 4,095 | |||||||||
Reclassifications from Other Comprehensive Income [Table Text Block] | ' | ||||||||||||
Reclassifications of gains (losses) from AOCI into earnings, net of taxes, were as follows: | |||||||||||||
Millions of dollars | 2013 | 2012 | Income Statement Line Item Affected | ||||||||||
Three months ended September 30, | |||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (2 | ) | Increase in interest expense | ||||||
Commodity contracts | — | (1 | ) | Increase in gas purchased for resale | |||||||||
Deferred employee benefit plan costs | (1 | ) | — | ||||||||||
Total reclassifications | $ | (3 | ) | $ | (3 | ) | |||||||
Nine months ended September 30, | |||||||||||||
Interest rate contracts | $ | (5 | ) | $ | (5 | ) | Increase in interest expense | ||||||
Commodity contracts | (2 | ) | (12 | ) | Increase in gas purchased for resale | ||||||||
Deferred employee benefit plan costs | (1 | ) | (1 | ) | |||||||||
Total reclassifications | $ | (8 | ) | $ | (18 | ) | |||||||
For information related to the reclassification of deferred employee benefit amounts from AOCI, see Note 8. | |||||||||||||
SCEG | ' | ||||||||||||
Schedule of Capitalization, Equity [Line Items] | ' | ||||||||||||
Schedule of Stockholders Equity [Table Text Block] | ' | ||||||||||||
Changes in common equity during the nine months ended September 30, 2013 and 2012 were as follows: | |||||||||||||
Millions of dollars | Common | Noncontrolling | Total | ||||||||||
Equity | Interest | Equity | |||||||||||
Balance at January 1, 2013 | $ | 3,929 | $ | 114 | $ | 4,043 | |||||||
Capital contribution from parent | 285 | — | 285 | ||||||||||
Dividends declared | (190 | ) | (5 | ) | (195 | ) | |||||||
Comprehensive income | 312 | 8 | 320 | ||||||||||
Balance as of September 30, 2013 | $ | 4,336 | $ | 117 | $ | 4,453 | |||||||
Balance at January 1, 2012 | $ | 3,665 | $ | 108 | $ | 3,773 | |||||||
Capital contribution from parent | 84 | — | 84 | ||||||||||
Dividends declared | (157 | ) | (5 | ) | (162 | ) | |||||||
Comprehensive income | 272 | 9 | 281 | ||||||||||
Balance as of September 30, 2012 | $ | 3,864 | $ | 112 | $ | 3,976 | |||||||
LONGTERM_AND_SHORTTERM_DEBT_LO
LONG-TERM AND SHORT-TERM DEBT LONG-TERM AND SHORT-TERM DEBT (Tables) | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ||||||||||||||||||||||||
Long-term Debt [Text Block] | ' | ||||||||||||||||||||||||
SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: | |||||||||||||||||||||||||
SCANA | SCE&G | PSNC Energy | |||||||||||||||||||||||
Millions of dollars | September 30, | December 31, | September 30, | December 31, | September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
LOC advances | — | — | — | — | — | — | |||||||||||||||||||
Weighted average interest rate | — | — | — | — | — | — | |||||||||||||||||||
Outstanding commercial paper | $ | 68 | $ | 142 | $ | 310 | $ | 449 | — | $ | 32 | ||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.43 | % | 0.58 | % | 0.3 | % | 0.42 | % | — | 0.44 | % | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 229 | $ | 155 | $ | 1,090 | $ | 951 | $ | 100 | $ | 68 | |||||||||||||
SCEG | ' | ||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ||||||||||||||||||||||||
Long-term Debt [Text Block] | ' | ||||||||||||||||||||||||
SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations: | |||||||||||||||||||||||||
Millions of dollars | September 30, | December 31, | |||||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
LOC advances | — | — | |||||||||||||||||||||||
Weighted average interest rate | — | — | |||||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 310 | $ | 449 | |||||||||||||||||||||
Weighted average interest rate | 0.3 | % | 0.42 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 1,090 | $ | 951 | |||||||||||||||||||||
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||
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 September 30, 2013 | ||||||||||||||||||||||||
Commodity | 8,820,000 | 10,407,000 | 3,078,500 | 22,305,500 | ||||||||||||||||||||
Energy Management (a) | — | — | 30,908,058 | 30,908,058 | ||||||||||||||||||||
Total (a) | 8,820,000 | 10,407,000 | 33,986,558 | 53,213,558 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Commodity | 5,170,000 | 6,490,000 | 4,877,000 | 16,537,000 | ||||||||||||||||||||
Energy Management (b) | — | — | 31,763,275 | 31,763,275 | ||||||||||||||||||||
Total (b) | 5,170,000 | 6,490,000 | 36,640,275 | 48,300,275 | ||||||||||||||||||||
(a) Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing. | ||||||||||||||||||||||||
(b) Includes an aggregate 3,500,000 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 energy-related derivatives and interest rate derivatives was reflected in the condensed consolidated balance sheet as follows: | ||||||||||||||||||||||||
Fair Values of Derivative Instruments | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 83 | Other current liabilities | $ | 5 | ||||||||||||||||||
Other deferred debits and other assets | 41 | Other deferred credits and other liabilities | 19 | |||||||||||||||||||||
Commodity | Other current liabilities | 3 | ||||||||||||||||||||||
Total | $ | 124 | $ | 27 | ||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||||||||||||||
Energy Management | Prepayments and other | 5 | Prepayments and other | $ | 1 | |||||||||||||||||||
Other current liabilities | 4 | |||||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | |||||||||||||||||||||
Total | $ | 11 | $ | 10 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 70 | ||||||||||||||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 36 | |||||||||||||||||||||
Commodity | Prepayments and other | 1 | Other current liabilities | 4 | ||||||||||||||||||||
Total | $ | 74 | $ | 110 | ||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||||||||||||||
Energy management | Prepayments and other | 7 | Prepayments and other | $ | 1 | |||||||||||||||||||
Other deferred debits and other assets | 6 | Other current liabilities | 6 | |||||||||||||||||||||
Other deferred debits and other assets | 6 | |||||||||||||||||||||||
Total | $ | 14 | $ | 13 | ||||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | ||||||||||||||||||||||||
Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
September 30, | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 19 | $ | 23 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||||
Nine Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 115 | $ | 51 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
Gain (Loss) Recognized in OCI, net of tax | Loss Reclassified from AOCI into Income, net of tax | |||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
September 30, | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||
Interest rate | — | $ | (1 | ) | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
Commodity | $ | (1 | ) | 2 | Gas purchased for resale | — | (1 | ) | ||||||||||||||||
Total | $ | (1 | ) | $ | 1 | $ | (2 | ) | $ | (3 | ) | |||||||||||||
Nine Months Ended | ||||||||||||||||||||||||
Interest rate | $ | 4 | $ | (5 | ) | Interest expense | $ | (5 | ) | $ | (5 | ) | ||||||||||||
Commodity | (1 | ) | (1 | ) | Gas purchased for resale | (2 | ) | (12 | ) | |||||||||||||||
Total | $ | 3 | $ | (6 | ) | $ | (7 | ) | $ | (17 | ) | |||||||||||||
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 | |||||||||||||||||||||||
Millions of dollars | Location | 2013 | 2012 | |||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | — | |||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) | |||||||||||||||||||
Offseting Assets [Table Text Block] | ' | |||||||||||||||||||||||
Information related to the Company's offsetting of derivative assets follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 124 | — | $ | 124 | $ | (3 | ) | — | $ | 121 | |||||||||||||
Commodity | 1 | — | 1 | — | — | 1 | ||||||||||||||||||
Energy Management | 10 | — | 10 | — | — | 10 | ||||||||||||||||||
Total | $ | 135 | — | $ | 135 | $ | (3 | ) | — | $ | 132 | |||||||||||||
Balance sheet location | Prepayments and other | $ | 89 | |||||||||||||||||||||
Other deferred debits and other assets | 46 | |||||||||||||||||||||||
Total | $ | 135 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||||
Commodity | 2 | — | 2 | — | — | 2 | ||||||||||||||||||
Energy Management | 13 | $ | (1 | ) | 12 | — | — | 12 | ||||||||||||||||
Total | $ | 88 | $ | (1 | ) | $ | 87 | $ | (17 | ) | — | $ | 70 | |||||||||||
Balance sheet location | Prepayments and other | $ | 50 | |||||||||||||||||||||
Other deferred debits and other assets | 37 | |||||||||||||||||||||||
Total | $ | 87 | ||||||||||||||||||||||
Offsetting Liabilities [Table Text Block] | ' | |||||||||||||||||||||||
Information related to the Company's offsetting of derivative liabilities follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 24 | — | $ | 24 | $ | (3 | ) | $ | (21 | ) | — | ||||||||||||
Commodity | 3 | — | 3 | — | (1 | ) | $ | 2 | ||||||||||||||||
Energy Management | 10 | — | 10 | — | (8 | ) | 2 | |||||||||||||||||
$ | 37 | — | $ | 37 | $ | (3 | ) | $ | (30 | ) | $ | 4 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 1 | |||||||||||||||||||||
Other current liabilities | 12 | |||||||||||||||||||||||
Other deferred credits and other liabilities | 24 | |||||||||||||||||||||||
Total | $ | 37 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (17 | ) | $ | (67 | ) | $ | 22 | |||||||||||
Commodity | 4 | — | 4 | — | — | 4 | ||||||||||||||||||
Energy Management | 13 | $ | (1 | ) | 12 | — | (11 | ) | 1 | |||||||||||||||
$ | 123 | $ | (1 | ) | $ | 122 | $ | (17 | ) | $ | (78 | ) | $ | 27 | ||||||||||
Balance sheet location | Other current liabilities | $ | 80 | |||||||||||||||||||||
Other deferred credits and other liabilities | 42 | |||||||||||||||||||||||
Total | $ | 122 | ||||||||||||||||||||||
SCEG | ' | |||||||||||||||||||||||
Derivative [Line Items] | ' | |||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | ' | |||||||||||||||||||||||
The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows: | ||||||||||||||||||||||||
Fair Values of Derivative Instruments | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 83 | Other current liabilities | $ | 2 | ||||||||||||||||||
Other deferred debits and other assets | 41 | Other deferred credits and other liabilities | 1 | |||||||||||||||||||||
Total | $ | 124 | $ | 3 | ||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Derivatives designated as hedging instruments | ||||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 66 | ||||||||||||||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 9 | |||||||||||||||||||||
Total | $ | 73 | $ | 75 | ||||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||||
Millions of dollars | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Interest rate | $ | 19 | $ | 23 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Interest rate | $ | 115 | $ | 51 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||||
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 | |||||||||||||||||||||||
Millions of dollars | Location | 2013 | 2012 | |||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | — | |||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) | |||||||||||||||||||
Offseting Assets [Table Text Block] | ' | |||||||||||||||||||||||
Information related to Consolidated SCE&G's derivative assets follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 124 | — | $ | 124 | $ | (3 | ) | — | $ | 121 | |||||||||||||
Balance Sheet Location | Prepayments and other | $ | 83 | |||||||||||||||||||||
Other deferred debits and other assets | 41 | |||||||||||||||||||||||
Total | $ | 124 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||||
Balance Sheet Location | Prepayments and other | $ | 42 | |||||||||||||||||||||
Other deferred debits and other assets | 31 | |||||||||||||||||||||||
Total | $ | 73 | ||||||||||||||||||||||
Offsetting Liabilities [Table Text Block] | ' | |||||||||||||||||||||||
Information related to Consolidated SCE&G's derivative liabilities follows: | ||||||||||||||||||||||||
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||||
As of September 30, 2013 | ||||||||||||||||||||||||
Interest rate | $ | 3 | — | $ | 3 | $ | (3 | ) | $ | — | $ | — | ||||||||||||
Balance Sheet Location | Other current liabilities | $ | 2 | |||||||||||||||||||||
Other deferred credits and other liabilities | 1 | |||||||||||||||||||||||
Total | $ | 3 | ||||||||||||||||||||||
As of December 31, 2012 | ||||||||||||||||||||||||
Interest rate | $ | 75 | — | $ | 75 | $ | (17 | ) | $ | (35 | ) | $ | 23 | |||||||||||
Balance Sheet Location | Other current liabilities | $ | 66 | |||||||||||||||||||||
Other deferred credits and other liabilities | 9 | |||||||||||||||||||||||
Total | $ | 75 | ||||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD1
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Table Text Block] | ' | ||||||||||||||||
Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | |||||||||||||||||
Fair Value Measurements Using | |||||||||||||||||
Quoted Prices in | |||||||||||||||||
Active Markets for | Significant Other | ||||||||||||||||
Identical Assets | Observable Inputs | ||||||||||||||||
Millions of dollars | (Level 1) | (Level 2) | |||||||||||||||
As of September 30, 2013 | |||||||||||||||||
Assets - | Available for sale securities | $ | 9 | — | |||||||||||||
Interest rate contracts | — | $ | 124 | ||||||||||||||
Commodity contracts | 1 | — | |||||||||||||||
Energy management contracts | — | 10 | |||||||||||||||
Liabilities - | Interest rate contracts | — | 24 | ||||||||||||||
Commodity contracts | — | 3 | |||||||||||||||
Energy management contracts | — | 13 | |||||||||||||||
As of December 31, 2012 | |||||||||||||||||
Assets - | Available for sale securities | $ | 6 | — | |||||||||||||
Interest rate contracts | — | $ | 73 | ||||||||||||||
Commodity contracts | 1 | 1 | |||||||||||||||
Energy management contracts | — | 13 | |||||||||||||||
Liabilities - | Interest rate contracts | — | 106 | ||||||||||||||
Commodity contracts | — | 4 | |||||||||||||||
Energy management contracts | 1 | 15 | |||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | ||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2013 and December 31, 2012 were as follows: | |||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,450.90 | $ | 5,936.70 | $ | 5,121.00 | $ | 6,115.00 | |||||||||
SCEG | ' | ||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Table Text Block] | ' | ||||||||||||||||
Fair value measurements based on significant other observable inputs (level 2) were as follows: | |||||||||||||||||
Fair Value Measurements Using Significant | |||||||||||||||||
Other Observable Inputs (Level 2) | |||||||||||||||||
Millions of dollars | 30-Sep-13 | 31-Dec-12 | |||||||||||||||
Assets - | Interest rate contracts | $ | 124 | $ | 73 | ||||||||||||
Liabilities - | Interest rate contracts | 3 | 75 | ||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | ||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at September 30, 2013 and December 31, 2012 were as follows: | |||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,056.40 | $ | 4,454.40 | $ | 3,722.00 | $ | 4,543.10 | |||||||||
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | ||||||||||||||||
: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Three months ended September 30, | |||||||||||||||||
Service cost | $ | 5.1 | $ | 5 | $ | 1.2 | $ | 1.1 | |||||||||
Interest cost | 9.5 | 10.9 | 2.8 | 2.9 | |||||||||||||
Expected return on assets | (15.1 | ) | (15.0 | ) | — | — | |||||||||||
Prior service cost amortization | 1.5 | 1.8 | 0.1 | 0.2 | |||||||||||||
Charge due to curtailment | 9.9 | — | — | — | |||||||||||||
Transition obligation amortization | — | — | — | 0.2 | |||||||||||||
Amortization of actuarial losses | 3.5 | 4.5 | 0.8 | — | |||||||||||||
Net periodic benefit cost | $ | 14.4 | $ | 7.2 | $ | 4.9 | $ | 4.4 | |||||||||
Nine months ended September 30, | |||||||||||||||||
Service cost | $ | 16.9 | $ | 14.7 | $ | 4.4 | $ | 3.6 | |||||||||
Interest cost | 28.4 | 32.2 | 8.3 | 8.9 | |||||||||||||
Expected return on assets | (45.8 | ) | (44.6 | ) | — | — | |||||||||||
Prior service cost amortization | 4.9 | 5.3 | 0.5 | 0.7 | |||||||||||||
Charge due to curtailment | 9.9 | — | — | — | |||||||||||||
Transition obligation amortization | — | — | 0.3 | 0.5 | |||||||||||||
Amortization of actuarial losses | 14.4 | 13.8 | 2.5 | 0.4 | |||||||||||||
Net periodic benefit cost | $ | 28.7 | $ | 21.4 | $ | 16 | $ | 14.1 | |||||||||
SCEG | ' | ||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | ||||||||||||||||
: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Three months ended September 30, | |||||||||||||||||
Service cost | $ | 4.1 | $ | 4.1 | $ | 1 | $ | 0.8 | |||||||||
Interest cost | 8 | 9.1 | 2.1 | 2.3 | |||||||||||||
Expected return on assets | (12.7 | ) | (12.6 | ) | — | — | |||||||||||
Prior service cost amortization | 1.3 | 1.6 | 0.1 | 0.1 | |||||||||||||
Charge due to curtailment | 8.4 | — | — | — | |||||||||||||
Amortization of actuarial losses | 3 | 3.7 | 0.7 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 12.1 | $ | 5.9 | $ | 3.9 | $ | 3.3 | |||||||||
Nine months ended September 30, | |||||||||||||||||
Service cost | $ | 13.7 | $ | 11.8 | $ | 3.5 | $ | 2.8 | |||||||||
Interest cost | 24 | 27.3 | 6.5 | 7 | |||||||||||||
Expected return on assets | (38.7 | ) | (37.8 | ) | — | — | |||||||||||
Prior service cost amortization | 4.1 | 4.5 | 0.4 | 0.5 | |||||||||||||
Charge due to curtailment | 8.4 | — | — | — | |||||||||||||
Amortization of actuarial losses | 12.2 | 11.7 | 2 | 0.3 | |||||||||||||
Net periodic benefit cost | $ | 23.7 | $ | 17.5 | $ | 12.4 | $ | 10.6 | |||||||||
SEGMENT_OF_BUSINESS_INFORMATIO1
SEGMENT OF BUSINESS INFORMATION (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | ||||||||||||||||
Millions of dollars | External | Intersegment | Operating | Net | |||||||||||||
Revenue | Revenue | Income | Income | ||||||||||||||
Three Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 704 | $ | 2 | $ | 257 | n/a | ||||||||||
Gas Distribution | 123 | — | (6 | ) | n/a | ||||||||||||
Retail Gas Marketing | 67 | — | n/a | $ | (2 | ) | |||||||||||
Energy Marketing | 152 | 44 | n/a | 1 | |||||||||||||
All Other | 11 | 95 | 8 | (3 | ) | ||||||||||||
Adjustments/Eliminations | (6 | ) | (141 | ) | (4 | ) | 135 | ||||||||||
Consolidated Total | $ | 1,051 | $ | — | $ | 255 | $ | 131 | |||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 1,898 | $ | 6 | $ | 588 | n/a | ||||||||||
Gas Distribution | 657 | — | 94 | n/a | |||||||||||||
Retail Gas Marketing | 325 | — | n/a | $ | 16 | ||||||||||||
Energy Marketing | 488 | 133 | n/a | 5 | |||||||||||||
All Other | 30 | 303 | 22 | (2 | ) | ||||||||||||
Adjustments/Eliminations | (20 | ) | (442 | ) | 34 | 349 | |||||||||||
Consolidated Total | $ | 3,378 | $ | — | $ | 738 | $ | 368 | |||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 714 | $ | 2 | $ | 243 | n/a | ||||||||||
Gas Distribution | 107 | — | (7 | ) | n/a | ||||||||||||
Retail Gas Marketing | 64 | — | n/a | $ | (5 | ) | |||||||||||
Energy Marketing | 151 | 35 | n/a | 1 | |||||||||||||
All Other | 11 | 100 | 6 | (3 | ) | ||||||||||||
Adjustments/Eliminations | (9 | ) | (137 | ) | (4 | ) | 129 | ||||||||||
Consolidated Total | $ | 1,038 | $ | — | $ | 238 | $ | 122 | |||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 1,851 | $ | 7 | $ | 534 | n/a | ||||||||||
Gas Distribution | 507 | — | 81 | n/a | |||||||||||||
Retail Gas Marketing | 288 | — | n/a | $ | 3 | ||||||||||||
Energy Marketing | 402 | 84 | n/a | 5 | |||||||||||||
All Other | 32 | 309 | 17 | (2 | ) | ||||||||||||
Adjustments/Eliminations | (26 | ) | (400 | ) | 15 | 309 | |||||||||||
Consolidated Total | $ | 3,054 | $ | — | $ | 647 | $ | 315 | |||||||||
September 30, | December 31, | ||||||||||||||||
Segment Assets | 2013 | 2012 | |||||||||||||||
Electric Operations | $ | 9,430 | $ | 8,989 | |||||||||||||
Gas Distribution | 2,286 | 2,292 | |||||||||||||||
Retail Gas Marketing | 131 | 153 | |||||||||||||||
Energy Marketing | 124 | 122 | |||||||||||||||
All Other | 1,287 | 1,415 | |||||||||||||||
Adjustments/Eliminations | 1,739 | 1,645 | |||||||||||||||
Consolidated Total | $ | 14,997 | $ | 14,616 | |||||||||||||
SCEG | ' | ||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | ||||||||||||||||
. | |||||||||||||||||
External | Operating | Earnings Available to | |||||||||||||||
Millions of dollars | Revenue | Income | Common Shareholder | ||||||||||||||
Three Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 706 | $ | 257 | n/a | ||||||||||||
Gas Distribution | 70 | (2 | ) | n/a | |||||||||||||
Adjustments/Eliminations | — | — | $ | 136 | |||||||||||||
Consolidated Total | $ | 776 | $ | 255 | $ | 136 | |||||||||||
Nine Months Ended September 30, 2013 | |||||||||||||||||
Electric Operations | $ | 1,903 | $ | 588 | n/a | ||||||||||||
Gas Distribution | 297 | 37 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 311 | |||||||||||||
Consolidated Total | $ | 2,200 | $ | 625 | $ | 311 | |||||||||||
Three Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 716 | $ | 244 | n/a | ||||||||||||
Gas Distribution | 61 | (3 | ) | n/a | |||||||||||||
Adjustments/Eliminations | — | — | $ | 129 | |||||||||||||
Consolidated Total | $ | 777 | $ | 241 | $ | 129 | |||||||||||
Nine Months Ended September 30, 2012 | |||||||||||||||||
Electric Operations | $ | 1,857 | $ | 534 | n/a | ||||||||||||
Gas Distribution | 244 | 27 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 272 | |||||||||||||
Consolidated Total | $ | 2,101 | $ | 561 | $ | 272 | |||||||||||
September 30, | December 31, | ||||||||||||||||
Segment Assets | 2013 | 2012 | |||||||||||||||
Electric Operations | $ | 9,430 | $ | 8,989 | |||||||||||||
Gas Distribution | 681 | 659 | |||||||||||||||
Adjustments/Eliminations | 2,583 | 2,456 | |||||||||||||||
Consolidated Total | $ | 12,694 | $ | 12,104 | |||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 |
SCEG | SCEG | SCEG | SCEG | Genco | ||||||
MW | MW | MW | MW | |||||||
Significant Accounting Policies | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of coal fired units to be retired | ' | ' | ' | ' | ' | ' | 2 | 6 | 6 | ' |
Power Generation Capacity Megawatts | ' | ' | ' | ' | ' | ' | ' | ' | ' | 605 |
Asset Management and Supply Service Agreements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent) | 47.00% | ' | 47.00% | ' | 44.00% | ' | ' | ' | ' | ' |
Natural gas inventory, carrying amount | $23.20 | ' | $23.20 | ' | $19.60 | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Net | $315 | ' | $315 | ' | $306 | ' | $68 | ' | $57 | $478 |
Power generation capacity six coal fired units | ' | ' | ' | ' | ' | ' | 730 | ' | ' | ' |
Power Capacity of Retired Unit | ' | ' | ' | ' | ' | ' | ' | ' | 90 | ' |
Power Capacity of unit to be retired | ' | ' | ' | ' | ' | 295 | ' | ' | ' | ' |
Earnings Per Share | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted Average Shares Outstanding - Basic | 140.1 | 131.4 | 138 | 130.8 | ' | ' | ' | ' | ' | ' |
Incremental Common Shares Attributable to Share-based Payment Arrangements and Equity Forward Agreements | 0 | 2.4 | 0.6 | 2.3 | ' | ' | ' | ' | ' | ' |
Weighted Average Number of Shares Outstanding, Diluted | 140.1 | 133.8 | 138.6 | 133.1 | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT2
RATE AND OTHER REGULATORY MATTERS (Details) (USD $) | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||||||||
Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | 1-May-15 | Dec. 31, 2012 | 15-May-14 | Oct. 01, 2013 | Mar. 31, 2013 | Jun. 30, 2012 | Mar. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | |
SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | PSNC Energy | PSNC Energy | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | |||
SCEG | SCEG | SCEG | SCEG | ||||||||||||||||||
Rate Matters [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | $1,333,000,000 | $1,464,000,000 | $1,377,000,000 | $1,259,000,000 | ' | ' | $1,377,000,000 | ' | ' | ' | ' | ' | $2,900,000 | $37,000,000 | $38,000,000 | $37,000,000 | $38,000,000 | $32,000,000 | $36,000,000 | $32,000,000 | $36,000,000 |
Amounts Recovered Through Electric Rates to offset Turbine Expenses | ' | ' | ' | 17,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Share in Approved Capital Costs | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Undercollected balance fuel | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of coal fired units to be retired | ' | ' | 6 | 2 | ' | ' | 6 | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | ' | ' | 4.23% | ' | 2.90% | ' | 2.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Allowable return on common equity (as a percent) | ' | ' | 10.25% | 11.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
historical average temperature | ' | ' | ' | ' | ' | ' | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | ' | ' | 19,600,000 | 16,900,000 | ' | ' | 19,600,000 | 10,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Asset Recovery Assessments | ' | ' | ' | ' | ' | '12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities Property Plant and Equipment Identifiable Capital Costs | ' | ' | ' | ' | ' | ' | 278,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capital Cost Related to New Federal Healthcare Etc | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities Additional Labor Expenses for Oversight of New Units | ' | ' | ' | ' | ' | ' | 132,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (decrease) in retail electric rate requested under the BLRA | ' | ' | ' | 67.2 | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | ' | 2.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities changes in Retail Natural Gas Rates Requested and Approved under RSA | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basis for rate calculation | ' | ' | ' | '12-month rolling average | ' | ' | ' | ' | ' | ' | ' | '12 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset Amortization Period | '30 | ' | ' | '30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 | ' | ' | ' |
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | ' | ' | 12 | 12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
MPG enviromental remediatio | '26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | ' | $63,000,000 | ' | ' | ' | $63,000,000 | ' | $14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT3
RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) | 9 Months Ended | 9 Months Ended | 24 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Jul. 31, 2012 | 15-May-14 | Oct. 01, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 |
SCEG | SCEG | SCEG | SCEG | SCEG | Deferred Income Tax Charges [Member] | Deferred Income Tax Charges [Member] | Deferred Income Tax Charges [Member] | Deferred Income Tax Charges [Member] | Regulatory Clause Revenues, under-recovered [Member] | Regulatory Clause Revenues, under-recovered [Member] | Regulatory Clause Revenues, under-recovered [Member] | Regulatory Clause Revenues, under-recovered [Member] | Environmental Restoration Costs [Member] | Environmental Restoration Costs [Member] | Environmental Restoration Costs [Member] | Environmental Restoration Costs [Member] | Asset Retirement Obligation Costs [Member] | Asset Retirement Obligation Costs [Member] | Asset Retirement Obligation Costs [Member] | Asset Retirement Obligation Costs [Member] | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Planned major maintenance [Member] | Planned major maintenance [Member] | Planned major maintenance [Member] | Planned major maintenance [Member] | Deferred Losses On Interest Rate Derivatives [Member] | Deferred Losses On Interest Rate Derivatives [Member] | Deferred Losses On Interest Rate Derivatives [Member] | Deferred Losses On Interest Rate Derivatives [Member] | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Deferred Pollution Control Costs | unrecovered plant [Member] | unrecovered plant [Member] | unrecovered plant [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | |||
SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | ||||||||||||||||||||||||||||||
Regulatory Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | ' | ' | $16.90 | ' | $10.30 | ' | $19.60 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
MPG enviromental remediatio | '26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset, Amortization Period | '30 | ' | '30 | ' | ' | ' | ' | '70 | ' | '70 | ' | ' | ' | ' | ' | ' | ' | ' | ' | '90 | ' | ' | ' | '20 | ' | ' | ' | ' | ' | '14 | '12 | '30 | ' | ' | ' | ' | '30 | ' | '30 | ' | ' | ' | ' | ' | '14 | ' | ' | '30 | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | ' | ' | ' | ' | 14 | 63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | 1,333 | 1,464 | 1,259 | ' | ' | ' | 1,377 | 254 | 254 | 248 | 248 | 52 | 66 | 52 | 66 | 42 | 44 | 37 | 39 | 359 | 319 | 342 | 304 | 32 | 36 | 32 | 36 | 319 | 460 | 284 | ' | 405 | 0 | 6 | 0 | 6 | 126 | 151 | 126 | 151 | 37 | 38 | 37 | 38 | 19 | 20 | 19 | 93 | 70 | 82 | 64 |
Amounts Recovered through Electric Rates to offset Turbine Expense | ' | ' | ' | $18.40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT4
RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | 24 Months Ended | |||||
Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Jul. 31, 2012 | 15-May-14 | Oct. 01, 2013 | Jun. 30, 2012 | |
MW | |||||||||
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
MPG enviromental remediatio | ' | ' | '26 | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | $882,000,000 | $1,007,000,000 | ' | $882,000,000 | ' | ' | ' | ' |
Amount allowed to be recovered through electric rates to offset incremental storm damage costs | ' | ' | 0 | ' | ' | ' | ' | ' | ' |
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates | ' | ' | 2.5 | ' | ' | ' | ' | ' | ' |
Accrual period of nuclear refueling charges in months | ' | ' | '18 | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset Amortization Period | ' | ' | '30 | ' | ' | ' | ' | ' | ' |
Deferred Income Tax Charges [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 21,000,000 | 19,000,000 | ' | 21,000,000 | ' | ' | ' | ' |
Asset Retirement Obligation Costs [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 692,000,000 | 718,000,000 | ' | 692,000,000 | ' | ' | ' | ' |
Storm damage reserve | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 27,000,000 | 27,000,000 | ' | 27,000,000 | ' | ' | ' | ' |
Monetization bankruptcy claim [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 32,000,000 | 30,000,000 | ' | 32,000,000 | ' | ' | ' | ' |
Deferred gains on interest rate derivatives | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 110,000,000 | 203,000,000 | ' | 110,000,000 | ' | ' | ' | ' |
Planned major maintenance [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory liabilities | ' | 0 | 10,000,000 | ' | 0 | ' | ' | ' | ' |
SCEG | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Undercollected balance fuel | ' | ' | ' | ' | ' | ' | ' | ' | 80,600,000 |
Public Utilities Property Plant and Equipment Identifiable Capital Costs | ' | ' | ' | ' | 278,000,000 | ' | ' | ' | ' |
Capital Cost Related to New Federal Healthcare Etc | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | ' | 4.23% | ' | 2.90% | 2.30% | ' | ' | ' | ' |
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | ' | 10.25% | 11.00% | ' | ' | ' | ' | ' | ' |
historical average temperature | ' | ' | ' | ' | 15 | ' | ' | ' | ' |
Power generation capacity six coal fired units | ' | ' | 730 | ' | ' | ' | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | ' | 19,600,000 | 16,900,000 | ' | 19,600,000 | ' | 10,300,000 | ' | ' |
Regulatory liabilities | ' | 665,000,000 | 781,000,000 | ' | 665,000,000 | ' | ' | ' | ' |
Amount allowed to be recovered through electric rates to offset incremental storm damage costs | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' |
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates | ' | ' | 2,500,000 | ' | ' | ' | ' | ' | ' |
Accrual period of nuclear refueling charges in months | '18 | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset Amortization Period | ' | ' | '30 | ' | ' | ' | ' | ' | ' |
Amounts Recovered through Electric Rates to offset Turbine Expense | ' | ' | ' | ' | ' | 18,400,000 | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | 63,000,000 | ' | ' | 63,000,000 | ' | ' | 14,000,000 | ' |
Share in Approved Capital Costs | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' |
Public Utilities Additional Labor Expenses for Oversight of New Units | ' | ' | ' | ' | $132,000,000 | ' | ' | ' | ' |
COMMON_EQUITY_Details
COMMON EQUITY (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2011 |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Defined Benefit Plan, Other Information | ' | ' | ' | ' | 'not significant | ' | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | ($2) | ' | ($3) | ($7) | ($17) | ' | ' |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax | -1 | ' | 0 | -1 | -1 | ' | ' |
OtherComprehensiveIncomeLossTotalReclassificationAdjustmentIncludedInNetIncomeNetOFTax | -3 | ' | -3 | -8 | -18 | ' | ' |
Common Stock, Shares Authorized | 200,000,000 | ' | ' | 200,000,000 | ' | 200,000,000 | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Common Shareholders' Equity | 4,598 | ' | ' | 4,598 | ' | 4,154 | ' |
Forward Contract Indexed to Issuer's Equity, Indexed Shares | ' | 6,600,000 | ' | ' | ' | ' | ' |
Dividends declared | ' | ' | ' | -212 | -194 | ' | ' |
Total Comprehensive Income (Loss) | 137 | ' | 126 | 383 | 327 | ' | ' |
Common Stock, Shares, Outstanding | 140,200,000 | ' | ' | 140,200,000 | ' | 132,000,000 | ' |
Proceeds from exercise of equity forward sales agreements | ' | 196.2 | ' | ' | ' | ' | ' |
Common stock issued | ' | ' | ' | 273 | 73 | ' | ' |
Common equity | 4,598 | ' | 4,095 | 4,598 | 4,095 | 4,154 | 3,889 |
SCEG | ' | ' | ' | ' | ' | ' | ' |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Common Stock, Shares Authorized | 50,000,000 | ' | ' | 50,000,000 | ' | 50,000,000 | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Stockholders' Equity Attributable to Noncontrolling Interest | 117 | ' | ' | 117 | ' | 114 | ' |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,453 | ' | 3,976 | 4,453 | 3,976 | 4,043 | 3,773 |
Proceeds from Contributions from Parent | ' | ' | ' | 285 | 84 | ' | ' |
Dividends | ' | ' | ' | -195 | -162 | ' | ' |
Total Comprehensive Income (Loss) | ' | ' | ' | 320 | 281 | ' | ' |
Common Stock, Shares, Outstanding | 40,300,000 | ' | ' | 40,300,000 | ' | 40,300,000 | ' |
Preferred Stock, Shares Authorized | 20,000,000 | ' | ' | 20,000,000 | ' | 20,000,000 | ' |
Preferred Stock, Shares Outstanding | 1,000 | ' | ' | 1,000 | ' | 1,000 | ' |
Common equity | 4,336 | ' | ' | 4,336 | ' | 3,929 | ' |
SCEG excluding VIEs [Domain] | ' | ' | ' | ' | ' | ' | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Contributions from Parent | ' | ' | ' | 285 | 84 | ' | ' |
Dividends | ' | ' | ' | -190 | -157 | ' | ' |
Common Shareholders' Equity | 4,336 | ' | 3,864 | 4,336 | 3,864 | ' | 3,665 |
Total Comprehensive Income (Loss) | ' | ' | ' | 312 | 272 | ' | ' |
SCEG excluding VIEs [Member] | ' | ' | ' | ' | ' | ' | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Common Shareholders' Equity | ' | ' | ' | ' | ' | 3,929 | ' |
Genco | ' | ' | ' | ' | ' | ' | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' | ' | ' | ' |
Stockholders' Equity Attributable to Noncontrolling Interest | 117 | ' | 112 | 117 | 112 | 114 | 108 |
Proceeds from Contributions from Parent | ' | ' | ' | 0 | 0 | ' | ' |
Dividends | ' | ' | ' | -5 | -5 | ' | ' |
Total Comprehensive Income (Loss) | ' | ' | ' | 8 | 9 | ' | ' |
Interest Rate Contract | ' | ' | ' | ' | ' | ' | ' |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | -2 | ' | -2 | -5 | -5 | ' | ' |
Commodity Contract | ' | ' | ' | ' | ' | ' | ' |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | $0 | ' | ($1) | ($2) | ($12) | ' | ' |
LONGTERM_AND_SHORTTERM_DEBT_De
LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | 1-May-13 | Dec. 31, 2012 | Oct. 15, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Mar. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Jan. 31, 2013 | Mar. 31, 2013 | Jan. 31, 2013 | Mar. 31, 2013 | Jan. 31, 2013 |
In Millions, unless otherwise specified | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCEG | SCEG | SCEG | Fuel Company | Fuel Company | Bonds [Member] | Bonds [Member] | Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary | Industrial Revenue Bonds issued by JEDA proceeds of which were loaned to subsidiary | Industrial and Pollution Control Bonds [Member] | Industrial and Pollution Control Bonds [Member] | ||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of First Mortgage Bond | ' | ' | ' | ' | ' | ' | ' | $400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Increase, Additional Borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39.5 | ' | 14.7 | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.60% | 7.13% | 3.63% | 4.00% | ' | 5.20% |
Debt Instrument, Decrease, Repayments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56.9 | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,800 | ' | 1,400 | 200 | 1,400 | 1,400 | 1,200 | ' | ' | 1,200 | 500 | 500 | ' | ' | ' | ' | ' | ' |
Commercial Paper | ' | ' | 310 | ' | 449 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt, Weighted Average Interest Rate | ' | ' | 0.30% | ' | 0.42% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount | ' | ' | 0.3 | ' | 0.3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | 1,090 | ' | 951 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Debt, Current Maturities | 19 | 172 | ' | ' | ' | ' | ' | 14 | 165 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long- Term Debt Noncurrent including Derivative Liabilities | 5,431 | 4,949 | ' | ' | ' | ' | ' | 4,043 | 3,557 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | $67.80 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
LONGTERM_AND_SHORTTERM_DEBT_De1
LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Oct. 15, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Oct. 15, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | 1-May-13 | Dec. 31, 2012 | Oct. 15, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Mar. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Jan. 31, 2013 |
In Millions, unless otherwise specified | Wells Fargo Bank, National Association (Member) | Bank of America, N.A. (Member) | Morgan Stanly Bank, N.A. (Member) | Branch Banking and Trust Company (Member) | Credit Suisse AG, Cayman Islands Branch (Member) | JPMorgan Chase Bank, N.A. (Member) | Mizuho Corporate Bank, Ltd (Member) | TD Bank, N.A. (Member) | UBS Loan Finance LLC (Member) | Deutsche Bank AG New York Branch [Member] [Member] | Union Bank, N.A. (Member) | US Bank National Association (Member) | Two other banks [Domain] | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | Parent Company [Member] | Parent Company [Member] | Parent Company [Member] | Retail Gas Marketing and Energy Marketing | Retail Gas Marketing and Energy Marketing | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | Fuel Company | Fuel Company | PSNC Energy | PSNC Energy | PSNC Energy | Bonds [Member] | Bonds [Member] | |||
Wells Fargo Bank, National Association (Member) | Bank of America, N.A. (Member) | Morgan Stanly Bank, N.A. (Member) | Branch Banking and Trust Company (Member) | Credit Suisse AG, Cayman Islands Branch (Member) | JPMorgan Chase Bank, N.A. (Member) | Mizuho Corporate Bank, Ltd (Member) | TD Bank, N.A. (Member) | UBS Loan Finance LLC (Member) | Deutsche Bank AG New York Branch [Member] [Member] | Union Bank, N.A. (Member) | US Bank National Association (Member) | Two other banks [Domain] | Wells Fargo Bank, National Association (Member) | Branch Banking and Trust Company (Member) | Credit Suisse AG, Cayman Islands Branch (Member) | ||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Issuance of First Mortgage Bond | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $400 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Repayments of First Mortgage Bond | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Due to Affiliate, Current | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 122 | 124 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.2 | 13.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.60% | 7.13% |
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 67.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Lines of credit: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,800 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300 | 300 | 300 | ' | ' | 1,400 | 200 | 1,400 | 1,400 | 1,200 | ' | ' | ' | 500 | 500 | 100 | 100 | 100 | ' | ' |
Commercial Paper | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 68 | 142 | ' | ' | ' | 310 | ' | 449 | ' | ' | ' | ' | ' | ' | ' | 0 | 32 | ' | ' | ' |
Commercial paper, weighted average interest rate (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.43% | 0.58% | ' | ' | ' | 0.30% | ' | 0.42% | ' | ' | ' | ' | ' | ' | ' | 0.00% | 0.44% | ' | ' | ' |
Letters of credit supported by LOC | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | ' | ' | ' | 0.3 | ' | 0.3 | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 229 | 155 | ' | ' | ' | 1,090 | ' | 951 | ' | ' | ' | ' | ' | ' | ' | 100 | 68 | ' | ' | ' |
LOC advances | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' |
3 year credit agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | ' | ' | ' | 10.70% | 10.70% | 10.70% | 8.90% | 8.90% | 8.90% | 8.90% | 8.90% | 8.90% | 6.30% | 6.30% | 6.30% | 6.00% | ' | ' | ' | ' | 10.70% | 10.70% | 10.70% | 8.90% | 8.90% | 8.90% | 8.90% | 8.90% | 8.90% | 6.30% | 6.30% | 6.30% | 6.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.70% | 6.30% | 8.90% | ' | ' | ' | ' | ' | ' | ' |
Number of other banks (in entities) | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction, Due from (to) Related Party, Current | $39.60 | $49.40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
INCOME_TAXES_Details
INCOME TAXES (Details) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ' | ' | ' |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 6.90% | 5.00% | 6.00% |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | MMBTU | MMBTU | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 53,213,558 | [1] | 48,300,275 | [2] |
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments | 674,308 | 3,500,000 | ||
Interest Rate Derivatives [Abstract] | ' | ' | ||
Derivative, Notional Amount | $663.80 | $1,100 | ||
Gas Distribution | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 8,820,000 | 5,170,000 | ||
Retail Gas Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 10,407,000 | 6,490,000 | ||
Energy Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 33,986,558 | [1] | 36,640,275 | [2] |
Commodity Contract | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 22,305,500 | 16,537,000 | ||
Commodity Contract | Gas Distribution | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 8,820,000 | 5,170,000 | ||
Commodity Contract | Retail Gas Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 10,407,000 | 6,490,000 | ||
Commodity Contract | Energy Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 3,078,500 | 4,877,000 | ||
Energy Management Contracts [Member] | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 30,908,058 | 31,763,275 | ||
Energy Management Contracts [Member] | Energy Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 30,908,058 | 31,763,275 | ||
SCEG | ' | ' | ||
Interest Rate Derivatives [Abstract] | ' | ' | ||
Derivative, Notional Amount | $571.40 | $971.40 | ||
[1] | (a) Includes an aggregate 674,308 MMBTU related to basis swap contracts in Energy Marketing. | |||
[2] | (b) Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing. |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | ($3,000,000) | ' | ($3,000,000) | ' | ($17,000,000) |
Asset Derivatives Fair Value | 135,000,000 | ' | 135,000,000 | ' | 88,000,000 |
Derivative Asset | 135,000,000 | ' | 135,000,000 | ' | 87,000,000 |
Derivative Asset, Fair Value, Gross Liability | ' | ' | ' | ' | -1,000,000 |
Liability Derivatives Fair Value | 37,000,000 | ' | 37,000,000 | ' | 123,000,000 |
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position | 0 | ' | 0 | ' | -1,000,000 |
Derivative Liability | 37,000,000 | ' | 37,000,000 | ' | 122,000,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -3,000,000 | ' | -3,000,000 | ' | -17,000,000 |
Derivative Liability, Fair Value of Collateral | 30,000,000 | ' | 30,000,000 | ' | 78,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 132,000,000 | ' | 132,000,000 | ' | 70,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 4,000,000 | ' | 4,000,000 | ' | 27,000,000 |
Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset | 89,000,000 | ' | 89,000,000 | ' | 50,000,000 |
Derivative Liability | 1,000,000 | ' | 1,000,000 | ' | ' |
Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Liability | 12,000,000 | ' | 12,000,000 | ' | 80,000,000 |
Other deferred credits and other liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Liability | 24,000,000 | ' | 24,000,000 | ' | 42,000,000 |
Other Deferred Debits and Other Assets [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset | 46,000,000 | ' | 46,000,000 | ' | 37,000,000 |
Derivatives designated as hedging instruments | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 124,000,000 | ' | 124,000,000 | ' | 74,000,000 |
Liability Derivatives Fair Value | 27,000,000 | ' | 27,000,000 | ' | 110,000,000 |
Derivatives not designated as hedging instruments | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 11,000,000 | ' | 11,000,000 | ' | 14,000,000 |
Liability Derivatives Fair Value | 10,000,000 | ' | 10,000,000 | ' | 13,000,000 |
Energy Management Contracts [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 10,000,000 | ' | 10,000,000 | ' | 13,000,000 |
Derivative Asset | 10,000,000 | ' | 10,000,000 | ' | 12,000,000 |
Derivative Asset, Fair Value, Gross Liability | ' | ' | ' | ' | -1,000,000 |
Liability Derivatives Fair Value | 10,000,000 | ' | 10,000,000 | ' | 13,000,000 |
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position | 0 | ' | 0 | ' | -1,000,000 |
Derivative Liability | 10,000,000 | ' | 10,000,000 | ' | 12,000,000 |
Derivative Liability, Fair Value of Collateral | -8,000,000 | ' | -8,000,000 | ' | -11,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 10,000,000 | ' | 10,000,000 | ' | 12,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 2,000,000 | ' | 2,000,000 | ' | 1,000,000 |
Interest Rate Contract | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -1,000,000 | -1,000,000 | -2,000,000 | -2,000,000 | ' |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -3,000,000 | ' | -3,000,000 | ' | -17,000,000 |
Asset Derivatives Fair Value | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Derivative Asset | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Liability Derivatives Fair Value | 24,000,000 | ' | 24,000,000 | ' | 106,000,000 |
Derivative Liability | 24,000,000 | ' | 24,000,000 | ' | 106,000,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -3,000,000 | ' | -3,000,000 | ' | -17,000,000 |
Derivative Liability, Fair Value of Collateral | -21,000,000 | ' | -21,000,000 | ' | -67,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 121,000,000 | ' | 121,000,000 | ' | 56,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 0 | ' | 0 | ' | 22,000,000 |
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 83,000,000 | ' | 83,000,000 | ' | 42,000,000 |
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 5,000,000 | ' | 5,000,000 | ' | 70,000,000 |
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 19,000,000 | ' | 19,000,000 | ' | 36,000,000 |
Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 41,000,000 | ' | 41,000,000 | ' | 31,000,000 |
Commodity Contract | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 1,000,000 | ' | 1,000,000 | ' | 2,000,000 |
Derivative Asset | 1,000,000 | ' | 1,000,000 | ' | 2,000,000 |
Liability Derivatives Fair Value | 3,000,000 | ' | 3,000,000 | ' | 4,000,000 |
Derivative Liability | 3,000,000 | ' | 3,000,000 | ' | 4,000,000 |
Derivative Liability, Fair Value of Collateral | -1,000,000 | ' | -1,000,000 | ' | ' |
Net Fair Value Derivative Asset offset against Collateral | 1,000,000 | ' | 1,000,000 | ' | 2,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 2,000,000 | ' | 2,000,000 | ' | 4,000,000 |
Commodity Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | ' | ' | ' | ' | 1,000,000 |
Commodity Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 3,000,000 | ' | 3,000,000 | ' | 4,000,000 |
Commodity Contract | Derivatives not designated as hedging instruments | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 1,000,000 | ' | 1,000,000 | ' | 1,000,000 |
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 5,000,000 | ' | 5,000,000 | ' | 7,000,000 |
Liability Derivatives Fair Value | 1,000,000 | ' | 1,000,000 | ' | 1,000,000 |
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 4,000,000 | ' | 4,000,000 | ' | 6,000,000 |
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other deferred credits and other liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 5,000,000 | ' | 5,000,000 | ' | ' |
Other Energy Management Contract [Member] | Derivatives not designated as hedging instruments | Other Deferred Debits and Other Assets [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 5,000,000 | ' | 5,000,000 | ' | 6,000,000 |
Liability Derivatives Fair Value | ' | ' | ' | ' | 6,000,000 |
SCEG | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Derivative Liability | 3,000,000 | ' | 3,000,000 | ' | 75,000,000 |
SCEG | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset | 83,000,000 | ' | 83,000,000 | ' | 42,000,000 |
SCEG | Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Liability | 2,000,000 | ' | 2,000,000 | ' | 66,000,000 |
SCEG | Other deferred credits and other liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Liability | 1,000,000 | ' | 1,000,000 | ' | 9,000,000 |
SCEG | Other Deferred Debits and Other Assets [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Asset | 41,000,000 | ' | 41,000,000 | ' | 31,000,000 |
SCEG | Derivatives designated as hedging instruments | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Liability Derivatives Fair Value | 3,000,000 | ' | 3,000,000 | ' | 75,000,000 |
SCEG | Interest Rate Contract | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -1,000,000 | -1,000,000 | -2,000,000 | -2,000,000 | ' |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -3,000,000 | ' | -3,000,000 | ' | -17,000,000 |
Asset Derivatives Fair Value | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Derivative Asset | 124,000,000 | ' | 124,000,000 | ' | 73,000,000 |
Liability Derivatives Fair Value | 3,000,000 | ' | 3,000,000 | ' | 75,000,000 |
Derivative Liability | 3,000,000 | ' | 3,000,000 | ' | 75,000,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -3,000,000 | ' | -3,000,000 | ' | -17,000,000 |
Derivative Liability, Fair Value of Collateral | 0 | ' | 0 | ' | 35,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 121,000,000 | ' | 121,000,000 | ' | 56,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 0 | ' | 0 | ' | 23,000,000 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | 83,000,000 | ' | 83,000,000 | ' | 42,000,000 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 2,000,000 | ' | 2,000,000 | ' | 66,000,000 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Liability Derivatives Fair Value | 1,000,000 | ' | 1,000,000 | ' | 9,000,000 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member] | ' | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' | ' |
Asset Derivatives Fair Value | $41,000,000 | ' | $41,000,000 | ' | $31,000,000 |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |
Gain (Loss) on Derivatives | ' | ' | ' | ' | ' |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | 'insignificant | 'insignificant | 'insignificant | 'insignificant | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax | ($1,000,000) | $1,000,000 | $3,000,000 | ($6,000,000) | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | -2,000,000 | -3,000,000 | -7,000,000 | -17,000,000 | ' |
Derivative, Credit Risk Related Contingent Features [Abstract] | ' | ' | ' | ' | ' |
Collateral Already Posted, Aggregate Fair Value | 35,400,000 | ' | 35,400,000 | ' | 78,300,000 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | ' | ' | ' | ' | 26,200,000 |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 35,300,000 | ' | 35,300,000 | ' | 104,500,000 |
Cashcollateralrequestedfromcounterparty | 78,600,000 | ' | 78,600,000 | ' | 32,100,000 |
Derivative, net asset position | 78,600,000 | ' | 78,600,000 | ' | 32,100,000 |
LetterofCreditAvailableCommodityDerivatives,assetposition | 9,000,000 | ' | 9,000,000 | ' | 10,000,000 |
Commodity Derivative, net asset position | 10,000,000 | ' | 10,000,000 | ' | 13,000,000 |
Interest Rate Contract | ' | ' | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | ' | ' | 6,200,000 | ' | ' |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | 19,000,000 | 23,000,000 | 115,000,000 | 51,000,000 | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -1,000,000 | -1,000,000 | -2,000,000 | -2,000,000 | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax | 0 | -1,000,000 | 4,000,000 | -5,000,000 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | -2,000,000 | -2,000,000 | -5,000,000 | -5,000,000 | ' |
Commodity Contract | ' | ' | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | ' | ' | 2,000,000 | ' | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax | 1,000,000 | -2,000,000 | 1,000,000 | 1,000,000 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | 0 | -1,000,000 | -2,000,000 | -12,000,000 | ' |
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale | 0 | 0 | 0 | -1,000,000 | ' |
SCEG | ' | ' | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' | ' | ' |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | 'insignificant | 'insignificant | 'insignificant | 'insignificant | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' | ' | ' |
Derivatives not designated as hedging instruments - gain (loss) recognized in income, classified in gas purchased for resale | 0 | 0 | 0 | -1,000,000 | ' |
Derivative, Credit Risk Related Contingent Features [Abstract] | ' | ' | ' | ' | ' |
Collateral Already Posted, Aggregate Fair Value | 3,300,000 | ' | 3,300,000 | ' | 35,200,000 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | ' | ' | ' | ' | 22,700,000 |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 2,600,000 | ' | 2,600,000 | ' | 57,900,000 |
Cashcollateralrequestedfromcounterparty | 78,600,000 | ' | 78,600,000 | ' | 32,100,000 |
Derivative, net asset position | 78,600,000 | ' | 78,600,000 | ' | 32,100,000 |
SCEG | Interest Rate Contract | ' | ' | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' | ' | ' |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | 19,000,000 | 23,000,000 | 115,000,000 | 51,000,000 | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | ($1,000,000) | ($1,000,000) | ($2,000,000) | ($2,000,000) | ' |
FAIR_VALUE_MEASUREMENTS_INCLUD2
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | $135,000,000 | $87,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 37,000,000 | 122,000,000 |
Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 124,000,000 | 73,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 24,000,000 | 106,000,000 |
Commodity Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 1,000,000 | 2,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 3,000,000 | 4,000,000 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Available-for-sale Securities | 9,000,000 | 6,000,000 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 1,000,000 | 1,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Other energy management contracts | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 0 | 0 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 0 | 1,000,000 |
Fair Value, Inputs, Level 2 [Member] | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Available-for-sale Securities | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 124,000,000 | 73,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 24,000,000 | 106,000,000 |
Fair Value, Inputs, Level 2 [Member] | Commodity Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 0 | 1,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 3,000,000 | 4,000,000 |
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 10,000,000 | 13,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 13,000,000 | 15,000,000 |
SCEG | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 124,000,000 | 73,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 3,000,000 | 75,000,000 |
SCEG | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 124,000,000 | 73,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 3,000,000 | 75,000,000 |
SCEG | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 124 | 73 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | $3 | $75 |
FAIR_VALUE_MEASUREMENTS_INCLUD3
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Carrying Amount | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | $5,450.90 | $5,121 |
Estimated Fair Value | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | 5,936.70 | 6,115 |
SCEG | Carrying Amount | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | 4,056.40 | 3,722 |
SCEG | Estimated Fair Value | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | $4,454.40 | $4,543.10 |
EMPLOYEE_BENEFIT_PLANS_Details
EMPLOYEE BENEFIT PLANS (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Pension and Other Postretirement Benefit Plans | ' | ' | ' | ' |
Pension Contributions | ' | ' | 'No | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Defined Benefit Plan, Curtailments | $9.90 | ' | $9.90 | ' |
Pension curtailment deferred in reg asset | 6.3 | ' | ' | ' |
Increase (Decrease) in Pension Plan Obligations | 128 | ' | ' | ' |
Pension Benefits | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Service cost | 5.1 | 5 | 16.9 | 14.7 |
Interest cost | 9.5 | 10.9 | 28.4 | 32.2 |
Expected return on assets | -15.1 | -15 | -45.8 | -44.6 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 1.5 | 1.8 | 4.9 | 5.3 |
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 0 | 0 | 0 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.5 | 4.5 | 14.4 | 13.8 |
Defined Benefit Plan, Net Periodic Benefit Cost | 14.4 | 7.2 | 28.7 | 21.4 |
Other Postretirement Benefits | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Service cost | 1.2 | 1.1 | 4.4 | 3.6 |
Interest cost | 2.8 | 2.9 | 8.3 | 8.9 |
Expected return on assets | 0 | 0 | 0 | 0 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.1 | 0.2 | 0.5 | 0.7 |
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | 0 | 0.2 | 0.3 | 0.5 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.8 | 0 | 2.5 | 0.4 |
Defined Benefit Plan, Net Periodic Benefit Cost | 4.9 | 4.4 | 16 | 14.1 |
SCEG | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Defined Benefit Plan, Curtailments | 8.4 | ' | 8.4 | ' |
Pension Costs Related to Retail Electric Operations and Natural Gas Operations Deferred as Regulatory Assets | 1.2 | 4 | 2.4 | 11.4 |
Pension curtailment deferred in reg asset | 5.4 | ' | ' | ' |
Increase (Decrease) in Pension Plan Obligations | 108 | ' | ' | ' |
SCEG | Pension Benefits | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Service cost | 4.1 | 4.1 | 13.7 | 11.8 |
Interest cost | 8 | 9.1 | 24 | 27.3 |
Expected return on assets | -12.7 | -12.6 | -38.7 | -37.8 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 1.3 | 1.6 | 4.1 | 4.5 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3 | 3.7 | 12.2 | 11.7 |
Defined Benefit Plan, Net Periodic Benefit Cost | 12.1 | 5.9 | 23.7 | 17.5 |
SCEG | Other Postretirement Benefits | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' |
Service cost | 1 | 0.8 | 3.5 | 2.8 |
Interest cost | 2.1 | 2.3 | 6.5 | 7 |
Expected return on assets | 0 | 0 | 0 | 0 |
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.1 | 0.1 | 0.4 | 0.5 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.7 | 0.1 | 2 | 0.3 |
Defined Benefit Plan, Net Periodic Benefit Cost | $3.90 | $3.30 | $12.40 | $10.60 |
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended |
Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2005 | |
SCEG | ' | ' | ' |
Nuclear Insurance | ' | ' | ' |
Federal Limit on Public Liability Claims from Nuclear Incident Approximate | ' | $13,600,000,000 | ' |
Maximum Insurance Coverage for each Nuclear Plant by ANI | 375,000,000 | 375,000,000 | ' |
Maximum liability assessment per reactor for each nuclear incident | 84,800,000 | 127,300,000 | ' |
Maximum Federal Limit on Public Liability Claims Per Incident for Each Year | ' | 12,600,000 | ' |
Maximum yearly assessment per reactor | ' | 18,900,000 | ' |
Inflation adjustment period for nuclear insurance | ' | 5 | ' |
Maximum retrospective insurance premium per nuclear incident | ' | 40,600,000 | ' |
Maximum amount of coverage to nuclear facility for property damage and outage costs | 2,750,000,000 | 2,750,000,000 | ' |
Maximum amount of coverage for accidental property damage | 500,000,000 | 500,000,000 | ' |
Maximum loss covered by insurance for a single incident | 2,750,000,000 | 2,750,000,000 | ' |
Environmental | ' | ' | ' |
Number of MGP decommissioned sites that contain residues of byproduct chemicals | ' | 4 | ' |
Site Contingency MGP Estimated Environmental Remediation Costs | ' | 21,200,000 | ' |
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets | 37,100,000 | 37,100,000 | ' |
Nuclear Generation | ' | ' | ' |
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site | ' | 5,700,000,000 | ' |
Number of states required to reduce emissions to attain mandated levels | ' | ' | 28 |
Estimated Delay costs related to New Units | ' | 200,000,000 | ' |
Est Delay cost for new unit | ' | $200,000,000 | ' |
PSNC Energy | ' | ' | ' |
Environmental | ' | ' | ' |
Number of MGP sites requiring cleanup | ' | 5 | ' |
SEGMENT_OF_BUSINESS_INFORMATIO2
SEGMENT OF BUSINESS INFORMATION (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | $704 | $714 | $1,898 | $1,851 | ' |
Intersegment Revenue | 0 | 0 | ' | ' | ' |
Operating Income | 255 | 238 | 738 | 647 | ' |
Regulated Operating Revenue, Gas | 128 | 109 | 667 | 513 | ' |
Regulated and Unregulated Operating Revenue | 1,051 | 1,038 | 3,378 | 3,054 | ' |
Income Available to Common Shareholders of SCANA | 131 | 122 | 368 | 315 | ' |
Segment Assets | 14,997 | ' | 14,997 | ' | 14,616 |
Electric Operations | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | 704 | 714 | 1,898 | 1,851 | ' |
Intersegment Revenue | 2 | 2 | 6 | 7 | ' |
Operating Income | 257 | 243 | 588 | 534 | ' |
Segment Assets | 9,430 | ' | 9,430 | ' | 8,989 |
Gas Distribution | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Intersegment Revenue | 0 | 0 | 0 | 0 | ' |
Operating Income | -6 | -7 | 94 | 81 | ' |
Regulated and Unregulated Operating Revenue | 123 | 107 | 657 | 507 | ' |
Segment Assets | 2,286 | ' | 2,286 | ' | 2,292 |
Retail Gas Marketing | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Intersegment Revenue | 0 | 0 | 0 | 0 | ' |
Regulated and Unregulated Operating Revenue | 67 | 64 | 325 | 288 | ' |
Income Available to Common Shareholders of SCANA | -2 | -5 | 16 | 3 | ' |
Segment Assets | 131 | ' | 131 | ' | 153 |
Energy Marketing | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Intersegment Revenue | 44 | 35 | 133 | 84 | ' |
Regulated and Unregulated Operating Revenue | 152 | 151 | 488 | 402 | ' |
Income Available to Common Shareholders of SCANA | 1 | 1 | 5 | 5 | ' |
Segment Assets | 124 | ' | 124 | ' | 122 |
All Other [member] | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Intersegment Revenue | 95 | 100 | 303 | 309 | ' |
Operating Income | 8 | 6 | 22 | 17 | ' |
Regulated and Unregulated Operating Revenue | 11 | 11 | 30 | 32 | ' |
Income Available to Common Shareholders of SCANA | -3 | -3 | -2 | -2 | ' |
Segment Assets | 1,287 | ' | 1,287 | ' | 1,415 |
Adjustments/Eliminations | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Intersegment Revenue | -141 | -137 | -442 | -400 | ' |
Operating Income | -4 | -4 | 34 | 15 | ' |
Regulated and Unregulated Operating Revenue | -6 | -9 | -20 | -26 | ' |
Income Available to Common Shareholders of SCANA | 135 | 129 | 349 | 309 | ' |
Segment Assets | 1,739 | ' | 1,739 | ' | 1,645 |
SCEG | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | 706 | 716 | 1,903 | 1,857 | ' |
Operating Income | 255 | 241 | 625 | 561 | ' |
Regulated Operating Revenue, Gas | 70 | 61 | 297 | 244 | ' |
Net Income (Loss) Attributable to Parent | 136 | 129 | 311 | 272 | ' |
Segment Assets | 12,694 | ' | 12,694 | ' | 12,104 |
Regulated Operating Revenue | 776 | 777 | 2,200 | 2,101 | ' |
SCEG | Electric Operations | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Electric Domestic Regulated Revenue | 706 | 716 | 1,903 | 1,857 | ' |
Operating Income | 257 | 244 | 588 | 534 | ' |
Segment Assets | 9,430 | ' | 9,430 | ' | 8,989 |
SCEG | Gas Distribution | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating Income | -2 | -3 | 37 | 27 | ' |
Regulated Operating Revenue, Gas | 70 | 61 | 297 | 244 | ' |
Segment Assets | 681 | ' | 681 | ' | 659 |
SCEG | Adjustments/Eliminations | ' | ' | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Operating Income | ' | 0 | ' | 0 | ' |
Net Income (Loss) Attributable to Parent | 136 | 129 | 311 | 272 | ' |
Segment Assets | 2,583 | ' | 2,583 | ' | 2,456 |
Regulated Operating Revenue | ' | $0 | $0 | $0 | ' |
AFFILIATED_TRANSACTIONS_SCEG_A
AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) | 9 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction, Expenses from Transactions with Related Party | $40.30 | ' | $45.80 |
Canadys Refined Coal LLC [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Equity Method Investment, Ownership Percentage | 40.00% | ' | ' |
Cope Refined Coal LLC [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction Purchases from Related Party | 73.7 | 87.3 | ' |
Due from Related Parties, Current | 73.4 | 86.9 | ' |
Increase (Decrease) Due from Affiliates | 19.7 | ' | 1.8 |
Equity Method Investment, Dividends or Distributions | 19.8 | ' | 1.8 |
SCEG | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Due to Affiliate, Current | 122 | ' | 124 |
SCEG | Canadys Refined Coal LLC [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Equity Method Investment, Ownership Percentage | ' | ' | 10.00% |
CGT [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction Purchases from Related Party | 25.3 | 27.1 | ' |
Due to Affiliate, Current | 3 | ' | 3.4 |
Retail Gas Marketing and Energy Marketing | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Due to Affiliate, Current | 13.2 | ' | 13.1 |
Cost of Natural Gas Purchases | $132.70 | $84 | ' |