Document_and_Entity_Informatio
Document and Entity Information Document | 3 Months Ended | |
Mar. 31, 2015 | Apr. 30, 2015 | |
Entity Information [Line Items] | ||
Entity Registrant Name | SCANA Corporation | |
Entity Central Index Key | 754737 | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | FALSE | |
Entity Common Stock, Shares Outstanding | 142,916,917 | |
SCEG | ||
Entity Information [Line Items] | ||
Entity Registrant Name | SOUTH CAROLINA ELECTRIC & GAS CO | |
Entity Central Index Key | 91882 | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Document Fiscal Year Focus | 2015 | |
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, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Assets | ||
Utility Plant In Service | $12,382 | $12,289 |
Accumulated Depreciation and Amortization | -4,141 | -4,088 |
Construction Work in Progress | 3,478 | 3,323 |
Plant to be Retired, Net | 164 | 169 |
Nuclear Fuel, Net of Accumulated Amortization | 317 | 329 |
Goodwill, Net of Writedown of $230 | 210 | 210 |
Utility Plant, Net | 12,410 | 12,232 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 285 | 284 |
Assets held in trust, net-nuclear decommissioning | 115 | 113 |
Other investments | 77 | 75 |
Nonutility Property and Investments, Net | 477 | 472 |
Current Assets: | ||
Cash and cash equivalents | 31 | 137 |
Receivables, net of allowance for uncollectible accounts | 778 | 838 |
Inventories (at average cost): | ||
Fuel | 175 | 222 |
Materials and supplies | 143 | 139 |
Prepaid Expense | 104 | 320 |
Other current assets | 204 | 148 |
Assets held for sale | 0 | 341 |
Total Current Assets | 1,435 | 2,145 |
Deferred Debits and Other Assets: | ||
Regulatory Assets, Noncurrent | 1,890 | 1,823 |
Other | 194 | 180 |
Total Deferred Debits and Other Assets | 2,084 | 2,003 |
Total | 16,406 | 16,852 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,392 | 2,378 |
Retained Earnings, Unappropriated | 3,006 | 2,684 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -73 | -75 |
Common equity | 5,325 | 4,987 |
Long-term Debt, Excluding Current Maturities | 5,525 | 5,531 |
Total Capitalization | 10,850 | 10,518 |
Current Liabilities: | ||
Short-term borrowings | 625 | 918 |
Current portion of long-term debt | 16 | 166 |
Accounts payable | 331 | 520 |
Customer deposits and customer prepayments | 109 | 98 |
Taxes accrued | 110 | 182 |
Interest accrued | 76 | 83 |
Dividends declared | 76 | 73 |
Liabilities held for sale | 52 | |
Derivative financial instruments | 292 | 233 |
Other | 97 | 208 |
Total Current Liabilities | 1,732 | 2,533 |
Deferred Credits and Other Liabilities: | ||
Deferred income taxes, net | 1,863 | 1,866 |
Deferred investment tax credits | 27 | 28 |
Asset retirement obligations | 566 | 563 |
Pension and other postretirement benefits | 316 | 315 |
Regulatory Liabilities | 829 | 814 |
Other | 223 | 215 |
Total Deferred Credits and Other Liabilities | 3,824 | 3,801 |
Total | 16,406 | 16,852 |
SCEG | ||
Assets | ||
Utility Plant In Service | 10,739 | 10,650 |
Accumulated Depreciation and Amortization | -3,716 | -3,667 |
Construction Work in Progress | 3,451 | 3,302 |
Plant to be Retired, Net | 164 | 169 |
Nuclear Fuel, Net of Accumulated Amortization | 317 | 329 |
Utility Plant, Net | 10,955 | 10,783 |
Nonutility Property and Investments: | ||
Nonutility property, net of accumulated depreciation | 67 | 67 |
Assets held in trust, net-nuclear decommissioning | 115 | 113 |
Other investments | 2 | 2 |
Nonutility Property and Investments, Net | 184 | 182 |
Current Assets: | ||
Cash and cash equivalents | 10 | 100 |
Receivables, net of allowance for uncollectible accounts | 490 | 524 |
Due from Affiliate, Current | 19 | 109 |
Inventories (at average cost): | ||
Fuel | 119 | 131 |
Materials and supplies | 131 | 129 |
Prepaid Expense | 79 | 154 |
Other current assets | 170 | 99 |
Total Current Assets | 1,018 | 1,246 |
Deferred Debits and Other Assets: | ||
Defined Benefit Plan, Assets for Plan Benefits, Noncurrent | 11 | 10 |
Regulatory Assets, Noncurrent | 1,817 | 1,745 |
Other | 149 | 141 |
Total Deferred Debits and Other Assets | 1,977 | 1,896 |
Total | 14,134 | 14,107 |
Capitalization and Liabilities | ||
Common Stock, Value, Outstanding | 2,556 | 2,560 |
Retained Earnings, Unappropriated | 2,130 | 2,077 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 |
Common equity | 4,683 | 4,634 |
Stockholders' Equity Attributable to Noncontrolling Interest | 126 | 123 |
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,809 | 4,757 |
Long-term Debt, Excluding Current Maturities | 4,293 | 4,299 |
Total Capitalization | 9,102 | 9,056 |
Current Liabilities: | ||
Short-term borrowings | 610 | 709 |
Current portion of long-term debt | 10 | 10 |
Accounts payable | 181 | 294 |
Due to Affiliate, Current | 365 | 180 |
Customer deposits and customer prepayments | 66 | 61 |
Taxes accrued | 120 | 170 |
Interest accrued | 57 | 64 |
Dividends declared | 71 | 74 |
Derivative financial instruments | 289 | 208 |
Other | 45 | 99 |
Total Current Liabilities | 1,814 | 1,869 |
Deferred Credits and Other Liabilities: | ||
Deferred income taxes, net | 1,703 | 1,696 |
Deferred investment tax credits | 27 | 28 |
Asset retirement obligations | 539 | 536 |
Pension and other postretirement benefits | 220 | 195 |
Regulatory Liabilities | 621 | 610 |
Other | 108 | 117 |
Total Deferred Credits and Other Liabilities | 3,218 | 3,182 |
Total | $14,134 | $14,107 |
CONDENSED_CONSOLIDATED_BALANCE1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Common Stock, Shares, Outstanding | 143 | 143 |
Public Utilities, Property, Plant and Equipment, Net | $12,410 | $12,232 |
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 120 | 122 |
Allowance for Doubtful Accounts Receivable, Current | 7 | 7 |
Write-down, Goodwill | 230 | 230 |
Assets, Current | 1,435 | 2,145 |
Regulated Entity, Other Assets, Noncurrent | 2,084 | 2,003 |
SCEG | ||
Common Stock, Shares, Outstanding | 40 | 40 |
Public Utilities, Property, Plant and Equipment, Net | 10,955 | 10,783 |
Allowance for Doubtful Accounts Receivable, Current | 3 | 4 |
Assets, Current | 1,018 | 1,246 |
Regulated Entity, Other Assets, Noncurrent | 1,977 | 1,896 |
SCEG | Variable Interest Entity, Primary Beneficiary [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 716 | 675 |
Assets, Current | 0 | 158 |
Regulated Entity, Other Assets, Noncurrent | $0 | $50 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Operating Revenues: | ||
Electric Domestic Regulated Revenue | $629 | $678 |
Regulated Operating Revenue, Gas | 369 | 458 |
Gas-nonregulated | 391 | 454 |
Regulated and Unregulated Operating Revenue | 1,389 | 1,590 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 174 | 212 |
Purchased power | 13 | 25 |
Gas purchased for resale | 523 | 670 |
Other operation and maintenance | 173 | 180 |
Depreciation and amortization | 96 | 95 |
Other taxes | 59 | 58 |
Total Operating Expenses | 1,038 | 1,240 |
Gain (Loss) on Disposition of Business | 235 | 0 |
Operating Income | 586 | 350 |
Other Income (Expense): | ||
Other income | 19 | 15 |
Other expenses | -12 | -14 |
Gain (Loss) On Disposition Of Unregulated Business Net Of Transaction Costs | 107 | 0 |
Interest Expense | -77 | -76 |
Allowance for equity funds used during construction | 5 | 7 |
Total Other Expense | 42 | -68 |
Income Before Income Tax Expense | 628 | 282 |
Income Tax Expense | 228 | 89 |
Net Income | 400 | 193 |
Per Common Share Data | ||
Basic Earnings Per Share of Common Stock (in dollars per share) | $2.80 | $1.37 |
Weighted Average Number of Shares Outstanding, Basic and Diluted | 142.9 | 141.1 |
Common Stock, Dividends, Per Share, Declared | $0.55 | $0.53 |
SCEG | ||
Operating Revenues: | ||
Electric Domestic Regulated Revenue | 630 | 680 |
Regulated Operating Revenue, Gas | 142 | 179 |
Regulated Operating Revenue | 772 | 859 |
Operating Expenses [Abstract] | ||
Fuel used in electric generation | 174 | 214 |
Purchased power | 13 | 25 |
Gas purchased for resale | 74 | 109 |
Other operation and maintenance | 139 | 142 |
Depreciation and amortization | 80 | 78 |
Other taxes | 55 | 52 |
Total Operating Expenses | 535 | 620 |
Operating Income | 237 | 239 |
Other Income (Expense): | ||
Other income | 9 | 3 |
Other expenses | -8 | -6 |
Interest Expense | -59 | -56 |
Allowance for equity funds used during construction | 5 | 5 |
Total Other Expense | -53 | -54 |
Income Before Income Tax Expense | 184 | 185 |
Income Tax Expense | 58 | 59 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 126 |
Net Income (Loss) Attributable to Noncontrolling Interest | -4 | -3 |
Earnings Available to Common Shareholder | 122 | 123 |
Per Common Share Data | ||
Dividends, Common Stock, Cash | $71 | $64 |
CONDENSED_CONSOLIDATED_STATEME1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Allowance for Funds Used During Construction, Capitalized Interest | $3 | $3 |
Earnings Per Share, Diluted | $2.80 | $1.37 |
SCEG | ||
Allowance for Funds Used During Construction, Capitalized Interest | $3 | $3 |
CONDENSED_CONSOLIDATED_STATEME2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | $400 | $193 |
Other Comprehensive Income (Loss) | ||
Unrealized gains (losses) on cash flow hedging activities arising during period | -3 | 1 |
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 6 | -1 |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Reclassification Adjustments, Net of Tax | -4 | 0 |
Other Comprehensive Income (Loss) | 2 | -1 |
SCEG | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 126 |
Other Comprehensive Income (Loss) | ||
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest | 126 | 126 |
Genco | ||
Other Comprehensive Income (Loss) | ||
Less comprehensive income attributable to noncontrolling interest | 4 | 3 |
SCE&G (including Fuel Company) | ||
Net Income (Loss) Attributable to Parent [Abstract] | ||
Net Income (Loss) Available to Common Stockholders, Basic | 122 | 123 |
Commodity Contract | ||
Other Comprehensive Income (Loss) | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 7 | -4 |
Interest Rate Contract | ||
Other Comprehensive Income (Loss) | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | 2 |
Cash Flow Hedging [Member] | Interest Expense [Member] | Interest Rate Contract | ||
Other Comprehensive Income (Loss) | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | ($2) | ($2) |
CONDENSED_CONSOLIDATED_STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax | $0 | $0 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax | -2 | 1 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax | 1 | 1 |
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income, Tax | 5 | -2 |
Commodity Contract | ||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $7 | ($4) |
CONDENSED_CONSOLIDATED_STATEME4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Cash Flows From Operating Activities: | ||
Net Income (Loss) Available to Common Stockholders, Basic | $400 | $193 |
Adjustments to reconcile net income to net cash provided from operating activities: | ||
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal | -353 | |
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions | 1 | 1 |
Deferred Income Tax Expense (Benefit) | -74 | 7 |
Depreciation and amortization | 100 | 99 |
Amortization of nuclear fuel | 13 | 15 |
Allowance for equity funds used during construction | -5 | -7 |
Carrying cost recovery | -3 | -2 |
Cash provided (used) by changes in certain assets and liabilities: | ||
Receivables | 33 | -56 |
Inventories | 31 | 70 |
Increase (Decrease) in Prepaid Expense | -218 | -12 |
Increase (Decrease) in Other Regulatory Assets | -68 | -108 |
Regulatory liabilities | 6 | -94 |
Accounts payable | -67 | 29 |
Taxes accrued | -71 | -143 |
Interest accrued | -7 | -7 |
Increase (Decrease) in Pension and Postretirement Obligations | -1 | -2 |
Increase (Decrease) in Derivative Assets and Liabilities | 59 | 39 |
Changes in other assets | -6 | 11 |
Changes in other liabilities | -11 | 81 |
Net Cash Provided From Operating Activities | 195 | 138 |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | -352 | -289 |
Proceeds from Sale of Property, Plant, and Equipment | 645 | |
Proceeds from investments (including derivative collateral posted) | 318 | 16 |
Purchase of investments (including derivative collateral posted) | -400 | -22 |
Net Cash Used in Investing Activities | 211 | -295 |
Cash Flows From Financing Activities: | ||
Proceeds from Issuance of Common Stock | 14 | 22 |
Repayments of Long-term Debt | -158 | -9 |
Dividends | -75 | -66 |
Short-term borrowings, net | -293 | 184 |
Net Cash Provided From Financing Activities | -512 | 131 |
Net (Decrease) Increase in Cash and Cash Equivalents | -106 | -26 |
Cash and Cash Equivalents, January 1 | 137 | 136 |
Cash and Cash Equivalents, March 31 | 31 | 110 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 81 | 80 |
Cash paid for-Income taxes | 8 | 100 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | 84 | 77 |
Capital Lease Obligations Incurred | 2 | 1 |
SCEG | ||
Cash Flows From Operating Activities: | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 126 |
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) | 7 | 5 |
Depreciation and amortization | 82 | 78 |
Amortization of nuclear fuel | 13 | 15 |
Allowance for equity funds used during construction | -5 | -5 |
Carrying cost recovery | -3 | -2 |
Cash provided (used) by changes in certain assets and liabilities: | ||
Receivables | 22 | -23 |
Inventories | 0 | 19 |
Increase (Decrease) in Prepaid Expense | -75 | -7 |
Increase (Decrease) in Other Regulatory Assets | -74 | -107 |
Regulatory liabilities | 6 | -94 |
Accounts payable | -20 | 27 |
Taxes accrued | -50 | -127 |
Interest accrued | -7 | -11 |
Increase (Decrease) in Pension and Postretirement Obligations | 22 | -2 |
Increase (Decrease) in Derivative Assets and Liabilities | 81 | 40 |
Changes in other assets | -3 | 15 |
Changes in other liabilities | -49 | 81 |
Net Cash Provided From Operating Activities | 224 | 43 |
Cash Flows From Investing Activities: | ||
Property additions and construction expenditures | -319 | -260 |
Proceeds from investments (including derivative collateral posted) | 274 | 4 |
Purchase of investments (including derivative collateral posted) | -356 | -9 |
Investment In Affiliate | 80 | |
Net Cash Used in Investing Activities | -321 | -265 |
Cash Flows From Financing Activities: | ||
Repayments of Long-term Debt | -8 | -9 |
Dividends | -74 | -62 |
Contributions from parent | -4 | 20 |
Short-term borrowings, net | -99 | 206 |
Short-term borrowings-affiliate,net | 192 | 7 |
Net Cash Provided From Financing Activities | 7 | 162 |
Net (Decrease) Increase in Cash and Cash Equivalents | -90 | -60 |
Cash and Cash Equivalents, January 1 | 100 | 92 |
Cash and Cash Equivalents, March 31 | 10 | 32 |
Supplemental Cash Flow Information: | ||
Cash paid for-Interest (net of capitalized interest ) | 62 | 62 |
Cash paid for-Income taxes | -83 | 59 |
Noncash Investing and Financing Activities: | ||
Accrued construction expenditures | 76 | 97 |
Capital Lease Obligations Incurred | $2 | $1 |
CONDENSED_CONSOLIDATED_STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Interest Paid, Capitalized | $3 | $3 |
SCEG | ||
Interest Paid, Capitalized | $3 | $3 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 3 Months Ended |
Mar. 31, 2015 | |
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 | |
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |
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.  There were no securities considered to be dilutive potential common stock during any period presented. The Company has issued no securities that would have an antidilutive effect on earnings per share. | |
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 32% and 48% of PSNC Energy’s natural gas inventory at March 31, 2015 | |
and December 31, 2014, respectively, with a carrying value of $8.7 million and $26.1 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, which expired on March 31, 2015, have been replaced with similar agreements that expire March 31, 2017. | |
Income Statement Presentation | |
The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense). | |
New Accounting Matters | |
In April 2014, the FASB issued new accounting guidance for reporting discontinued operations and disclosures of disposals of components of an entity. Under this new guidance, only those discontinued operations which represent a strategic shift that will have a major effect on an entity’s operations and financial results should be reported as discontinued operations in the financial statements. As permitted, the Company adopted this new guidance for the period ended December 31, 2014. | |
In May 2014, the FASB issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Currently, the Company would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year. The Company has not determined the impact this guidance will have on its results of operations, cash flows or financial position. | |
In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, the Company expects to early adopt this new guidance in the fourth quarter of 2015. The Company does not expect the adoption of this guidance to have a significant impact on its financial position. The guidance will not affect the Company’s results of operations or cash flows. | |
In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement.  Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. The Company expects to adopt this new guidance in the first quarter of 2016. The Company is evaluating this guidance and has not determined what impact it will have on the Company’s results of operations, cash flows or financial position. | |
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 has a controlling financial interest in 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 $498 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 | |
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |
    | |
New Accounting Matters | |
In May 2014, the FASB issued new accounting guidance for revenue arising from contracts with customers that supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Currently, Consolidated SCE&G would be required to adopt the new guidance in the first quarter of 2017, and early adoption would not be permitted. However, the FASB may defer the adoption of this guidance for one year. Consolidated SCE&G has not determined the impact this guidance will have on its results of operations, cash flows or financial position. | |
In April 2015, the FASB issued new accounting guidance intended to simplify the presentation of debt issuance costs by requiring that such costs be deducted from the carrying amounts related to debt liabilities when presented in the balance sheet. As permitted, Consolidated SCE&G expects to early adopt this new guidance in the fourth quarter of 2015. Consolidated SCE&G does not expect the adoption of this guidance to have a significant impact on its financial position. The guidance will not affect Consolidated SCE&G’s results of operations or cash flows. | |
In April 2015, the FASB issued new accounting guidance related to fees paid by a customer in a cloud computing arrangement. Â Among other things, the new guidance clarifies how to account for a software license element included in a cloud computing arrangement, and makes explicit that a cloud computing arrangement not containing a software license element should be accounted for as a service contract. Consolidated SCE&G expects to adopt this new guidance in the first quarter of 2016. Consolidated SCE&G is evaluating this guidance and has not determined what impact it will have on its results of operations, cash flows or financial position. |
RATE_AND_OTHER_REGULATORY_MATT
RATE AND OTHER REGULATORY MATTERS | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
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 base 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 the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, the Company's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. See also Note 6. | |||||||||
The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings. | |||||||||
By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015. | |||||||||
On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015. Â Â Â Â | |||||||||
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 $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. | |||||||||
SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. | |||||||||
SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenues associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below: | |||||||||
Year | Effective | Amount | |||||||
2015 | First billing cycle of May | $32.0 million | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 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 revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | ||||||||
• | In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. | ||||||||
• | In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year. | ||||||||
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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: | |||||||||
Year | Action | Amount | |||||||
2014 | 2.8 | % | Increase | $66.2 million | |||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9. | |||||||||
In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above. Any additional financing cost recovery approved by the SCPSC would be expected to be effective for bills rendered on and after October 30, 2015. It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition. | |||||||||
Gas | |||||||||
SCE&G | |||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years:Â | |||||||||
Year | Action | Amount | |||||||
2014 | 0.6 | % | Decrease | $2.6 million | |||||
2013 | Â Â No change | - | |||||||
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 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 September 2014, in connection with PSNC Energy's 2014 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2014. | |||||||||
In May 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate that had been enacted by the North Carolina legislature and to file a proposal to refund amounts previously collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and refunded the amounts collected on a provisional basis through the normal operation of its Rider D rate mechanism. These amounts were not significant for any period presented. | |||||||||
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, | |||||||
2015 | 2014 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 282 | $ | 284 | |||||
Under-collections - electric fuel adjustment clause | 4 | 20 | |||||||
Environmental remediation costs | 40 | 40 | |||||||
AROs and related funding | 370 | 366 | |||||||
Franchise agreements | 25 | 26 | |||||||
Deferred employee benefit plan costs | 337 | 350 | |||||||
Planned major maintenance | — | 2 | |||||||
Deferred losses on interest rate derivatives | 549 | 453 | |||||||
Deferred pollution control costs | 35 | 36 | |||||||
Unrecovered plant | 132 | 137 | |||||||
DSM Programs | 58 | 56 | |||||||
Carrying costs on deferred tax assets related to nuclear construction | 11 | 9 | |||||||
Pipeline integrity management costs | 10 | 9 | |||||||
Other | 37 | 35 | |||||||
Total Regulatory Assets | $ | 1,890 | $ | 1,823 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 22 | $ | 22 | |||||
Asset removal costs | 712 | 703 | |||||||
Storm damage reserve | 6 | 6 | |||||||
Deferred gains on interest rate derivatives | 82 | 82 | |||||||
Planned major maintenance | 7 | — | |||||||
Other | — | 1 | |||||||
Total Regulatory Liabilities | $ | 829 | $ | 814 | |||||
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | |||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. | |||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by the Company, and are expected to be recovered over periods of up to approximately 25 years. | |||||||||
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. | |||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2020. | |||||||||
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years. | |||||||||
Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders. SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. | |||||||||
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 approximately 2025. Unamortized amounts are included in rate base and are earning a current return. | |||||||||
DSM Programs represent deferred costs associated with such programs. As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. | |||||||||
Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021. | |||||||||
Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to certain natural gas pipelines located near moderate to high density populations. Such costs will be considered for recovery through rates in PSNC Energy's next general rate proceeding. | |||||||||
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 2015, no amounts were applied to offset incremental storm damage costs. | |||||||||
The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. | |||||||||
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. In connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of base fuel costs, and approved SCE&G's total fuel cost component. | |||||||||
By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The base fuel cost increase was offset by a reduction in SCE&G's rate rider related to pension costs, which was approved by the SCPSC in March 2014. In addition, pursuant to the April 29, 2014 order, SCE&G's electric revenue for 2014 was reduced by approximately $46 million for adjustments to the fuel cost component and related under-collected fuel balance. Such adjustments are fully offset by the recognition within other income of gains realized from the late 2013 settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. The order also provided for the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015. See also Note 6. | |||||||||
    | |||||||||
The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. The impact of changes to the Nuclear Waste Act fee is considered during annual fuel rate proceedings. | |||||||||
By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G, the ORS, and the SCEUC in which SCE&G agreed to decrease the total fuel cost component of its retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, which is estimated to be $36.1 million, over a 12-month period beginning with the first billing cycle of May 2015. | |||||||||
On February 9, 2015, SCE&G petitioned the SCPSC for approval to participate in a DER program and to recover DER program costs as a separate component of SCE&G's overall fuel factor. SCE&G's DER program is structured to achieve, no later than December 31, 2020, renewable energy facilities within South Carolina with an aggregate amount of installed nameplate generating capacity equal to at least two percent of the previous five-year average of SCE&G's retail peak demand. A public hearing on this matter has been scheduled to begin on June 2, 2015. | |||||||||
Electric - Base Rates | |||||||||
In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate, and $1.9 million and $1.2 million of such carrying costs were accrued within other income during each of the three months ended March 31, 2015 and 2014, respectively. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized. | |||||||||
    SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G previously identified six coal-fired units that it has subsequently retired or intends to retire by 2020, subject to future developments in environmental regulations, among other matters. Three of these units were retired by December 31, 2013, and their net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. The net carrying value of the remaining units is included in Plant to be Retired, Net. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. | |||||||||
SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenues associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC approved recovery of the following amounts pursuant to annual DSM Programs filings, which went into effect as indicated below: | |||||||||
Year | Effective | Amount | |||||||
2015 | First billing cycle of May | $32.0 million | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 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 revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014. | ||||||||
• | In April 2014 the SCPSC approved SCE&G’s request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments, to the remaining balance of deferred net lost revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order. | ||||||||
• | In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year. | ||||||||
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 recovery of the following amounts under the BLRA effective for bills rendered on and after October 30 in the following years: | |||||||||
Year | Action | Amount | |||||||
2014 | 2.8 | % | Increase | $66.2 million | |||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
On March 12, 2015, SCE&G petitioned the SCPSC seeking approval of an updated construction milestone schedule and capital cost schedule for the New Units. The updated construction schedule reflects new substantial completion dates for Units 2 and 3 of June 2019, and June 2020, respectively. The petition also incorporates in the construction cost schedules approximately $698 million (SCE&G’s portion in 2007 dollars) in incremental capital costs that have been identified since the last approved order in November 2012, of which $539 million (SCE&G’s portion in 2007 dollars) are associated with construction delays and other contested costs. The total project capital cost is now estimated at approximately $5.2 billion (SCE&G’s portion in 2007 dollars) or $6.8 billion including escalation and allowance for funds used during construction (SCE&G’s portion in future dollars). As noted in the petition, the construction and capital cost schedules are subject to continuing review and negotiations by the parties. In making this filing, SCE&G does not waive any claims related to delay and other related contested costs with the Consortium. A public hearing on this matter is scheduled to begin on July 21, 2015, and the SCPSC is expected to issue its order in September 2015. See Note 9. | |||||||||
In May 2015, SCE&G expects to file an application to recover through revised rates the financing cost of incremental construction work in progress incurred for new nuclear generation since the last rate action described above. Any additional financing cost recovery approved by the SCPSC would be expected to be effective for bills rendered on and after October 30, 2015. It is expected that such rate action would be contingent upon a favorable SCPSC order on the March 2015 petition. | |||||||||
Gas | |||||||||
  | |||||||||
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years: | |||||||||
Year | Action | Amount | |||||||
2014 | 0.6 | % | Decrease | $2.6 million | |||||
2013 | Â Â No change | - | |||||||
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2014 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, | |||||||
2015 | 2014 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 276 | $ | 278 | |||||
Under collections – electric fuel adjustment clause | 4 | 20 | |||||||
Environmental remediation costs | 35 | 36 | |||||||
AROs and related funding | 350 | 347 | |||||||
Franchise agreements | 25 | 26 | |||||||
Deferred employee benefit plan costs | 305 | 310 | |||||||
Planned major maintenance | — | 2 | |||||||
Deferred losses on interest rate derivatives | 549 | 453 | |||||||
Deferred pollution control costs | 35 | 36 | |||||||
Unrecovered plant | 132 | 137 | |||||||
DSM Programs | 58 | 56 | |||||||
Carrying costs on deferred tax assets related to nuclear construction | 11 | 9 | |||||||
Other | 37 | 35 | |||||||
Total Regulatory Assets | $ | 1,817 | $ | 1,745 | |||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 16 | $ | 17 | |||||
Asset removal costs | 510 | 505 | |||||||
Storm damage reserve | 6 | 6 | |||||||
Deferred gains on interest rate derivatives | 82 | 82 | |||||||
Planned major maintenance | 7 | — | |||||||
Total Regulatory Liabilities | $ | 621 | $ | 610 | |||||
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset.  Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. | |||||||||
Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC which are expected to be recovered in retail electric rates over periods exceeding 12 months. | |||||||||
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 25 years. | |||||||||
ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs related to generation, transmission and distribution properties, including gas pipelines. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. | |||||||||
Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2020. | |||||||||
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. Accordingly, in 2013 SCE&G began recovering through utility rates approximately $63 million of deferred pension costs for electric operations over approximately 30 years and approximately $14 million of deferred pension costs for gas operations over approximately 14 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years. | |||||||||
Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, pursuant to specific SCPSC orders.  SCE&G collects and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges. | |||||||||
Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments made or received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. | |||||||||
Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045. | |||||||||
Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. | |||||||||
DSM Programs represent deferred costs associated with such programs. As a result of an April 2015 SCPSC order, deferred costs are currently being recovered over approximately five years through an approved rate rider. | |||||||||
Carrying costs on deferred tax assets related to nuclear construction represent accrued carrying costs on accumulated deferred income tax assets associated with the New Units which are not part of electric base rates. These carrying costs are computed using weighted average debt cost of capital and will be amortized over ten years beginning in approximately 2021. | |||||||||
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 2015, no amounts were applied to offset incremental storm damage costs. | |||||||||
The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by the SCPSC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded. |
COMMON_EQUITY
COMMON EQUITY | 3 Months Ended | |||||||||||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||||||||||
Schedule of Capitalization, Equity [Line Items] | ||||||||||||||||||||||||||||
Stockholders' Equity Note Disclosure [Text Block] | Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows: | |||||||||||||||||||||||||||
Common Stock | Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||||||||||
Millions | Shares | Amount | Retained Earnings | Gains(Losses) on Cash Flow Hedges | Deferred Employee Benefit Plans | Total AOCI | Total Common Equity | |||||||||||||||||||||
Balance as of January 1, 2015 | 143 | $ | 2,378 | $ | 2,684 | $ | (63 | ) | $ | (12 | ) | $ | (75 | ) | $ | 4,987 | ||||||||||||
Net Income | 400 | 400 | ||||||||||||||||||||||||||
Other Comprehensive Income (Loss): | ||||||||||||||||||||||||||||
Losses arising during the period | (3 | ) | (4 | ) | (7 | ) | (7 | ) | ||||||||||||||||||||
Gains/amortization reclassified from AOCI | 9 | — | 9 | 9 | ||||||||||||||||||||||||
Total Comprehensive Income (Loss) | 400 | 6 | (4 | ) | 2 | 402 | ||||||||||||||||||||||
Issuance of Common Stock | — | 14 | 14 | |||||||||||||||||||||||||
Dividends Declared | (78 | ) | (78 | ) | ||||||||||||||||||||||||
Balance as of March 31, 2015 | 143 | $ | 2,392 | $ | 3,006 | $ | (57 | ) | $ | (16 | ) | $ | (73 | ) | $ | 5,325 | ||||||||||||
Balance as of January 1, 2014 | 141 | $ | 2,280 | $ | 2,444 | $ | (52 | ) | $ | (8 | ) | $ | (60 | ) | $ | 4,664 | ||||||||||||
Net Income | 193 | 193 | ||||||||||||||||||||||||||
Other Comprehensive Income: | ||||||||||||||||||||||||||||
Gains arising during the period | 1 | — | 1 | 1 | ||||||||||||||||||||||||
Losses/amortization reclassified from AOCI | (2 | ) | — | (2 | ) | (2 | ) | |||||||||||||||||||||
Total Comprehensive Income | 193 | (1 | ) | — | (1 | ) | 192 | |||||||||||||||||||||
Issuance of Common Stock | — | 27 | 27 | |||||||||||||||||||||||||
Dividends Declared | (74 | ) | (74 | ) | ||||||||||||||||||||||||
Balance as of March 31, 2014 | 141 | $ | 2,307 | $ | 2,563 | $ | (53 | ) | $ | (8 | ) | $ | (61 | ) | $ | 4,809 | ||||||||||||
Gains and losses on cash flow hedges reclassified during the three months ended March 31, 2015 resulted in higher interest expense of $2 million and higher cost of gas purchased for resale of $7 million. Such reclassifications during the comparable period in 2014 resulted in higher interest expense of $2 million and lower cost of gas purchased for resale of $4 million. | ||||||||||||||||||||||||||||
SCANA had 200 million shares of common stock authorized as of March 31, 2015 and December 31, 2014. | ||||||||||||||||||||||||||||
SCEG | ||||||||||||||||||||||||||||
Schedule of Capitalization, Equity [Line Items] | ||||||||||||||||||||||||||||
Stockholders' Equity Note Disclosure [Text Block] | EQUITY | |||||||||||||||||||||||||||
Changes in common equity during the three months ended March 31, 2015 and 2014 were as follows: | ||||||||||||||||||||||||||||
Common Stock | Retained | Accumulated Other Comprehensive | Noncontrolling | Total | ||||||||||||||||||||||||
Millions | Shares | Amount | Earnings | Income (Loss) | Interest | Equity | ||||||||||||||||||||||
Balance at January 1, 2015 | 40 | $ | 2,560 | $ | 2,077 | $ | (3 | ) | $ | 123 | $ | 4,757 | ||||||||||||||||
Earnings available to common shareholder | 122 | 4 | 126 | |||||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | ||||||||||||||||||||||||||
Total Comprehensive Income | 122 | — | 4 | 126 | ||||||||||||||||||||||||
Capital returned to parent | (4 | ) | (4 | ) | ||||||||||||||||||||||||
Cash dividend declared | (69 | ) | (1 | ) | (70 | ) | ||||||||||||||||||||||
Balance at March 31, 2015 | 40 | $ | 2,556 | $ | 2,130 | $ | (3 | ) | $ | 126 | $ | 4,809 | ||||||||||||||||
Balance at January 1, 2014 | 40 | $ | 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 | 40 | $ | 2,499 | $ | 1,957 | $ | (3 | ) | $ | 118 | $ | 4,571 | ||||||||||||||||
SCE&G had 50 million shares of common stock authorized as of March 31, 2015 and December 31, 2014. SCE&G had 20 million shares of preferred stock authorized as of March 31, 2015 and December 31, 2014, 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, 2015 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Long-term Debt [Text Block] | LONG-TERM DEBT AND LIQUIDITY | ||||||||||||||||||||||||
Long-term Debt | |||||||||||||||||||||||||
In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes. | |||||||||||||||||||||||||
On February 2, 2015, SCANA redeemed prior to maturity $150 million of its 7.7% junior subordinated notes at their face value. | |||||||||||||||||||||||||
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:Â | |||||||||||||||||||||||||
SCANA | SCE&G | PSNCÂ Energy | |||||||||||||||||||||||
Millions of dollars | March 31, | December 31, | March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||
2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
Outstanding commercial paper | $ | 15 | $ | 179 | $ | 610 | $ | 709 | — | 30 | |||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.65 | % | 0.54 | % | 0.54 | % | 0.52 | % | — | 0.65 | % | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 282 | $ | 118 | $ | 790 | $ | 691 | $ | 100 | $ | 70 | |||||||||||||
  | |||||||||||||||||||||||||
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, which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which 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 TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019. | |||||||||||||||||||||||||
SCEG | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Long-term Debt [Text Block] | LONG-TERM DEBT AND LIQUIDITY | ||||||||||||||||||||||||
Long-term Debt | |||||||||||||||||||||||||
In May 2014, SCE&G issued $300 million of 4.5% first mortgage bonds due June 1, 2064. Proceeds from this sale were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes. | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 610 | $ | 709 | |||||||||||||||||||||
Weighted average interest rate | 0.54 | % | 0.52 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 790 | $ | 691 | |||||||||||||||||||||
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), which expire in October 2019. In addition, SCE&G is a party to a three-year credit agreement in the amount of $200 million, which expires in October 2016. These credit agreements are used for general corporate purposes, including liquidity support for each company’s commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N. A. and Morgan Stanley Bank, N.A. each provide 10.7% of the aggregate $1.4 billion credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch and UBS Loan Finance LLC each provide 8.9% and Branch Banking and Trust Company, Union Bank, N.A. and U.S. Bank National Association each provide 6.3%. Two other banks provide the remaining support. Consolidated SCE&G pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented. | |||||||||||||||||||||||||
Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019. | |||||||||||||||||||||||||
Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. At March 31, 2015, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $275.5 million. At December 31, 2014, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $83.0 million and money pool investments due from an affiliate of $80.0 million. |
INCOME_TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2015 | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | INCOME TAXES |
During 2013 and 2014, the Company amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, the Company recorded an unrecognized tax benefit of $16 million. If recognized, $13 million of the tax benefit would affect the Company’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of the Company’s tax positions have occurred through March 31, 2015. | |
    | |
The Company recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Because no refunds related to the unrecognized tax benefits have yet been received, the Company has not recorded any interest expense or penalties associated with them. | |
SCEG | |
income tax [Line Items] | |
Income Tax Disclosure [Text Block] | INCOME TAXES |
During 2013 and 2014, SCANA amended certain of its tax returns to claim certain tax-defined research and development deductions and credits. In connection with these filings, Consolidated SCE&G recorded an unrecognized tax benefit of $16 million. If recognized, $13 million of the tax benefit would affect Consolidated SCE&G’s effective tax rate. It is reasonably possible that this tax benefit will increase by an additional $2 million within the next 12 months. It is also reasonably possible that this tax benefit may decrease by $7 million within the next 12 months. No other material changes in the status of Consolidated SCE&G’s tax positions have occurred through March 31, 2015. | |
    | |
               Consolidated SCE&G recognizes interest accrued related to unrecognized tax benefits within interest expense and recognizes tax penalties within other expenses. Because no refunds related to the unrecognized tax benefits have yet been received, Consolidated SCE&G has not recorded any interest expense or penalties associated with them. |
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 3 Months Ended | |||||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||||
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 their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. | ||||||||||||||||||||||
Commodity Derivatives | ||||||||||||||||||||||
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the condensed consolidated statements of cash flows. | ||||||||||||||||||||||
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes. | ||||||||||||||||||||||
Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas.  The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit. | ||||||||||||||||||||||
As an accommodation to certain customers, SEMI, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes. | ||||||||||||||||||||||
Interest Rate Swaps | ||||||||||||||||||||||
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. Â 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, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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, 2015 | ||||||||||||||||||||||
Commodity contracts | 10,140,000 | 5,633,000 | 3,528,964 | 19,301,964 | ||||||||||||||||||
Energy management contracts (a) | — | — | 40,811,533 | 40,811,533 | ||||||||||||||||||
Total (a) | 10,140,000 | 5,633,000 | 44,340,497 | 60,113,497 | ||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Commodity contracts | 6,840,000 | 7,951,000 | 3,446,720 | 18,237,720 | ||||||||||||||||||
Energy management contracts (b) | — | — | 37,495,339 | 37,495,339 | ||||||||||||||||||
Total (b) | 6,840,000 | 7,951,000 | 40,942,059 | 55,733,059 | ||||||||||||||||||
(a)Â Â Includes an aggregate 3,148,404 MMBTU related to basis swap contracts in Energy Marketing. | ||||||||||||||||||||||
(b)Â Â Includes an aggregate 933,893 MMBTU related to basis swap contracts in Energy Marketing. | ||||||||||||||||||||||
 | ||||||||||||||||||||||
The Company was party to interest rate swaps designated as cash flow hedges with aggregate notional amounts of $124.4 million at March 31, 2015 and $124.4 million at December 31, 2014. 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, 2015 and $1.1 billion at December 31, 2014. | ||||||||||||||||||||||
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, 2015 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 4 | |||||||||||||||||||
Other deferred credits and other liabilities | 33 | |||||||||||||||||||||
Commodity contracts | Other current assets | 1 | ||||||||||||||||||||
Derivative financial instruments | 4 | |||||||||||||||||||||
Total | $ | 42 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 288 | |||||||||||||||||||
Other deferred credits and other liabilities | 30 | |||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | |||||||||||||||||||
Energy management contracts | Other current assets | 13 | Other current assets | 3 | ||||||||||||||||||
Derivative financial instruments | 10 | |||||||||||||||||||||
Other deferred debits and other assets | 6 | Other deferred credits and other liabilities | 6 | |||||||||||||||||||
Total | $ | 20 | $ | 337 | ||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | |||||||||||||||||||
Other deferred credits and other liabilities | 28 | |||||||||||||||||||||
Commodity contracts | Other current assets | 1 | ||||||||||||||||||||
Derivative financial instruments | 11 | |||||||||||||||||||||
Total | $ | 45 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | |||||||||||||||||||
Other deferred credits and other liabilities | 17 | |||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | |||||||||||||||||||
Energy management contracts | Other current assets | 15 | Other current assets | 5 | ||||||||||||||||||
Derivative financial instruments | 10 | |||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | |||||||||||||||||||
Total | $ | 21 | $ | 244 | ||||||||||||||||||
 The effect of derivative instruments on the condensed consolidated statements of income is as follows: | ||||||||||||||||||||||
Derivatives Designated as Fair Value Hedges | ||||||||||||||||||||||
The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented. | ||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | ||||||||||||||||||||||
Loss Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (3 | ) | Interest expense | — | $ | (1 | ) | |||||||||||
Gain (Loss) Recognized in OCI, net of tax | Gain (Loss) Reclassified from AOCI into Income, net of tax | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (2 | ) | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||
Commodity contracts | (1 | ) | 3 | Gas purchased for resale | (7 | ) | 4 | |||||||||||||||
Total | $ | (3 | ) | $ | 1 | $ | (9 | ) | $ | 2 | ||||||||||||
As of March 31, 2015, the Company expects that during the next 12 months reclassifications from accumulated other comprehensive income (loss) to earnings arising from cash flow hedges will include approximately $4.0 million as an increase to gas cost and approximately $6.4 million as an increase to interest expense, assuming natural gas and financial markets remain at their current levels.  As of March 31, 2015, all of the Company’s commodity cash flow hedges settle by their terms before the end of the first quarter of 2017. | ||||||||||||||||||||||
As of March 31, 2015, the Company expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels. | ||||||||||||||||||||||
Hedge Ineffectiveness | ||||||||||||||||||||||
Other losses recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in the three months ended March 31, 2015 and 2014, respectively. | ||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | ||||||||||||||||||||||
Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (94 | ) | $ | (112 | ) | Other income | $ | 4 | — | ||||||||||||
As of March 31, 2015, 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 $0.7 million as an increase to other income. | ||||||||||||||||||||||
Credit Risk Considerations | ||||||||||||||||||||||
The Company limits credit risk in its commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, the Company uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data, as well as financial statements, to assess the financial health of counterparties. 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, 2015 and December 31, 2014, the Company has posted $233.5 million and $152.4 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, 2015 and December 31, 2014, the Company could have been required to post an additional $141.7 million and $129.8 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, 2015 and December 31, 2014 is $375.2 million and $282.2 million, respectively. | ||||||||||||||||||||||
As noted previously, for all periods presented, the Company did not have interest rate derivative instruments in a net asset position and did not have commodity derivatives with underlying contingent features which, if triggered, would have permitted the Company to request collateral from its counterparties. At March 31, 2015, the Company could have called on letters of credit in the amount of $3.0 million related to $19.0 million in commodity derivatives that are in a net asset position, compared to letters of credit of $9.2 million related to derivatives of $20.0 million at December 31, 2014, 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 of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Commodity contracts | $ | 1 | — | $ | 1 | — | — | $ | 1 | |||||||||||||
Energy management contracts | 19 | — | 19 | — | — | 19 | ||||||||||||||||
   Total | $ | 20 | — | $ | 20 | — | — | $ | 20 | |||||||||||||
Balance sheet location | Other current assets | $ | 14 | |||||||||||||||||||
Other deferred debits and other assets | 6 | |||||||||||||||||||||
Total | $ | 20 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Commodity contracts | $ | 1 | — | $ | 1 | — | — | $ | 1 | |||||||||||||
Energy management contracts | 20 | — | 20 | — | — | 20 | ||||||||||||||||
   Total | $ | 21 | — | $ | 21 | — | — | $ | 21 | |||||||||||||
Balance sheet location | Other current assets | $ | 16 | |||||||||||||||||||
Other deferred debits and other assets | 5 | |||||||||||||||||||||
Total | $ | 21 | ||||||||||||||||||||
Information related to the Company's offsetting of derivative liabilities follows: | ||||||||||||||||||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Interest rate contracts | $ | 355 | — | $ | 355 | — | $ | (216 | ) | $ | 139 | |||||||||||
Commodity contracts | 5 | — | 5 | — | (4 | ) | 1 | |||||||||||||||
Energy management contracts | 19 | — | 19 | — | (13 | ) | 6 | |||||||||||||||
   Total | $ | 379 | — | $ | 379 | — | $ | (233 | ) | $ | 146 | |||||||||||
Balance sheet location | Other current assets | $ | 4 | |||||||||||||||||||
Derivative financial instruments | 306 | |||||||||||||||||||||
Other deferred credits and other liabilities | 69 | |||||||||||||||||||||
Total | $ | 379 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Interest rate contracts | $ | 257 | — | $ | 257 | — | $ | (131 | ) | $ | 126 | |||||||||||
Commodity contracts | 12 | — | 12 | — | (10 | ) | 2 | |||||||||||||||
Energy management contracts | 20 | — | 20 | — | (11 | ) | 9 | |||||||||||||||
   Total | $ | 289 | — | $ | 289 | — | $ | (152 | ) | $ | 137 | |||||||||||
Balance sheet location | Other current assets | $ | 6 | |||||||||||||||||||
Derivative financial instruments | 233 | |||||||||||||||||||||
Other deferred credits and other liabilities | 50 | |||||||||||||||||||||
Total | $ | 289 | ||||||||||||||||||||
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 Consolidated SCE&G’s Risk Management Officer and senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions. | ||||||||||||||||||||||
Interest Rate Swaps | ||||||||||||||||||||||
Consolidated SCE&G synthetically converts variable rate debt to fixed rate debt using swaps that are designated as cash flow hedges. Periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense. | ||||||||||||||||||||||
In anticipation of the issuance of debt, Consolidated SCE&G may use treasury rate lock or forward starting swap agreements. Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and all related fair value changes and settlement amounts are recorded as regulatory assets or liabilities. Interest rate derivatives entered into before October 2013 were designated as cash flow hedges, and for such instruments only the effective portion of fair value changes and settlement amounts are recorded in regulatory assets or regulatory liabilities. Upon settlement, losses on swaps are amortized over the lives of related debt issuances, and gains are applied to under-collected fuel, are amortized to interest expense or are 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 | ||||||||||||||||||||||
GENCO was party to an interest rate swap designated as a cash flow hedge with a notional amount of $36.4 million at March 31, 2015 and $36.4 million at December 31, 2014. 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, 2015 and $1.1 billion at December 31, 2014, respectively. | ||||||||||||||||||||||
The fair value of interest rate derivatives (each of which was a liability derivative for all periods presented) was reflected in the condensed consolidated balance sheet as follows: | ||||||||||||||||||||||
Fair Values of Derivative Instruments | Liability Derivatives | |||||||||||||||||||||
Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | |||||||||||||||||||
Other deferred credits and other liabilities | 10 | |||||||||||||||||||||
Total | $ | 11 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 288 | |||||||||||||||||||
Other deferred credits and other liabilities | 30 | |||||||||||||||||||||
Total | $ | 318 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | |||||||||||||||||||
Other deferred credits and other liabilities | 8 | |||||||||||||||||||||
Total | $ | 9 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | |||||||||||||||||||
Other deferred credits and other liabilities | 17 | |||||||||||||||||||||
Total | $ | 224 | ||||||||||||||||||||
     | ||||||||||||||||||||||
The effect of derivative instruments on the condensed consolidated statement of income is as follows: | ||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Loss Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (3 | ) | Interest expense | — | $ | (1 | ) | |||||||||||
As of March 31, 2015, Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $2.3 million as an increase to interest expense, assuming financial markets remain at their current levels. | ||||||||||||||||||||||
Hedge Ineffectiveness | ||||||||||||||||||||||
Other gains (losses) recognized in income representing ineffectiveness on interest rate hedges designated as cash flow hedges were insignificant in each of the three ended March 31, 2015 and 2014, respectively. | ||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | ||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (94 | ) | $ | (112 | ) | Other income | $ | 4 | — | ||||||||||||
As of March 31, 2015, 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 $0.7 million as an increase to other income. | ||||||||||||||||||||||
Credit Risk Considerations | ||||||||||||||||||||||
Consolidated SCE&G limits credit risk in its derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. In this regard, Consolidated SCE&G uses credit ratings provided by credit rating agencies and current market-based qualitative and quantitative data as well as financial statements, to assess the financial health of counterparties. 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, 2015 and December 31, 2014, Consolidated SCE&G has posted $188.6 million and $107.1 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, 2015 and December 31, 2014, Consolidated SCE&G could have been required to post an additional $140.7 million and $125.9 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, 2015 and December 31, 2014 is $329.3 million and $233.0 million, respectively. | ||||||||||||||||||||||
As noted previously, Consolidated SCE&G did not have interest rate derivatives in a net asset position for any period presented. | ||||||||||||||||||||||
Information related to Consolidated SCE&G's derivative liabilities follows: | ||||||||||||||||||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Interest rate contracts | $ | 329 | — | $ | 329 | — | $ | (189 | ) | $ | 140 | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 289 | |||||||||||||||||||
Other deferred credits and other liabilities | 40 | |||||||||||||||||||||
Total | $ | 329 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Interest rate contracts | $ | 233 | — | $ | 233 | — | $ | (107 | ) | $ | 126 | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 208 | |||||||||||||||||||
Other deferred credits and other liabilities | 25 | |||||||||||||||||||||
$ | 233 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
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, 2015 | As of December 31, 2014 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 13 | — | $ | 13 | — | |||||||||||
Commodity contracts | 1 | — | 1 | — | |||||||||||||
Energy management contracts | — | $ | 19 | — | $ | 20 | |||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 355 | — | 257 | |||||||||||||
Commodity contracts | — | — | 1 | 11 | |||||||||||||
Energy management contracts | 3 | 23 | 5 | 18 | |||||||||||||
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 were as follows: | |||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,541.60 | $ | 6,501.60 | $ | 5,697.20 | $ | 6,592.10 | |||||||||
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates.  As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent. | |||||||||||||||||
Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2. | |||||||||||||||||
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. These fair values are considered to be Level 2. The fair value of derivative liabilities were $329 million at March 31, 2015 and $233 million at December 31, 2014. Consolidated SCE&G did not have derivative assets for any period presented. | |||||||||||||||||
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 were as follows: | |||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,303.30 | $ | 5,119.20 | $ | 4,308.60 | $ | 5,070.90 | |||||||||
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, 2015 | |||||||||||||||||
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:Â | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 5.8 | $ | 5 | $ | 1.4 | $ | 1.2 | |||||||||
Interest cost | 9.5 | 10.2 | 2.9 | 3.1 | |||||||||||||
Expected return on assets | (15.5 | ) | (16.8 | ) | — | — | |||||||||||
Prior service cost amortization | 1 | 1 | 0.1 | 0.1 | |||||||||||||
Amortization of actuarial losses | 3.5 | 1.3 | 0.6 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 4.3 | $ | 0.7 | $ | 5 | $ | 4.5 | |||||||||
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 the majority of all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to retired employees.  Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows: | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 4.6 | $ | 4 | $ | 1.1 | $ | 1 | |||||||||
Interest cost | 8 | 8.6 | 2.3 | 2.4 | |||||||||||||
Expected return on assets | (13.0 | ) | (14.2 | ) | — | — | |||||||||||
Prior service cost amortization | 0.8 | 0.9 | 0.1 | 0.1 | |||||||||||||
Amortization of actuarial losses | 3 | 1.1 | 0.4 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 3.4 | $ | 0.4 | $ | 3.9 | $ | 3.6 | |||||||||
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. |
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended | |
Mar. 31, 2015 | ||
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 $43.5 million. | ||
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G'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 | ||
In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  | ||
SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. | ||
EPC Contract and BLRA Matters | ||
The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA. | ||
The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | ||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule. | ||
Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 to be ready for placement on the nuclear island of Unit 2 during the first half of 2015. | ||
During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. | ||
The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. | ||
As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively. | ||
As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations. | ||
The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As discussed in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015. | ||
Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. | ||
Santee Cooper Matters | ||
As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above. | ||
Nuclear Production Tax Credits | ||
The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized. | ||
Other Project Matters | ||
When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. | ||
Environmental | ||
The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's financial condition, results of operations and cash flows. In addition, the Company often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company expects to recover such expenditures and costs through existing ratemaking provisions. | ||
SCE&G | ||
The EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The proposed rule was issued on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. The Company is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions. | ||
From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. | ||
In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR. | ||
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. | ||
The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, the Company expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. | ||
The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. | ||
On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds. | ||
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2014, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. | ||
 The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 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, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 million and are included in regulatory assets. | ||
PSNC Energy | ||
PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. Actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. PSNC Energy has recorded a liability and associated regulatory asset of approximately $1.0 million, the estimated remaining liability at March 31, 2015. 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 $43.5 million. | ||
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G'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 | ||
In 2008, SCE&G, on behalf of itself and as agent for Santee Cooper, contracted with the Consortium for the design and construction of the New Units at the site of Summer Station.  | ||
SCE&G's current ownership share in the New Units is 55%. As discussed below, under an agreement signed in January 2014 (and subject to customary closing conditions, including necessary regulatory approvals), SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. | ||
EPC Contract and BLRA Matters | ||
The construction of the New Units and SCE&G’s related recovery of financing costs through rates is subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified schedule contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. Such annual rate changes are described in Note 2. As of March 31, 2015, SCE&G’s investment in the New Units totaled $2.9 billion, for which the financing costs on $2.4 billion have been reflected in rates under the BLRA. | ||
The SCPSC granted initial approval of the construction schedule, including 146 milestones within that schedule, and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, the SCPSC approved an updated milestone schedule and additional updated capital costs for the New Units. In addition, the SCPSC approved revised substantial completion dates for the New Units based on that March 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve known claims by the Consortium for costs related to COL delays, design modifications of the shield building and certain prefabricated structural modules for the New Units and unanticipated rock conditions at the site. In October 2014, the South Carolina Supreme Court affirmed the SCPSC's order on appeal. | ||
The substantial completion dates currently approved by the SCPSC for Units 2 and 3 are March 15, 2017 and May 15, 2018. The SCPSC also approved an 18-month contingency period beyond each of these dates, and for each of the 146 milestones in the schedule. | ||
Since the settlement of delay-related claims in 2012, the Consortium has continued to experience delays in the schedule, including those related to fabrication and delivery of sub-modules for the New Units. The fabrication and delivery of sub-modules have been and remain focus areas of the Consortium, including sub-modules for module CA01, which houses components inside the containment vessel. Module CA01 and shield building modules are considered critical path items for both New Units. The delivery schedule of sub-modules for CA01 is expected to support completion of on-site fabrication to allow CA01 to be ready for placement on the nuclear island of Unit 2 during the first half of 2015. | ||
During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3 construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities necessary to accomplish the schedules and to provide a detailed reassessment of the impact of the revised Unit 2 and Unit 3 schedules on engineering and design resource allocations, procurement, construction work crew efficiencies, and other items. The result was a revised, fully integrated project schedule with timing of specific construction activities (Revised, Fully-Integrated Construction Schedule) along with related cost information. | ||
The Revised, Fully-Integrated Construction Schedule indicated that the substantial completion of Unit 2 was expected to occur in mid-June 2019 and that the substantial completion of Unit 3 was expected to be approximately 12 months later. SCE&G has not, however, accepted the Consortium's contention that the new substantial completion dates are made necessary by delays that are excusable under the EPC Contract. The Consortium continues to refine and update the Revised, Fully-Integrated Construction Schedule as designs are finalized, as construction progresses, and as additional information is received. | ||
As discussed above, the milestone schedule approved by the SCPSC in November 2012 provides for 146 milestone dates, each of which is subject to an 18-month schedule contingency. As of April 30, 2015, 105 milestones have been completed, and three of the remaining milestones have not been completed within their 18-month contingency periods. In light of the Revised, Fully Integrated Schedule, it is anticipated that the completion dates for a substantial number of the remaining milestone dates will also extend beyond their contingency periods. Further, capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) are projected to exceed amounts currently approved by the SCPSC of $4.5 billion and $5.8 billion, respectively. | ||
As such, in March 2015 SCE&G petitioned the SCPSC for an order to update the BLRA milestone schedule based on revised substantial completion dates for Units 2 and 3 of June 2019 and June 2020, respectively. In addition, that petition included certain updated owner's costs ($245 million) and other capital costs ($453 million) which, if approved, would reset projected capital costs (in 2007 dollars) and gross construction cost estimates (including escalation and AFC) to $5.2 billion and $6.8 billion, respectively. These projections include cost amounts related to the Revised, Fully-Integrated Construction Schedule for which SCE&G has not accepted responsibility and which may be the subject of dispute. As such, the petition does not reflect the resolution of negotiations. | ||
The SCPSC will hold a public hearing related to the petition in July 2015. While 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, SCE&G cannot predict the outcome of this regulatory process. As described in Note 2, SCE&G expects the SCPSC to issue its order on the petition in September 2015. | ||
Additional claims by the Consortium or SCE&G involving the project schedule and budget may arise as the project continues. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve such issues. SCE&G expects to resolve all disputes (including any ultimate disagreements involving the preliminary cost estimates provided by the Consortium in the third quarter of 2014) through both the informal and formal procedures and anticipates that any costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. | ||
Santee Cooper Matters | ||
As noted above, SCE&G has agreed to acquire an additional 5% ownership in the New Units from Santee Cooper. Under the terms of this agreement, SCE&G will acquire a 1% ownership interest in the New Units at the commercial operation date of Unit 2, an additional 2% ownership interest no later than the first anniversary of such commercial operation date, and the final 2% no later than the second anniversary of such commercial operation date. SCE&G has agreed to pay an amount equal to Santee Cooper's actual cost of the percentage conveyed as of the date of each conveyance. In addition, the agreement provides that Santee Cooper will not transfer any of its remaining interest in the New Units to third parties until the New Units are complete. This transaction will not affect the payment obligations between the parties during construction for the New Units, nor is it anticipated that the payments for the additional ownership interest would be reflected in a revised rates filing under the BLRA. Based on the current milestone schedule and capital costs schedule approved by the SCPSC in November 2012, SCE&G’s estimated cost would be approximately $500 million for the additional 5% interest being acquired from Santee Cooper. This cost figure is expected to be higher in light of the delays and related costs discussed above. | ||
Nuclear Production Tax Credits | ||
The IRS has notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units (advanced nuclear units, as defined) would qualify for nuclear production tax credits under Section 45J of the Internal Revenue Code to the extent that such New Unit is operational before January 1, 2021 and other eligibility requirements are met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could total as much as approximately $1.4 billion. Such credits would be earned over the first eight years of each New Unit's operations and would be realized by SCE&G over those years or during allowable carry-forward periods. Based on the above substantial completion dates provided by the Consortium of June 2019 and June 2020 for Units 2 and 3, respectively, both New Units are expected to be operational and to qualify for the nuclear production tax credits; however, further delays in the schedule or changes in tax law could impact such conclusions. To the extent that production tax credits are realized, their benefits are expected to be provided directly to SCE&G's electric customers as so realized. | ||
Other Project Matters | ||
When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation. SCE&G prepared and submitted an integrated response plan for the New Units to the NRC in August 2013. That plan is currently under review by the NRC and SCE&G does not anticipate any additional regulatory actions as a result of that review, but it cannot predict future regulatory activities or how such initiatives would impact construction or operation of the New Units. | ||
Environmental | ||
Consolidated SCE&G's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, Consolidated SCE&G expects to recover such expenditures and costs through existing ratemaking provisions. | ||
The EPA issued a revised carbon standard for new power plants by re-proposing NSPS under the CAA for emissions of carbon dioxide from newly constructed fossil fuel-fired units. The proposed rule was issued on January 8, 2014 and requires all new fossil fuel-fired power plants to meet the carbon dioxide emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without carbon capture and sequestration capabilities. Consolidated SCE&G is evaluating the proposed rule, but does not plan to construct new coal-fired units in the near future. In addition, on June 2, 2014, the EPA issued proposed emission guidelines for states to follow in developing plans to address GHG emissions from existing units. These guidelines are expected to be made final in late summer 2015, and include state-specific rate based goals for carbon dioxide emissions. | ||
From a regulatory perspective, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the sulfur dioxide and nitrogen oxide emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at several larger coal-fired electric generating plants. Further, SCE&G is engaged in construction activities of the New Units which are expected to reduce GHG emission levels significantly once they are completed and dispatched by potentially displacing some of the current coal-fired generation sources. These actions are expected to address many of the rules and regulations discussed herein. | ||
In July 2011, the EPA issued the CSAPR to reduce emissions of sulfur dioxide and nitrogen oxide from power plants in the eastern half of the United States. A series of court actions stayed this rule until October 23, 2014, when the Court of Appeals granted a motion to lift the stay. On December 3, 2014, the EPA published an interim final rule that aligns the dates in the CSAPR text with the revised court-ordered schedule, thus delaying the implementation dates to 2015 for Phase 1 and to 2017 for Phase 2. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual sulfur dioxide emissions and annual or ozone season nitrogen oxide emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for sulfur dioxide and nitrogen oxide and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the allowances set by the CSAPR. | ||
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for generating facilities to meet the standards, and SCE&G and GENCO's evaluation of the rule is ongoing. SCE&G's decision to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in SCE&G's compliance with MATS. On November 19, 2014, the EPA finalized its reconsideration of certain provisions applicable during startup and shutdown of generating facilities. SCE&G and GENCO have received a one year extension (until April 2016) to comply with MATS at Cope, McMeekin, Wateree and Williams Stations. These extensions will allow time to convert McMeekin Station to burn natural gas and to install additional pollution control devices at the other plants that will enhance the control of certain MATS-regulated pollutants. | ||
The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every five years), any new effluent limitations would be incorporated. The ELG Rule was published in the Federal Register on June 7, 2013, and is expected to be finalized no later than September 30, 2015. Once the rule becomes effective, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five year permit cycle and thus may range from 2018 to 2023. Based on the proposed rule, Consolidated SCE&G expects that wastewater treatment technology retrofits will be required at Williams and Wateree Stations and may be required at other facilities. | ||
The CWA Section 316(b) Existing Facilities Rule became effective on October 14, 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans to ensure compliance with this rule. In addition, Congress is expected to consider further amendments to the CWA. Such legislation may include toxicity-based standards as well as limitations to mixing zones. | ||
On April 17, 2015, the EPA's final rule for CCR was published in the Federal Register and will become effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act. In addition, this rule imposes certain requirements on ash storage ponds at SCE&G's and GENCO's generating facilities. While this rule is still being evaluated, SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds. | ||
The Nuclear Waste Act required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998. The Nuclear Waste Act also imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&G entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2014, the federal government has not accepted any spent fuel from Summer Station Unit 1, and it remains unclear when the repository may become available. SCE&G has on-site spent nuclear fuel storage capability in its existing fuel pool until at least 2017 and is constructing a dry cask storage facility to accommodate the spent nuclear fuel output for the life of Summer Station Unit 1. SCE&G may evaluate other technology as it becomes available. | ||
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The state of South Carolina has similar laws. SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify SCE&G that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through rates. | ||
SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of by-product chemicals.  These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2017 and will cost an additional $19.2 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, 2015, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $35.2 million and are included in regulatory assets. |
SEGMENT_OF_BUSINESS_INFORMATIO
SEGMENT OF BUSINESS INFORMATION | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
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 the parent company, a services company and other nonreportable segments that were insignificant for all periods presented. In addition, All Other includes gains from the sales of CGT and SCI (see Note 11) and their operating results and assets prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. For the period ended March 31, 2015, operating income and net income for All Other include $235 million and $202 million, respectively, related to the sales of CGT and SCI. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented. | |||||||||||||||||
Millions of dollars | External | Intersegment Revenue | Operating | Net | |||||||||||||
Revenue | Income | Income | |||||||||||||||
Three Months Ended March 31, 2015 | |||||||||||||||||
Electric Operations | $ | 629 | — | $ | 199 | n/a | |||||||||||
Gas Distribution | 368 | — | 96 | n/a | |||||||||||||
Retail Gas Marketing | 204 | — | n/a | $ | 27 | ||||||||||||
Energy Marketing | 187 | $ | 35 | n/a | 6 | ||||||||||||
All Other | 4 | 114 | 238 | 207 | |||||||||||||
Adjustments/Eliminations | (3 | ) | (149 | ) | 53 | 160 | |||||||||||
Consolidated Total | $ | 1,389 | $ | — | $ | 586 | $ | 400 | |||||||||
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 | |||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2015 | 2014 | |||||||||||||||
Electric Operations | $ | 10,300 | $ | 10,182 | |||||||||||||
Gas Distribution | 2,504 | 2,487 | |||||||||||||||
Retail Gas Marketing | 155 | 140 | |||||||||||||||
Energy Marketing | 128 | 150 | |||||||||||||||
All Other | 1,494 | 1,474 | |||||||||||||||
Adjustments/Eliminations | 1,825 | 2,419 | |||||||||||||||
Consolidated Total | $ | 16,406 | $ | 16,852 | |||||||||||||
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. | |||||||||||||||||
Millions of dollars | External Revenue | Operating Income | Earnings Available to Common Shareholder | ||||||||||||||
Three Months Ended March 31, 2015 | |||||||||||||||||
Electric Operations | $ | 630 | $ | 199 | n/a | ||||||||||||
Gas Distribution | 142 | 38 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 122 | |||||||||||||
Consolidated Total | $ | 772 | $ | 237 | $ | 122 | |||||||||||
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 | |||||||||||
Segment Assets | 31-Mar-15 | 31-Dec-14 | |||||||||||||||
Electric Operations | $ | 10,300 | $ | 10,182 | |||||||||||||
Gas Distribution | 731 | 721 | |||||||||||||||
Adjustments/Eliminations | 3,103 | 3,204 | |||||||||||||||
Consolidated Total | $ | 14,134 | $ | 14,107 | |||||||||||||
AFFILIATED_TRANSACTIONS_SCEG
AFFILIATED TRANSACTIONS - SCEG (SCEG) | 3 Months Ended |
Mar. 31, 2015 | |
SCEG | |
Related Party Transactions Disclosure [Text Block] | AFFILIATED TRANSACTIONS |
CGT transports natural gas to SCE&G to serve retail gas customers and certain electric generation requirements. Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA, and SCE&G's transactions with CGT prior to January 31, 2015 were affiliated transactions. SCE&G's affiliated purchases from CGT totaled approximately $3.4 million and $5.5 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G's affiliated payables to CGT for transportation services were $3.3 million at December 31, 2014, and SCE&G's affiliated receivables from CGT related to such transportation services were $1.2 million at December 31, 2014. | |
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 $34.6 million and $53.4 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G’s payables to SEMI for such purposes were $10.6 million at March 31, 2015 and $12.6 million at December 31, 2014. | |
SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. SCE&G’s total purchases from this affiliate were $70.1 million and $39.2 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G’s total sales to this affiliate were $69.7 million and $39.0 million for the three months ended March 31, 2015 and 2014, respectively. SCE&G’s receivable from this affiliate was $18.5 million at March 31, 2015 and $27.8 million at December 31, 2014. SCE&G’s payable to this affiliate was $18.6 million at March 31, 2015 and $27.9 million at December 31, 2014. | |
SCANA Services provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems services, telecommunications services, customer services, marketing and sales, human resources, corporate compliance, purchasing, financial services, risk management, public affairs, legal services, investor relations, gas supply and capacity management, strategic planning, general administrative services, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services were $73.1 million and $76.2 million for the three months ended March 31, 2015 and 2014, respectively. Consolidated SCE&G's payables to SCANA Services for these services were $48.4 million at March 31, 2015 and $47.3 million at December 31, 2014. | |
Money pool borrowings from an affiliate are described in Note 4. |
Dispositions_Notes
Dispositions (Notes) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Disposal groups [Abstract] | |||||||||||||
Disposal Group, Held for Sale [Text Block] | DISPOSITIONS | ||||||||||||
In December 2014, SCANA entered into definitive agreements to sell CGT and SCI. CGT is an interstate natural gas pipeline regulated by FERC that transports natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provides fiber optic communications and other services and builds, manages and leases communications towers in several southeastern states, and it was sold to a subsidiary of Spirit Communications. These sales closed in the first quarter of 2015. The pre-tax gain on the sales recognized during the first quarter of 2015 was approximately $342 million. As further described in Note 1, the pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the consolidated income statement. | |||||||||||||
CGT and SCI operate principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment and were included within All Other in Note 10. The sales of CGT and SCI did not represent a strategic shift that will have a major effect on SCANA's operations; therefore, these sales do not meet the criteria for classification as discontinued operations. | |||||||||||||
The carrying values of the major classes of assets and liabilities classified as held for sale in the consolidated balance sheet as of December 31, 2014, were as follows: | |||||||||||||
Millions of dollars | CGT | SCI | Total | ||||||||||
Assets Held for Sale | |||||||||||||
Utility Plant, Net | $ | 288.4 | — | $ | 288.4 | ||||||||
Nonutility Property and Investments, Net | 0.6 | $ | 40.1 | 40.7 | |||||||||
Current Assets | 6.5 | 3.9 | 10.4 | ||||||||||
Deferred Debits and Other Assets | 0.9 | 0.2 | 1.1 | ||||||||||
Total Assets Held for Sale | 296.4 | 44.2 | 340.6 | ||||||||||
Liabilities Held for Sale | |||||||||||||
Current Liabilities | $ | 3.5 | $ | 2.2 | $ | 5.7 | |||||||
Deferred Credits and Other Liabilities | 42.9 | 3.1 | 46 | ||||||||||
Total Liabilities Held for Sale | $ | 46.4 | $ | 5.3 | $ | 51.7 | |||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 3 Months Ended |
Mar. 31, 2015 | |
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. | |
Plant to be retired [Policy Text Block] | Plant to be Retired |
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |
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.  There were no securities considered to be dilutive potential common stock during any period presented. The Company has issued no securities that would have an antidilutive effect on earnings per share. | |
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 32% and 48% of PSNC Energy’s natural gas inventory at March 31, 2015 | |
and December 31, 2014, respectively, with a carrying value of $8.7 million and $26.1 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, which expired on March 31, 2015, have been replaced with similar agreements that expire March 31, 2017. | |
Income Statement policy [Policy Text Block] | Income Statement Presentation |
The Company presents the revenues and expenses of its regulated businesses and its retail natural gas marketing businesses (including those activities of segments described in Note 10) within operating income, and it presents all other activities within other income (expense). Consistent with this presentation, the gain on the sale of CGT is reflected within operating income and the gain on the sale of SCI is reflected within other income (expense). | |
SCEG | |
Significant Accounting Policies | |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Variable Interest Entities |
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying 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 $498 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 |
SCE&G expects to retire three units that are or were coal-fired by 2020, subject to future developments in environmental regulations, among other matters. The net carrying value of these units is identified as Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. In the meantime, these units remain in rate base, and SCE&G depreciates them using composite straight-line rates approved by the SCPSC. The net carrying value of three previously retired units is recorded in regulatory assets within unrecovered plant (see Note 2). | |
    |
RATE_AND_OTHER_REGULATORY_MATT1
RATE AND OTHER REGULATORY MATTERS (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Regulatory Assets | |||||||||
Demand reduction programs [Table Text Block] | : | ||||||||
Year | Effective | Amount | |||||||
2015 | First billing cycle of May | $32.0 million | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | |||||||||
Year | Action | Amount | |||||||
2014 | 2.8 | % | Increase | $66.2 million | |||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | |||||||||
Year | Action | Amount | |||||||
2014 | 0.6 | % | Decrease | $2.6 million | |||||
2013 | Â Â No change | - | |||||||
Schedule of Regulatory Assets [Table Text Block] | . | ||||||||
Millions of dollars | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 282 | $ | 284 | |||||
Under-collections - electric fuel adjustment clause | 4 | 20 | |||||||
Environmental remediation costs | 40 | 40 | |||||||
AROs and related funding | 370 | 366 | |||||||
Franchise agreements | 25 | 26 | |||||||
Deferred employee benefit plan costs | 337 | 350 | |||||||
Planned major maintenance | — | 2 | |||||||
Deferred losses on interest rate derivatives | 549 | 453 | |||||||
Deferred pollution control costs | 35 | 36 | |||||||
Unrecovered plant | 132 | 137 | |||||||
DSM Programs | 58 | 56 | |||||||
Carrying costs on deferred tax assets related to nuclear construction | 11 | 9 | |||||||
Pipeline integrity management costs | 10 | 9 | |||||||
Other | 37 | 35 | |||||||
Total Regulatory Assets | $ | 1,890 | $ | 1,823 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | |||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 22 | $ | 22 | |||||
Asset removal costs | 712 | 703 | |||||||
Storm damage reserve | 6 | 6 | |||||||
Deferred gains on interest rate derivatives | 82 | 82 | |||||||
Planned major maintenance | 7 | — | |||||||
Other | — | 1 | |||||||
Total Regulatory Liabilities | $ | 829 | $ | 814 | |||||
SCEG | |||||||||
Regulatory Assets | |||||||||
Demand reduction programs [Table Text Block] | |||||||||
Year | Effective | Amount | |||||||
2015 | First billing cycle of May | $32.0 million | |||||||
2014 | First billing cycle of May | $15.4 million | |||||||
2013 | First billing cycle of May | $16.9 million | |||||||
Schedule of Changes in Electric Rate BLRA [Table Text Block] | |||||||||
Year | Action | Amount | |||||||
2014 | 2.8 | % | Increase | $66.2 million | |||||
2013 | 2.9 | % | Increase | $67.2 million | |||||
Schedule of Changes in Gas Rate RSA [Table Text Block] | |||||||||
Year | Action | Amount | |||||||
2014 | 0.6 | % | Decrease | $2.6 million | |||||
2013 | Â Â No change | - | |||||||
Schedule of Regulatory Assets [Table Text Block] | |||||||||
Millions of dollars | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Regulatory Assets: | |||||||||
Accumulated deferred income taxes | $ | 276 | $ | 278 | |||||
Under collections – electric fuel adjustment clause | 4 | 20 | |||||||
Environmental remediation costs | 35 | 36 | |||||||
AROs and related funding | 350 | 347 | |||||||
Franchise agreements | 25 | 26 | |||||||
Deferred employee benefit plan costs | 305 | 310 | |||||||
Planned major maintenance | — | 2 | |||||||
Deferred losses on interest rate derivatives | 549 | 453 | |||||||
Deferred pollution control costs | 35 | 36 | |||||||
Unrecovered plant | 132 | 137 | |||||||
DSM Programs | 58 | 56 | |||||||
Carrying costs on deferred tax assets related to nuclear construction | 11 | 9 | |||||||
Other | 37 | 35 | |||||||
Total Regulatory Assets | $ | 1,817 | $ | 1,745 | |||||
Schedule of Regulatory Liabilities [Table Text Block] | |||||||||
Regulatory Liabilities: | |||||||||
Accumulated deferred income taxes | $ | 16 | $ | 17 | |||||
Asset removal costs | 510 | 505 | |||||||
Storm damage reserve | 6 | 6 | |||||||
Deferred gains on interest rate derivatives | 82 | 82 | |||||||
Planned major maintenance | 7 | — | |||||||
Total Regulatory Liabilities | $ | 621 | $ | 610 | |||||
COMMON_EQUITY_Tables
COMMON EQUITY (Tables) | 3 Months Ended | |||||||||||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||||||||||
Schedule of Capitalization, Equity [Line Items] | ||||||||||||||||||||||||||||
Schedule of Stockholders Equity [Table Text Block] | ||||||||||||||||||||||||||||
Common Stock | Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||||||||||
Millions | Shares | Amount | Retained Earnings | Gains(Losses) on Cash Flow Hedges | Deferred Employee Benefit Plans | Total AOCI | Total Common Equity | |||||||||||||||||||||
Balance as of January 1, 2015 | 143 | $ | 2,378 | $ | 2,684 | $ | (63 | ) | $ | (12 | ) | $ | (75 | ) | $ | 4,987 | ||||||||||||
Net Income | 400 | 400 | ||||||||||||||||||||||||||
Other Comprehensive Income (Loss): | ||||||||||||||||||||||||||||
Losses arising during the period | (3 | ) | (4 | ) | (7 | ) | (7 | ) | ||||||||||||||||||||
Gains/amortization reclassified from AOCI | 9 | — | 9 | 9 | ||||||||||||||||||||||||
Total Comprehensive Income (Loss) | 400 | 6 | (4 | ) | 2 | 402 | ||||||||||||||||||||||
Issuance of Common Stock | — | 14 | 14 | |||||||||||||||||||||||||
Dividends Declared | (78 | ) | (78 | ) | ||||||||||||||||||||||||
Balance as of March 31, 2015 | 143 | $ | 2,392 | $ | 3,006 | $ | (57 | ) | $ | (16 | ) | $ | (73 | ) | $ | 5,325 | ||||||||||||
Balance as of January 1, 2014 | 141 | $ | 2,280 | $ | 2,444 | $ | (52 | ) | $ | (8 | ) | $ | (60 | ) | $ | 4,664 | ||||||||||||
Net Income | 193 | 193 | ||||||||||||||||||||||||||
Other Comprehensive Income: | ||||||||||||||||||||||||||||
Gains arising during the period | 1 | — | 1 | 1 | ||||||||||||||||||||||||
Losses/amortization reclassified from AOCI | (2 | ) | — | (2 | ) | (2 | ) | |||||||||||||||||||||
Total Comprehensive Income | 193 | (1 | ) | — | (1 | ) | 192 | |||||||||||||||||||||
Issuance of Common Stock | — | 27 | 27 | |||||||||||||||||||||||||
Dividends Declared | (74 | ) | (74 | ) | ||||||||||||||||||||||||
Balance as of March 31, 2014 | 141 | $ | 2,307 | $ | 2,563 | $ | (53 | ) | $ | (8 | ) | $ | (61 | ) | $ | 4,809 | ||||||||||||
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, 2015 and 2014 were as follows: | |||||||||||||||||||||||||||
Common Stock | Retained | Accumulated Other Comprehensive | Noncontrolling | Total | ||||||||||||||||||||||||
Millions | Shares | Amount | Earnings | Income (Loss) | Interest | Equity | ||||||||||||||||||||||
Balance at January 1, 2015 | 40 | $ | 2,560 | $ | 2,077 | $ | (3 | ) | $ | 123 | $ | 4,757 | ||||||||||||||||
Earnings available to common shareholder | 122 | 4 | 126 | |||||||||||||||||||||||||
Deferred cost of employee benefit plans | — | — | ||||||||||||||||||||||||||
Total Comprehensive Income | 122 | — | 4 | 126 | ||||||||||||||||||||||||
Capital returned to parent | (4 | ) | (4 | ) | ||||||||||||||||||||||||
Cash dividend declared | (69 | ) | (1 | ) | (70 | ) | ||||||||||||||||||||||
Balance at March 31, 2015 | 40 | $ | 2,556 | $ | 2,130 | $ | (3 | ) | $ | 126 | $ | 4,809 | ||||||||||||||||
Balance at January 1, 2014 | 40 | $ | 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 | 40 | $ | 2,499 | $ | 1,957 | $ | (3 | ) | $ | 118 | $ | 4,571 | ||||||||||||||||
LONGTERM_AND_SHORTTERM_DEBT_Ta
LONG-TERM AND SHORT-TERM DEBT (Tables) | 3 Months Ended | ||||||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||||||
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:Â | ||||||||||||||||||||||||
SCANA | SCE&G | PSNCÂ Energy | |||||||||||||||||||||||
Millions of dollars | March 31, | December 31, | March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||
2015 | 2014 | 2015 | 2014 | 2015 | 2014 | ||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | |||||||||||||
Outstanding commercial paper | $ | 15 | $ | 179 | $ | 610 | $ | 709 | — | 30 | |||||||||||||||
(270 or fewer days) | |||||||||||||||||||||||||
Weighted average interest rate | 0.65 | % | 0.54 | % | 0.54 | % | 0.52 | % | — | 0.65 | % | ||||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | |||||||||||||||
Available | $ | 282 | $ | 118 | $ | 790 | $ | 691 | $ | 100 | $ | 70 | |||||||||||||
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, | |||||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||||||
Lines of credit: | |||||||||||||||||||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | |||||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 610 | $ | 709 | |||||||||||||||||||||
Weighted average interest rate | 0.54 | % | 0.52 | % | |||||||||||||||||||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | |||||||||||||||||||||
Available | $ | 790 | $ | 691 | |||||||||||||||||||||
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 3 Months Ended | |||||||||||||||||||||
Mar. 31, 2015 | ||||||||||||||||||||||
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, 2015 | ||||||||||||||||||||||
Commodity contracts | 10,140,000 | 5,633,000 | 3,528,964 | 19,301,964 | ||||||||||||||||||
Energy management contracts (a) | — | — | 40,811,533 | 40,811,533 | ||||||||||||||||||
Total (a) | 10,140,000 | 5,633,000 | 44,340,497 | 60,113,497 | ||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Commodity contracts | 6,840,000 | 7,951,000 | 3,446,720 | 18,237,720 | ||||||||||||||||||
Energy management contracts (b) | — | — | 37,495,339 | 37,495,339 | ||||||||||||||||||
Total (b) | 6,840,000 | 7,951,000 | 40,942,059 | 55,733,059 | ||||||||||||||||||
(a)Â Â Includes an aggregate 3,148,404 MMBTU related to basis swap contracts in Energy Marketing. | ||||||||||||||||||||||
(b)Â Â Includes an aggregate 933,893 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, 2015 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 4 | |||||||||||||||||||
Other deferred credits and other liabilities | 33 | |||||||||||||||||||||
Commodity contracts | Other current assets | 1 | ||||||||||||||||||||
Derivative financial instruments | 4 | |||||||||||||||||||||
Total | $ | 42 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 288 | |||||||||||||||||||
Other deferred credits and other liabilities | 30 | |||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | |||||||||||||||||||
Energy management contracts | Other current assets | 13 | Other current assets | 3 | ||||||||||||||||||
Derivative financial instruments | 10 | |||||||||||||||||||||
Other deferred debits and other assets | 6 | Other deferred credits and other liabilities | 6 | |||||||||||||||||||
Total | $ | 20 | $ | 337 | ||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 5 | |||||||||||||||||||
Other deferred credits and other liabilities | 28 | |||||||||||||||||||||
Commodity contracts | Other current assets | 1 | ||||||||||||||||||||
Derivative financial instruments | 11 | |||||||||||||||||||||
Total | $ | 45 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | |||||||||||||||||||
Other deferred credits and other liabilities | 17 | |||||||||||||||||||||
Commodity contracts | Other current assets | $ | 1 | |||||||||||||||||||
Energy management contracts | Other current assets | 15 | Other current assets | 5 | ||||||||||||||||||
Derivative financial instruments | 10 | |||||||||||||||||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | |||||||||||||||||||
Total | $ | 21 | $ | 244 | ||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives in Cash Flow Hedging Relationships | |||||||||||||||||||||
Loss Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (3 | ) | Interest expense | — | $ | (1 | ) | |||||||||||
Gain (Loss) Recognized in OCI, net of tax | Gain (Loss) Reclassified from AOCI into Income, net of tax | |||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (2 | ) | Interest expense | $ | (2 | ) | $ | (2 | ) | |||||||||
Commodity contracts | (1 | ) | 3 | Gas purchased for resale | (7 | ) | 4 | |||||||||||||||
Total | $ | (3 | ) | $ | 1 | $ | (9 | ) | $ | 2 | ||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | ||||||||||||||||||||||
Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (94 | ) | $ | (112 | ) | Other income | $ | 4 | — | ||||||||||||
Offseting Assets [Table Text Block] | Information related to the Company's offsetting of derivative assets follows: | |||||||||||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Received | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Commodity contracts | $ | 1 | — | $ | 1 | — | — | $ | 1 | |||||||||||||
Energy management contracts | 19 | — | 19 | — | — | 19 | ||||||||||||||||
   Total | $ | 20 | — | $ | 20 | — | — | $ | 20 | |||||||||||||
Balance sheet location | Other current assets | $ | 14 | |||||||||||||||||||
Other deferred debits and other assets | 6 | |||||||||||||||||||||
Total | $ | 20 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Commodity contracts | $ | 1 | — | $ | 1 | — | — | $ | 1 | |||||||||||||
Energy management contracts | 20 | — | 20 | — | — | 20 | ||||||||||||||||
   Total | $ | 21 | — | $ | 21 | — | — | $ | 21 | |||||||||||||
Balance sheet location | Other current assets | $ | 16 | |||||||||||||||||||
Other deferred debits and other assets | 5 | |||||||||||||||||||||
Total | $ | 21 | ||||||||||||||||||||
Offsetting Liabilities [Table Text Block] | Information related to the Company's offsetting of derivative liabilities follows: | |||||||||||||||||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Interest rate contracts | $ | 355 | — | $ | 355 | — | $ | (216 | ) | $ | 139 | |||||||||||
Commodity contracts | 5 | — | 5 | — | (4 | ) | 1 | |||||||||||||||
Energy management contracts | 19 | — | 19 | — | (13 | ) | 6 | |||||||||||||||
   Total | $ | 379 | — | $ | 379 | — | $ | (233 | ) | $ | 146 | |||||||||||
Balance sheet location | Other current assets | $ | 4 | |||||||||||||||||||
Derivative financial instruments | 306 | |||||||||||||||||||||
Other deferred credits and other liabilities | 69 | |||||||||||||||||||||
Total | $ | 379 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Interest rate contracts | $ | 257 | — | $ | 257 | — | $ | (131 | ) | $ | 126 | |||||||||||
Commodity contracts | 12 | — | 12 | — | (10 | ) | 2 | |||||||||||||||
Energy management contracts | 20 | — | 20 | — | (11 | ) | 9 | |||||||||||||||
   Total | $ | 289 | — | $ | 289 | — | $ | (152 | ) | $ | 137 | |||||||||||
Balance sheet location | Other current assets | $ | 6 | |||||||||||||||||||
Derivative financial instruments | 233 | |||||||||||||||||||||
Other deferred credits and other liabilities | 50 | |||||||||||||||||||||
Total | $ | 289 | ||||||||||||||||||||
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 (each of which was a liability derivative for all periods presented) was reflected in the condensed consolidated balance sheet as follows: | |||||||||||||||||||||
Fair Values of Derivative Instruments | Liability Derivatives | |||||||||||||||||||||
Balance Sheet | Fair | |||||||||||||||||||||
Millions of dollars | Location | Value | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | |||||||||||||||||||
Other deferred credits and other liabilities | 10 | |||||||||||||||||||||
Total | $ | 11 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 288 | |||||||||||||||||||
Other deferred credits and other liabilities | 30 | |||||||||||||||||||||
Total | $ | 318 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 1 | |||||||||||||||||||
Other deferred credits and other liabilities | 8 | |||||||||||||||||||||
Total | $ | 9 | ||||||||||||||||||||
Not designated as hedging instruments | ||||||||||||||||||||||
Interest rate contracts | Derivative financial instruments | $ | 207 | |||||||||||||||||||
Other deferred credits and other liabilities | 17 | |||||||||||||||||||||
Total | $ | 224 | ||||||||||||||||||||
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The effect of derivative instruments on the condensed consolidated statement of income is as follows: | |||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Loss Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (2 | ) | $ | (3 | ) | Interest expense | — | $ | (1 | ) | |||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | ||||||||||||||||||||||
Derivatives not designated as Hedging Instruments | Loss Deferred in Regulatory Accounts | Gain Reclassified from Deferred Accounts into Income | ||||||||||||||||||||
Millions of dollars | 2015 | 2014 | Location | 2015 | 2014 | |||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
Interest rate contracts | $ | (94 | ) | $ | (112 | ) | Other income | $ | 4 | — | ||||||||||||
Offsetting Liabilities [Table Text Block] | Information related to Consolidated SCE&G's derivative liabilities follows: | |||||||||||||||||||||
Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Gross Amounts Not Offset in the Statement of Financial Position | Net Amount | ||||||||||||||||||
Millions of dollars | Financial Instruments | Cash Collateral Posted | ||||||||||||||||||||
As of March 31, 2015 | ||||||||||||||||||||||
Interest rate contracts | $ | 329 | — | $ | 329 | — | $ | (189 | ) | $ | 140 | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 289 | |||||||||||||||||||
Other deferred credits and other liabilities | 40 | |||||||||||||||||||||
Total | $ | 329 | ||||||||||||||||||||
As of December 31, 2014 | ||||||||||||||||||||||
Interest rate contracts | $ | 233 | — | $ | 233 | — | $ | (107 | ) | $ | 126 | |||||||||||
Balance Sheet Location | Derivative financial instruments | $ | 208 | |||||||||||||||||||
Other deferred credits and other liabilities | 25 | |||||||||||||||||||||
$ | 233 | |||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_INCLUD1
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
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, 2015 | As of December 31, 2014 | ||||||||||||||||
Millions of dollars | Level 1 | Level 2 | Level 1 | Level 2 | |||||||||||||
Assets: | |||||||||||||||||
Available for sale securities | $ | 13 | — | $ | 13 | — | |||||||||||
Commodity contracts | 1 | — | 1 | — | |||||||||||||
Energy management contracts | — | $ | 19 | — | $ | 20 | |||||||||||
Liabilities: | |||||||||||||||||
Interest rate contracts | — | 355 | — | 257 | |||||||||||||
Commodity contracts | — | — | 1 | 11 | |||||||||||||
Energy management contracts | 3 | 23 | 5 | 18 | |||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value were as follows: | ||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair Value | Amount | Fair Value | ||||||||||||||
Long-term debt | $ | 5,541.60 | $ | 6,501.60 | $ | 5,697.20 | $ | 6,592.10 | |||||||||
SCEG | |||||||||||||||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value were as follows: | ||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
Millions of dollars | Carrying | Estimated | Carrying | Estimated | |||||||||||||
Amount | Fair | Amount | Fair | ||||||||||||||
Value | Value | ||||||||||||||||
Long-term debt | $ | 4,303.30 | $ | 5,119.20 | $ | 4,308.60 | $ | 5,070.90 | |||||||||
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | :Â | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 5.8 | $ | 5 | $ | 1.4 | $ | 1.2 | |||||||||
Interest cost | 9.5 | 10.2 | 2.9 | 3.1 | |||||||||||||
Expected return on assets | (15.5 | ) | (16.8 | ) | — | — | |||||||||||
Prior service cost amortization | 1 | 1 | 0.1 | 0.1 | |||||||||||||
Amortization of actuarial losses | 3.5 | 1.3 | 0.6 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 4.3 | $ | 0.7 | $ | 5 | $ | 4.5 | |||||||||
SCEG | |||||||||||||||||
Pension and Other Postretirement Benefit Plans | |||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | : | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Millions of dollars | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Three months ended March 31, | |||||||||||||||||
Service cost | $ | 4.6 | $ | 4 | $ | 1.1 | $ | 1 | |||||||||
Interest cost | 8 | 8.6 | 2.3 | 2.4 | |||||||||||||
Expected return on assets | (13.0 | ) | (14.2 | ) | — | — | |||||||||||
Prior service cost amortization | 0.8 | 0.9 | 0.1 | 0.1 | |||||||||||||
Amortization of actuarial losses | 3 | 1.1 | 0.4 | 0.1 | |||||||||||||
Net periodic benefit cost | $ | 3.4 | $ | 0.4 | $ | 3.9 | $ | 3.6 | |||||||||
SEGMENT_OF_BUSINESS_INFORMATIO1
SEGMENT OF BUSINESS INFORMATION (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
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, 2015 | |||||||||||||||||
Electric Operations | $ | 629 | — | $ | 199 | n/a | |||||||||||
Gas Distribution | 368 | — | 96 | n/a | |||||||||||||
Retail Gas Marketing | 204 | — | n/a | $ | 27 | ||||||||||||
Energy Marketing | 187 | $ | 35 | n/a | 6 | ||||||||||||
All Other | 4 | 114 | 238 | 207 | |||||||||||||
Adjustments/Eliminations | (3 | ) | (149 | ) | 53 | 160 | |||||||||||
Consolidated Total | $ | 1,389 | $ | — | $ | 586 | $ | 400 | |||||||||
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 | |||||||||
March 31, | December 31, | ||||||||||||||||
Segment Assets | 2015 | 2014 | |||||||||||||||
Electric Operations | $ | 10,300 | $ | 10,182 | |||||||||||||
Gas Distribution | 2,504 | 2,487 | |||||||||||||||
Retail Gas Marketing | 155 | 140 | |||||||||||||||
Energy Marketing | 128 | 150 | |||||||||||||||
All Other | 1,494 | 1,474 | |||||||||||||||
Adjustments/Eliminations | 1,825 | 2,419 | |||||||||||||||
Consolidated Total | $ | 16,406 | $ | 16,852 | |||||||||||||
SCEG | |||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | . | ||||||||||||||||
Millions of dollars | External Revenue | Operating Income | Earnings Available to Common Shareholder | ||||||||||||||
Three Months Ended March 31, 2015 | |||||||||||||||||
Electric Operations | $ | 630 | $ | 199 | n/a | ||||||||||||
Gas Distribution | 142 | 38 | n/a | ||||||||||||||
Adjustments/Eliminations | — | — | $ | 122 | |||||||||||||
Consolidated Total | $ | 772 | $ | 237 | $ | 122 | |||||||||||
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 | |||||||||||
Segment Assets | 31-Mar-15 | 31-Dec-14 | |||||||||||||||
Electric Operations | $ | 10,300 | $ | 10,182 | |||||||||||||
Gas Distribution | 731 | 721 | |||||||||||||||
Adjustments/Eliminations | 3,103 | 3,204 | |||||||||||||||
Consolidated Total | $ | 14,134 | $ | 14,107 | |||||||||||||
Dispositions_Tables
Dispositions (Tables) | 3 Months Ended | ||||||||||||
Mar. 31, 2015 | |||||||||||||
Disposal groups [Abstract] | |||||||||||||
Schedule of Disposal Group, Held for Sale [Table Text Block] | |||||||||||||
Millions of dollars | CGT | SCI | Total | ||||||||||
Assets Held for Sale | |||||||||||||
Utility Plant, Net | $ | 288.4 | — | $ | 288.4 | ||||||||
Nonutility Property and Investments, Net | 0.6 | $ | 40.1 | 40.7 | |||||||||
Current Assets | 6.5 | 3.9 | 10.4 | ||||||||||
Deferred Debits and Other Assets | 0.9 | 0.2 | 1.1 | ||||||||||
Total Assets Held for Sale | 296.4 | 44.2 | 340.6 | ||||||||||
Liabilities Held for Sale | |||||||||||||
Current Liabilities | $ | 3.5 | $ | 2.2 | $ | 5.7 | |||||||
Deferred Credits and Other Liabilities | 42.9 | 3.1 | 46 | ||||||||||
Total Liabilities Held for Sale | $ | 46.4 | $ | 5.3 | $ | 51.7 | |||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Management and Supply Service Agreements | ||||
Property, Plant and Equipment, Net | $285 | $284 | ||
SCEG | ||||
Significant Accounting Policies | ||||
Number of coal fired units to be retired | 3 | 6 | ||
Number of Units retired | 3 | 3 | ||
Asset Management and Supply Service Agreements | ||||
Property, Plant and Equipment, Net | 67 | 67 | ||
Genco | ||||
Significant Accounting Policies | ||||
Power Generation Capacity Megawatts | 605 | |||
Asset Management and Supply Service Agreements | ||||
Property, Plant and Equipment, Net | 498 | |||
PSNC Energy [Member] | ||||
Asset Management and Supply Service Agreements | ||||
Percentage of natural gas inventory held by counterparties under asset management and supply service agreements (as a percent) | 32.00% | 48.00% | ||
Natural gas inventory, carrying amount | $8.70 | $26.10 | ||
PercentOfStorageFeesCreditedToRatePayers | 75.00% |
RATE_AND_OTHER_REGULATORY_MATT2
RATE AND OTHER REGULATORY MATTERS (Details) (USD $) | 3 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2015 | Mar. 31, 2013 | Dec. 31, 2012 | |
Rate Matters [Line Items] | ||||||||
Estimated undercollected base fuel and variable environmental costs | $36,100,000 | |||||||
Carrying cost recovery | -3,000,000 | -2,000,000 | ||||||
Regulatory Assets, Noncurrent | 1,890,000,000 | 1,823,000,000 | ||||||
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | |||||||
SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Forecasted incremental capital costs, 2015 petition | 698,000,000 | |||||||
Forecasted Capital Cost, 2015 Petition | 5,200,000,000 | |||||||
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs | 17,200,000 | |||||||
Net Lost Revenues associated with DSM programs | 6,600,000 | |||||||
Fuel Costs | 10,300,000 | |||||||
Undercollected balance fuel | 46,000,000 | |||||||
Estimated undercollected base fuel and variable environmental costs | 36,100,000 | |||||||
Carrying costs on deferred income tax assets | 1,900,000 | 1,200,000 | ||||||
Carrying cost recovery | -3,000,000 | -2,000,000 | ||||||
Regulatory Assets, Noncurrent | 1,817,000,000 | 1,745,000,000 | ||||||
Number of coal fired units to be retired | 3 | 6 | ||||||
Allowable return on common equity (as a percent) | 11.00% | |||||||
Demand Side Management Program Costs, Noncurrent | 32,000,000 | 15,400,000 | 16,900,000 | |||||
Regulatory Asset Recovery Assessments | 12 | |||||||
Increase (decrease) in retail electric rate requested under the BLRA | 66,200,000 | 67,200,000 | ||||||
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | 2.80% | 2.90% | ||||||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 0.60% | |||||||
Public Utilities changes in Retail Natural Gas Rates Approved under RSA | 2,600,000 | |||||||
Public Utilities, Rate Calculation Basis | 12-month rolling average | |||||||
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | |||||||
Derivative, Gain on Derivative | 17,800,000 | |||||||
Storm Damage Reserve Cost Applied | 5,000,000 | |||||||
Reduction to Net Lost Revenues from DSM programs | 25.00% | |||||||
Reduction to DSM Program costs deferred | 6,600,000 | |||||||
Number of Units retired | 3 | 3 | ||||||
Demand side management recovery period | 5 | |||||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100,000,000 | |||||||
PSNC Energy | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 1,000,000 | |||||||
Public Utilities, Rate Calculation Basis | 12 | |||||||
Pension Costs [Member] | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 337,000,000 | 350,000,000 | ||||||
Pension Costs [Member] | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 305,000,000 | 310,000,000 | ||||||
Regulatory Noncurrent Asset Amortization Period | 12 | 14 | 30 | |||||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | 14,000,000 | 63,000,000 | ||||||
Other Regulatory Assets [Member] | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 37,000,000 | 35,000,000 | ||||||
Regulatory Noncurrent Asset Amortization Period | 30 | 30 | ||||||
Other Regulatory Assets [Member] | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 37,000,000 | 35,000,000 | ||||||
Regulatory Noncurrent Asset Amortization Period | 50 | 50 | ||||||
Deferred Pollution Control Costs | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 35,000,000 | 36,000,000 | ||||||
Deferred Pollution Control Costs | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 35,000,000 | 36,000,000 | ||||||
Franchise agreement Costs | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 25,000,000 | 26,000,000 | ||||||
Franchise agreement Costs | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Regulatory Assets, Noncurrent | 25,000,000 | 26,000,000 | ||||||
Capital costs, construction delays [Domain] | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Forecasted incremental capital costs, 2015 petition | 539,000,000 | |||||||
Grossconstructioncosts [Member] | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Forecasted Capital Cost, 2015 Petition | 6,800,000,000 | |||||||
Planned major maintenance [Member] | SCEG | ||||||||
Rate Matters [Line Items] | ||||||||
Amounts Recovered through Electric Rates to offset Turbine Expense | 18,400,000 | |||||||
Storm damage reserve [Member] | ||||||||
Rate Matters [Line Items] | ||||||||
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM | 5,000,000 | |||||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | $100,000,000 |
RATE_AND_OTHER_REGULATORY_MATT3
RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $) | 3 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | ||||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2015 | Mar. 31, 2013 | Dec. 31, 2012 |
Regulatory Assets | ||||||||
Regulatory Liabilities | $829 | $814 | ||||||
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | |||||||
Regulatory Assets, Noncurrent | 1,890 | 1,823 | ||||||
SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Asset Recovery Assessments | 12 | |||||||
Public Utilities, Rate Calculation Basis | 12-month rolling average | |||||||
Net Lost Revenues associated with DSM programs | 6.6 | |||||||
Reduction to DSM Program costs deferred | 6.6 | |||||||
Fuel Costs | 10.3 | |||||||
Undercollected balance fuel | 46 | |||||||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 0.60% | |||||||
Regulatory Liabilities | 621 | 610 | ||||||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | |||||||
Carrying costs on deferred income tax assets | 1.9 | 1.2 | ||||||
Derivative, Gain on Derivative | 17.8 | |||||||
Storm Damage Reserve Cost Applied | 5 | |||||||
Demand Side Management Program Costs, Noncurrent | 32 | 15.4 | 16.9 | |||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | |||||||
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | |||||||
Regulatory Assets, Noncurrent | 1,817 | 1,745 | ||||||
Demand side management recovery period | 5 | |||||||
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net | 5 | |||||||
Reduction to Net Lost Revenues from DSM programs | 25.00% | |||||||
Public Utilities changes in Retail Natural Gas Rates Approved under RSA | 2.6 | |||||||
Amounts Recovered Through Electric Rates to offset Nuclear Related Outage Costs | 17.2 | |||||||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 11.00% | |||||||
PSNC Energy [Member] | ||||||||
Regulatory Assets | ||||||||
Public Utilities, Rate Calculation Basis | 12 | |||||||
Regulatory Assets, Noncurrent | 1 | |||||||
Other Regulatory Liability [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 0 | 1 | ||||||
Asset Retirement Obligation Costs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 712 | 703 | ||||||
Asset Retirement Obligation Costs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 510 | 505 | ||||||
Deferred Income Tax Charges [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 22 | 22 | ||||||
Deferred Income Tax Charges [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 16 | 17 | ||||||
Storm damage reserve [Member] | ||||||||
Regulatory Assets | ||||||||
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM | 5 | |||||||
Regulatory Liabilities | 6 | 6 | ||||||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | |||||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | |||||||
Storm damage reserve [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 6 | 6 | ||||||
Planned major maintenance [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 7 | 0 | ||||||
Planned major maintenance [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 7 | 0 | ||||||
Amounts Recovered through Electric Rates to offset Turbine Expense | 18.4 | |||||||
Deferred gains on interest rate derivatives [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 82 | 82 | ||||||
Deferred gains on interest rate derivatives [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Liabilities | 82 | 82 | ||||||
Franchise agreement Costs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 25 | 26 | ||||||
Franchise agreement Costs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 25 | 26 | ||||||
Deferred Losses On Interest Rate Derivatives [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 549 | 453 | ||||||
Deferred Losses On Interest Rate Derivatives [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 549 | 453 | ||||||
Deferred Pollution Control Cost [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 35 | 36 | ||||||
Deferred Pollution Control Cost [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 35 | 36 | ||||||
Regulatory Clause Revenues, under-recovered [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 4 | 20 | ||||||
Regulatory Clause Revenues, under-recovered [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 4 | 20 | ||||||
Planned major maintenance [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 0 | 2 | ||||||
Planned major maintenance [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 0 | 2 | ||||||
Asset Retirement Obligation Costs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 90 | |||||||
Regulatory Assets, Noncurrent | 370 | 366 | ||||||
Asset Retirement Obligation Costs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 350 | 347 | ||||||
unrecovered plant [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 132 | 137 | ||||||
unrecovered plant [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 132 | 137 | ||||||
Demand Side Management programs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 58 | 56 | ||||||
Demand Side Management programs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 58 | 56 | ||||||
Carrying cost on nuclear construction [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 11 | 9 | ||||||
Carrying cost on nuclear construction [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 11 | 9 | ||||||
Pipeline integerity management costs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 10 | 9 | ||||||
Deferred Income Tax Charges [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 70 | |||||||
Regulatory Assets, Noncurrent | 282 | 284 | ||||||
Deferred Income Tax Charges [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 70 | |||||||
Regulatory Assets, Noncurrent | 276 | 278 | ||||||
Environmental Restoration Costs [Member] | ||||||||
Regulatory Assets | ||||||||
MPG enviromental remediatio | 25 | |||||||
Regulatory Assets, Noncurrent | 40 | 40 | ||||||
Environmental Restoration Costs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 35 | 36 | ||||||
Pension Costs [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Assets, Noncurrent | 337 | 350 | ||||||
Pension Costs [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 12 | 14 | 30 | |||||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | 14 | 63 | ||||||
Regulatory Assets, Noncurrent | 305 | 310 | ||||||
Other Regulatory Assets [Member] | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 30 | 30 | ||||||
Regulatory Assets, Noncurrent | 37 | 35 | ||||||
Other Regulatory Assets [Member] | SCEG | ||||||||
Regulatory Assets | ||||||||
Regulatory Noncurrent Asset, Amortization Period | 50 | 50 | ||||||
Regulatory Assets, Noncurrent | $37 | $35 |
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2013 |
Regulatory Liabilities [Line Items] | |||||
Regulatory Assets, Noncurrent | $1,890 | $1,823 | |||
Regulatory Liabilities | 829 | 814 | |||
SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 0.60% | ||||
Regulatory Assets, Noncurrent | 1,817 | 1,745 | |||
Public Utilities Increase (Decrease) in Retail Electric Rates Approved under BLRA | 66.2 | 67.2 | |||
Public Utilities, Authorized Allowable Return on Common Equity, Percentage | 11.00% | ||||
Demand Side Management Program Costs, Noncurrent | 32 | 15.4 | 16.9 | ||
Regulatory Liabilities | 621 | 610 | |||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | ||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | ||||
PSNC Energy [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Assets, Noncurrent | 1 | ||||
Asset Retirement Obligation Costs [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 712 | 703 | |||
Asset Retirement Obligation Costs [Member] | SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 510 | 505 | |||
Storm damage reserve [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Storm Damage Reserve Applied To Offset Net Lost Margin Related To DSM | 5 | ||||
Regulatory Liabilities | 6 | 6 | |||
Annual Storm Damage Costs not offset by Amounts Recovered through Electric Rates | 2.5 | ||||
Amount Allowed to be Recovered through Electric Rates to Offset Incremental Storm Damage Costs | 100 | ||||
Storm damage reserve [Member] | SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 6 | 6 | |||
Deferred gains on interest rate derivatives [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 82 | 82 | |||
Deferred gains on interest rate derivatives [Member] | SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 82 | 82 | |||
Deferred Income Tax Charges [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 22 | 22 | |||
Deferred Income Tax Charges [Member] | SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 16 | 17 | |||
Planned major maintenance [Member] | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | 7 | 0 | |||
Planned major maintenance [Member] | SCEG | |||||
Regulatory Liabilities [Line Items] | |||||
Regulatory Liabilities | $7 | $0 |
COMMON_EQUITY_Details
COMMON EQUITY (Details) (USD $) | 3 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule of Capitalization, Equity [Line Items] | ||||
Common Stock, Shares Authorized | 200 | 200 | ||
COMMON EQUITY [Abstract] | ||||
Dividends declared | ($78) | ($74) | ||
Other comprehensive income (loss), unrealized holding gain (loss) net of reclassification to AOCI arising during period, net of tax | 6 | -1 | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | -4 | |||
Other Comprehensive Income (Loss), Net of Tax | 2 | -1 | ||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 402 | 192 | ||
Stock Issued During Period, Value, New Issues | 14 | 27 | ||
Common Stock, Shares, Outstanding | 143 | 141 | 143 | 141 |
Common Stock, Value, Outstanding | 2,392 | 2,307 | 2,378 | 2,280 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -73 | -61 | -75 | -60 |
Retained Earnings, Unappropriated | 3,006 | 2,563 | 2,684 | 2,444 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | 3 | 1 | ||
Income Available to Common Shareholders | 400 | 193 | ||
Common equity | 5,325 | 4,809 | 4,987 | 4,664 |
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | -57 | -53 | -63 | -52 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | -16 | -8 | -12 | -8 |
SCEG | ||||
Schedule of Capitalization, Equity [Line Items] | ||||
Common Stock, Shares, Issued | 40 | 40 | 40 | 40 |
Common Stock, Shares Authorized | 50 | 50 | ||
COMMON EQUITY [Abstract] | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 126 | 126 | ||
Proceeds from Contributions from Parent | -4 | 20 | ||
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 | 4 | 3 | ||
Dividends | -70 | -64 | ||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 126 | 126 | ||
Common Stock, Shares, Outstanding | 40 | 40 | ||
Preferred Stock, Shares Authorized | 20 | 20 | ||
Preferred Stock, Shares Outstanding | 0 | 0 | ||
Common Stock, Value, Outstanding | 2,556 | 2,560 | ||
Preferred Stock, Value, Issued | 0 | 0 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 | ||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 4,809 | 4,571 | 4,757 | 4,489 |
Retained Earnings, Unappropriated | 2,130 | 2,077 | ||
Reclassifcations of deferred employee benefit costs | not significant | |||
Common equity | 4,683 | 4,634 | ||
SCEG excluding VIEs [Member] | ||||
COMMON EQUITY [Abstract] | ||||
Proceeds from Contributions from Parent | -4 | 20 | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | 0 | 0 | ||
Dividends | -69 | 62 | ||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 122 | 123 | ||
Common Stock, Value, Outstanding | 2,556 | 2,499 | 2,560 | 2,479 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -3 | -3 | -3 | -3 |
Retained Earnings, Unappropriated | 2,130 | 1,957 | 2,077 | 1,896 |
Income Available to Common Shareholders | 122 | 123 | ||
Noncontrolling Interest [Member] | ||||
COMMON EQUITY [Abstract] | ||||
Net Income (Loss) Attributable to Noncontrolling Interest | 4 | 3 | ||
Dividends | 1 | 2 | ||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 126 | 118 | 123 | 117 |
Interest Rate Contract | ||||
COMMON EQUITY [Abstract] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -2 | -2 | ||
Commodity Contract | ||||
COMMON EQUITY [Abstract] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -7 | 4 | ||
Interest Expense [Member] | Cash Flow Hedging [Member] | Interest Rate Contract | ||||
COMMON EQUITY [Abstract] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | 2 | ||
Gas Purchased for Resale [Member] [Member] | ||||
COMMON EQUITY [Abstract] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | -7 | |||
Gas Purchased for Resale [Member] [Member] | Cash Flow Hedging [Member] | Commodity Contract | ||||
COMMON EQUITY [Abstract] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $7 | ($4) |
LONGTERM_AND_SHORTTERM_DEBT_De
LONG-TERM AND SHORT-TERM DEBT (Details) (USD $) | 3 Months Ended | 6 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Jun. 30, 2014 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $1,800 | ||
Commercial Paper Maximum Term | Outstanding commercial paper (270 or fewer days) | ||
Number of other banks (in entities) | 2 | ||
Long-term Debt, Current Maturities | 16 | 166 | |
Debt Instrument, Interest Rate Terms | 0.077 | ||
Junior Subordinated Notes | 150 | ||
Credit Suisse AG, Cayman Islands Branch (Member) | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | ||
Branch Banking Trust Company [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | ||
SCE&G (including Fuel Company) | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400 | 1,400 | |
Commercial Paper Maximum Term | Outstanding commercial paperB (270 or fewer days) | ||
Commercial Paper | -610 | -709 | |
Debt, Weighted Average Interest Rate | 0.54% | 0.52% | |
Letters of Credit Outstanding, Amount | 0.3 | -0.3 | |
Line of Credit Facility, Remaining Borrowing Capacity | 790 | 691 | |
SCEG | |||
Debt Instrument [Line Items] | |||
Proceeds from Issuance of First Mortgage Bond | 300 | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,200 | ||
Number of other banks (in entities) | 2 | ||
Long-term Debt, Current Maturities | 10 | 10 | |
Debt Instrument, Face Amount | 67.8 | ||
Debt Instrument, Interest Rate Terms | 0.045 | ||
SCEG | Credit Suisse AG, Cayman Islands Branch (Member) | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | ||
SCEG | Branch Banking Trust Company [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | ||
PSNC Energy [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 100 | 100 | |
Commercial Paper | 0 | -30 | |
Debt, Weighted Average Interest Rate | 0.00% | 0.65% | |
Letters of Credit Outstanding, Amount | 0 | 0 | |
Line of Credit Facility, Remaining Borrowing Capacity | 100 | 70 | |
Fuel Company | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $500 |
LONGTERM_AND_SHORTTERM_DEBT_De1
LONG-TERM AND SHORT-TERM DEBT (Details 2) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Dec. 31, 2014 | |
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | $1,800,000,000 | |
Commercial Paper Maximum Term | Outstanding commercial paper (270 or fewer days) | |
Number of other banks (in entities) | 2 | |
Bank of America, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
Morgan Stanly Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
Credit Suisse AG, Cayman Islands Branch (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
JPMorgan Chase Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
Mizuho Corporate Bank, Ltd (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
TD Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
UBS Loan Finance LLC (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
Deutsche Bank AG New York Branch [Member] [Member] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
Union Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
US Bank National Association (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
Two other banks [Domain] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.00% | |
JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCEG | ||
Debt Instrument [Line Items] | ||
Due to Affiliate, Current | 365,000,000 | 180,000,000 |
Debt Instruments [Abstract] | ||
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 | 1,200,000,000 | |
3 year credit agreement | 200,000,000 | |
Number of other banks (in entities) | 2 | |
Related Party Transaction, Due from (to) Related Party, Current | 275,500,000 | 83,000,000 |
Due from Other Related Parties, Current | 80,000,000 | |
SCEG | Bank of America, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
SCEG | Morgan Stanly Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
SCEG | Credit Suisse AG, Cayman Islands Branch (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 10.70% | |
SCEG | JPMorgan Chase Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCEG | Mizuho Corporate Bank, Ltd (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCEG | TD Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCEG | UBS Loan Finance LLC (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
SCEG | Deutsche Bank AG New York Branch [Member] [Member] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
SCEG | Union Bank, N.A. (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
SCEG | US Bank National Association (Member) | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.30% | |
SCEG | Two other banks [Domain] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 6.00% | |
SCEG | JP Morgan Chase, Mizuho Corp, TD Bank, Credit Suisse AG ,Cayman Islands Branch and UBS Loan Finance [Member] | ||
Lines of credit: | ||
Line of Credit Facility Percentage of Credit Facilities Provided by Each Bank | 8.90% | |
Parent Company [Member] | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 300,000,000 | 300,000,000 |
Commercial Paper | 15,000,000 | 179,000,000 |
Commercial paper, weighted average interest rate (as a percent) | 0.65% | 0.54% |
Letters of credit supported by LOC | 3,000,000 | 3,000,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 282,000,000 | 118,000,000 |
SCE&G (including Fuel Company) | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400,000,000 | 1,400,000,000 |
Commercial Paper | 610,000,000 | 709,000,000 |
Commercial paper, weighted average interest rate (as a percent) | 0.54% | 0.52% |
Commercial Paper Maximum Term | Outstanding commercial paperB (270 or fewer days) | |
Letters of credit supported by LOC | -300,000 | 300,000 |
Line of Credit Facility, Remaining Borrowing Capacity | 790,000,000 | 691,000,000 |
3 year credit agreement | 200,000,000 | |
Long-term Line of Credit | 1,400,000,000 | |
Fuel Company | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 500,000,000 | |
PSNC Energy | ||
Lines of credit: | ||
Line of Credit Facility, Maximum Borrowing Capacity | 100,000,000 | 100,000,000 |
Commercial Paper | 0 | 30,000,000 |
Commercial paper, weighted average interest rate (as a percent) | 0.00% | 0.65% |
Letters of credit supported by LOC | 0 | 0 |
Line of Credit Facility, Remaining Borrowing Capacity | $100,000,000 | $70,000,000 |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | Mar. 31, 2015 |
In Millions, unless otherwise specified | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $16 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 13 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 2 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound | 7 |
SCEG | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 16 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 13 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound | 2 |
Significant (Increase) Decrease in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound | $7 |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS (Details) (USD $) | 3 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
MMBTU | MMBTU | |
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 60,113,497 | 55,733,059 |
Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 10,140,000 | 6,840,000 |
Retail Gas Marketing | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 5,633,000 | 7,951,000 |
Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 44,340,497 | 40,942,059 |
Commodity Contract | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 19,301,964 | 18,237,720 |
Commodity Contract | Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 10,140,000 | 6,840,000 |
Commodity Contract | Retail Gas Marketing | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 5,633,000 | 7,951,000 |
Commodity Contract | Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 3,528,964 | 3,446,720 |
Energy Related Derivative [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 40,811,533 | 37,495,339 |
Energy Related Derivative [Member] | Gas Distribution | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 0 | 0 |
Energy Related Derivative [Member] | Retail Gas Marketing | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 0 | 0 |
Energy Related Derivative [Member] | Energy Marketing [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 40,811,533 | 37,495,339 |
Energy Related Derivative [Member] | Basis Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | 3,148,404 | 933,893 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | ||
Interest Rate Derivatives [Abstract] | ||
Derivative, Notional Amount | 1,300 | 1,100 |
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | ||
Interest Rate Derivatives [Abstract] | ||
Derivative, Notional Amount | 124.4 | 124.4 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | ||
Interest Rate Derivatives [Abstract] | ||
Derivative, Notional Amount | 1,300 | 1,100 |
SCEG | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||
Interest Rate Derivatives [Abstract] | ||
Derivative, Notional Amount | 36.4 | 36.4 |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS Fair Value on Balance Sheet (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Derivative [Line Items] | ||
Derivative Asset | $20 | $21 |
Derivative Liability | 379 | 289 |
Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 6 | 5 |
Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 69 | 50 |
Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 14 | 16 |
Derivative Liability | 4 | 6 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 355 | 257 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 1 | 1 |
Derivative Liability | 5 | 12 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 19 | 20 |
Derivative Liability | 19 | 20 |
Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 42 | 45 |
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 4 | 5 |
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 33 | 28 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 4 | 11 |
Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 1 | 1 |
Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 20 | 21 |
Derivative Liability | 337 | 244 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 288 | 207 |
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 30 | 17 |
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 1 | 1 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 10 | 10 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 6 | 5 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 6 | 5 |
Not Designated as Hedging Instrument [Member] | Other Energy Management Contract [Member] | Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 13 | 15 |
Derivative Liability | 3 | 5 |
SCEG | ||
Derivative [Line Items] | ||
Derivative Liability | 329 | 233 |
SCEG | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 40 | 25 |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 329 | 233 |
SCEG | Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 11 | 9 |
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 1 | 1 |
SCEG | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 10 | 8 |
SCEG | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 318 | 224 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Derivative Financial Instruments, Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 288 | 207 |
SCEG | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | $30 | $17 |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS On Income Statement (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Derivative [Line Items] | ||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | ($3) | ($1) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | -9 | 2 |
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant |
Commodity Contract | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | -1 | 3 |
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | -2 | -2 |
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -2 | -3 |
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -94 | -112 |
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 0.7 | |
Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 4 | 0 |
Gas Purchased for Resale [Member] [Member] | Commodity Contract | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 4 | |
Interest Expense [Member] | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred | 6.4 | |
Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 0 | -1 |
Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 2.3 | |
SCEG | ||
Derivative [Line Items] | ||
Interest Rate Cash Flow Hedge Ineffectiveness is Immaterial | insignificant | insignificant |
SCEG | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -94 | -112 |
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income | 4 | 0 |
SCEG | Other Nonoperating Income (Expense) [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | 0.7 | |
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Reclassified from Deferred Accounts into Income Effective Portion, Net | 0 | -1 |
SCEG | Interest Expense [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||
Derivative [Line Items] | ||
Derivative Instruments, Gain (Loss) Deferred in Regulatory Accounts Effective Portion, Net | -2 | -3 |
Derivative Instruments, Gain (Loss) Reclassified from Regulatory Accounts into Income, Estimated Net Amount to be Transferrred | $2.30 |
DERIVATIVE_FINANCIAL_INSTRUMEN5
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments (Credit Risk) (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | $233.50 | $152.40 |
Additional Collateral, Aggregate Fair Value | 141.7 | 129.8 |
Derivative, Net Liability Position, Aggregate Fair Value | 375.2 | 282.2 |
LetterofCreditAvailableCommodityDerivatives,assetposition | 3 | 9.2 |
Commodity Derivative, net asset position | 19 | 20 |
SCEG | ||
Derivative [Line Items] | ||
Collateral Already Posted, Aggregate Fair Value | 188.6 | 107.1 |
Additional Collateral, Aggregate Fair Value | 140.7 | 125.9 |
Derivative, Net Liability Position, Aggregate Fair Value | $329.30 | $233 |
DERIVATIVE_FINANCIAL_INSTRUMEN6
DERIVATIVE FINANCIAL INSTRUMENTS Derivative Financial Instruments Offsetting Assets and Liabilities (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | $0 | $0 |
Derivative Liability | 379 | 289 |
Derivative, Collateral, Right to Reclaim Securities | 0 | 0 |
Derivative Asset, Fair Value, Gross Asset | 20 | 21 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 20 | 21 |
Derivative, Collateral, Obligation to Return Securities | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 20 | 21 |
Derivative, Collateral, Right to Reclaim Cash | -233 | -152 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 146 | 137 |
Derivative Liability, Fair Value, Gross Liability | 379 | 289 |
Other Deferred Debits and Other Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Asset | 6 | 5 |
Other Current Assets [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 4 | 6 |
Derivative Asset | 14 | 16 |
Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 306 | 233 |
Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 69 | 50 |
Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability | 355 | 257 |
Derivative, Collateral, Right to Reclaim Securities | 0 | 0 |
Derivative, Collateral, Right to Reclaim Cash | -216 | -131 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 139 | 126 |
Derivative Liability, Fair Value, Gross Liability | 355 | 257 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability | 5 | 12 |
Derivative, Collateral, Right to Reclaim Securities | 0 | 0 |
Derivative Asset, Fair Value, Gross Asset | 1 | 1 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 1 | 1 |
Derivative, Collateral, Obligation to Return Securities | 0 | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1 | 1 |
Derivative, Collateral, Right to Reclaim Cash | -4 | -10 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 1 | 2 |
Derivative Liability, Fair Value, Gross Liability | 5 | 12 |
Other Energy Management Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability | 19 | 20 |
Derivative, Collateral, Right to Reclaim Securities | 0 | 0 |
Derivative Asset, Fair Value, Gross Asset | 19 | 20 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset | 19 | 20 |
Derivative, Collateral, Obligation to Return Securities | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 19 | 20 |
Derivative, Collateral, Right to Reclaim Cash | -13 | -11 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 6 | 9 |
Derivative Liability, Fair Value, Gross Liability | 19 | 20 |
SCEG | ||
Derivative [Line Items] | ||
Derivative Liability | 329 | 233 |
SCEG | Other Current Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 289 | 208 |
SCEG | Other Deferred Credits and Other Liabilities [Member] | ||
Derivative [Line Items] | ||
Derivative Liability | 40 | 25 |
SCEG | Interest Rate Contract [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability | 329 | 233 |
Derivative, Collateral, Right to Reclaim Securities | 0 | 0 |
Derivative, Collateral, Right to Reclaim Cash | -189 | -107 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 140 | 126 |
Derivative Liability, Fair Value, Gross Liability | $329 | $233 |
FAIR_VALUE_MEASUREMENTS_INCLUD2
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | $20 | $21 |
Derivative Liability | 379 | 289 |
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 13 | 13 |
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 0 | 0 |
Interest Rate Contract | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | 355 | 257 |
Interest Rate Contract | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | 0 | 0 |
Interest Rate Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | 355 | 257 |
Commodity Contract | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 1 | 1 |
Derivative Liability | 5 | 12 |
Commodity Contract | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 1 | 1 |
Derivative Liability | 0 | 1 |
Commodity Contract | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 0 | 11 |
Other energy management contracts [Member] [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 19 | 20 |
Derivative Liability | 19 | 20 |
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 0 | 0 |
Derivative Liability | 3 | 5 |
Other energy management contracts [Member] [Member] | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Asset | 19 | 20 |
Derivative Liability | 23 | 18 |
SCEG | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | 329 | 233 |
SCEG | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | 329 | 233 |
SCEG | Interest Rate Contract | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Derivative Liability | $329 | $233 |
FAIR_VALUE_MEASUREMENTS_INCLUD3
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | $5,541.60 | $5,697.20 |
Long-term Debt, Fair Value | 6,501.60 | 6,592.10 |
SCEG | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt | 4,303.30 | 4,308.60 |
Long-term Debt, Fair Value | $5,119.20 | $5,070.90 |
EMPLOYEE_BENEFIT_PLANS_Details
EMPLOYEE BENEFIT PLANS (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Pension and Other Postretirement Benefit Plans | |||||
Pension Contributions | No | No | |||
Pension Benefits | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 5.8 | 5 | |||
Interest cost | 9.5 | 10.2 | |||
Expected return on assets | -15.5 | -16.8 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 1 | 1 | |||
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3.5 | 1.3 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 4.3 | 0.7 | |||
Other Postretirement Benefits | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 1.4 | 1.2 | |||
Interest cost | 2.9 | 3.1 | |||
Expected return on assets | 0 | 0 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.1 | 0.1 | |||
Defined Benefit Plan, Actuarial Net (Gains) Losses | 0.6 | 0.1 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 5 | 4.5 | |||
SCEG | |||||
Pension and Other Postretirement Benefit Plans | |||||
Pension Contributions | No | No | |||
SCEG | Pension Benefits | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 4.6 | 4 | |||
Interest cost | 8 | 8.6 | |||
Expected return on assets | 13 | 14.2 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.8 | 0.9 | |||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -3 | -1.1 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 3.4 | 0.4 | |||
SCEG | Other Postretirement Benefits | |||||
Components of Net Periodic Benefit Cost | |||||
Service cost | 1.1 | 1 | |||
Interest cost | 2.3 | 2.4 | |||
Expected return on assets | 0 | 0 | |||
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Recognized in Net Periodic Benefit Cost, before Tax | 0.1 | 0.1 | |||
Defined Benefit Plan, Actuarial Net (Gains) Losses | -0.4 | -0.1 | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 3.9 | 3.6 | |||
Pension Costs [Member] | SCEG | |||||
Components of Net Periodic Benefit Cost | |||||
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 | ||||
Mar. 31, 2015 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2014 | |
Environmental | |||||
NPDES permit renewal permit period | five | ||||
MIlestones Extended | 3 | ||||
ForecastedCapitalCostsApproved2012Order | $4,548,000,000 | ||||
Regulatory Assets, Noncurrent | 1,890,000,000 | 1,823,000,000 | |||
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 | 43,500,000 | ||||
Maximum amount of coverage to nuclear facility for property damage and outage costs | 2,750,000,000 | ||||
Maximum amount of coverage for accidental property damage | 500,000,000 | ||||
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 | 19,200,000 | ||||
Deferred costs net of costs previously recovered through rates and insurance settlements included in regulatory assets | 35,200,000 | ||||
Current ownership share in New Unit | 55.00% | ||||
Total additional ownership in new units | 5.00% | ||||
Additional ownership in new units | 0.00% | 2.00% | 1.00% | ||
Additional ownership in new units, dollars | 500,000,000 | ||||
Total Construction Milestones | 146 | ||||
Milestone Schedule Contingency Period | 18 | ||||
Completed Construction Milestones | 105 | ||||
MIlestones Extended | 3 | ||||
Forecasted incremental capital costs, 2015 petition | 698,000,000 | ||||
Regulatory Assets, Noncurrent | 1,817,000,000 | 1,745,000,000 | |||
PSNC Energy | |||||
Environmental | |||||
Number of MGP sites requiring cleanup | 5 | ||||
Regulatory Assets, Noncurrent | 1,000,000 | ||||
Summer Station New Units [Domain] | |||||
Nuclear Insurance | |||||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 2,900,000,000 | ||||
jointly owned utility plant ownership, construction financing cost | 2,425,000,000 | ||||
Environmental | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 55.00% | ||||
Nuclear Production Tax Credits | 1,400,000,000 | ||||
Nuclear Production Tax Credit realization period | 8 | ||||
Summer Station New Units [Domain] | SCEG | |||||
Environmental | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 55.00% | ||||
Nuclear Production Tax Credits | 1,400,000,000 | ||||
Nuclear Production Tax Credit realization period | 8 | ||||
Grossconstructioncosts [Member] | |||||
Environmental | |||||
ForecastedCapitalCostsApproved2012Order | 5,755,000,000 | ||||
Capital costs, owners [Domain] | |||||
Environmental | |||||
Forecasted incremental capital costs, 2015 petition | 245,000,000 | ||||
Capital costs, owners [Domain] | SCEG | |||||
Environmental | |||||
Forecasted incremental capital costs, 2015 petition | 245,000,000 | ||||
Capital costs, Other [Domain] [Domain] | |||||
Environmental | |||||
Forecasted incremental capital costs, 2015 petition | 453,000,000 | ||||
Capital costs, Other [Domain] [Domain] | SCEG | |||||
Environmental | |||||
Forecasted incremental capital costs, 2015 petition | $453,000,000 |
SEGMENT_OF_BUSINESS_INFORMATIO2
SEGMENT OF BUSINESS INFORMATION (Details) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | |||
Gain (Loss) on Disposition of Nonregulated Business, Net of Transaction Costs | $202 | ||
Electric Domestic Regulated Revenue | 629 | 678 | |
Intersegment Revenue | 0 | 0 | |
Operating Income | 586 | 350 | |
Regulated Operating Revenue, Gas | 369 | 458 | |
Regulated and Unregulated Operating Revenue | 1,389 | 1,590 | |
Income Available to Common Shareholders | 400 | 193 | |
Segment Assets | 16,406 | 16,852 | |
Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 629 | 678 | |
Intersegment Revenue | 0 | 2 | |
Operating Income | 199 | 198 | |
Segment Assets | 10,300 | 10,182 | |
Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Intersegment Revenue | 0 | 0 | |
Operating Income | 96 | 97 | |
Regulated and Unregulated Operating Revenue | 368 | 455 | |
Segment Assets | 2,504 | 2,487 | |
Retail Gas Marketing | |||
Segment Reporting Information [Line Items] | |||
Intersegment Revenue | 0 | 0 | |
Regulated and Unregulated Operating Revenue | 204 | 220 | |
Income Available to Common Shareholders | 27 | 22 | |
Segment Assets | 155 | 140 | |
Energy Marketing [Member] | |||
Segment Reporting Information [Line Items] | |||
Intersegment Revenue | 35 | 53 | |
Regulated and Unregulated Operating Revenue | 187 | 234 | |
Income Available to Common Shareholders | 6 | 7 | |
Segment Assets | 128 | 150 | |
All Other [member] | |||
Segment Reporting Information [Line Items] | |||
Intersegment Revenue | 114 | 110 | |
Operating Income | 238 | 8 | |
Regulated and Unregulated Operating Revenue | 4 | 9 | |
Income Available to Common Shareholders | 207 | 4 | |
Segment Assets | 1,494 | 1,474 | |
Adjustments/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Intersegment Revenue | -149 | -165 | |
Operating Income | 53 | 47 | |
Regulated and Unregulated Operating Revenue | -3 | -6 | |
Income Available to Common Shareholders | 160 | 160 | |
Segment Assets | 1,825 | 2,419 | |
SCEG | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 630 | 680 | |
Operating Income | 237 | 239 | |
Regulated Operating Revenue, Gas | 142 | 179 | |
Net Income (Loss) Attributable to Parent | 122 | 123 | |
Segment Assets | 14,134 | 14,107 | |
Regulated Operating Revenue | 772 | 859 | |
SCEG | Electric Operations | |||
Segment Reporting Information [Line Items] | |||
Electric Domestic Regulated Revenue | 630 | 680 | |
Operating Income | 199 | 198 | |
Segment Assets | 10,300 | 10,182 | |
SCEG | Gas Distribution | |||
Segment Reporting Information [Line Items] | |||
Operating Income | 38 | 41 | |
Regulated Operating Revenue, Gas | 142 | 179 | |
Segment Assets | 731 | 721 | |
SCEG | Adjustments/Eliminations | |||
Segment Reporting Information [Line Items] | |||
Operating Income | 0 | 0 | |
Net Income (Loss) Attributable to Parent | 122 | 123 | |
Segment Assets | 3,103 | 3,204 | |
Regulated Operating Revenue | $0 | $0 |
AFFILIATED_TRANSACTIONS_SCEG_D
AFFILIATED TRANSACTIONS -SCEG (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Sep. 30, 2014 |
Canadys Refined Coal [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction, Amounts of Transaction | $69.70 | $39 | ||
Due to Affiliate, Current | 18.6 | 27.9 | ||
Due from Affiliate, Current | 18.5 | 27.8 | ||
Equity Method Investment, Ownership Percentage | 40.00% | |||
CGT [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction Purchases from Related Party | 3.4 | 5.5 | ||
Due to Affiliate, Current | 3.3 | |||
Due from Affiliate, Current | 1.2 | 0 | ||
Energy Marketing [Member] | ||||
Related Party Transaction [Line Items] | ||||
Due to Affiliate, Current | 10.6 | 12.6 | ||
Cost of Natural Gas Purchases | 34.6 | 53.4 | ||
Canadys Refined Coal [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction Purchases from Related Party | 70.1 | 39.2 | ||
SCANA Services [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction Purchases from Related Party | 48.4 | 47.3 | ||
Related Party Transaction, Expenses from Transactions with Related Party | $73.10 | $76.20 |
Dispositions_Details
Dispositions (Details) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Public Utilities, Property, Plant and Equipment, Net | $12,410 | $12,232 |
Nonutility Property and Investments, Net | 477 | 472 |
Assets, Current | 1,435 | 2,145 |
Regulated Entity, Other Assets, Noncurrent | 2,084 | 2,003 |
Assets held for sale | 0 | 341 |
Liabilities, Current | 1,732 | 2,533 |
Liabilities, Noncurrent | 3,824 | 3,801 |
Liabilities held for sale | 52 | |
Estimated pre-tax gain on sale of CGT and SCI | 342 | |
Assets Held-for-sale [Member] | CGT [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 288.4 | |
Nonutility Property and Investments, Net | 0.6 | |
Assets, Current | 6.5 | |
Regulated Entity, Other Assets, Noncurrent | 0.9 | |
Assets held for sale | 296.4 | |
Assets Held-for-sale [Member] | SCANA Communications [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 0 | |
Nonutility Property and Investments, Net | 40.1 | |
Assets, Current | 3.9 | |
Regulated Entity, Other Assets, Noncurrent | 0.2 | |
Assets held for sale | 44.2 | |
Assets Held-for-sale [Member] | Held for Sale, CGT and SCI [Member] | ||
Public Utilities, Property, Plant and Equipment, Net | 288.4 | |
Nonutility Property and Investments, Net | 40.7 | |
Assets, Current | 10.4 | |
Regulated Entity, Other Assets, Noncurrent | 1.1 | |
Assets held for sale | 340.6 | |
Liabilities, Held for Sale [Member] | CGT [Member] | ||
Liabilities, Current | 3.5 | |
Liabilities, Noncurrent | 42.9 | |
Liabilities held for sale | 46.4 | |
Liabilities, Held for Sale [Member] | SCANA Communications [Member] | ||
Liabilities, Current | 2.2 | |
Liabilities, Noncurrent | 3.1 | |
Liabilities held for sale | 5.3 | |
Liabilities, Held for Sale [Member] | Held for Sale, CGT and SCI [Member] | ||
Liabilities, Current | 5.7 | |
Liabilities, Noncurrent | 46 | |
Liabilities held for sale | $51.70 |