Document_and_Entity_Informatio
Document and Entity Information Document | 3 Months Ended | |
Mar. 31, 2014 | Apr. 30, 2014 | |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'SCANA Corporation | ' |
Entity Central Index Key | '0000754737 | ' |
Current Fiscal Year End Date | '--03-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 31-Mar-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 141,591,499 |
SCEG | ' | ' |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'SOUTH CAROLINA ELECTRIC & GAS CO | ' |
Entity Central Index Key | '0000091882 | ' |
Current Fiscal Year End Date | '--03-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Document Type | '10-Q | ' |
Document Period End Date | 31-Mar-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Amendment Flag | 'false | ' |
Entity Common Stock, Shares Outstanding | ' | 40,296,147 |
CONDENSED_CONSOLIDATED_BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Assets | ' | ' |
Utility Plant In Service | $12,291 | $12,213 |
Accumulated Depreciation and Amortization | -4,050 | -4,011 |
Construction Work in Progress | 2,856 | 2,724 |
Plant to be Retired, Net | 176 | 177 |
Nuclear Fuel, Net of Accumulated Amortization | 298 | 310 |
Goodwill, Net of Writedown of $230 | 230 | 230 |
Utility Plant, Net | 11,801 | 11,643 |
Nonutility Property and Investments: | ' | ' |
Nonutility property, net of accumulated depreciation | 315 | 317 |
Assets held in trust, net-nuclear decommissioning | 104 | 101 |
Other investments | 89 | 86 |
Nonutility Property and Investments, Net | 508 | 504 |
Current Assets: | ' | ' |
Cash and cash equivalents | 110 | 136 |
Receivables, net of allowance for uncollectible accounts | 846 | 802 |
Inventories (at average cost): | ' | ' |
Fuel | 146 | 232 |
Materials and supplies | 134 | 131 |
Prepayments and other | 108 | 120 |
Total Current Assets | 1,344 | 1,421 |
Deferred Debits and Other Assets: | ' | ' |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 49 | 47 |
Regulatory Assets, Noncurrent | 1,467 | 1,360 |
Other | 173 | 189 |
Total Deferred Debits and Other Assets | 1,689 | 1,596 |
Total | 15,342 | 15,164 |
Capitalization and Liabilities | ' | ' |
Common Stock, Value, Outstanding | 2,307 | 2,280 |
Retained Earnings, Unappropriated | 2,563 | 2,444 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -61 | -60 |
Common equity | 4,809 | 4,664 |
Long-term Debt, Excluding Current Maturities | 5,388 | 5,395 |
Total Capitalization | 10,197 | 10,059 |
Current Liabilities: | ' | ' |
Short-term borrowings | 560 | 376 |
Current portion of long-term debt | 53 | 54 |
Accounts payable | 390 | 425 |
Customer deposits and customer prepayments | 116 | 88 |
Taxes accrued | 63 | 206 |
Interest accrued | 75 | 82 |
Dividends declared | 72 | 69 |
Derivative financial instruments | 47 | 8 |
Other | 132 | 134 |
Total Current Liabilities | 1,508 | 1,442 |
Deferred Credits and Other Liabilities: | ' | ' |
Deferred income taxes, net | 1,710 | 1,703 |
Deferred investment tax credits | 31 | 32 |
Asset retirement obligations | 583 | 576 |
Pension and other postretirement benefits | 228 | 227 |
Regulatory liabilities | 882 | 966 |
Other | 203 | 159 |
Total Deferred Credits and Other Liabilities | 3,637 | 3,663 |
Commitments and Contingencies (Note 9) | ' | ' |
Total | 15,342 | 15,164 |
SCEG | ' | ' |
Assets | ' | ' |
Utility Plant In Service | 10,447 | 10,378 |
Accumulated Depreciation and Amortization | -3,531 | -3,499 |
Construction Work in Progress | 2,798 | 2,682 |
Plant to be Retired, Net | 176 | 177 |
Nuclear Fuel, Net of Accumulated Amortization | 298 | 310 |
Utility Plant, Net | 10,188 | 10,048 |
Nonutility Property and Investments: | ' | ' |
Nonutility property, net of accumulated depreciation | 71 | 69 |
Assets held in trust, net-nuclear decommissioning | 104 | 101 |
Other investments | 2 | 3 |
Nonutility Property and Investments, Net | 177 | 173 |
Current Assets: | ' | ' |
Cash and cash equivalents | 32 | 92 |
Receivables, net of allowance for uncollectible accounts | 506 | 486 |
Due from Affiliate, Current | 10 | 19 |
Inventories (at average cost): | ' | ' |
Fuel | 101 | 132 |
Materials and supplies | 122 | 120 |
Prepayments and other | 73 | 80 |
Total Current Assets | 844 | 929 |
Deferred Debits and Other Assets: | ' | ' |
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 98 | 96 |
Regulatory Assets, Noncurrent | 1,409 | 1,303 |
Other | 133 | 151 |
Total Deferred Debits and Other Assets | 1,640 | 1,550 |
Total | 12,849 | 12,700 |
Capitalization and Liabilities | ' | ' |
Common Stock, Value, Outstanding | 2,499 | 2,479 |
Retained Earnings, Unappropriated | 1,957 | 1,896 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 |
Common equity | 4,453 | 4,372 |
Stockholders' Equity Attributable to Noncontrolling Interest | 118 | 117 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,571 | 4,489 |
Long-term Debt, Excluding Current Maturities | 4,001 | 4,007 |
Total Capitalization | 8,572 | 8,496 |
Current Liabilities: | ' | ' |
Short-term borrowings | 457 | 251 |
Current portion of long-term debt | 47 | 48 |
Accounts payable | 214 | 241 |
Due to Affiliate, Current | 117 | 117 |
Customer deposits and customer prepayments | 55 | 56 |
Taxes accrued | 96 | 223 |
Interest accrued | 53 | 64 |
Dividends declared | 64 | 62 |
Derivative financial instruments | 41 | 1 |
Other | 95 | 71 |
Total Current Liabilities | 1,239 | 1,134 |
Deferred Credits and Other Liabilities: | ' | ' |
Deferred income taxes, net | 1,514 | 1,509 |
Deferred investment tax credits | 31 | 32 |
Asset retirement obligations | 553 | 547 |
Pension and other postretirement benefits | 174 | 173 |
Regulatory liabilities | 644 | 732 |
Other | 122 | 77 |
Total Deferred Credits and Other Liabilities | 3,038 | 3,070 |
Commitments and Contingencies (Note 9) | ' | ' |
Total | $12,849 | $12,700 |
CONDENSED_CONSOLIDATED_BALANCE1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Common Stock, Shares, Outstanding | 141.3 | 140.7 |
Public Utilities, Property, Plant and Equipment, Net | $11,801 | $11,643 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 150 | 150 |
Allowance for Doubtful Accounts Receivable, Current | 8 | 6 |
Assets, Current | 1,344 | 1,421 |
Regulated Entity, Other Assets, Noncurrent | 1,689 | 1,596 |
PSNC Energy [Member] | ' | ' |
Write-down, Goodwill | 230 | 230 |
SCEG | ' | ' |
Common Stock, Shares, Outstanding | 40.3 | 40.3 |
Public Utilities, Property, Plant and Equipment, Net | 10,188 | 10,048 |
Allowance for Doubtful Accounts Receivable, Current | 3 | 3 |
Assets, Current | 844 | 929 |
Regulated Entity, Other Assets, Noncurrent | 1,640 | 1,550 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ' | ' |
Public Utilities, Property, Plant and Equipment, Net | 708 | 720 |
Assets, Current | 93 | 147 |
Regulated Entity, Other Assets, Noncurrent | $39 | $35 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | |
Share data in Millions, except Per Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Operating Revenues: | ' | ' |
Electric Domestic Regulated Revenue | $678,000,000 | $583,000,000 |
Regulated Operating Revenue, Gas | 458,000,000 | 382,000,000 |
Gas-nonregulated | 454,000,000 | 346,000,000 |
Regulated and Unregulated Operating Revenue | 1,590,000,000 | 1,311,000,000 |
Operating Expenses [Abstract] | ' | ' |
Fuel used in electric generation | 212,000,000 | 186,000,000 |
Purchased power | 25,000,000 | 7,000,000 |
Gas purchased for resale | 670,000,000 | 501,000,000 |
Other operation and maintenance | 180,000,000 | 176,000,000 |
Depreciation and amortization | 95,000,000 | 93,000,000 |
Other taxes | 58,000,000 | 55,000,000 |
Total Operating Expenses | 1,240,000,000 | 1,018,000,000 |
Operating Income | 350,000,000 | 293,000,000 |
Other Income (Expense): | ' | ' |
Interest Expense | -76,000,000 | -75,000,000 |
Other income | 15,000,000 | 13,000,000 |
Other expenses | -14,000,000 | -12,000,000 |
Allowance for equity funds used during construction | 7,000,000 | 4,000,000 |
Total Other Expense | -68,000,000 | -70,000,000 |
Income Before Income Tax Expense | 282,000,000 | 223,000,000 |
Income Tax Expense | 89,000,000 | 72,000,000 |
Income Available to Common Shareholders | 193,000,000 | 151,000,000 |
Per Common Share Data | ' | ' |
Basic Earnings Per Share of Common Stock (in dollars per share) | $1.37 | $1.13 |
Diluted Earnings Per Share of Common Stock (in dollars per share) | $1.37 | $1.11 |
Weighted Average Common Shares Outstanding (millions) | ' | ' |
Weighted Average Number of Shares Outstanding, Basic | 141.1 | 134.4 |
Weighted Average Number of Shares Outstanding, Diluted | 141.1 | 136.1 |
Dividends Declared Per Share of Common Stock (in dollars per share) | $0.53 | $0.51 |
SCEG | ' | ' |
Operating Revenues: | ' | ' |
Electric Domestic Regulated Revenue | 680,000,000 | 585,000,000 |
Regulated Operating Revenue, Gas | 179,000,000 | 143,000,000 |
Regulated Operating Revenue | 859,000,000 | 728,000,000 |
Operating Expenses [Abstract] | ' | ' |
Fuel used in electric generation | 214,000,000 | 188,000,000 |
Purchased power | 25,000,000 | 7,000,000 |
Gas purchased for resale | 109,000,000 | 77,000,000 |
Other operation and maintenance | 142,000,000 | 138,000,000 |
Depreciation and amortization | 78,000,000 | 77,000,000 |
Other taxes | 52,000,000 | 50,000,000 |
Total Operating Expenses | 620,000,000 | 537,000,000 |
Operating Income | 239,000,000 | 191,000,000 |
Other Income (Expense): | ' | ' |
Interest Expense | -56,000,000 | -55,000,000 |
Other income | 3,000,000 | 0 |
Other expenses | -6,000,000 | -4,000,000 |
Allowance for equity funds used during construction | 5,000,000 | 4,000,000 |
Total Other Expense | -54,000,000 | -55,000,000 |
Income Before Income Tax Expense | 185,000,000 | 136,000,000 |
Income Tax Expense | 59,000,000 | 44,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126,000,000 | 92,000,000 |
Net Income (Loss) Attributable to Noncontrolling Interest | -3,000,000 | -3,000,000 |
Net Income (Loss) Attributable to Parent | 123,000,000 | 89,000,000 |
Weighted Average Common Shares Outstanding (millions) | ' | ' |
Dividends, Common Stock, Cash | $64,000,000 | $64,000,000 |
CONDENSED_CONSOLIDATED_STATEME1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Allowance for Funds Used During Construction, Capitalized Interest | $3 | $2 |
SCEG | ' | ' |
Allowance for Funds Used During Construction, Capitalized Interest | $3 | $2 |
CONDENSED_CONSOLIDATED_STATEME2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Net Income (Loss) Attributable to Parent [Abstract] | ' | ' |
Income Available to Common Shareholders | $193 | $151 |
Other Comprehensive Income (Loss) | ' | ' |
Unrealized gains (losses) on cash flow hedging activities arising during period | 1 | 3 |
(Gains) Losses on cash flow hedging activities reclassified to net income | -2 | 4 |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax | -1 | 7 |
Other Comprehensive Income (Loss) | -1 | 7 |
Total Comprehensive Income (Loss) | 192 | 158 |
SCEG | ' | ' |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 92 |
Other Comprehensive Income (Loss) | ' | ' |
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 126 | 92 |
Total Comprehensive Income (Loss) | 126 | 92 |
Genco | ' | ' |
Other Comprehensive Income (Loss) | ' | ' |
Less comprehensive income attributable to noncontrolling interest | 3 | 3 |
SCE&G (including Fuel Company) | ' | ' |
Net Income (Loss) Attributable to Parent [Abstract] | ' | ' |
Income Available to Common Shareholders | 123 | 89 |
Other Comprehensive Income (Loss) | ' | ' |
Total Comprehensive Income (Loss) | $123 | $89 |
CONDENSED_CONSOLIDATED_STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | $1 | $2 |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax | -1 | 2 |
Other Comprehensive (Income) Loss, Pension and Other Postretirment Benefit Plans, Remeasurement and Curtailment Adjustment, Tax | $0 | $0 |
CONDENSED_CONSOLIDATED_STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Cash Flows From Operating Activities: | ' | ' |
Income Available to Common Shareholders | $193 | $151 |
Adjustments to reconcile net income to net cash provided from operating activities: | ' | ' |
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions | 1 | 0 |
Deferred Income Tax Expense (Benefit) | 7 | 17 |
Depreciation and amortization | 99 | 97 |
Amortization of nuclear fuel | 15 | 13 |
Allowance for equity funds used during construction | -7 | -4 |
Carrying cost recovery | -2 | 0 |
Cash provided (used) by changes in certain assets and liabilities: | ' | ' |
Receivables | -56 | -22 |
Inventories | 70 | 37 |
Prepayments and other | -5 | 21 |
Regulatory liabilities | -94 | 26 |
Accounts payable | 29 | 5 |
Taxes accrued | -143 | -101 |
Interest accrued | -7 | -6 |
Increase (Decrease) in Pension and Postretirement Obligations | -2 | 0 |
Regulatory assets | -108 | 12 |
Changes in other assets | 28 | -16 |
Changes in other liabilities | 120 | -37 |
Net Cash Provided From Operating Activities | 138 | 193 |
Cash Flows From Investing Activities: | ' | ' |
Property additions and construction expenditures | -289 | -291 |
Proceeds from investments (including derivative collateral posted) | 16 | 100 |
Purchase of investments (including derivative collateral posted) | -22 | -84 |
Net Cash Used in Investing Activities | -295 | -275 |
Cash Flows From Financing Activities: | ' | ' |
Proceeds from Issuance of Common Stock | 22 | 221 |
Proceeds from issuance of long-term debt | 0 | 57 |
Repayments of Long-term Debt | -9 | -66 |
Dividends | -66 | -66 |
Short-term borrowings, net | 184 | -93 |
Net Cash Provided From Financing Activities | 131 | 53 |
Net (Decrease) Increase in Cash and Cash Equivalents | -26 | -29 |
Cash and Cash Equivalents, January 1 | 136 | 72 |
Cash and Cash Equivalents, March 31 | 110 | 43 |
Supplemental Cash Flow Information: | ' | ' |
Cash paid for-Interest (net of capitalized interest ) | 80 | 77 |
Cash paid for-Income taxes | 100 | 1 |
Noncash Investing and Financing Activities: | ' | ' |
Accrued construction expenditures | 77 | 88 |
Capital Lease Obligations Incurred | 1 | 3 |
Noncash or Part Noncash Acquisition, Value of Assets Acquired | 0 | 97 |
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 5 | 0 |
SCEG | ' | ' |
Cash Flows From Operating Activities: | ' | ' |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 92 |
Adjustments to reconcile net income to net cash provided from operating activities: | ' | ' |
Income (Loss) from Equity Method Investments | 1 | 1 |
Deferred Income Tax Expense (Benefit) | 5 | 12 |
Depreciation and amortization | 78 | 78 |
Amortization of nuclear fuel | 15 | 13 |
Allowance for equity funds used during construction | -5 | -4 |
Carrying cost recovery | -2 | 0 |
Cash provided (used) by changes in certain assets and liabilities: | ' | ' |
Receivables | -23 | -7 |
Inventories | 19 | 10 |
Prepayments and other | 7 | -12 |
Regulatory liabilities | -94 | 27 |
Accounts payable | 27 | 4 |
Taxes accrued | -127 | -81 |
Interest accrued | -11 | -12 |
Increase (Decrease) in Pension and Postretirement Obligations | -2 | 0 |
Regulatory assets | -107 | 11 |
Changes in other assets | 15 | -21 |
Changes in other liabilities | 121 | -21 |
Net Cash Provided From Operating Activities | 43 | 90 |
Cash Flows From Investing Activities: | ' | ' |
Property additions and construction expenditures | -260 | -264 |
Proceeds from investments (including derivative collateral posted) | 4 | 81 |
Purchase of investments (including derivative collateral posted) | -9 | -70 |
Net Cash Used in Investing Activities | -265 | -253 |
Cash Flows From Financing Activities: | ' | ' |
Proceeds from issuance of long-term debt | 0 | 57 |
Repayments of Long-term Debt | -9 | -66 |
Dividends | -62 | -46 |
Contributions from parent | 20 | 221 |
Short-term borrowings, net | 206 | -41 |
Short-term borrowings- affiliate,net | 7 | -1 |
Net Cash Provided From Financing Activities | 162 | 124 |
Net (Decrease) Increase in Cash and Cash Equivalents | -60 | -39 |
Cash and Cash Equivalents, January 1 | 92 | 51 |
Cash and Cash Equivalents, March 31 | 32 | 12 |
Supplemental Cash Flow Information: | ' | ' |
Cash paid for-Interest (net of capitalized interest ) | 62 | 62 |
Noncash Investing and Financing Activities: | ' | ' |
Accrued construction expenditures | 67 | 81 |
Capital Lease Obligations Incurred | 1 | 1 |
Noncash or Part Noncash Acquisition, Value of Assets Acquired | $0 | $97 |
CONDENSED_CONSOLIDATED_STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Interest Paid, Capitalized | $3 | $2 |
SCEG | ' | ' |
Interest Paid, Capitalized | $3 | $2 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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 | |||||||||
As previously disclosed, in 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in use and in rate base, and SCE&G depreciates 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: | |||||||||
March 31, | |||||||||
Millions | 2014 | 2013 | |||||||
Weighted Average Shares Outstanding - Basic | 141.1 | 134.4 | |||||||
Effect of dilutive equity forward shares | — | 1.7 | |||||||
Weighted Average Shares - Diluted | 141.1 | 136.1 | |||||||
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 26% and 48% of PSNC Energy’s natural gas inventory at March 31, 2014 | |||||||||
and December 31, 2013, respectively, with a carrying value of $4.2 million and $22.8 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. No fees are received under supply service agreements. 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 $476 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 | |||||||||
As previously disclosed, in 2012, SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating | |||||||||
capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. |
RATE_AND_OTHER_REGULATORY_MATT
RATE AND OTHER REGULATORY MATTERS | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs, and approved SCE&G's total fuel cost component. | |||||||||
By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The SCPSC's order also provides for, among other things, the application of approximately $46 million in deferred gains from the settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of fuel costs during the period May 1, 2014 through April 30, 2015. | |||||||||
The increase to the base fuel cost component is offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of the lower net periodic benefit cost it expects to record during 2014. See also Note 8. | |||||||||
Electric - Base Rates | |||||||||
In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate, and during the first quarter of 2014, $1.2 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. | |||||||||
SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1. | |||||||||
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 margin 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 margin revenues, program costs, incentives and net program benefits. The SCPSC approved the following rate changes pursuant to annual DSM Programs filings, which went into effect as indicated: | |||||||||
Year | Effective | Amount | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Other activity related to SCE&G’s DSM Programs is as follows: | |||||||||
• | In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | ||||||||
• | In November 2013 the SCPSC approved SCE&G’s continued use of DSM Programs for another six years, including use of the rate rider mechanism and a revised portfolio of DSM Programs. | ||||||||
• | By order dated April 30, 2014, in response to SCE&G’s annual DSM Programs filing, the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the recent settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million, to the remaining balance of deferred net lost margin revenue as of April 30, 2014, deferred within regulatory assets resulting from the May 2013 order previously described. In addition, the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million , the amount of net lost margin revenues SCE&G expects to experience over the 12 month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider is subject to true up in the following program year. | ||||||||
Electric – BLRA | |||||||||
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 | |||||
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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. | |||||||||
PSNC Energy | |||||||||
PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales. | |||||||||
PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. | |||||||||
In October 2013, in connection with PSNC Energy's 2013 Annual Prudence Review, the NCUC issued an order finding that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2013. | |||||||||
During the third quarter of 2013, the State of North Carolina passed legislation that changed statutes covering gross receipts, sales and use, excise, franchise and income taxes. In the fourth quarter, in response to this legislation, the NCUC initiated a proceeding to investigate how it should proceed in response to the enactment of such legislation. Because the investigation was not completed before January 1, 2014, the NCUC issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014. As of March 31, 2014, revenues subject to refund were not significant. PSNC Energy cannot predict when the NCUC’s investigation will be complete, but does not expect the resolution of this matter to have a material impact on its financial condition, results of operations or cash flows. | |||||||||
Regulatory Assets and Regulatory Liabilities | |||||||||
The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. | |||||||||
Millions of dollars | March 31, | December 31, | |||||||
2014 | 2013 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 258 | $ | 259 | |||||
Under-collections - electric fuel adjustment clause | 36 | 18 | |||||||
Environmental remediation costs | 41 | 41 | |||||||
AROs and related funding | 373 | 368 | |||||||
Franchise agreements | 30 | 31 | |||||||
Deferred employee benefit plan costs | 235 | 238 | |||||||
Deferred losses on interest rate derivatives | 210 | 124 | |||||||
Deferred pollution control costs | 37 | 37 | |||||||
Unrecovered plant | 143 | 145 | |||||||
DSM Programs | 56 | 51 | |||||||
Other | 48 | 48 | |||||||
Total Regulatory Assets | $ | 1,467 | $ | 1,360 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 23 | $ | 24 | |||||
Asset removal costs | 705 | 695 | |||||||
Storm damage reserve | 14 | 27 | |||||||
Monetization of bankruptcy claim | 28 | 29 | |||||||
Deferred gains on interest rate derivatives | 106 | 181 | |||||||
Planned major maintenance | 5 | 10 | |||||||
Other | 1 | — | |||||||
Total Regulatory Liabilities | $ | 882 | $ | 966 | |||||
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | |||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC 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 sites currently or formerly owned by the Company, and 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 related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. | |||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2021. | |||||||||
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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $16.8 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, as discussed at Rate Matters - Electric - Base Rates, certain of these deferred amounts will be applied to offset unrecorded net lost margin revenues related to DSM Programs. | |||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. | |||||||||
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. | |||||||||
DSM Programs represents deferred costs and certain unrecovered net lost margin revenues associated with such programs at SCE&G. Deferred costs are currently being recovered over five years through a SCPSC approved rider. Unrecovered net lost margin revenues are to be recovered over periods not to exceed 24 months from date of deferral. See Rate Matters - Electric - Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered net lost margin revenues. | |||||||||
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. During the first quarter of 2014, $13.6 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve will be applied to offset unrecovered net lost margin revenues related to DSM Programs. | |||||||||
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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs. and approved SCE&G's total fuel cost component. | |||||||||
By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The SCPSC's order also provides for, among other things, the application of approximately $46 million in deferred gains from the settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of fuel costs during the period May 1, 2014 through April 30, 2015. | |||||||||
The increase to the base fuel cost component is offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of the lower net periodic benefit cost it expects to record during 2014. See also Note 8. | |||||||||
Electric - Base Rates | |||||||||
In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate, and during the first quarter of 2014, $1.2 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these deferred income tax assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. | |||||||||
SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. See also Note 1. | |||||||||
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 margin revenues associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost margin revenues, program costs, incentives and net program benefits. The SCPSC approved the following rate changes pursuant to annual DSM Programs filings, which went into effect as indicated: | |||||||||
Year | Effective | Amount | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Other activity related to SCE&G’s DSM Programs is as follows: | |||||||||
• | In May 2013 the SCPSC ordered the deferral as a regulatory asset of one-half of net lost margin revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | ||||||||
• | In November 2013 the SCPSC approved SCE&G’s continued use of DSM Programs for another six years, including use of the rate rider mechanism and a revised portfolio of DSM Programs. | ||||||||
• | By order dated April 30, 2014, in response to SCE&G’s annual DSM Programs filing, the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the recent settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million , to the remaining balance of deferred net lost margin revenue as of April 30, 2014, deferred within regulatory assets resulting from the May 2013 order previously described. In addition, the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million , the amount of net lost margin revenues SCE&G expects to experience over the 12 month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost magin revenues not collected in the current DSM Programs rate rider is subject to true up in the following program year. | ||||||||
Electric – BLRA | |||||||||
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 | |||||
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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. | |||||||||
Regulatory Assets and Regulatory Liabilities | |||||||||
Consolidated SCE&G has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities, which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. | |||||||||
Millions of dollars | March 31, | December 31, | |||||||
2014 | 2013 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 254 | $ | 256 | |||||
Under collections – electric fuel adjustment clause | 36 | 18 | |||||||
Environmental remediation costs | 37 | 37 | |||||||
AROs and related funding | 354 | 350 | |||||||
Franchise agreements | 30 | 31 | |||||||
Deferred employee benefit plan costs | 212 | 215 | |||||||
Deferred losses on interest rate derivatives | 210 | 124 | |||||||
Deferred pollution control costs | 37 | 37 | |||||||
Unrecovered plant | 143 | 145 | |||||||
DSM Programs | 56 | 51 | |||||||
Other | 40 | 39 | |||||||
Total Regulatory Assets | $ | 1,409 | $ | 1,303 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 18 | 19 | ||||||
Asset removal costs | 501 | 495 | |||||||
Storm damage reserve | 14 | 27 | |||||||
Deferred gains on interest rate derivatives | 106 | 181 | |||||||
Planned major maintenance | 5 | 10 | |||||||
Total Regulatory Liabilities | $ | 644 | $ | 732 | |||||
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | |||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC 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 sites currently or formerly owned by SCE&G and 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 related to generation, transmission and distribution properties. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. | |||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2021. | |||||||||
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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $16.8 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, as discussed at Rate Matters - Electric - Base Rates, certain of these deferred amounts will be applied to offset unrecorded net lost margin revenues related to DSM Programs. | |||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. | |||||||||
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. | |||||||||
DSM Programs represents deferred costs and certain unrecovered net lost margin revenues associated with such programs at SCE&G. Deferred costs are currently being recovered over five years through a SCPSC approved rider. Unrecovered net lost margin revenues are to be recovered over periods not to exceed 24 months from date of deferral. See Rate Matters - Electric - Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered net lost margin revenues. | |||||||||
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. During the first quarter of 2014, $13.6 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve will be applied to offset unrecovered net lost margin revenues related to DSM Programs. | |||||||||
The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been 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 | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||||||||||
COMMON EQUITY | ' | ||||||||||||||||||||||||
COMMON EQUITY | |||||||||||||||||||||||||
Changes in common equity during the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||||||||
Millions | Common Stock | Retained Earnings | Gains (Losses) on Cash Flow Hedges | Deferred Employee Benefit Plans | Total AOCI | Total Common Equity | |||||||||||||||||||
Balance as of January 1, 2014 | $ | 2,280 | $ | 2,444 | $ | (52 | ) | $ | (8 | ) | $ | (60 | ) | $ | 4,664 | ||||||||||
Net Income | 193 | 193 | |||||||||||||||||||||||
Other Comprehensive Loss | (1 | ) | — | (1 | ) | (1 | ) | ||||||||||||||||||
Total Comprehensive Income (Loss) | 193 | (1 | ) | — | (1 | ) | 192 | ||||||||||||||||||
Issuance of Common Stock | 27 | 27 | |||||||||||||||||||||||
Dividends Declared | (74 | ) | (74 | ) | |||||||||||||||||||||
Balance as of March 31, 2014 | $ | 2,307 | $ | 2,563 | $ | (53 | ) | $ | (8 | ) | $ | (61 | ) | $ | 4,809 | ||||||||||
Balance as of January 1, 2013 | $ | 1,983 | $ | 2,257 | $ | (70 | ) | $ | (16 | ) | $ | (86 | ) | $ | 4,154 | ||||||||||
Net Income | 151 | 151 | |||||||||||||||||||||||
Other Comprehensive Loss | 7 | — | 7 | 7 | |||||||||||||||||||||
Total Comprehensive Income | 151 | 7 | — | 7 | 158 | ||||||||||||||||||||
Issuance of Common Stock | 221 | 221 | |||||||||||||||||||||||
Dividends Declared | (70 | ) | (70 | ) | |||||||||||||||||||||
Balance as of March 31, 2013 | $ | 2,204 | $ | 2,338 | $ | (63 | ) | $ | (16 | ) | $ | (79 | ) | $ | 4,463 | ||||||||||
SCANA had 200 million shares of common stock authorized as of March 31, 2014 and December 31, 2013, of which 141.3 million and 140.7 million were issued and outstanding at March 31, 2014 and December 31, 2013, 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. | |||||||||||||||||||||||||
For information related to the reclassifications from AOCI, see Note 6. | |||||||||||||||||||||||||
SCEG | ' | ||||||||||||||||||||||||
Stockholders' Equity Note [Abstract] | ' | ||||||||||||||||||||||||
COMMON EQUITY | ' | ||||||||||||||||||||||||
EQUITY | |||||||||||||||||||||||||
Changes in common equity during the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||
Millions | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Total Equity | ||||||||||||||||||||
Balance at January 1, 2014 | $ | 2,479 | $ | 1,896 | $ | (3 | ) | $ | 117 | $ | 4,489 | ||||||||||||||
Earnings available to common shareholder | 123 | 3 | 126 | ||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | |||||||||||||||||||||||
Total Comprehensive Income | 123 | — | 3 | 126 | |||||||||||||||||||||
Capital contributions from parent | 20 | 20 | |||||||||||||||||||||||
Cash dividend declared | (62 | ) | (2 | ) | (64 | ) | |||||||||||||||||||
Balance at March 31, 2014 | $ | 2,499 | $ | 1,957 | $ | (3 | ) | $ | 118 | $ | 4,571 | ||||||||||||||
Balance at January 1, 2013 | $ | 2,167 | $ | 1,766 | $ | (4 | ) | $ | 114 | $ | 4,043 | ||||||||||||||
Earnings available to common shareholder | 89 | 3 | 92 | ||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | |||||||||||||||||||||||
Total Comprehensive Income | 89 | — | 3 | 92 | |||||||||||||||||||||
Capital contributions from parent | 221 | 221 | |||||||||||||||||||||||
Cash dividend declared | (62 | ) | (2 | ) | (64 | ) | |||||||||||||||||||
Balance at March 31, 2013 | $ | 2,388 | $ | 1,793 | $ | (4 | ) | $ | 115 | $ | 4,292 | ||||||||||||||
SCE&G had 50 million shares of common stock authorized as of March 31, 2014 and December 31, 2013, 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 March 31, 2014 and December 31, 2013, of which 1,000 shares at a stated value of $100,000 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 | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||||||||
Long-term Debt [Text Block] | ' | ||||||||||||||||||||||||
LONG-TERM DEBT AND LIQUIDITY | |||||||||||||||||||||||||
Long-term Debt | |||||||||||||||||||||||||
In March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016. | |||||||||||||||||||||||||
In January 2013, JEDA issued at a premium, for the benefit of SCE&G,$39.5 million of 4.00% tax-exempt industrial revenue bonds due February 1, 2028, and $14.7 million of3.63% 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. | |||||||||||||||||||||||||
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 | March 31, | December 31, | March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
Outstanding commercial paper | $ | 103 | $ | 125 | $ | 457 | $ | 251 | — | — | |||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.37 | % | 0.39 | % | 0.26 | % | 0.27 | % | — | — | |||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 194 | $ | 172 | $ | 943 | $ | 1,149 | $ | 100 | $ | 100 | |||||||||||||
SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to five-year credit agreements in the amounts of $300 million, $1.2 billion (of which $500 million relates to Fuel Company) and $100 million respectively. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. 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 March 2013, SCE&G entered into a contract for the purchase of nuclear fuel totaling $100 million and payable in 2016. | |||||||||||||||||||||||||
In January 2013, JEDA issued at a premium, for the benefit of SCE&G,$39.5 million of 4.00% 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. | |||||||||||||||||||||||||
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 | March 31, | December 31, | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | 457 | $ | 251 | ||||||||||||||||||||||
Weighted average interest rate | 0.26 | % | 0.27 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 943 | $ | 1,149 | |||||||||||||||||||||
SCE&G and Fuel Company are parties to five-year credit agreements in the amount of $1.2 billion (of which $500 million relates to Fuel Company). In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million. 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 $1.4 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 were not significant for any period presented. At March 31, 2014 and December 31, 2013, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $33.8 million and $27.3 million, respectively. |
INCOME_TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2014 | |
income tax [Line Items] | ' |
Income Tax Disclosure [Text Block] | ' |
INCOME TAXES | |
During 2013, the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $3.0 million. If recognized, this tax benefit would affect the Company’s effective tax rate. No other material changes in the status of the Company’s tax positions have occurred through March 31, 2014. | |
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. The Company has not recorded interest expense or penalties associated with the 2013 uncertain tax position. | |
During the third quarter of 2013, the State of North Carolina passed legislation that lowered the state corporate income tax rate from 6.9% to 6.0% in 2014 and 5.0% in 2015. In connection with this change in tax rates, related state deferred tax amounts were remeasured, with the change in their balances being credited to a regulatory liability. The change in income tax rates did not and is not expected to have a material impact on the Company’s financial position, results of operations or cash flows. | |
Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). Related IRS revenue procedures were then issued on January 24, 2014. These regulations did not and are not expected to have a material impact on the Company's financial position, results of operations or cash flows. | |
SCEG | ' |
income tax [Line Items] | ' |
Income Tax Disclosure [Text Block] | ' |
INCOME TAXES | |
During 2013, SCANA amended certain of its consolidated tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $3.0 million. If recognized, this tax benefit would affect the Company’s effective tax rate. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through March 31, 2014. | |
Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Consolidated SCE&G has not recorded interest expense or penalties associated with the 2013 uncertain tax position. | |
Additionally, during the third quarter of 2013, the IRS issued final regulations regarding the capitalization of certain costs for income tax purposes and re-proposed certain other related regulations (collectively referred to as tangible personal property regulations). Related IRS revenue procedures were then issued on January 24, 2014. These regulations did not and are not expected to have a material impact on Consolidated SCE&G's financial position, results of operations or cash flows. |
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
Derivative [Line Items] | ' | ||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Text Block] | ' | ||||||||||||||||||||||
DERIVATIVE FINANCIAL INSTRUMENTS | |||||||||||||||||||||||
The Company recognizes all derivative instruments as either assets or liabilities in 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 orders issued, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, be amortized to interest expense or applied as otherwise directed by the SCPSC. | |||||||||||||||||||||||
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. | |||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | |||||||||||||||||||||||
The Company was party to natural gas derivative contracts outstanding in the following quantities: | |||||||||||||||||||||||
Commodity and Other Energy Management Contracts (in MMBTU) | |||||||||||||||||||||||
Hedge designation | Gas Distribution | Retail Gas | Energy Marketing | Total | |||||||||||||||||||
Marketing | |||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||
Commodity | 4,780,000 | 4,325,000 | 1,903,000 | 11,008,000 | |||||||||||||||||||
Energy Management (a) | — | — | 26,073,219 | 26,073,219 | |||||||||||||||||||
Total (a) | 4,780,000 | 4,325,000 | 27,976,219 | 37,081,219 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Commodity | 6,070,000 | 6,726,000 | 2,560,000 | 15,356,000 | |||||||||||||||||||
Energy Management (b) | — | — | 27,359,958 | 27,359,958 | |||||||||||||||||||
Total (b) | 6,070,000 | 6,726,000 | 29,919,958 | 42,715,958 | |||||||||||||||||||
(a) Includes an aggregate 258,615 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
(b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $128.8 million at March 31, 2014 and $128.8 million at December 31, 2013. The Company was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2014 and $1.3 billion at December 31, 2013. | |||||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Derivative financial instruments | $ | 4 | ||||||||||||||||||||
Other deferred credits and other liabilities | 19 | ||||||||||||||||||||||
Commodity | Prepayments and other | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 23 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Other deferred debits and other assets | $ | 2 | Derivative financial instruments | $ | 40 | |||||||||||||||||
Other deferred credits and other liabilities | 43 | ||||||||||||||||||||||
Commodity | Prepayments and other | 3 | |||||||||||||||||||||
Energy Management | Prepayments and other | 3 | Derivative financial instruments | 3 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 12 | $ | 90 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 14 | ||||||||||||||||||||||
Commodity | Prepayments and other | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 19 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Commodity | Prepayments and other | 2 | |||||||||||||||||||||
Energy management | Prepayments and other | 4 | Derivative financial instruments | 4 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 42 | $ | 9 | |||||||||||||||||||
The effect of derivative instruments on the condensed consolidated statements of income is as follows: | |||||||||||||||||||||||
Fair Value Hedges | |||||||||||||||||||||||
The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. | |||||||||||||||||||||||
Cash Flow Hedges | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | |||||||||||||||||||||||
Gain (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | |||||||||||||||||||||
2014 | 2013 | Location | 2014 | 2013 | |||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate | $ | (3 | ) | $ | 35 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||
Gain (Loss) Recognized in OCI, net of tax | Gain (Loss) Reclassified from AOCI into Income, net of tax | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | |||||||||||||||||||||
2014 | 2013 | Location | 2014 | 2013 | |||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate | $ | (2 | ) | $ | 1 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||
Commodity | 3 | 2 | Gas purchased for resale | 4 | (2 | ) | |||||||||||||||||
Total | $ | 1 | $ | 3 | $ | 2 | $ | (4 | ) | ||||||||||||||
As of March 31, 2014, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $1.0 million as a decrease 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 March 31, 2014, all of the Company’s commodity cash flow hedges settle by their terms before the end of 2016. | |||||||||||||||||||||||
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 months ended March 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | |||||||||||||||||||||||
Millions of dollars | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Three Months Ended March 31, 2014 | Location | Amount | |||||||||||||||||||||
Interest rate contracts | $ | (112 | ) | Other Income | $ | — | |||||||||||||||||
No losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income, for the three months ended March 31, 2013. As of March 31, 2014, the Company expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $67.8 million as an increase to other income. The effect of this increase on net income will be entirely offset by the recovery of certain undercollected fuel costs and net lost margin revenues from DSM Programs as further described in Note 2. | |||||||||||||||||||||||
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 March 31, 2014 and December 31, 2013, the Company has posted $30.9 million and $26.8 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months is recorded in Prepayments and other on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2014 and December 31, 2013, the Company could have been required to post an additional $78.1 million and $0.0 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 March 31, 2014 and December 31, 2013 is $109.0 million and $25.2 million, respectively. | |||||||||||||||||||||||
In addition, as of March 31, 2014 and December 31, 2013, the Company has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2014 and December 31, 2013, the Company could request $2.0 million and $34.1 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2014 and December 31, 2013 is $2.0 million and $34.1 million, respectively. In addition, at March 31, 2014, the Company could have called on letters of credit in the amount of $5.0 million related to $7.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $6.0 million related to derivatives of $6.0 million at December 31, 2013, 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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (2 | ) | — | — | |||||||||||||
Commodity | 5 | — | 5 | — | — | $ | 5 | ||||||||||||||||
Energy Management | 7 | — | 7 | — | — | 7 | |||||||||||||||||
Total | $ | 14 | — | $ | 14 | $ | (2 | ) | — | $ | 12 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 8 | ||||||||||||||||||||
Other deferred debits and other assets | 6 | ||||||||||||||||||||||
Total | $ | 14 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
Energy Management | 8 | — | 8 | — | — | 8 | |||||||||||||||||
Total | $ | 44 | — | $ | 44 | $ | (1 | ) | — | $ | 43 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 21 | ||||||||||||||||||||
Other deferred debits and other assets | 23 | ||||||||||||||||||||||
Total | $ | 44 | |||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (2 | ) | $ | (26 | ) | $ | 78 | ||||||||||
Energy Management | 7 | — | 7 | — | (5 | ) | 2 | ||||||||||||||||
$ | 113 | — | $ | 113 | $ | (2 | ) | $ | (31 | ) | $ | 80 | |||||||||||
Balance sheet location | Derivative financial instruments | $ | 47 | ||||||||||||||||||||
Other deferred credits and other liabilities | 66 | ||||||||||||||||||||||
Total | $ | 113 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | (19 | ) | — | |||||||||||
Energy Management | 8 | — | 8 | — | (6 | ) | $ | 2 | |||||||||||||||
$ | 28 | — | $ | 28 | $ | (1 | ) | $ | (25 | ) | $ | 2 | |||||||||||
Balance sheet location | Derivative financial instruments | $ | 10 | ||||||||||||||||||||
Other deferred credits and other liabilities | 18 | ||||||||||||||||||||||
Total | $ | 28 | |||||||||||||||||||||
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. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are no longer designated as cash flow hedges, and fair value changes and settlement amounts are recorded as regulatory assets and liabilities. Upon settlement, losses on swaps will be amortized over the lives of related debt issuances, and gains may be applied to under-collected fuel, be amortized to interest expense or applied as otherwise directed by the SCPSC. | |||||||||||||||||||||||
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes. | |||||||||||||||||||||||
Quantitative Disclosures Related to Derivatives | |||||||||||||||||||||||
Consolidated SCE&G was a party to interest rate swaps designated as cash flow hedges with an aggregate notional amount of $36.4 million at March 31, 2014 and $36.4 million at December 31, 2013. Consolidated SCE&G was party to interest rate swaps not designated as cash flow hedges with an aggregate notional amount of $1.3 billion at March 31, 2014 and $1.3 billion at December 31, 2013, respectively. | |||||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Other deferred credits and other liabilities | 2 | ||||||||||||||||||||||
Total | $ | 3 | |||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other deferred debits and other assets | $ | 2 | Derivative financial instruments | $ | 40 | |||||||||||||||||
Other deferred credits and other liabilities | 43 | ||||||||||||||||||||||
Total | $ | 2 | $ | 83 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Total | $ | 1 | |||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Prepayments and other | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | $ | 1 | |||||||||||||||||||
The effect of derivative instruments on the condensed consolidated statement of income is as follows: | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | Location | 2014 | 2013 | ||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate contracts | $ | (3 | ) | $ | 35 | Interest expense | $ | (1 | ) | $ | (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 months ended March 31, 2014 and 2013, respectively. | |||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | |||||||||||||||||||||||
Millions of dollars | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Location | Amount | ||||||||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (112 | ) | Other Income | $ | — | |||||||||||||||||
No losses were deferred in regulatory accounts, and no amounts were reclassified from deferred accounts into income, for the three months ended March 31, 2013. As of March 31, 2014, Consolidated SCE&G expects that during the next 12 months reclassifications from other current liabilities and deferred regulatory accounts to earnings arising from derivatives not designated as hedges will include $67.8 million as an increase to other income. The effect of this increase on net income will be entirely offset by the recovery of certain undercollected fuel costs and net lost margin revenues from DSM Programs as further described in Note 2. | |||||||||||||||||||||||
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 March 31, 2014 and December 31, 2013, Consolidated SCE&G has posted $4.1 million and $1.5 million, respectively, of collateral related to derivatives with contingent provisions that were in a net liability position. Collateral related to the positions expected to close in the next 12 months are recorded in Prepayments and other on the condensed consolidated balance sheets. Collateral related to noncurrent positions is recorded in Other within Deferred Debits and Other Assets on the condensed consolidated balance sheets. If all of the contingent features underlying these instruments had been fully triggered as of March 31, 2014 and December 31, 2013, Consolidated SCE&G could have been required to post an additional $80.1 million and $0.0 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 March 31, 2014 and December 31, 2013 is $84.2 million and $1.0 million, respectively. | |||||||||||||||||||||||
In addition, as of March 31, 2014 and December 31, 2013, Consolidated SCE&G has collected no cash collateral related to interest rate derivatives with contingent provisions that are in a net asset position. If all the contingent features underlying these instruments were fully triggered as of March 31, 2014 and December 31, 2013, Consolidated SCE&G could request $0.0 million and $31.7 million, respectively, of cash collateral from its counterparties. The aggregate fair value of all derivative instruments with contingent provisions that are in a net asset position as of March 31, 2014 and December 31, 2013 is $0.0 million and $31.7 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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (2 | ) | — | — | |||||||||||||
Balance Sheet Location | Other deferred debits and other assets | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Balance Sheet Location | Prepayments and other | $ | 13 | ||||||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | |||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 86 | — | $ | 86 | $ | (2 | ) | $ | (4 | ) | $ | 80 | ||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 41 | ||||||||||||||||||||
Other deferred credits and other liabilities | 45 | ||||||||||||||||||||||
Total | $ | 86 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (1 | ) | $ | (1 | ) | — | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
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 data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | |||||||||||||||||
As of March 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 11 | — | $ | 9 | — | |||||||||||
Interest rate contracts | — | $ | 2 | — | $ | 32 | |||||||||||
Commodity contracts | 3 | 2 | 2 | 2 | |||||||||||||
Energy management contracts | 1 | 6 | 1 | 7 | |||||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 106 | — | 20 | |||||||||||||
Commodity contracts | — | — | — | — | |||||||||||||
Energy management contracts | — | 10 | — | 12 | |||||||||||||
There were no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. | |||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,441.50 | $ | 6,096.80 | $ | 5,449.30 | $ | 5,916.30 | |||||||||
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. | |||||||||||||||||
Carrying values of short-term borrowings approximate 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 Level 2 measurements were as follows: | |||||||||||||||||
Millions of dollars | 31-Mar-14 | 31-Dec-13 | |||||||||||||||
Assets - | Interest rate contracts | $ | 2 | $ | 32 | ||||||||||||
Liabilities - | Interest rate contracts | 86 | 2 | ||||||||||||||
There were no Level 1 or Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. | |||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,047.60 | $ | 4,574.20 | $ | 4,054.90 | $ | 4,433.00 | |||||||||
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. | |||||||||||||||||
Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
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 | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 5 | $ | 5.9 | $ | 1.2 | $ | 1.6 | |||||||||
Interest cost | 10.2 | 9.5 | 3.1 | 2.8 | |||||||||||||
Expected return on assets | (16.8 | ) | (15.4 | ) | — | — | |||||||||||
Prior service cost amortization | 1 | 1.7 | 0.1 | 0.2 | |||||||||||||
Transition obligation amortization | — | — | — | 0.2 | |||||||||||||
Amortization of actuarial losses | 1.3 | 5.4 | 0.1 | 0.8 | |||||||||||||
Net periodic benefit cost | $ | 0.7 | $ | 7.1 | $ | 4.5 | $ | 5.6 | |||||||||
No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed in Note 2. | |||||||||||||||||
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 | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 4 | $ | 4.8 | $ | 1 | $ | 1.2 | |||||||||
Interest cost | 8.6 | 8 | 2.4 | 2.2 | |||||||||||||
Expected return on assets | (14.2 | ) | (13.0 | ) | — | — | |||||||||||
Prior service cost amortization | 0.9 | 1.4 | 0.1 | 0.2 | |||||||||||||
Amortization of actuarial losses | 1.1 | 4.6 | 0.1 | 0.6 | |||||||||||||
Net periodic benefit cost | $ | 0.4 | $ | 5.8 | $ | 3.6 | $ | 4.2 | |||||||||
No significant contribution to the pension trust is expected for the foreseeable future, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. Certain pension costs arising prior to 2013 were deferred for future recovery under regulatory orders as discussed in Note 2. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended | |
Mar. 31, 2014 | ||
Statement [Line Items] | ' | |
Commitments and Contingencies Disclosure [Text Block] | ' | |
COMMITMENTS AND CONTINGENCIES | ||
Nuclear Insurance | ||
Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $41.6 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, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s results of operations, cash flows and financial position. | ||
New Nuclear Construction | ||
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 $5.4 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. | ||
SCE&G's current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments would be reflected in a revised rates filing under the BLRA. | ||
Under the BLRA, the SCPSC has approved, among other things, the construction milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved construction milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. | ||
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 have impacted the project budget and schedule. Claims by the Consortium specifically relating 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 which resulted in assertions of contractual entitlement to recover additional costs have been resolved. SCE&G expects to resolve any additional disputes 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. | ||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. | ||
In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated construction milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. The South Carolina Supreme Court heard arguments related to those appeals on April 16, 2014. SCE&G is unable to predict the outcome of these appeals. | ||
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, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its assembly is underway. CA20 is expected to be ready for placement on the nuclear island of Unit 2 in May 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the latter half of 2014. With this schedule, the Consortium continues to indicate that the substantial completion of Unit 2 is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of Unit 3 is expected to be approximately 12 months after that of Unit 2. These dates are within the SCPSC-approved 18-month contingency period. 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. | ||
During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedule and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule that will provide detailed information on budget and cost and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that the revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in the latter half of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new schedule. | ||
The construction milestone schedule approved by the SCPSC in November 2012 provides for 146 construction milestone dates, which are each subject to an 18-month schedule contingency. As of May 3, 2014, 98 milestones have been completed. The currently scheduled completion dates for 44 of the remaining milestones have been delayed between two and 17 months. If, as a result of the re-baselining of the construction schedules for the New Units, the time period for achieving any of the milestones extends beyond its 18-month schedule contingency and/or the capital costs estimates increase, then SCE&G, as provided for under the BLRA, may petition the SCPSC for an order to update the construction milestone schedule and/or capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G. | ||
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. | ||
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 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. | ||
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 New Units’ reactor buildings (March 2013 for Unit 2 and November 2013 for Unit 3), SCE&G has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. | ||
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 re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants can be constructed without carbon capture and sequestration capabilities. The Company is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015. 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR and will also allow it to comply with CSAPR, if reinstated. 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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed. | ||
Additionally, the EPA is expected to issue a rule that modifies requirements for existing cooling water intake structures in 2014. The Company is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of the Company. The Company believes that any additional costs imposed by such regulations would be recoverable through rates. | ||
In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While the Company cannot predict how extensive the regulations will be, the Company believes that any additional costs imposed by such regulations would be recoverable through rates. | ||
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of March 31, 2014, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. | ||
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of 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 $20.2 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 March 31, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $36.7 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 $2.8 million, the estimated remaining liability at March 31, 2014. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites. | ||
SCEG | ' | |
Statement [Line Items] | ' | |
Commitments and Contingencies Disclosure [Text Block] | ' | |
COMMITMENTS AND CONTINGENCIES | ||
Nuclear Insurance | ||
Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to $13.6 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 $41.6 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, 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 Consolidated SCE&G’s results of operations, cash flows and financial position. | ||
New Nuclear Construction | ||
SCE&G, on behalf of itself and as agent for Santee Cooper, 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 $5.4 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. | ||
SCE&G's current ownership share in the New Units is 55%. Under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, will acquire an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and will acquire the final 2% no later than the second anniversary of such commercial operation date. Under the terms of the agreement SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of conveyance, which SCE&G estimates will be approximately $500 million for the entire 5% interest. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments would be reflected in a revised rates filing under the BLRA. | ||
Under the BLRA, the SCPSC has approved, among other things, the construction milestone schedule and capital costs estimates schedule for the New Units. The effect of this approval is that it constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved construction milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. The BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. | ||
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 have impacted the project budget and schedule. Claims by the Consortium specifically relating 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 which resulted in assertions of contractual entitlement to recover additional costs have been resolved. SCE&G expects to resolve any additional disputes 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. | ||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC has also approved an 18-month contingency period beyond each of these dates. | ||
In November 2012, the SCPSC approved a petition by SCE&G under the BLRA for an updated construction milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Immediately thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its order, and 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, contending that the SCPSC erred in granting approval of the updated capital costs for the New Units. The South Carolina Supreme Court heard arguments related to those appeals on April 16, 2014. SCE&G is unable to predict the outcome of these appeals. | ||
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, including sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01 are considered critical path items for both New Units. All sub-modules for CA20 have been received on site and its assembly is underway. CA20 is expected to be ready for placement on the nuclear island of Unit 2 in May 2014. In addition, the delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow it to be ready for placement on the nuclear island of Unit 2 during the latter half of 2014. With this schedule, the Consortium continues to indicate that the substantial completion of Unit 2 is expected to be late 2017 or the first quarter of 2018 and that the substantial completion of Unit 3 is expected to be approximately 12 months after that of Unit 2. These dates are within the SCPSC-approved 18-month contingency period. 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. | ||
During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedule and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result will be a revised fully integrated project schedule that will provide detailed information on budget and cost and the timing of specific construction activities and cash flow requirements. SCE&G anticipates that the revised schedule and the cost estimate at completion for all non-firm and fixed scopes of work will be finalized in the latter half of 2014. SCE&G plans to reevaluate and reschedule its owners cost estimates and cash flow requirements in light of the new schedule. | ||
The construction milestone schedule approved by the SCPSC in November 2012 provides for 146 construction milestone dates, which are each subject to an 18-month schedule contingency. As of May 3, 2014, 98 milestones have been completed. The currently scheduled completion dates for 44 of the remaining milestones have been delayed between two and 17 months. If, as a result of the re-baselining of the construction schedules for the New Units, the time period for achieving any of the milestones extends beyond its 18-month schedule contingency and/or the capital costs estimates increase, then SCE&G, as provided for under the BLRA, may petition the SCPSC for an order to update the construction milestone schedule and/or capital costs estimates schedule. The BLRA provides that the SCPSC shall grant the petition for modification if the record justifies a finding that the change is not the result of imprudence by SCE&G. | ||
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. | ||
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 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. | ||
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 New Units’ reactor buildings (March 2013 for Unit 2 and November 2013 for Unit 3), SCE&G has applied to the IRS for its allocations of such national megawatt capacity limitation. The IRS will forward the applications to the DOE for appropriate certification. | ||
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 re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The rule became final on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants can be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the final rule, but does not plan to construct new coal-fired units in the foreseeable future. The Memorandum also directed the EPA to issue standards, regulations, or guidelines for existing units by June 1, 2014, to be made final no later than June 1, 2015. 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 Court of Appeals 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. On April 29, 2014, the U. S. Supreme Court reversed the judgment of the Court of Appeals and CSAPR was remanded to the Court of Appeals for further proceedings consistent with the U. S. Supreme Court opinion. Air quality control installations that SCE&G and GENCO have already completed have allowed Consolidated SCE&G to comply with the reinstated CAIR and will also allow it to comply with CSAPR, if reinstated. 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 CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized September 30, 2015. The EPA expects compliance within a three to six year time frame as NPDES permits are renewed. | ||
Additionally, the EPA is expected to issue a rule that modifies requirements for existing cooling water intake structures in 2014. Consolidated SCE&G is conducting studies and is developing or implementing compliance plans for these initiatives. Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. These provisions, if passed, could have a material impact on the financial condition, results of operations and cash flows of Consolidated SCE&G. Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates. | ||
In response to a federal court order to establish a definite timeline for a CCR rule and subsequent obligation via consent decree, the EPA committed to issue new federal regulations affecting the management and disposal of CCRs, such as ash, by December 19, 2014. Such regulations could result in the treatment of some CCRs as hazardous waste and could impose significant costs to utilities, such as SCE&G and GENCO. While Consolidated SCE&G cannot predict how extensive the regulations will be, Consolidated SCE&G believes that any additional costs imposed by such regulations would be recoverable through rates. | ||
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2013, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017, and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. | ||
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. In addition, the state of South Carolina has similar laws. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify Consolidated SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of 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 $20.2 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 March 31, 2014, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $36.7 million and are included in regulatory assets. |
SEGMENT_OF_BUSINESS_INFORMATIO
SEGMENT OF BUSINESS INFORMATION | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
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 Revenue | Operating | Net | |||||||||||||
Revenue | Income | Income | |||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||
Electric Operations | $ | 678 | $ | 2 | $ | 198 | n/a | ||||||||||
Gas Distribution | 455 | — | 97 | n/a | |||||||||||||
Retail Gas Marketing | 220 | — | n/a | $ | 22 | ||||||||||||
Energy Marketing | 234 | 53 | n/a | 7 | |||||||||||||
All Other | 9 | 110 | 8 | 4 | |||||||||||||
Adjustments/Eliminations | (6 | ) | (165 | ) | 47 | 160 | |||||||||||
Consolidated Total | $ | 1,590 | $ | — | $ | 350 | $ | 193 | |||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
Electric Operations | $ | 583 | $ | 2 | $ | 153 | n/a | ||||||||||
Gas Distribution | 379 | — | 93 | n/a | |||||||||||||
Retail Gas Marketing | 179 | — | n/a | $ | 22 | ||||||||||||
Energy Marketing | 167 | 42 | n/a | 3 | |||||||||||||
All Other | 12 | 107 | 7 | 3 | |||||||||||||
Adjustments/Eliminations | (9 | ) | (151 | ) | 40 | 123 | |||||||||||
Consolidated Total | $ | 1,311 | $ | — | $ | 293 | $ | 151 | |||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2014 | 2013 | |||||||||||||||
Electric Operations | $ | 9,542 | $ | 9,488 | |||||||||||||
Gas Distribution | 2,408 | 2,340 | |||||||||||||||
Retail Gas Marketing | 162 | 172 | |||||||||||||||
Energy Marketing | 154 | 133 | |||||||||||||||
All Other | 1,363 | 1,378 | |||||||||||||||
Adjustments/Eliminations | 1,713 | 1,653 | |||||||||||||||
Consolidated Total | $ | 15,342 | $ | 15,164 | |||||||||||||
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 March 31, 2014 | |||||||||||||||||
Electric Operations | $ | 680 | $ | 198 | n/a | ||||||||||||
Gas Distribution | 179 | 41 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 123 | |||||||||||||
Consolidated Total | $ | 859 | $ | 239 | $ | 123 | |||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
Electric Operations | $ | 585 | $ | 153 | n/a | ||||||||||||
Gas Distribution | 143 | 38 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 89 | |||||||||||||
Consolidated Total | $ | 728 | $ | 191 | $ | 89 | |||||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2014 | 2013 | |||||||||||||||
Electric Operations | $ | 9,542 | $ | 9,488 | |||||||||||||
Gas Distribution | 692 | 686 | |||||||||||||||
Adjustments/Eliminations | 2,615 | 2,526 | |||||||||||||||
Consolidated Total | $ | 12,849 | $ | 12,700 | |||||||||||||
AFFILIATED_TRANSACTIONS_SCEG
AFFILIATED TRANSACTIONS - SCEG (SCEG) | 3 Months Ended |
Mar. 31, 2014 | |
SCEG | ' |
AFFILIATED TRANSACTIONS | ' |
AFFILIATED TRANSACTIONS | |
CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. Such purchases totaled approximately $5.5 million and $8.4 million for the three months ended March 31, 2014 and 2013, respectively. SCE&G had approximately $3.3 million and $3.3 million payable to CGT for transportation services at March 31, 2014 and December 31, 2013, respectively. SCE&G had approximately $2.5 million and1.3 million receivable from CGT for transportation services at March 31, 2014 and December 31, 2013, respectively. | |
SCE&G purchases natural gas and related pipeline capacity from SEMI to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately $53.4 million and $42.1 million for the three months ended March 30, 2014 and 2013, respectively. SCE&G’s payables to SEMI for such purposes were $17.2 million and $12.5 million as of March 31, 2014 and December 31, 2013, 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 accounts for this investment using the equity method. SCE&G’s receivable from this affiliate was $4.4 million at March 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s payable to this affiliate was $4.4 million at March 31, 2014 and $18.0 million at December 31, 2013. SCE&G’s total purchases from this affiliate were $39.2 million and $14.3 million for the three months ended March 31, 2014 and 2013, respectively. SCE&G’s total sales to this affiliate were $39.0 million and $14.3 million for the three months ended March 31, 2014 and 2013, respectively. | |
SCANA Services provides the following services to Consolidated SCE&G, 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. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $76.2 million and $78.6 million for the three months ended March 31, 2014 and 2013, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $45.6 million and $49.1 million at March 31, 2014 and December 31, 2013, respectively. | |
Money pool borrowings from an affiliate are described in Note 4. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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 26% and 48% of PSNC Energy’s natural gas inventory at March 31, 2014 | |
and December 31, 2013, respectively, with a carrying value of $4.2 million and $22.8 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees of which 75% are credited to rate payers. No fees are received under supply service agreements. 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. | |
Plant to be retired [Policy Text Block] | ' |
Plant to be Retired | |
As previously disclosed, in 2012 SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. | |
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 $476 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. | |
Plant to be retired [Policy Text Block] | ' |
Plant to be Retired | |
As previously disclosed, in 2012, SCE&G identified six coal-fired units that it intends to retire by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating | |
capacity (summer 2012) of 730 MW. Three of these units had been retired by December 31, 2013, and their net carrying value is recorded in regulatory assets (see Note 2). The net carrying value of the remaining units is identified as Plant to be Retired, Net in the condensed consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in use and in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
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: | |||||||||
March 31, | |||||||||
Millions | 2014 | 2013 | |||||||
Weighted Average Shares Outstanding - Basic | 141.1 | 134.4 | |||||||
Effect of dilutive equity forward shares | — | 1.7 | |||||||
Weighted Average Shares - Diluted | 141.1 | 136.1 | |||||||
RATE_AND_OTHER_REGULATORY_MATT1
RATE AND OTHER REGULATORY MATTERS (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2014 | |||||||||
Regulatory Assets | ' | ||||||||
Demand reduction programs [Table Text Block] | ' | ||||||||
: | |||||||||
Year | Effective | Amount | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Schedule of Regulatory Assets [Table Text Block] | ' | ||||||||
. | |||||||||
Millions of dollars | March 31, | December 31, | |||||||
2014 | 2013 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 258 | $ | 259 | |||||
Under-collections - electric fuel adjustment clause | 36 | 18 | |||||||
Environmental remediation costs | 41 | 41 | |||||||
AROs and related funding | 373 | 368 | |||||||
Franchise agreements | 30 | 31 | |||||||
Deferred employee benefit plan costs | 235 | 238 | |||||||
Deferred losses on interest rate derivatives | 210 | 124 | |||||||
Deferred pollution control costs | 37 | 37 | |||||||
Unrecovered plant | 143 | 145 | |||||||
DSM Programs | 56 | 51 | |||||||
Other | 48 | 48 | |||||||
Total Regulatory Assets | $ | 1,467 | $ | 1,360 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | ' | ||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 23 | $ | 24 | |||||
Asset removal costs | 705 | 695 | |||||||
Storm damage reserve | 14 | 27 | |||||||
Monetization of bankruptcy claim | 28 | 29 | |||||||
Deferred gains on interest rate derivatives | 106 | 181 | |||||||
Planned major maintenance | 5 | 10 | |||||||
Other | 1 | — | |||||||
Total Regulatory Liabilities | $ | 882 | $ | 966 | |||||
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 | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
2012 | First billing cycle of May | $19.6 million | |||||||
Schedule of Regulatory Assets [Table Text Block] | ' | ||||||||
Millions of dollars | March 31, | December 31, | |||||||
2014 | 2013 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 254 | $ | 256 | |||||
Under collections – electric fuel adjustment clause | 36 | 18 | |||||||
Environmental remediation costs | 37 | 37 | |||||||
AROs and related funding | 354 | 350 | |||||||
Franchise agreements | 30 | 31 | |||||||
Deferred employee benefit plan costs | 212 | 215 | |||||||
Deferred losses on interest rate derivatives | 210 | 124 | |||||||
Deferred pollution control costs | 37 | 37 | |||||||
Unrecovered plant | 143 | 145 | |||||||
DSM Programs | 56 | 51 | |||||||
Other | 40 | 39 | |||||||
Total Regulatory Assets | $ | 1,409 | $ | 1,303 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | ' | ||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 18 | 19 | ||||||
Asset removal costs | 501 | 495 | |||||||
Storm damage reserve | 14 | 27 | |||||||
Deferred gains on interest rate derivatives | 106 | 181 | |||||||
Planned major maintenance | 5 | 10 | |||||||
Total Regulatory Liabilities | $ | 644 | $ | 732 | |||||
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) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
Schedule of Capitalization, Equity [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Stockholders Equity [Table Text Block] | ' | ||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||||||||
Millions | Common Stock | Retained Earnings | Gains (Losses) on Cash Flow Hedges | Deferred Employee Benefit Plans | Total AOCI | Total Common Equity | |||||||||||||||||||
Balance as of January 1, 2014 | $ | 2,280 | $ | 2,444 | $ | (52 | ) | $ | (8 | ) | $ | (60 | ) | $ | 4,664 | ||||||||||
Net Income | 193 | 193 | |||||||||||||||||||||||
Other Comprehensive Loss | (1 | ) | — | (1 | ) | (1 | ) | ||||||||||||||||||
Total Comprehensive Income (Loss) | 193 | (1 | ) | — | (1 | ) | 192 | ||||||||||||||||||
Issuance of Common Stock | 27 | 27 | |||||||||||||||||||||||
Dividends Declared | (74 | ) | (74 | ) | |||||||||||||||||||||
Balance as of March 31, 2014 | $ | 2,307 | $ | 2,563 | $ | (53 | ) | $ | (8 | ) | $ | (61 | ) | $ | 4,809 | ||||||||||
Balance as of January 1, 2013 | $ | 1,983 | $ | 2,257 | $ | (70 | ) | $ | (16 | ) | $ | (86 | ) | $ | 4,154 | ||||||||||
Net Income | 151 | 151 | |||||||||||||||||||||||
Other Comprehensive Loss | 7 | — | 7 | 7 | |||||||||||||||||||||
Total Comprehensive Income | 151 | 7 | — | 7 | 158 | ||||||||||||||||||||
Issuance of Common Stock | 221 | 221 | |||||||||||||||||||||||
Dividends Declared | (70 | ) | (70 | ) | |||||||||||||||||||||
Balance as of March 31, 2013 | $ | 2,204 | $ | 2,338 | $ | (63 | ) | $ | (16 | ) | $ | (79 | ) | $ | 4,463 | ||||||||||
Reclassifications from Other Comprehensive Income [Table Text Block] | ' | ||||||||||||||||||||||||
For information related to the reclassifications from AOCI, see Note 6. | |||||||||||||||||||||||||
SCEG | ' | ||||||||||||||||||||||||
Schedule of Capitalization, Equity [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Stockholders Equity [Table Text Block] | ' | ||||||||||||||||||||||||
Changes in common equity during the three months ended March 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||
Millions | Common Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest | Total Equity | ||||||||||||||||||||
Balance at January 1, 2014 | $ | 2,479 | $ | 1,896 | $ | (3 | ) | $ | 117 | $ | 4,489 | ||||||||||||||
Earnings available to common shareholder | 123 | 3 | 126 | ||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | |||||||||||||||||||||||
Total Comprehensive Income | 123 | — | 3 | 126 | |||||||||||||||||||||
Capital contributions from parent | 20 | 20 | |||||||||||||||||||||||
Cash dividend declared | (62 | ) | (2 | ) | (64 | ) | |||||||||||||||||||
Balance at March 31, 2014 | $ | 2,499 | $ | 1,957 | $ | (3 | ) | $ | 118 | $ | 4,571 | ||||||||||||||
Balance at January 1, 2013 | $ | 2,167 | $ | 1,766 | $ | (4 | ) | $ | 114 | $ | 4,043 | ||||||||||||||
Earnings available to common shareholder | 89 | 3 | 92 | ||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | |||||||||||||||||||||||
Total Comprehensive Income | 89 | — | 3 | 92 | |||||||||||||||||||||
Capital contributions from parent | 221 | 221 | |||||||||||||||||||||||
Cash dividend declared | (62 | ) | (2 | ) | (64 | ) | |||||||||||||||||||
Balance at March 31, 2013 | $ | 2,388 | $ | 1,793 | $ | (4 | ) | $ | 115 | $ | 4,292 | ||||||||||||||
LONGTERM_AND_SHORTTERM_DEBT_LO
LONG-TERM AND SHORT-TERM DEBT LONG-TERM AND SHORT-TERM DEBT (Tables) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Line of Credit Facilities [Table 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 | March 31, | December 31, | March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
Outstanding commercial paper | $ | 103 | $ | 125 | $ | 457 | $ | 251 | — | — | |||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.37 | % | 0.39 | % | 0.26 | % | 0.27 | % | — | — | |||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 194 | $ | 172 | $ | 943 | $ | 1,149 | $ | 100 | $ | 100 | |||||||||||||
SCEG | ' | ||||||||||||||||||||||||
Short-term Debt [Line Items] | ' | ||||||||||||||||||||||||
Schedule of Line of Credit Facilities [Table 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 | March 31, | December 31, | |||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | 457 | $ | 251 | ||||||||||||||||||||||
Weighted average interest rate | 0.26 | % | 0.27 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 943 | $ | 1,149 | |||||||||||||||||||||
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 3 Months Ended | ||||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||||
Derivative [Line Items] | ' | ||||||||||||||||||||||
Schedule of Derivative Instruments [Table Text Block] | ' | ||||||||||||||||||||||
The Company was party to natural gas derivative contracts outstanding in the following quantities: | |||||||||||||||||||||||
Commodity and Other Energy Management Contracts (in MMBTU) | |||||||||||||||||||||||
Hedge designation | Gas Distribution | Retail Gas | Energy Marketing | Total | |||||||||||||||||||
Marketing | |||||||||||||||||||||||
As of March 31, 2014 | |||||||||||||||||||||||
Commodity | 4,780,000 | 4,325,000 | 1,903,000 | 11,008,000 | |||||||||||||||||||
Energy Management (a) | — | — | 26,073,219 | 26,073,219 | |||||||||||||||||||
Total (a) | 4,780,000 | 4,325,000 | 27,976,219 | 37,081,219 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Commodity | 6,070,000 | 6,726,000 | 2,560,000 | 15,356,000 | |||||||||||||||||||
Energy Management (b) | — | — | 27,359,958 | 27,359,958 | |||||||||||||||||||
Total (b) | 6,070,000 | 6,726,000 | 29,919,958 | 42,715,958 | |||||||||||||||||||
(a) Includes an aggregate 258,615 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
(b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. | |||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | ' | ||||||||||||||||||||||
The fair value of 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 March 31, 2014 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Derivative financial instruments | $ | 4 | ||||||||||||||||||||
Other deferred credits and other liabilities | 19 | ||||||||||||||||||||||
Commodity | Prepayments and other | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 23 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Other deferred debits and other assets | $ | 2 | Derivative financial instruments | $ | 40 | |||||||||||||||||
Other deferred credits and other liabilities | 43 | ||||||||||||||||||||||
Commodity | Prepayments and other | 3 | |||||||||||||||||||||
Energy Management | Prepayments and other | 3 | Derivative financial instruments | 3 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 12 | $ | 90 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Derivative financial instruments | $ | 5 | ||||||||||||||||||||
Other deferred credits and other liabilities | 14 | ||||||||||||||||||||||
Commodity | Prepayments and other | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | $ | 19 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate | Prepayments and other | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Commodity | Prepayments and other | 2 | |||||||||||||||||||||
Energy management | Prepayments and other | 4 | Derivative financial instruments | 4 | |||||||||||||||||||
Other deferred debits and other assets | 4 | Other deferred credits and other liabilities | 4 | ||||||||||||||||||||
Total | $ | 42 | $ | 9 | |||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | |||||||||||||||||||||||
Gain (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | |||||||||||||||||||||
2014 | 2013 | Location | 2014 | 2013 | |||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate | $ | (3 | ) | $ | 35 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||
Gain (Loss) Recognized in OCI, net of tax | Gain (Loss) Reclassified from AOCI into Income, net of tax | ||||||||||||||||||||||
Millions of dollars | (Effective Portion) | (Effective Portion) | |||||||||||||||||||||
2014 | 2013 | Location | 2014 | 2013 | |||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate | $ | (2 | ) | $ | 1 | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||||
Commodity | 3 | 2 | Gas purchased for resale | 4 | (2 | ) | |||||||||||||||||
Total | $ | 1 | $ | 3 | $ | 2 | $ | (4 | ) | ||||||||||||||
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 | |||||||||||||||||||||||
Millions of dollars | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Three Months Ended March 31, 2014 | Location | Amount | |||||||||||||||||||||
Interest rate contracts | $ | (112 | ) | Other Income | $ | — | |||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (2 | ) | — | — | |||||||||||||
Commodity | 5 | — | 5 | — | — | $ | 5 | ||||||||||||||||
Energy Management | 7 | — | 7 | — | — | 7 | |||||||||||||||||
Total | $ | 14 | — | $ | 14 | $ | (2 | ) | — | $ | 12 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 8 | ||||||||||||||||||||
Other deferred debits and other assets | 6 | ||||||||||||||||||||||
Total | $ | 14 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
Energy Management | 8 | — | 8 | — | — | 8 | |||||||||||||||||
Total | $ | 44 | — | $ | 44 | $ | (1 | ) | — | $ | 43 | ||||||||||||
Balance sheet location | Prepayments and other | $ | 21 | ||||||||||||||||||||
Other deferred debits and other assets | 23 | ||||||||||||||||||||||
Total | $ | 44 | |||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (2 | ) | $ | (26 | ) | $ | 78 | ||||||||||
Energy Management | 7 | — | 7 | — | (5 | ) | 2 | ||||||||||||||||
$ | 113 | — | $ | 113 | $ | (2 | ) | $ | (31 | ) | $ | 80 | |||||||||||
Balance sheet location | Derivative financial instruments | $ | 47 | ||||||||||||||||||||
Other deferred credits and other liabilities | 66 | ||||||||||||||||||||||
Total | $ | 113 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 20 | — | $ | 20 | $ | (1 | ) | $ | (19 | ) | — | |||||||||||
Energy Management | 8 | — | 8 | — | (6 | ) | $ | 2 | |||||||||||||||
$ | 28 | — | $ | 28 | $ | (1 | ) | $ | (25 | ) | $ | 2 | |||||||||||
Balance sheet location | Derivative financial instruments | $ | 10 | ||||||||||||||||||||
Other deferred credits and other liabilities | 18 | ||||||||||||||||||||||
Total | $ | 28 | |||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Other deferred credits and other liabilities | 2 | ||||||||||||||||||||||
Total | $ | 3 | |||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Other deferred debits and other assets | $ | 2 | Derivative financial instruments | $ | 40 | |||||||||||||||||
Other deferred credits and other liabilities | 43 | ||||||||||||||||||||||
Total | $ | 2 | $ | 83 | |||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | ||||||||||||||||||||
Total | $ | 1 | |||||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||||
Interest rate contracts | Prepayments and other | $ | 13 | Derivative financial instruments | $ | 1 | |||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | $ | 1 | |||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | ||||||||||||||||||||||
Millions of dollars | 2014 | 2013 | Location | 2014 | 2013 | ||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||||
Interest rate contracts | $ | (3 | ) | $ | 35 | Interest expense | $ | (1 | ) | $ | (1 | ) | |||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ' | ||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | |||||||||||||||||||||||
Millions of dollars | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Location | Amount | ||||||||||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||||||||
Interest rate contracts | $ | (112 | ) | Other Income | $ | — | |||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (2 | ) | — | — | |||||||||||||
Balance Sheet Location | Other deferred debits and other assets | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 32 | — | $ | 32 | $ | (1 | ) | — | $ | 31 | ||||||||||||
Balance Sheet Location | Prepayments and other | $ | 13 | ||||||||||||||||||||
Other deferred debits and other assets | 19 | ||||||||||||||||||||||
Total | $ | 32 | |||||||||||||||||||||
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 March 31, 2014 | |||||||||||||||||||||||
Interest rate | $ | 86 | — | $ | 86 | $ | (2 | ) | $ | (4 | ) | $ | 80 | ||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 41 | ||||||||||||||||||||
Other deferred credits and other liabilities | 45 | ||||||||||||||||||||||
Total | $ | 86 | |||||||||||||||||||||
As of December 31, 2013 | |||||||||||||||||||||||
Interest rate | $ | 2 | — | $ | 2 | $ | (1 | ) | $ | (1 | ) | — | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 2 | ||||||||||||||||||||
Total | $ | 2 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD1
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
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: | |||||||||||||||||
As of March 31, 2014 | As of December 31, 2013 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 11 | — | $ | 9 | — | |||||||||||
Interest rate contracts | — | $ | 2 | — | $ | 32 | |||||||||||
Commodity contracts | 3 | 2 | 2 | 2 | |||||||||||||
Energy management contracts | 1 | 6 | 1 | 7 | |||||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 106 | — | 20 | |||||||||||||
Commodity contracts | — | — | — | — | |||||||||||||
Energy management contracts | — | 10 | — | 12 | |||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | ||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,441.50 | $ | 6,096.80 | $ | 5,449.30 | $ | 5,916.30 | |||||||||
SCEG | ' | ||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ||||||||||||||||
Fair Value, Measurement Inputs, Disclosure [Table Text Block] | ' | ||||||||||||||||
Fair value Level 2 measurements were as follows: | |||||||||||||||||
Millions of dollars | 31-Mar-14 | 31-Dec-13 | |||||||||||||||
Assets - | Interest rate contracts | $ | 2 | $ | 32 | ||||||||||||
Liabilities - | Interest rate contracts | 86 | 2 | ||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | ' | ||||||||||||||||
Financial instruments for which the carrying amount may not equal estimated fair value at March 31, 2014 and December 31, 2013 were as follows: | |||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,047.60 | $ | 4,574.20 | $ | 4,054.90 | $ | 4,433.00 | |||||||||
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | ||||||||||||||||
: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 5 | $ | 5.9 | $ | 1.2 | $ | 1.6 | |||||||||
Interest cost | 10.2 | 9.5 | 3.1 | 2.8 | |||||||||||||
Expected return on assets | (16.8 | ) | (15.4 | ) | — | — | |||||||||||
Prior service cost amortization | 1 | 1.7 | 0.1 | 0.2 | |||||||||||||
Transition obligation amortization | — | — | — | 0.2 | |||||||||||||
Amortization of actuarial losses | 1.3 | 5.4 | 0.1 | 0.8 | |||||||||||||
Net periodic benefit cost | $ | 0.7 | $ | 7.1 | $ | 4.5 | $ | 5.6 | |||||||||
SCEG | ' | ||||||||||||||||
Pension and Other Postretirement Benefit Plans | ' | ||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | ' | ||||||||||||||||
: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2014 | 2013 | 2014 | 2013 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 4 | $ | 4.8 | $ | 1 | $ | 1.2 | |||||||||
Interest cost | 8.6 | 8 | 2.4 | 2.2 | |||||||||||||
Expected return on assets | (14.2 | ) | (13.0 | ) | — | — | |||||||||||
Prior service cost amortization | 0.9 | 1.4 | 0.1 | 0.2 | |||||||||||||
Amortization of actuarial losses | 1.1 | 4.6 | 0.1 | 0.6 | |||||||||||||
Net periodic benefit cost | $ | 0.4 | $ | 5.8 | $ | 3.6 | $ | 4.2 | |||||||||
SEGMENT_OF_BUSINESS_INFORMATIO1
SEGMENT OF BUSINESS INFORMATION (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | ' | ||||||||||||||||
Millions of dollars | External | Intersegment Revenue | Operating | Net | |||||||||||||
Revenue | Income | Income | |||||||||||||||
Three Months Ended March 31, 2014 | |||||||||||||||||
Electric Operations | $ | 678 | $ | 2 | $ | 198 | n/a | ||||||||||
Gas Distribution | 455 | — | 97 | n/a | |||||||||||||
Retail Gas Marketing | 220 | — | n/a | $ | 22 | ||||||||||||
Energy Marketing | 234 | 53 | n/a | 7 | |||||||||||||
All Other | 9 | 110 | 8 | 4 | |||||||||||||
Adjustments/Eliminations | (6 | ) | (165 | ) | 47 | 160 | |||||||||||
Consolidated Total | $ | 1,590 | $ | — | $ | 350 | $ | 193 | |||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
Electric Operations | $ | 583 | $ | 2 | $ | 153 | n/a | ||||||||||
Gas Distribution | 379 | — | 93 | n/a | |||||||||||||
Retail Gas Marketing | 179 | — | n/a | $ | 22 | ||||||||||||
Energy Marketing | 167 | 42 | n/a | 3 | |||||||||||||
All Other | 12 | 107 | 7 | 3 | |||||||||||||
Adjustments/Eliminations | (9 | ) | (151 | ) | 40 | 123 | |||||||||||
Consolidated Total | $ | 1,311 | $ | — | $ | 293 | $ | 151 | |||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2014 | 2013 | |||||||||||||||
Electric Operations | $ | 9,542 | $ | 9,488 | |||||||||||||
Gas Distribution | 2,408 | 2,340 | |||||||||||||||
Retail Gas Marketing | 162 | 172 | |||||||||||||||
Energy Marketing | 154 | 133 | |||||||||||||||
All Other | 1,363 | 1,378 | |||||||||||||||
Adjustments/Eliminations | 1,713 | 1,653 | |||||||||||||||
Consolidated Total | $ | 15,342 | $ | 15,164 | |||||||||||||
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 March 31, 2014 | |||||||||||||||||
Electric Operations | $ | 680 | $ | 198 | n/a | ||||||||||||
Gas Distribution | 179 | 41 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 123 | |||||||||||||
Consolidated Total | $ | 859 | $ | 239 | $ | 123 | |||||||||||
Three Months Ended March 31, 2013 | |||||||||||||||||
Electric Operations | $ | 585 | $ | 153 | n/a | ||||||||||||
Gas Distribution | 143 | 38 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 89 | |||||||||||||
Consolidated Total | $ | 728 | $ | 191 | $ | 89 | |||||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2014 | 2013 | |||||||||||||||
Electric Operations | $ | 9,542 | $ | 9,488 | |||||||||||||
Gas Distribution | 692 | 686 | |||||||||||||||
Adjustments/Eliminations | 2,615 | 2,526 | |||||||||||||||
Consolidated Total | $ | 12,849 | $ | 12,700 | |||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 3 Months Ended | |||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 |
SCEG | SCEG | SCEG | SCEG | Genco | PSNC Energy [Member] | PSNC Energy [Member] | ||||
MW | MW | MW | ||||||||
Significant Accounting Policies | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of coal fired units to be retired | ' | ' | ' | ' | ' | 6 | 6 | ' | ' | ' |
Number of Units retired | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' |
Power Capacity of Retired Unit | ' | ' | ' | ' | ' | ' | 730 | ' | ' | ' |
Power generation capacity six coal fired units | ' | ' | ' | 730 | ' | ' | ' | ' | ' | ' |
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) | ' | ' | ' | ' | ' | ' | ' | ' | 26.00% | 48.00% |
Natural gas inventory, carrying amount | ' | ' | ' | ' | ' | ' | ' | ' | $4.20 | $22.80 |
Property, Plant and Equipment, Net | $315 | ' | $317 | $71 | $69 | ' | ' | $476 | ' | ' |
Earnings Per Share | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted Average Shares Outstanding - Basic | 141.1 | 134.4 | ' | ' | ' | ' | ' | ' | ' | ' |
Incremental Shares Attributable Equity Forward Agreements | 0 | 1.7 | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted Average Number of Shares Outstanding, Diluted | 141.1 | 136.1 | ' | ' | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT2
RATE AND OTHER REGULATORY MATTERS (Details) (USD $) | 3 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | ||||||||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | 1-May-15 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 |
SCEG | SCEG | SCEG | SCEG | SCEG | PSNC Energy | PSNC Energy | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Deferred Pollution Control Costs | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | Franchise agreement Costs | Storm damage reserve [Member] | ||||
SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | ||||||||||||||||||
Rate Matters [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fuel Costs | ' | ' | ' | $10.30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Undercollected balance fuel | ' | ' | ' | ' | ' | ' | 46 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Carrying costs on deferred income tax assets | ' | ' | ' | -1.2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Storm reserve applied to offset storm damage costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13.6 |
Carrying cost recovery | 2 | 0 | ' | 2 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | 1,467 | ' | 1,360 | 1,409 | ' | ' | 1,303 | ' | ' | 2.8 | 235 | 238 | 212 | 215 | ' | 37 | 37 | 37 | 30 | 31 | 30 | 31 | ' |
Number of coal fired units to be retired | ' | ' | ' | ' | 6 | ' | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | ' | ' | ' | ' | ' | ' | 2.90% | 2.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Allowable return on common equity (as a percent) | ' | ' | ' | 11.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | ' | ' | ' | 15.4 | 16.9 | ' | ' | 19.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Asset Recovery Assessments | ' | ' | ' | ' | ' | '12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (decrease) in retail electric rate requested under the BLRA | ' | ' | ' | ' | ' | ' | 67.2 | 52.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | 7.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Basis for rate calculation | ' | ' | ' | '12-month rolling average | ' | ' | ' | ' | '12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset Amortization Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 | '14 | '30 | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | ' | ' | 12 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14 | ' | 63 | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative, Gain on Derivative | ' | ' | ' | 17.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Storm Damage Reserve Cost Applied | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Offset From Interest Rate Regulatory Liability | ' | ' | ' | 5.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reduction to Net Lost Revenues from DSM programs | ' | ' | ' | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Lost Revenues associated with DSM programs | ' | ' | ' | 6.6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reduction to DSM Program costs deferred | ' | ' | ' | $6.60 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Units retired | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Demand side management recovery period | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecovered lost revenue period DSM programs | ' | ' | ' | 24 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT3
RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 |
In Millions, unless otherwise specified | 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] | 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 | unrecovered plant [Member] | unrecovered plant [Member] | unrecovered plant [Member] | unrecovered plant [Member] | Demand Side Management programs [Member] | Demand Side Management programs [Member] | Demand Side Management programs [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Other Regulatory Assets [Member] | Other Regulatory Liability [Member] | ||
SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | SCEG | ||||||||||||||||||||||||||||||
Regulatory Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liability, Noncurrent | $882 | $966 | $644 | $732 | $732 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1 |
Derivative, Gain on Derivative | ' | ' | 17.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Storm Damage Reserve Cost Applied | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | ' | ' | ' | 2.90% | 2.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | ' | ' | 15.4 | ' | 19.6 | 16.9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
MPG enviromental remediatio | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Noncurrent Asset, Amortization Period | ' | ' | ' | ' | ' | ' | '70 | ' | '70 | ' | ' | ' | ' | ' | ' | ' | ' | ' | '90 | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 | '14 | '30 | '30 | ' | '30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '30 | ' | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14 | ' | 63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | 1,467 | 1,360 | 1,409 | 1,303 | ' | ' | 258 | 259 | 254 | 256 | 36 | 18 | 36 | 18 | 41 | 41 | 37 | 37 | 373 | 368 | 354 | 350 | 30 | 31 | 30 | 31 | 235 | 238 | 212 | 215 | ' | 210 | 124 | 210 | 124 | 37 | 37 | 37 | 143 | 145 | 143 | 145 | 56 | 51 | 56 | 48 | 48 | 40 | 39 | ' |
Demand side management recovery period | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecovered lost revenue period DSM programs | ' | ' | 24 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Offset From Interest Rate Regulatory Liability | ' | ' | $5.50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
RATE_AND_OTHER_REGULATORY_MATT4
RATE AND OTHER REGULATORY MATTERS (Details 3) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2013 |
MW | ||||
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | $882 | $966 | ' | ' |
Deferred Income Tax Charges [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 23 | 24 | ' | ' |
Asset Retirement Obligation Costs [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 705 | 695 | ' | ' |
Storm damage reserve [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 14 | ' | ' | ' |
Amount allowed to be recovered through electric rates to offset incremental storm damage costs | 100 | ' | ' | ' |
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates | 2.5 | ' | ' | ' |
Monetization bankruptcy claim [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 28 | 29 | ' | ' |
Deferred gains on interest rate derivatives | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 106 | ' | ' | ' |
Planned major maintenance [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | 5 | ' | 10 | ' |
SCEG | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs | 16.8 | ' | ' | ' |
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | ' | 2.90% | 2.30% | ' |
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 11.00% | ' | ' | ' |
Power generation capacity six coal fired units | 730 | ' | ' | ' |
Demand Side Management Program Costs, Noncurrent | 15.4 | ' | 19.6 | 16.9 |
Regulatory liabilities | 644 | 732 | 732 | ' |
Amount allowed to be recovered through electric rates to offset incremental storm damage costs | 100 | ' | ' | ' |
Annual amount of storm damage costs which can not be offset by amounts recovered through electric rates | 2.5 | ' | ' | ' |
SCEG | Storm damage reserve [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | ' | 27 | ' | ' |
SCEG | Deferred gains on interest rate derivatives | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Regulatory liabilities | ' | 181 | ' | ' |
SCEG | Planned major maintenance [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
Amounts Recovered through Electric Rates to offset Turbine Expense | $18.40 | ' | ' | ' |
Environmental Restoration Costs [Member] | ' | ' | ' | ' |
Regulatory Liabilities: | ' | ' | ' | ' |
MPG enviromental remediatio | '26 | ' | ' | ' |
COMMON_EQUITY_Details
COMMON EQUITY (Details) (USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' |
Common Stock, Shares Authorized | 200,000,000 | ' | 200,000,000 | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' |
Forward Contract Indexed to Issuer's Equity, Indexed Shares | ' | 6,600,000 | ' | ' |
Dividends declared | ($74,000,000) | ($70,000,000) | ' | ' |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | -1,000,000 | 7,000,000 | ' | ' |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 0 | ' | ' |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 192,000,000 | 158,000,000 | ' | ' |
Stock Issued During Period, Value, New Issues | 27,000,000 | 221,000,000 | ' | ' |
Common Stock, Shares, Outstanding | 141,300,000 | ' | 140,700,000 | ' |
Proceeds from exercise of equity forward sales agreements | ' | 196,200,000 | ' | ' |
Common Stock, Value, Outstanding | 2,307,000,000 | 2,204,000,000 | 2,280,000,000 | 1,983,000,000 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -61,000,000 | -79,000,000 | -60,000,000 | -86,000,000 |
Retained Earnings, Unappropriated | 2,563,000,000 | 2,338,000,000 | 2,444,000,000 | 2,257,000,000 |
Other Comprehensive Income (Loss), Net of Tax | -1,000,000 | 7,000,000 | ' | ' |
Income Available to Common Shareholders | 193,000,000 | 151,000,000 | ' | ' |
Common equity | 4,809,000,000 | 4,463,000,000 | 4,664,000,000 | 4,154,000,000 |
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | -53,000,000 | -63,000,000 | -52,000,000 | -70,000,000 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | -8,000,000 | -16,000,000 | -8,000,000 | -16,000,000 |
SCEG | ' | ' | ' | ' |
Schedule of Capitalization, Equity [Line Items] | ' | ' | ' | ' |
Common Stock, Shares Authorized | 50,000,000 | ' | 50,000,000 | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126,000,000 | 92,000,000 | ' | ' |
Proceeds from Contributions from Parent | 20,000,000 | 221,000,000 | ' | ' |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 0 | ' | ' |
Net Income (Loss) Attributable to Noncontrolling Interest | 3,000,000 | 3,000,000 | ' | ' |
Dividends | -64,000,000 | -64,000,000 | ' | ' |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 126,000,000 | 92,000,000 | ' | ' |
Common Stock, Shares, Outstanding | 40,300,000 | ' | 40,300,000 | ' |
Preferred Stock, Shares Authorized | 20,000,000 | ' | 20,000,000 | ' |
Preferred Stock, Shares Outstanding | 1,000 | ' | 1,000 | ' |
Common Stock, Value, Outstanding | 2,499,000,000 | ' | 2,479,000,000 | ' |
Preferred Stock, Value, Issued | 100,000 | ' | 100,000 | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3,000,000 | ' | -3,000,000 | ' |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,571,000,000 | 4,292,000,000 | 4,489,000,000 | 4,043,000,000 |
Retained Earnings, Unappropriated | 1,957,000,000 | ' | 1,896,000,000 | ' |
Common equity | 4,453,000,000 | ' | 4,372,000,000 | ' |
SCEG excluding VIEs [Member] | ' | ' | ' | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' |
Proceeds from Contributions from Parent | 20,000,000 | 221,000,000 | ' | ' |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 0 | ' | ' |
Dividends | -62,000,000 | -62,000,000 | ' | ' |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 123,000,000 | 89,000,000 | ' | ' |
Common Stock, Value, Outstanding | 2,499,000,000 | 2,388,000,000 | 2,479,000,000 | 2,167,000,000 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3,000,000 | -4,000,000 | -3,000,000 | -4,000,000 |
Retained Earnings, Unappropriated | 1,957,000,000 | 1,793,000,000 | 1,896,000,000 | 1,766,000,000 |
Income Available to Common Shareholders | 123,000,000 | 89,000,000 | ' | ' |
Noncontrolling Interest [Member] | ' | ' | ' | ' |
COMMON EQUITY [Abstract] | ' | ' | ' | ' |
Net Income (Loss) Attributable to Noncontrolling Interest | 3,000,000 | 3,000,000 | ' | ' |
Dividends | -2,000,000 | -2,000,000 | ' | ' |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $118,000,000 | $115,000,000 | $117,000,000 | $114,000,000 |
LONGTERM_AND_SHORTTERM_DEBT_De
LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Jan. 31, 2013 |
In Millions, unless otherwise specified | Credit Suisse AG, Cayman Islands Branch (Member) | Branch Banking Trust Company [Member] | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCE&G (including Fuel Company) | SCEG | SCEG | SCEG | SCEG | PSNC Energy [Member] | PSNC Energy [Member] | Fuel Company | Fuel Company | Bonds [Member] | 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] | |||
Credit Suisse AG, Cayman Islands Branch (Member) | Branch Banking Trust Company [Member] | Credit Suisse AG, Cayman Islands Branch (Member) | Branch Banking Trust Company [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Increase, Additional Borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $39.50 | $14.70 | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | 3.63% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.20% | ' | ' | 4.00% |
Debt Instrument, Decrease, Repayments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56.9 | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,800 | ' | ' | ' | ' | 1,400 | 1,400 | ' | ' | 1,200 | ' | ' | ' | 100 | 100 | 500 | 500 | ' | ' | ' | ' |
Commercial Paper | ' | ' | ' | ' | ' | 457 | 251 | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' |
Debt, Weighted Average Interest Rate | ' | ' | ' | ' | ' | 0.26% | 0.27% | ' | ' | ' | ' | ' | ' | 0.00% | 0.00% | ' | ' | ' | ' | ' | ' |
Letters of Credit Outstanding, Amount | ' | ' | ' | ' | ' | 0.3 | 0.3 | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | 943 | 1,149 | ' | ' | ' | ' | ' | ' | 100 | 100 | ' | ' | ' | ' | ' | ' |
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | ' | ' | ' | 8.90% | 8.90% | ' | ' | 8.90% | 6.30% | ' | ' | 8.90% | 8.90% | ' | ' | ' | ' | ' | ' | ' | ' |
Number of other banks (in entities) | ' | 2 | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Debt, Current Maturities | 53 | 54 | ' | ' | ' | ' | ' | ' | ' | 47 | 48 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | $67.80 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
LONGTERM_AND_SHORTTERM_DEBT_De1
LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | 1-May-13 | Oct. 15, 2012 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Jan. 31, 2013 |
Wells Fargo Bank, National Association (Member) | Bank of America, N.A. (Member) | Morgan Stanly Bank, N.A. (Member) | Branch Banking 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 | Parent Company [Member] | Parent Company [Member] | 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 | Bonds [Member] | 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] | ||||
Wells Fargo Bank, National Association (Member) | Bank of America, N.A. (Member) | Morgan Stanly Bank, N.A. (Member) | Branch Banking 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 Trust Company [Member] | Credit Suisse AG, Cayman Islands Branch (Member) | |||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long Term Contract for Nuclear Fuel Purchase | ' | $100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Due to Affiliate, Current | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 117,000,000 | 117,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instruments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Increase, Additional Borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39,500,000 | 14,700,000 | ' |
Debt Instrument, Interest Rate, Stated Percentage | ' | ' | 3.63% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.20% | ' | ' | 4.00% |
Face value of Industrial Revenue Bonds issued, proceeds of which were availed as loan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 67,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Lines of credit: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | 1,800,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | 300,000,000 | 1,400,000,000 | 1,400,000,000 | ' | ' | ' | ' | ' | 500,000,000 | 500,000,000 | 100,000,000 | 100,000,000 | ' | ' | ' | ' |
Commercial Paper | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 103,000,000 | 125,000,000 | 457,000,000 | 251,000,000 | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' |
Commercial paper, weighted average interest rate (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.37% | 0.39% | 0.26% | 0.27% | ' | ' | ' | ' | ' | ' | ' | 0.00% | 0.00% | ' | ' | ' | ' |
Letters of credit supported by LOC | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | 3,000,000 | 300,000 | 300,000 | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 194,000,000 | 172,000,000 | 943,000,000 | 1,149,000,000 | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | 100,000,000 | ' | ' | ' | ' |
3 year credit agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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% | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term Line of Credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of other banks (in entities) | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction, Due from (to) Related Party, Current | 33,800,000 | 27,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Repayments of Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $56,900,000 | ' |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | 3 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2013 |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ' | ' | ' |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 6.00% | 5.00% | 6.90% |
SCEG | ' | ' | ' |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ' | ' | ' |
Unrecognized Tax Benefits | ' | ' | 3 |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
MMBTU | MMBTU | |||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 37,081,219 | [1] | 42,715,958 | [2] |
Nonmonetary Notional Amount of Basis Swap, Price Risk Derivative Instruments Not Designated as Hedging Instruments | 258,615 | 348,453 | ||
Interest Rate Derivatives [Abstract] | ' | ' | ||
Derivative, Notional Amount | $128,800,000 | $128,800,000 | ||
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value | 1,300,000,000 | 1,300,000,000 | ||
Additional Collateral, Aggregate Fair Value | 78,100,000 | 0 | ||
Derivative, Net Liability Position, Aggregate Fair Value | 109,000,000 | 25,200,000 | ||
Cash collateral to request from interest rate derivative counterparty | 2,000,000 | 34,100,000 | ||
Interest Rate Derivative, net asset position | 2,000,000 | 34,100,000 | ||
Gas Distribution | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 4,780,000 | 6,070,000 | ||
Retail Gas Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 4,325,000 | 6,726,000 | ||
Derivative not designated as hedging, nonmonetary amount | ' | 0 | ||
Energy Marketing [Member] | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 27,976,219 | [1] | 29,919,958 | [2] |
Commodity Contract | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 11,008,000 | 15,356,000 | ||
Commodity Contract | Gas Distribution | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 4,780,000 | 6,070,000 | ||
Commodity Contract | Retail Gas Marketing | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 4,325,000 | 6,726,000 | ||
Commodity Contract | Energy Marketing [Member] | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 1,903,000 | 2,560,000 | ||
Energy Management Contracts [Member] | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 26,073,219 | 27,359,958 | ||
Energy Management Contracts [Member] | Gas Distribution | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 0 | 0 | ||
Energy Management Contracts [Member] | Energy Marketing [Member] | ' | ' | ||
Derivative [Line Items] | ' | ' | ||
Derivative, Nonmonetary Notional Amount | 26,073,219 | 27,359,958 | ||
SCEG | ' | ' | ||
Interest Rate Derivatives [Abstract] | ' | ' | ||
Derivative, Notional Amount | 36,400,000 | 36,400,000 | ||
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value | 1,300,000,000 | 1,300,000,000 | ||
Additional Collateral, Aggregate Fair Value | 80,100,000 | 0 | ||
Derivative, Net Liability Position, Aggregate Fair Value | 84,200,000 | 1,000,000 | ||
Cash collateral to request from interest rate derivative counterparty | 0 | 31,700,000 | ||
Interest Rate Derivative, net asset position | $0 | $31,700,000 | ||
[1] | (a) Includes an aggregate 258,615 MMBTU related to basis swap contracts in Energy Marketing. | |||
[2] | (b) Includes an aggregate 348,453 MMBTU related to basis swap contracts in Energy Marketing. |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS (Details 2) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | $14,000,000 | $44,000,000 |
Derivative Asset | 14,000,000 | 44,000,000 |
Derivative Asset, Fair Value, Gross Liability | ' | 0 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability | 113,000,000 | 28,000,000 |
Liability Derivatives Fair Value | 113,000,000 | 28,000,000 |
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position | 0 | 0 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability, Fair Value of Collateral | 31,000,000 | 25,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 12,000,000 | 43,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 80,000,000 | 2,000,000 |
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value | 1,300,000,000 | 1,300,000,000 |
Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Asset | 8,000,000 | 21,000,000 |
Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Liability | 47,000,000 | 10,000,000 |
Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Liability | 66,000,000 | 18,000,000 |
Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Asset | 6,000,000 | 23,000,000 |
Derivatives designated as hedging instruments | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 2,000,000 |
Liability Derivatives Fair Value | 23,000,000 | 19,000,000 |
Not Designated as Hedging Instrument [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 12,000,000 | 42,000,000 |
Liability Derivatives Fair Value | 90,000,000 | 9,000,000 |
Energy Management Contracts [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 7,000,000 | 8,000,000 |
Derivative Asset | 7,000,000 | 8,000,000 |
Derivative Asset, Fair Value, Gross Liability | ' | 0 |
Derivative Liability | 7,000,000 | 8,000,000 |
Liability Derivatives Fair Value | 7,000,000 | 8,000,000 |
Derivative Liability Fair Value Gross Amount Offset in the Statement of Financial Position | 0 | 0 |
Derivative Liability, Fair Value of Collateral | -5,000,000 | -6,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 7,000,000 | 8,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 2,000,000 | 2,000,000 |
Interest Rate Contract | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 32,000,000 |
Derivative Asset | 2,000,000 | 32,000,000 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability | 106,000,000 | 20,000,000 |
Liability Derivatives Fair Value | 106,000,000 | 20,000,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability, Fair Value of Collateral | -26,000,000 | -19,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 0 | 31,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 78,000,000 | 0 |
Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | ' |
Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 4,000,000 | 5,000,000 |
Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 19,000,000 | ' |
Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | ' |
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 13,000,000 |
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 40,000,000 | 1,000,000 |
Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | 19,000,000 |
Commodity Contract | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 5,000,000 | 4,000,000 |
Derivative Asset | 5,000,000 | 4,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 5,000,000 | 4,000,000 |
Commodity Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 2,000,000 |
Commodity Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | ' | ' |
Commodity Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | ' | 14,000,000 |
Commodity Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 3,000,000 | 2,000,000 |
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 3,000,000 | 4,000,000 |
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 3,000,000 | 4,000,000 |
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 4,000,000 | ' |
Other Energy Management Contract [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 4,000,000 | 4,000,000 |
Liability Derivatives Fair Value | ' | 4,000,000 |
SCEG | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Asset | 2,000,000 | 32,000,000 |
Derivative Liability | 86,000,000 | 2,000,000 |
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value | 1,300,000,000 | 1,300,000,000 |
SCEG | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Asset | ' | 13,000,000 |
SCEG | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Liability | 41,000,000 | 2,000,000 |
SCEG | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Liability | 45,000,000 | ' |
SCEG | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Derivative Asset | 2,000,000 | 19,000,000 |
SCEG | Derivatives designated as hedging instruments | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | ' |
Liability Derivatives Fair Value | 3,000,000 | 1,000,000 |
SCEG | Not Designated as Hedging Instrument [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 32,000,000 |
Liability Derivatives Fair Value | 83,000,000 | 1,000,000 |
SCEG | Interest Rate Contract | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | 2,000,000 | 32,000,000 |
Derivative Asset | 2,000,000 | 32,000,000 |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability | 86,000,000 | 2,000,000 |
Liability Derivatives Fair Value | 86,000,000 | 2,000,000 |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -2,000,000 | -1,000,000 |
Derivative Liability, Fair Value of Collateral | 4,000,000 | 1,000,000 |
Net Fair Value Derivative Asset offset against Collateral | 0 | 31,000,000 |
Net Fair Value Derivative Liability offset against Collateral | 80,000,000 | 0 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | ' |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 1,000,000 | 1,000,000 |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 2,000,000 | ' |
SCEG | Interest Rate Contract | Derivatives designated as hedging instruments | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | ' |
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Prepayments and other current assets [member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | ' | 13,000,000 |
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other current liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 40,000,000 | 1,000,000 |
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other deferred credits and other liabilities | ' | ' |
Derivative [Line Items] | ' | ' |
Liability Derivatives Fair Value | 43,000,000 | ' |
SCEG | Interest Rate Contract | Not Designated as Hedging Instrument [Member] | Other Deferred Debits and Other Assets [Member] | ' | ' |
Derivative [Line Items] | ' | ' |
Asset Derivatives Fair Value | $2,000,000 | $19,000,000 |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Gain (Loss) on Derivatives | ' | ' | ' |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | '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 | $3 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | 2 | -4 | ' |
Derivative, Credit Risk Related Contingent Features [Abstract] | ' | ' | ' |
Collateral Already Posted, Aggregate Fair Value | 30.9 | ' | 26.8 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | 78.1 | ' | 0 |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 109 | ' | 25.2 |
Cashcollateralrequestedfromcounterparty | 2 | ' | 34.1 |
Derivative, net asset position | 2 | ' | 34.1 |
LetterofCreditAvailableCommodityDerivatives,assetposition | 5 | ' | 6 |
Commodity Derivative, net asset position | 7 | ' | 6 |
Interest Rate Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -3 | 35 | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -1 | -1 | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax | -2 | 1 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | -2 | -2 | ' |
Commodity Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 1 | ' | ' |
Effect of Cash Flow Hedges on Statement of Income | ' | ' | ' |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) On Derivatives Arising During Period, Net of Tax | -3 | -2 | ' |
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax | 4 | -2 | ' |
SCEG | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | 'insignificant | 'insignificant | ' |
Derivative, Credit Risk Related Contingent Features [Abstract] | ' | ' | ' |
Collateral Already Posted, Aggregate Fair Value | 4.1 | ' | 1.5 |
Additional collateral required to be posted to counterparties if all underlying contingent features were fully triggered | 80.1 | ' | 0 |
Aggregate fair value of all derivative instruments with contingent provisions that are in a net liability position | 84.2 | ' | 1 |
Cashcollateralrequestedfromcounterparty | 0 | ' | 31.7 |
Derivative, net asset position | 0 | ' | 31.7 |
SCEG | Interest Rate Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -3 | 35 | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | -1 | -1 | ' |
Interest Expense [Member] | Interest Rate Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 6.2 | ' | ' |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | -67.8 | ' | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | 0 | ' | ' |
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 | ' | ' |
Not Designated as Hedging Instrument [Member] | SCEG | Interest Rate Contract | ' | ' | ' |
Gain (Loss) on Derivatives | ' | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | -67.8 | ' | ' |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | 0 | ' | ' |
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 | ' | ' |
FAIR_VALUE_MEASUREMENTS_INCLUD2
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Additional Collateral, Aggregate Fair Value | $78,100,000 | $0 |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 14,000,000 | 44,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 113,000,000 | 28,000,000 |
Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 2,000,000 | 32,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 106,000,000 | 20,000,000 |
Commodity Contract | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 1,000,000 | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 5,000,000 | 4,000,000 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Available-for-sale Securities | 11,000,000 | 9,000,000 |
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 | 3,000,000 | 2,000,000 |
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 | 1,000,000 | 1,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 0 | 0 |
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 | 2,000,000 | 32,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 106,000,000 | 20,000,000 |
Fair Value, Inputs, Level 2 [Member] | Commodity Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 2,000,000 | 2,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | Other energy management contracts | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 6,000,000 | 7,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 10,000,000 | 12,000,000 |
SCEG | ' | ' |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ' | ' |
Additional Collateral, Aggregate Fair Value | 80,100,000 | 0 |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 2,000,000 | 32,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 86,000,000 | 2,000,000 |
SCEG | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 2,000,000 | 32,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | 86,000,000 | 2,000,000 |
SCEG | Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract | ' | ' |
Assets, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Asset | 2,000,000 | 32,000,000 |
Liabilities, Fair Value Disclosure [Abstract] | ' | ' |
Derivative Liability | $86,000,000 | $2,000,000 |
FAIR_VALUE_MEASUREMENTS_INCLUD3
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) | Mar. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Carrying Amount | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | $5,441.50 | $5,449.30 |
Estimated Fair Value | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | 6,096.80 | 5,916.30 |
SCEG | Carrying Amount | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | 4,047.60 | 4,054.90 |
SCEG | Estimated Fair Value | ' | ' |
Financial instruments for which the carrying amount may not equal estimated fair value | ' | ' |
Long-term debt | $4,574.20 | $4,433 |
EMPLOYEE_BENEFIT_PLANS_Details
EMPLOYEE BENEFIT PLANS (Details) (USD $) | 3 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Pension Benefits | Pension Benefits | Other Postretirement Benefits | Other Postretirement Benefits | SCEG | SCEG | SCEG | SCEG | SCEG | Pension Costs [Member] | Pension Costs [Member] | Pension Costs [Member] | ||
Pension Benefits | Pension Benefits | Other Postretirement Benefits | Other Postretirement Benefits | SCEG | SCEG | SCEG | |||||||
Pension and Other Postretirement Benefit Plans | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Pension Contributions | 'No | ' | ' | ' | ' | 'No | ' | ' | ' | ' | ' | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Service cost | ' | $5 | $5.90 | $1.20 | $1.60 | ' | $4 | $4.80 | $1 | $1.20 | ' | ' | ' |
Interest cost | ' | 10.2 | 9.5 | 3.1 | 2.8 | ' | 8.6 | 8 | 2.4 | 2.2 | ' | ' | ' |
Expected return on assets | ' | -16.8 | -15.4 | 0 | 0 | ' | -14.2 | -13 | 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 | ' | 1 | 1.7 | 0.1 | 0.2 | ' | 0.9 | 1.4 | 0 | 0.2 | ' | ' | ' |
Defined Benefit Plan, Amortization of Transition Obligations (Assets) | ' | 0 | 0 | 0 | 0.2 | ' | ' | ' | ' | ' | ' | ' | ' |
Defined Benefit Plan, Actuarial Net (Gains) Losses | ' | 1.3 | 5.4 | 0.1 | 0.8 | ' | 1.1 | 4.6 | 0 | -0.6 | ' | ' | ' |
Defined Benefit Plan, Net Periodic Benefit Cost | ' | 0.7 | 7.1 | 4.5 | 5.6 | ' | 0.4 | 5.8 | 3.6 | 4.2 | ' | ' | ' |
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $14 | ' | $63 |
Regulatory Noncurrent Asset, Amortization Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 | '14 | '30 |
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES (Details) (USD $) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Mar. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | Dec. 31, 2005 | Mar. 31, 2020 | Mar. 31, 2019 | Mar. 31, 2018 | |
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 | ' | ' | ' | ' | ' | ' |
Maximum liability assessment per reactor for each nuclear incident | 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 | ' | ' | ' | ' | ' | ' |
Maximum Federal Limit on Public Liability Claims per Reactor for each Nuclear Incident at 2/3 | 84,800,000 | ' | ' | ' | ' | ' | ' |
Inflation adjustment period for nuclear insurance | 5 | ' | ' | ' | ' | ' | ' |
Maximum retrospective insurance premium per nuclear incident | 41,600,000 | ' | ' | ' | ' | ' | ' |
Maximum amount of coverage to nuclear facility for property damage and outage costs | 2,750,000,000 | ' | ' | ' | ' | ' | ' |
Maximum amount of coverage for accidental property damage | 500,000,000 | ' | ' | ' | ' | ' | ' |
Maximum loss for a single nuclear incident | 2,750,000,000 | ' | ' | ' | ' | ' | ' |
Environmental | ' | ' | ' | ' | ' | ' | ' |
Number of MGP decommissioned sites that contain residues of byproduct chemicals | 4 | ' | ' | ' | ' | ' | ' |
Site Contingency MGP Estimated Environmental Remediation Costs | 20,200,000 | ' | ' | ' | ' | ' | ' |
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets | 36,700,000 | ' | ' | ' | ' | ' | ' |
Nuclear Generation | ' | ' | ' | ' | ' | ' | ' |
Estimated cash outflow for plant costs and related transmission infrastructure costs of nuclear electric generation site | 5,400,000,000 | ' | ' | ' | ' | ' | ' |
Current ownership share in New Unit | 55.00% | ' | ' | ' | ' | ' | ' |
Total additional ownership in new units | 5.00% | ' | ' | ' | ' | ' | ' |
Additional ownership in new units | ' | ' | ' | ' | 2.00% | 2.00% | 1.00% |
Jointly owned plant cost of additional 5% | ' | ' | 500,000,000 | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' |
Total Construction Milestones | ' | 146 | ' | ' | ' | ' | ' |
Milestone Schedule Contingency Period | ' | '18 | ' | ' | ' | ' | ' |
Completed Construction Milestones | ' | 98 | ' | ' | ' | ' | ' |
Delayed Construction Milestones | ' | 44 | ' | ' | ' | ' | ' |
Minimum Identified Delay Period | ' | '2 | ' | ' | ' | ' | ' |
Maximum Identified Delay Period | ' | '17 | ' | ' | ' | ' | ' |
PSNC Energy | ' | ' | ' | ' | ' | ' | ' |
Environmental | ' | ' | ' | ' | ' | ' | ' |
Number of MGP sites requiring cleanup | 5 | ' | ' | ' | ' | ' | ' |
SEGMENT_OF_BUSINESS_INFORMATIO2
SEGMENT OF BUSINESS INFORMATION (Details) (USD $) | 3 Months Ended | ||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | ' | ' | ' |
Electric Domestic Regulated Revenue | $678,000,000 | $583,000,000 | ' |
Intersegment Revenue | 0 | ' | ' |
Operating Income | 350,000,000 | 293,000,000 | ' |
Regulated Operating Revenue, Gas | 458,000,000 | 382,000,000 | ' |
Regulated and Unregulated Operating Revenue | 1,590,000,000 | 1,311,000,000 | ' |
Income Available to Common Shareholders of SCANA | 193,000,000 | 151,000,000 | ' |
Segment Assets | 15,342,000,000 | ' | 15,164,000,000 |
Electric Operations | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Electric Domestic Regulated Revenue | 678,000,000 | 583,000,000 | ' |
Intersegment Revenue | 2,000,000 | 2,000,000 | ' |
Operating Income | 198,000,000 | 153,000,000 | ' |
Segment Assets | 9,542,000,000 | ' | 9,488,000,000 |
Gas Distribution | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Intersegment Revenue | 0 | 0 | ' |
Operating Income | 97,000,000 | 93,000,000 | ' |
Regulated and Unregulated Operating Revenue | 455,000,000 | 379,000,000 | ' |
Segment Assets | 2,408,000,000 | ' | 2,340,000,000 |
Retail Gas Marketing | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Intersegment Revenue | 0 | 0 | ' |
Regulated and Unregulated Operating Revenue | 220,000,000 | 179,000,000 | ' |
Income Available to Common Shareholders of SCANA | 22,000,000 | 22,000,000 | ' |
Segment Assets | 162,000,000 | ' | 172,000,000 |
Energy Marketing [Member] | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Intersegment Revenue | 53,000,000 | 42,000,000 | ' |
Regulated and Unregulated Operating Revenue | 234,000,000 | 167,000,000 | ' |
Income Available to Common Shareholders of SCANA | 7,000,000 | 3,000,000 | ' |
Segment Assets | 154,000,000 | ' | 133,000,000 |
All Other [member] | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Intersegment Revenue | 110,000,000 | 107,000,000 | ' |
Operating Income | 8,000,000 | 7,000,000 | ' |
Regulated and Unregulated Operating Revenue | 9,000,000 | 12,000,000 | ' |
Income Available to Common Shareholders of SCANA | 4,000,000 | 3,000,000 | ' |
Segment Assets | 1,363,000,000 | ' | 1,378,000,000 |
Adjustments/Eliminations | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Intersegment Revenue | -165,000,000 | -151,000,000 | ' |
Operating Income | 47,000,000 | 40,000,000 | ' |
Regulated and Unregulated Operating Revenue | -6,000,000 | -9,000,000 | ' |
Income Available to Common Shareholders of SCANA | 160,000,000 | 123,000,000 | ' |
Segment Assets | 1,713,000,000 | ' | 1,653,000,000 |
SCEG | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Electric Domestic Regulated Revenue | 680,000,000 | 585,000,000 | ' |
Operating Income | 239,000,000 | 191,000,000 | ' |
Regulated Operating Revenue, Gas | 179,000,000 | 143,000,000 | ' |
Net Income (Loss) Attributable to Parent | 123,000,000 | 89,000,000 | ' |
Segment Assets | 12,849,000,000 | ' | 12,700,000,000 |
Regulated Operating Revenue | 859,000,000 | 728,000,000 | ' |
SCEG | Electric Operations | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Electric Domestic Regulated Revenue | 680,000,000 | 585,000,000 | ' |
Operating Income | 198,000,000 | 153,000,000 | ' |
Segment Assets | 9,542,000,000 | ' | 9,488,000,000 |
SCEG | Gas Distribution | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating Income | 41,000,000 | 38,000,000 | ' |
Regulated Operating Revenue, Gas | 179,000,000 | 143,000,000 | ' |
Segment Assets | 692,000,000 | ' | 686,000,000 |
SCEG | Adjustments/Eliminations | ' | ' | ' |
Segment Reporting Information [Line Items] | ' | ' | ' |
Operating Income | 0 | 0 | ' |
Net Income (Loss) Attributable to Parent | 123,000,000 | 89,000,000 | ' |
Segment Assets | 2,615,000,000 | ' | 2,526,000,000 |
Regulated Operating Revenue | $0 | $0 | ' |
AFFILIATED_TRANSACTIONS_SCEG_A
AFFILIATED TRANSACTIONS - SCEG AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) | 3 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Canadys Refined Coal LLC [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction Purchases from Related Party | $39.20 | $14.30 | ' |
Related Party Transaction, Amounts of Transaction | 39 | 14.3 | ' |
Due to Affiliate, Current | 4.4 | ' | 18 |
Due from Affiliate, Current | 4.4 | ' | 18 |
Equity Method Investment, Ownership Percentage | 40.00% | ' | ' |
CGT [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction Purchases from Related Party | 5.5 | 8.4 | ' |
Due to Affiliate, Current | 3.3 | ' | 3.3 |
Due from Affiliate, Current | 2.5 | ' | 1.3 |
Energy Marketing [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Due to Affiliate, Current | 17.2 | ' | 12.5 |
Cost of Natural Gas Purchases | 53.4 | 42.1 | ' |
SCANA Services [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Related Party Transaction Purchases from Related Party | 45.6 | ' | 49.1 |
Related Party Transaction, Expenses from Transactions with Related Party | $76.20 | $78.60 | ' |