x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission | Registrant, State of Incorporation, | I.R.S. Employer | ||
File Number | Address and Telephone Number | Identification No. | ||
1-8809 | SCANA Corporation | 57-0784499 | ||
(a South Carolina corporation) | ||||
100 SCANA Parkway, Cayce, South Carolina 29033 | ||||
(803) 217-9000 | ||||
1-3375 | South Carolina Electric & Gas Company | 57-0248695 | ||
(a South Carolina corporation) | ||||
100 SCANA Parkway, Cayce, South Carolina 29033 | ||||
(803) 217-9000 |
SCANA Corporation | Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ |
Smaller reporting company ¨ | |||
South Carolina Electric & Gas Company | Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x |
Smaller reporting company ¨ |
Description of | Shares Outstanding | |
Registrant | Common Stock | at July 31, 2013 |
SCANA Corporation | Without Par Value | 139,985,242 |
South Carolina Electric & Gas Company | Without Par Value | 40,296,147 (a) |
Page | |||
(1) | the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment; |
(2) | regulatory actions, particularly changes in rate regulation, regulations governing electric grid reliability, environmental regulations, and actions affecting the construction of new nuclear units; |
(3) | current and future litigation; |
(4) | changes in the economy, especially in areas served by subsidiaries of SCANA; |
(5) | the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; |
(6) | the impact of conservation and demand side management efforts and/or technological advances on customer usage; |
(7) | growth opportunities for SCANA’s regulated and diversified subsidiaries; |
(8) | the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity; |
(9) | changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; |
(10) | the effects of weather, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries (the Company) are located and in areas served by SCANA’s subsidiaries; |
(11) | payment and performance by counterparties and customers as contracted and when due; |
(12) | the results of efforts to license, site, construct and finance facilities for electric generation and transmission; |
(13) | maintaining creditworthy joint owners for SCE&G’s new nuclear generation project; |
(14) | the ability of suppliers, both domestic and international, to timely provide the labor, components, parts, tools, equipment and other supplies needed, at agreed upon prices, for our construction program, operations and maintenance; |
(15) | the results of efforts to ensure the physical and cyber security of key assets and processes; |
(16) | the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power; |
(17) | the availability of skilled and experienced human resources to properly manage, operate, and grow the Company’s businesses; |
(18) | labor disputes; |
(19) | performance of SCANA’s pension plan assets; |
(20) | changes in taxes; |
(21) | inflation or deflation; |
(22) | compliance with regulations; |
(23) | natural disasters and man-made mishaps that directly affect our operations or the regulations governing them; and |
(24) | the other risks and uncertainties described from time to time in the periodic reports filed by SCANA or SCE&G with the SEC. |
TERM | MEANING |
AFC | Allowance for Funds Used During Construction |
ANI | American Nuclear Insurers |
AOCI | Accumulated Other Comprehensive Income |
ARO | Asset Retirement Obligation |
BACT | Best Available Control Technology |
BLRA | Base Load Review Act |
CAA | Clean Air Act, as amended |
CAIR | Clean Air Interstate Rule |
CEO | Chief Executive Officer |
CFO | Chief Financial Officer |
CGT | Carolina Gas Transmission Corporation |
COL | Combined Construction and Operating License |
Company | SCANA, together with its consolidated subsidiaries |
Consolidated SCE&G | SCE&G and its consolidated affiliates |
Consortium | A consortium consisting of Westinghouse Electric Company LLC and Stone and Webster, Inc., a subsidiary of Chicago Bridge & Iron Company N.V. |
CSAPR | Cross-State Air Pollution Rule |
CUT | Customer Usage Tracker |
DHEC | South Carolina Department of Health and Environmental Control |
DOJ | United States Department of Justice |
DSM Programs | Demand reduction and energy efficiency programs |
EIZ Credits | South Carolina Capital Investment Tax Credits (formerly known as Economic Impact Zone Income Tax Credits) |
Energy Marketing | The divisions of SEMI, excluding SCANA Energy |
EPA | United States Environmental Protection Agency |
EPC Contract | Engineering, Procurement and Construction Agreement dated May 23, 2008 |
eWNA | Pilot Electric Weather Normalization Adjustment |
FERC | United States Federal Energy Regulatory Commission |
Fuel Company | South Carolina Fuel Company, Inc. |
GENCO | South Carolina Generating Company, Inc. |
GHG | Greenhouse Gas |
GWh | Gigawatt hour |
IRP | Integrated Resource Plan |
JEDA | South Carolina Jobs-Economic Development Authority |
LOC | Lines of Credit |
MGP | Manufactured Gas Plant |
MMBTU | Million British Thermal Units |
MW | Megawatt |
NASDAQ | The NASDAQ Stock Market, Inc. |
NCUC | North Carolina Utilities Commission |
NEIL | Nuclear Electric Insurance Limited |
New Units | Nuclear Units 2 and 3 under construction at Summer Station |
NRC | United States Nuclear Regulatory Commission |
NSPS | New Source Performance Standards |
NSR | New Source Review |
NYMEX | New York Mercantile Exchange |
OCI | Other Comprehensive Income |
ORS | South Carolina Office of Regulatory Staff |
PGA | Purchased Gas Adjustment |
Price-Anderson | Price-Anderson Indemnification Act |
PRP | Potentially Responsible Party |
PSNC Energy | Public Service Company of North Carolina, Incorporated |
Retail Gas Marketing | SCANA Energy |
RSA | Natural Gas Rate Stabilization Act |
Santee Cooper | South Carolina Public Service Authority |
SCANA | SCANA Corporation, the parent company |
SCANA Energy | A division of SEMI which markets natural gas in Georgia |
SCE&G | South Carolina Electric & Gas Company |
SCEUC | South Carolina Energy Users Committee |
SCPSC | Public Service Commission of South Carolina |
SEC | United States Securities and Exchange Commission |
SEMI | SCANA Energy Marketing, Inc. |
Summer Station | V. C. Summer Nuclear Station |
VIE | Variable Interest Entity |
Item 1. | FINANCIAL STATEMENTS |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Assets | ||||||||
Utility Plant In Service | $ | 12,037 | $ | 11,865 | ||||
Accumulated Depreciation and Amortization | (3,916 | ) | (3,811 | ) | ||||
Construction Work in Progress | 2,379 | 2,084 | ||||||
Plant to be Retired, Net | 351 | 362 | ||||||
Nuclear Fuel, Net of Accumulated Amortization | 267 | 166 | ||||||
Goodwill, net of writedown of $230 | 230 | 230 | ||||||
Utility Plant, Net | 11,348 | 10,896 | ||||||
Nonutility Property and Investments: | ||||||||
Nonutility property, net of accumulated depreciation of $145 and $139 | 313 | 306 | ||||||
Assets held in trust, net-nuclear decommissioning | 95 | 94 | ||||||
Other investments | 89 | 87 | ||||||
Nonutility Property and Investments, Net | 497 | 487 | ||||||
Current Assets: | ||||||||
Cash and cash equivalents | 92 | 72 | ||||||
Receivables, net of allowance for uncollectible accounts of $6 and $7 | 685 | 780 | ||||||
Inventories (at average cost): | ||||||||
Fuel and gas supply | 271 | 304 | ||||||
Materials and supplies | 140 | 136 | ||||||
Emission allowances | 1 | 1 | ||||||
Prepayments and other | 218 | 223 | ||||||
Deferred income taxes | 12 | 11 | ||||||
Total Current Assets | 1,419 | 1,527 | ||||||
Deferred Debits and Other Assets: | ||||||||
Regulatory assets | 1,439 | 1,464 | ||||||
Other | 235 | 242 | ||||||
Total Deferred Debits and Other Assets | 1,674 | 1,706 | ||||||
Total | $ | 14,938 | $ | 14,616 |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Capitalization and Liabilities | ||||||||
Common Equity | $ | 4,506 | $ | 4,154 | ||||
Long-Term Debt, net | 5,432 | 4,949 | ||||||
Total Capitalization | 9,938 | 9,103 | ||||||
Current Liabilities: | ||||||||
Short-term borrowings | 304 | 623 | ||||||
Current portion of long-term debt | 23 | 172 | ||||||
Accounts payable | 401 | 428 | ||||||
Customer deposits and customer prepayments | 79 | 86 | ||||||
Taxes accrued | 101 | 164 | ||||||
Interest accrued | 82 | 82 | ||||||
Dividends declared | 71 | 66 | ||||||
Derivative financial instruments | 14 | 80 | ||||||
Other | 88 | 110 | ||||||
Total Current Liabilities | 1,163 | 1,811 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Deferred income taxes, net | 1,698 | 1,653 | ||||||
Deferred investment tax credits | 34 | 36 | ||||||
Asset retirement obligations | 570 | 561 | ||||||
Postretirement benefits | 392 | 387 | ||||||
Regulatory liabilities | 976 | 882 | ||||||
Other | 167 | 183 | ||||||
Total Deferred Credits and Other Liabilities | 3,837 | 3,702 | ||||||
Commitments and Contingencies (Note 9) | — | — | ||||||
Total | $ | 14,938 | $ | 14,616 |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Millions of dollars, except per share amounts | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Operating Revenues: | ||||||||||||||||
Electric | $ | 610 | $ | 592 | $ | 1,193 | $ | 1,137 | ||||||||
Gas - regulated | 158 | 127 | 540 | 404 | ||||||||||||
Gas - nonregulated | 248 | 189 | 594 | 474 | ||||||||||||
Total Operating Revenues | 1,016 | 908 | 2,327 | 2,015 | ||||||||||||
Operating Expenses: | ||||||||||||||||
Fuel used in electric generation | 188 | 198 | 374 | 379 | ||||||||||||
Purchased power | 9 | 4 | 16 | 10 | ||||||||||||
Gas purchased for resale | 310 | 223 | 811 | 588 | ||||||||||||
Other operation and maintenance | 171 | 170 | 347 | 345 | ||||||||||||
Depreciation and amortization | 94 | 89 | 188 | 178 | ||||||||||||
Other taxes | 55 | 53 | 109 | 106 | ||||||||||||
Total Operating Expenses | 827 | 737 | 1,845 | 1,606 | ||||||||||||
Operating Income | 189 | 171 | 482 | 409 | ||||||||||||
Other Income (Expense): | ||||||||||||||||
Other income | 12 | 12 | 25 | 26 | ||||||||||||
Other expense | (10 | ) | (9 | ) | (22 | ) | (19 | ) | ||||||||
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $5 and $4 | (74 | ) | (73 | ) | (148 | ) | (145 | ) | ||||||||
Allowance for equity funds used during construction | 6 | 4 | 10 | 7 | ||||||||||||
Total Other Expense | (66 | ) | (66 | ) | (135 | ) | (131 | ) | ||||||||
Income Before Income Tax Expense | 123 | 105 | 347 | 278 | ||||||||||||
Income Tax Expense | 38 | 33 | 110 | 85 | ||||||||||||
Net Income | $ | 85 | $ | 72 | $ | 237 | $ | 193 | ||||||||
Per Common Share Data | ||||||||||||||||
Basic Earnings Per Share of Common Stock | $ | 0.60 | $ | 0.55 | $ | 1.73 | $ | 1.48 | ||||||||
Diluted Earnings Per Share of Common Stock | $ | 0.60 | $ | 0.54 | $ | 1.72 | $ | 1.46 | ||||||||
Weighted Average Common Shares Outstanding (millions) | ||||||||||||||||
Basic | 139.6 | 130.9 | 137.0 | 130.6 | ||||||||||||
Diluted | 139.6 | 133.1 | 137.9 | 132.7 | ||||||||||||
Dividends Declared Per Share of Common Stock | $ | 0.5075 | $ | 0.495 | $ | 1.015 | $ | 0.990 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net Income | $ | 85 | $ | 72 | $ | 237 | $ | 193 | ||||||||
Other Comprehensive Income (Loss), net of tax: | ||||||||||||||||
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $-, $(2), $2 and $(4) | — | (3 | ) | 3 | (7 | ) | ||||||||||
Losses on cash flow hedging activities reclassified to net income, net of tax of $-, $2, $3 and $9 | 1 | 4 | 5 | 14 | ||||||||||||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $-, $- and $- | 1 | 1 | 1 | 1 | ||||||||||||
Other Comprehensive Income | 2 | 2 | 9 | 8 | ||||||||||||
Total Comprehensive Income | $ | 87 | $ | 74 | $ | 246 | $ | 201 |
Six Months Ended June 30, | ||||||||
Millions of dollars | 2013 | 2012 | ||||||
Cash Flows From Operating Activities: | ||||||||
Net income | $ | 237 | $ | 193 | ||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||
Deferred income taxes, net | 39 | 65 | ||||||
Depreciation and amortization | 194 | 183 | ||||||
Amortization of nuclear fuel | 27 | 26 | ||||||
Allowance for equity funds used during construction | (10 | ) | (7 | ) | ||||
Cash provided (used) by changes in certain assets and liabilities: | ||||||||
Receivables | 101 | 77 | ||||||
Inventories | 2 | (25 | ) | |||||
Prepayments and other | (16 | ) | 17 | |||||
Regulatory liabilities | 56 | 28 | ||||||
Accounts payable | (15 | ) | (32 | ) | ||||
Taxes accrued | (63 | ) | (47 | ) | ||||
Interest accrued | — | 4 | ||||||
Regulatory assets | 9 | 20 | ||||||
Changes in other assets | (45 | ) | (13 | ) | ||||
Changes in other liabilities | (23 | ) | (50 | ) | ||||
Net Cash Provided From Operating Activities | 493 | 439 | ||||||
Cash Flows From Investing Activities: | ||||||||
Property additions and construction expenditures | (526 | ) | (591 | ) | ||||
Proceeds from investments (including derivative collateral posted) | 175 | 237 | ||||||
Purchase of investments (including derivative collateral posted) | (135 | ) | (211 | ) | ||||
Proceeds from interest rate contract settlement | 43 | 13 | ||||||
Payments upon interest rate contract settlement | (49 | ) | (51 | ) | ||||
Net Cash Used For Investing Activities | (492 | ) | (603 | ) | ||||
Cash Flows From Financing Activities: | ||||||||
Proceeds from issuance of common stock | 247 | 50 | ||||||
Proceeds from issuance of long-term debt | 451 | 494 | ||||||
Repayment of long-term debt | (223 | ) | (270 | ) | ||||
Dividends | (137 | ) | (128 | ) | ||||
Short-term borrowings, net | (319 | ) | 17 | |||||
Net Cash Provided From Financing Activities | 19 | 163 | ||||||
Net Increase (Decrease) In Cash and Cash Equivalents | 20 | (1 | ) | |||||
Cash and Cash Equivalents, January 1 | 72 | 29 | ||||||
Cash and Cash Equivalents, June 30 | $ | 92 | $ | 28 | ||||
Supplemental Cash Flow Information: | ||||||||
Cash paid for– Interest (net of capitalized interest of $5 and $4) | $ | 144 | $ | 141 | ||||
– Income taxes | 43 | 3 | ||||||
Noncash Investing and Financing Activities: | ||||||||
Accrued construction expenditures | 90 | 61 | ||||||
Capital leases | 5 | 2 | ||||||
Nuclear fuel purchase | 97 | — |
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Second Quarter | Year to Date | ||||||||||||
Millions | 2013 | 2012 | 2013 | 2012 | |||||||||
Weighted Average Shares Outstanding - Basic | 139.6 | 130.9 | 137.0 | 130.6 | |||||||||
Effect of dilutive equity forward shares | — | 2.2 | 0.9 | 2.1 | |||||||||
Weighted Average Shares - Diluted | 139.6 | 133.1 | 137.9 | 132.7 |
2. | RATE AND OTHER REGULATORY MATTERS |
Year | Effective | Amount | ||
2012 | First billing cycle of May | $19.6 million | ||
2011 | First billing cycle of June | $7.0 million |
Year | Action | Amount | ||||
2012 | 2.3 | % | Increase | $52.1 million | ||
2011 | 2.4 | % | Increase | $52.8 million |
Year | Action | Amount | ||||
2012 | 2.1 | % | Increase | $7.5 million | ||
2011 | 2.1 | % | Increase | $8.6 million |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Regulatory Assets: | ||||||||
Accumulated deferred income taxes | $ | 253 | $ | 254 | ||||
Under-collections - electric fuel adjustment clause | 71 | 66 | ||||||
Environmental remediation costs | 42 | 44 | ||||||
AROs and related funding | 328 | 319 | ||||||
Franchise agreements | 33 | 36 | ||||||
Deferred employee benefit plan costs | 445 | 460 | ||||||
Planned major maintenance | — | 6 | ||||||
Deferred losses on interest rate derivatives | 128 | 151 | ||||||
Deferred pollution control costs | 38 | 38 | ||||||
Unrecovered plant | 19 | 20 | ||||||
Other | 82 | 70 | ||||||
Total Regulatory Assets | $ | 1,439 | $ | 1,464 |
Regulatory Liabilities: | ||||||||
Accumulated deferred income taxes | $ | 20 | $ | 21 | ||||
Asset removal costs | 709 | 692 | ||||||
Storm damage reserve | 27 | 27 | ||||||
Monetization of bankruptcy claim | 30 | 32 | ||||||
Deferred gains on interest rate derivatives | 185 | 110 | ||||||
Planned major maintenance | 4 | — | ||||||
Other | 1 | — | ||||||
Total Regulatory Liabilities | $ | 976 | $ | 882 |
Millions of dollars | 2013 | 2012 | ||||||
Balance at January 1, | $ | 4,154 | $ | 3,889 | ||||
Common stock issued | 247 | 50 | ||||||
Dividends declared | (141 | ) | (130 | ) | ||||
Comprehensive income | 246 | 201 | ||||||
Balance as of June 30, | $ | 4,506 | $ | 4,010 | ||||
Millions of dollars | 2013 | 2012 | Income Statement Line Item Affected | |||||||
Three months ended June 30, | ||||||||||
Interest rate contracts | $ | (1 | ) | $ | (1 | ) | Increase in interest expense | |||
Commodity contracts | — | (3 | ) | Increase in gas purchased for resale | ||||||
Amortization of deferred employee benefit plan costs | (1 | ) | (1 | ) | ||||||
Total reclassifications | $ | (2 | ) | $ | (5 | ) | ||||
Six months ended June 30, | ||||||||||
Interest rate contracts | $ | (3 | ) | $ | (3 | ) | Increase in interest expense | |||
Commodity contracts | (2 | ) | (11 | ) | Increase in gas purchased for resale | |||||
Amortization of deferred employee benefit plan costs | (1 | ) | (1 | ) | ||||||
Total reclassifications | $ | (6 | ) | $ | (15 | ) |
4. | LONG-TERM DEBT AND LIQUIDITY |
SCANA | SCE&G | PSNC Energy | ||||||||||||||||||||||
Millions of dollars | June 30, 2013 | December 31, 2012 | June 30, 2013 | December 31, 2012 | June 30, 2013 | December 31, 2012 | ||||||||||||||||||
Lines of credit: | ||||||||||||||||||||||||
Total committed long-term | $ | 300 | $ | 300 | $ | 1,400 | $ | 1,400 | $ | 100 | $ | 100 | ||||||||||||
LOC advances | — | — | — | — | — | — | ||||||||||||||||||
Weighted average interest rate | — | — | — | — | — | — | ||||||||||||||||||
Outstanding commercial paper (270 or fewer days) | $ | 65 | $ | 142 | $ | 238 | $ | 449 | — | $ | 32 | |||||||||||||
Weighted average interest rate | 0.48 | % | 0.58 | % | 0.30 | % | 0.42 | % | — | 0.44 | % | |||||||||||||
Letters of credit supported by LOC | $ | 3 | $ | 3 | $ | 0.3 | $ | 0.3 | — | — | ||||||||||||||
Available | $ | 232 | $ | 155 | $ | 1,162 | $ | 951 | $ | 100 | $ | 68 |
Commodity and Other Energy Management Contracts (in MMBTU) | ||||||||||||
Hedge designation | Gas Distribution | Retail Gas Marketing | Energy Marketing | Total | ||||||||
As of June 30, 2013 | ||||||||||||
Cash flow | — | 6,924,000 | 16,162,250 | 23,086,250 | ||||||||
Not designated (a) | 6,680,000 | 200,000 | 15,206,863 | 22,086,863 | ||||||||
Total (a) | 6,680,000 | 7,124,000 | 31,369,113 | 45,173,113 | ||||||||
As of December 31, 2012 | ||||||||||||
Cash flow | — | 6,490,000 | 18,937,000 | 25,427,000 | ||||||||
Not designated (b) | 5,170,000 | — | 17,703,275 | 22,873,275 | ||||||||
Total (b) | 5,170,000 | 6,490,000 | 36,640,275 | 48,300,275 |
Fair Values of Derivative Instruments | ||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||
As of June 30, 2013 | ||||||||||||
Derivatives designated as hedging instruments | ||||||||||||
Interest rate | Prepayments and other | $ | 72 | Other current liabilities | $ | 6 | ||||||
Other deferred debits and other assets | 34 | Other deferred credits and other liabilities | 21 | |||||||||
Commodity | Prepayments and other | 1 | ||||||||||
Other current liabilities | 3 | |||||||||||
Total | $ | 106 | $ | 31 | ||||||||
Derivatives not designated as hedging instruments | ||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||
Energy management | Prepayments and other | 5 | Other current liabilities | $ | 5 | |||||||
Other deferred debits and other assets | 5 | Other deferred credits and other liabilities | 5 | |||||||||
Total | $ | 11 | $ | 10 |
As of December 31, 2012 | ||||||||||||
Derivatives designated as hedging instruments | ||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 70 | ||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 36 | |||||||||
Commodity | Prepayments and other | 1 | Other current liabilities | 4 | ||||||||
Total | $ | 74 | $ | 110 | ||||||||
Derivatives not designated as hedging instruments | ||||||||||||
Commodity | Prepayments and other | $ | 1 | |||||||||
Energy management | Prepayments and other | 7 | Prepayments and other | $ | 1 | |||||||
Other deferred debits and other assets | 6 | Other current liabilities | 6 | |||||||||
Other deferred debits and other assets | 6 | |||||||||||
Total | $ | 14 | $ | 13 |
Gain (Loss) Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | |||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||
Millions of dollars | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||
Three Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 61 | $ | (2 | ) | Interest expense | — | — | ||||||||||
Six Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 96 | $ | 28 | Interest expense | $ | (1 | ) | $ | (1 | ) |
Gain (Loss) Recognized in OCI, net of tax | Loss Reclassified from AOCI into Income, net of tax | |||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||
Millions of dollars | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||
Three Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 3 | $ | (4 | ) | Interest expense | $ | (1 | ) | $ | (1 | ) | ||||||
Commodity | (3 | ) | 1 | Gas purchased for resale | — | (3 | ) | |||||||||||
Total | — | $ | (3 | ) | $ | (1 | ) | $ | (4 | ) | ||||||||
Six Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 4 | $ | (4 | ) | Interest expense | $ | (3 | ) | $ | (3 | ) | ||||||
Commodity | (1 | ) | (3 | ) | Gas purchased for resale | (2 | ) | (11 | ) | |||||||||
Total | $ | 3 | $ | (7 | ) | $ | (5 | ) | $ | (14 | ) |
Derivatives not designated as Hedging Instruments | Loss Recognized in Income | ||||||||
Millions of dollars | Location | 2013 | 2012 | ||||||
Three Months Ended June 30, | |||||||||
Commodity | Gas purchased for resale | — | — | ||||||
Six Months Ended June 30, | |||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) |
Gross Amounts Not Offset in the Statement of Financial Position | |||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | |||||||||||||||
As of June 30, 2013 | |||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (5 | ) | — | $ | 101 | ||||||||||
Commodity | 1 | — | 1 | — | — | 1 | |||||||||||||||
Energy management | 10 | — | 10 | — | — | 10 | |||||||||||||||
Total | $ | 117 | — | $ | 117 | $ | (5 | ) | — | $ | 112 | ||||||||||
Balance sheet location | Prepayments and other | $ | 78 | ||||||||||||||||||
Other deferred debits and other assets | 39 | ||||||||||||||||||||
Total | $ | 117 |
As of December 31, 2012 | ||||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | |||||||||||
Commodity | 2 | — | 2 | — | — | 2 | ||||||||||||||||
Energy management | 13 | $ | (1 | ) | 12 | — | — | 12 | ||||||||||||||
Total | $ | 88 | $ | (1 | ) | $ | 87 | $ | (17 | ) | — | $ | 70 | |||||||||
Balance sheet location | Prepayments and other | $ | 50 | |||||||||||||||||||
Other deferred debits and other assets | 37 | |||||||||||||||||||||
Total | $ | 87 |
Gross Amounts Not Offset in the Statement of Financial Position | |||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | |||||||||||||||||
As of June 30, 2013 | |||||||||||||||||||||||
Interest rate | $ | 27 | — | $ | 27 | $ | (5 | ) | $ | (22 | ) | — | |||||||||||
Commodity | 4 | — | 4 | — | — | $ | 4 | ||||||||||||||||
Energy management | 11 | $ | (1 | ) | 10 | — | (9 | ) | 1 | ||||||||||||||
$ | 42 | $ | (1 | ) | $ | 41 | $ | (5 | ) | $ | (31 | ) | $ | 5 | |||||||||
Balance sheet location | Prepayments and other | $ | 1 | ||||||||||||||||||||
Other current liabilities | 14 | ||||||||||||||||||||||
Other deferred credits and other liabilities | 26 | ||||||||||||||||||||||
Total | $ | 41 |
As of December 31, 2012 | |||||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (17 | ) | $ | (67 | ) | $ | 22 | ||||||||||
Commodity | 4 | — | 4 | — | — | 4 | |||||||||||||||||
Energy management | 13 | $ | (1 | ) | 12 | — | (11 | ) | 1 | ||||||||||||||
$ | 123 | $ | (1 | ) | $ | 122 | $ | (17 | ) | $ | (78 | ) | $ | 27 | |||||||||
Balance sheet location | Other current liabilities | $ | 80 | ||||||||||||||||||||
Other deferred credits and other liabilities | 42 | ||||||||||||||||||||||
Total | $ | 122 |
7. | FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES |
Fair Value Measurements Using | ||||||||||
Quoted Prices in | ||||||||||
Active Markets for | Significant Other | |||||||||
Identical Assets | Observable Inputs | |||||||||
Millions of dollars | (Level 1) | (Level 2) | ||||||||
As of June 30, 2013 | ||||||||||
Assets - | Available for sale securities | $ | 9 | — | ||||||
Interest rate contracts | — | $ | 106 | |||||||
Commodity contracts | 1 | — | ||||||||
Energy management contracts | — | 10 | ||||||||
Liabilities - | Interest rate contracts | — | 27 | |||||||
Commodity contracts | — | 4 | ||||||||
Energy management contracts | — | 13 | ||||||||
As of December 31, 2012 | ||||||||||
Assets - | Available for sale securities | $ | 6 | — | ||||||
Interest rate contracts | — | $ | 73 | |||||||
Commodity contracts | 1 | 1 | ||||||||
Energy management contracts | — | 13 | ||||||||
Liabilities - | Interest rate contracts | — | 106 | |||||||
Commodity contracts | — | 4 | ||||||||
Energy management contracts | 1 | 15 |
June 30, 2013 | December 31, 2012 | |||||||||||||||
Millions of dollars | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
Long-term debt | $ | 5,454.6 | $ | 5,961.3 | $ | 5,121.0 | $ | 6,115.0 |
8. | EMPLOYEE BENEFIT PLANS |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Three months ended June 30, | ||||||||||||||||
Service cost | $ | 5.9 | $ | 4.9 | $ | 1.6 | $ | 1.2 | ||||||||
Interest cost | 9.4 | 10.6 | 2.7 | 3.0 | ||||||||||||
Expected return on assets | (15.3 | ) | (14.8 | ) | — | — | ||||||||||
Prior service cost amortization | 1.7 | 1.8 | 0.2 | 0.3 | ||||||||||||
Transition obligation amortization | — | — | 0.1 | 0.1 | ||||||||||||
Amortization of actuarial losses | 5.5 | 4.6 | 0.9 | 0.2 | ||||||||||||
Net periodic benefit cost | $ | 7.2 | $ | 7.1 | $ | 5.5 | $ | 4.8 |
Six months ended June 30, | ||||||||||||||||
Service cost | $ | 11.8 | $ | 9.7 | $ | 3.2 | $ | 2.5 | ||||||||
Interest cost | 18.9 | 21.3 | 5.5 | 6.0 | ||||||||||||
Expected return on assets | (30.7 | ) | (29.6 | ) | — | — | ||||||||||
Prior service cost amortization | 3.4 | 3.5 | 0.4 | 0.5 | ||||||||||||
Transition obligation amortization | — | — | 0.3 | 0.3 | ||||||||||||
Amortization of actuarial losses | 10.9 | 9.3 | 1.7 | 0.4 | ||||||||||||
Net periodic benefit cost | $ | 14.3 | $ | 14.2 | $ | 11.1 | $ | 9.7 |
9. | COMMITMENTS AND CONTINGENCIES |
10. | SEGMENT OF BUSINESS INFORMATION |
Millions of dollars | External Revenue | Intersegment Revenue | Operating Income | Net Income | ||||||||||||
Three Months Ended June 30, 2013 | ||||||||||||||||
Electric Operations | $ | 610 | $ | 2 | $ | 178 | n/a | |||||||||
Gas Distribution | 155 | — | 7 | n/a | ||||||||||||
Retail Gas Marketing | 79 | — | — | $ | (3 | ) | ||||||||||
Energy Marketing | 169 | 47 | — | 1 | ||||||||||||
All Other | 7 | 101 | 6 | (2 | ) | |||||||||||
Adjustments/Eliminations | (4 | ) | (150 | ) | (2 | ) | 89 | |||||||||
Consolidated Total | $ | 1,016 | $ | — | $ | 189 | $ | 85 |
Six Months Ended June 30, 2013 | ||||||||||||||||
Electric Operations | $ | 1,193 | $ | 4 | $ | 331 | n/a | |||||||||
Gas Distribution | 534 | — | 100 | n/a | ||||||||||||
Retail Gas Marketing | 258 | — | — | $ | 19 | |||||||||||
Energy Marketing | 336 | 89 | — | 4 | ||||||||||||
All Other | 19 | 208 | 13 | 1 | ||||||||||||
Adjustments/Eliminations | (13 | ) | (301 | ) | 38 | 213 | ||||||||||
Consolidated Total | $ | 2,327 | $ | — | $ | 482 | $ | 237 |
Three Months Ended June 30, 2012 | ||||||||||||||||
Electric Operations | $ | 592 | $ | 3 | $ | 164 | n/a | |||||||||
Gas Distribution | 126 | — | 5 | n/a | ||||||||||||
Retail Gas Marketing | 71 | — | n/a | $ | (3 | ) | ||||||||||
Energy Marketing | 118 | 23 | n/a | 2 | ||||||||||||
All Other | 10 | 103 | 4 | (4 | ) | |||||||||||
Adjustments/Eliminations | (9 | ) | (129 | ) | (2 | ) | 77 | |||||||||
Consolidated Total | $ | 908 | $ | — | $ | 171 | $ | 72 |
Six Months Ended June 30, 2012 | ||||||||||||||||
Electric Operations | $ | 1,137 | $ | 5 | $ | 291 | n/a | |||||||||
Gas Distribution | 400 | — | 88 | n/a | ||||||||||||
Retail Gas Marketing | 224 | — | n/a | $ | 8 | |||||||||||
Energy Marketing | 250 | 49 | n/a | 4 | ||||||||||||
All Other | 21 | 209 | 11 | 1 | ||||||||||||
Adjustments/Eliminations | (17 | ) | (263 | ) | 19 | 180 | ||||||||||
Consolidated Total | $ | 2,015 | $ | — | $ | 409 | $ | 193 |
June 30, | December 31, | |||||||||||
Segment Assets | 2013 | 2012 | ||||||||||
Electric Operations | $ | 9,272 | $ | 8,989 | ||||||||
Gas Distribution | 2,294 | 2,292 | ||||||||||
Retail Gas Marketing | 162 | 153 | ||||||||||
Energy Marketing | 112 | 122 | ||||||||||
All Other | 1,435 | 1,415 | ||||||||||
Adjustments/Eliminations | 1,663 | 1,645 | ||||||||||
Consolidated Total | $ | 14,938 | $ | 14,616 |
Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Second Quarter | Year to Date | |||||||
2013 | 2012 | 2013 | 2012 | |||||
Basic earnings per share | $0.60 | $0.55 | $1.73 | $1.48 | ||||
Diluted earnings per share | $0.60 | $0.54 | $1.72 | $1.46 |
Declaration Date | Dividend Per Share | Record Date | Payment Date | |||
February 20, 2013 | $0.5075 | March 11, 2013 | April 1, 2013 | |||
April 25, 2013 | $0.5075 | June 10, 2013 | July 1, 2013 | |||
July 31, 2013 | $0.5075 | September 10, 2013 | October 1, 2013 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 611.6 | 2.9 | % | $ | 594.1 | $ | 1,197.2 | 4.9 | % | $ | 1,141.4 | ||||||||||
Less: Fuel used in generation | 189.2 | (5.0 | )% | 199.2 | 376.9 | (1.3 | )% | 381.9 | ||||||||||||||
Purchased power | 8.8 | 91.3 | % | 4.6 | 15.8 | 53.4 | % | 10.3 | ||||||||||||||
Margin | $ | 413.6 | 6.0 | % | $ | 390.3 | $ | 804.5 | 7.4 | % | $ | 749.2 |
Second Quarter | Year to Date | |||||||||||||||||
Classification | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||
Residential | 1,784 | (0.8 | )% | 1,799 | 3,642 | 4.4 | % | 3,490 | ||||||||||
Commercial | 1,777 | (3.7 | )% | 1,846 | 3,446 | (1.3 | )% | 3,490 | ||||||||||
Industrial | 1,518 | 0.3 | % | 1,514 | 2,921 | 0.8 | % | 2,899 | ||||||||||
Other | 144 | (2.0 | )% | 147 | 279 | (1.1 | )% | 282 | ||||||||||
Total Retail Sales | 5,223 | (1.6 | )% | 5,306 | 10,288 | 1.2 | % | 10,161 | ||||||||||
Wholesale | 228 | (63.4 | )% | 623 | 491 | (60.9 | )% | 1,257 | ||||||||||
Total Sales | 5,451 | (8.1 | )% | 5,929 | 10,779 | (5.6 | )% | 11,418 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 154.7 | 23.4 | % | $ | 125.4 | $ | 534.0 | 33.5 | % | $ | 400.0 | ||||||||||
Less: Gas purchased for resale | 85.5 | 49.2 | % | 57.3 | 308.2 | 65.8 | % | 185.9 | ||||||||||||||
Margin | $ | 69.2 | 1.6 | % | $ | 68.1 | $ | 225.8 | 5.5 | % | $ | 214.1 |
Second Quarter | Year to Date | |||||||||||||||||
Classification (in thousands) | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||
Residential | 3,866 | 23.0 | % | 3,142 | 25,240 | 38.9 | % | 18,168 | ||||||||||
Commercial | 4,886 | 4.4 | % | 4,682 | 15,644 | 19.9 | % | 13,048 | ||||||||||
Industrial | 5,438 | 8.2 | % | 5,025 | 11,599 | 10.8 | % | 10,470 | ||||||||||
Transportation | 9,787 | 9.6 | % | 8,928 | 20,988 | 9.6 | % | 19,152 | ||||||||||
Total | 23,977 | 10.1 | % | 21,777 | 73,471 | 20.8 | % | 60,838 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 79.2 | 11.1 | % | $ | 71.3 | $ | 258.2 | 15.2 | % | $ | 224.1 | ||||||||||
Net income (loss) | (2.7 | ) | (15.6 | )% | (3.2 | ) | 19.4 | * | 7.9 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 216.4 | 53.6 | % | $ | 140.9 | $ | 425.5 | 42.3 | % | $ | 299.0 | ||||||||||
Net Income | 1.0 | (44.4 | )% | 1.8 | 3.7 | 2.8 | % | 3.6 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Other operation and maintenance | $ | 170.8 | 0.6 | % | $ | 169.8 | $ | 346.9 | 0.6 | % | $ | 344.9 | ||||||||||
Depreciation and amortization | 94.5 | 5.9 | % | 89.2 | 187.8 | 5.6 | % | 177.9 | ||||||||||||||
Other taxes | 54.5 | 3.0 | % | 52.9 | 109.3 | 3.6 | % | 105.5 |
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Expected Maturity | Expected Maturity | ||||||||||||||
Futures - Long | 2013 | 2014 | Options Purchased Call - Long | 2013 | 2014 | ||||||||||
Settlement Price (a) | 3.64 | 3.77 | Strike Price (a) | 4.05 | 4.09 | ||||||||||
Contract Amount (b) | 8.5 | 7.1 | Contract Amount (b) | 14.1 | 13.9 | ||||||||||
Fair Value (b) | 8.0 | 6.8 | Fair Value (b) | 0.5 | 0.8 | ||||||||||
(a) Weighted average, in dollars | |||||||||||||||
(b) Millions of dollars |
Expected Maturity | |||||||||||||||
Swaps | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||
Commodity Swaps: | |||||||||||||||
Pay fixed/receive variable (b) | 29.2 | 34.9 | 14.3 | 8.2 | 0.5 | ||||||||||
Average pay rate (a) | 4.3972 | 4.4806 | 5.1180 | 4.8661 | 4.2850 | ||||||||||
Average received rate (a) | 3.6638 | 3.8953 | 4.1439 | 4.3286 | 4.5695 | ||||||||||
Fair value (b) | 24.3 | 30.4 | 11.6 | 7.3 | 0.5 | ||||||||||
Pay variable/receive fixed (b) | 14.4 | 20.7 | 11.5 | 7.3 | 0.5 | ||||||||||
Average pay rate (a) | 3.6356 | 3.8987 | 4.1440 | 4.3286 | 4.5695 | ||||||||||
Average received rate (a) | 4.3831 | 4.5877 | 5.1366 | 4.8925 | 4.2900 | ||||||||||
Fair value (b) | 17.3 | 24.4 | 14.2 | 8.2 | 0.5 | ||||||||||
Basis Swaps: | |||||||||||||||
Pay variable/receive variable (b) | 3.5 | 1.1 | 0.5 | — | — | ||||||||||
Average pay rate (a) | 3.6322 | 3.9613 | 4.2721 | — | — | ||||||||||
Average received rate (a) | 3.6149 | 3.9461 | 4.2575 | — | — | ||||||||||
Fair value (b) | 3.5 | 1.1 | 0.5 | — | — | ||||||||||
(a) Weighted average, in dollars | |||||||||||||||
(b) Millions of dollars | |||||||||||||||
ITEM 4. | CONTROLS AND PROCEDURES |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Assets | ||||||||
Utility Plant In Service | $ | 10,242 | $ | 10,096 | ||||
Accumulated Depreciation and Amortization | (3,414 | ) | (3,322 | ) | ||||
Construction Work in Progress | 2,356 | 2,073 | ||||||
Plant to be Retired, Net | 351 | 362 | ||||||
Nuclear Fuel, Net of Accumulated Amortization | 267 | 166 | ||||||
Utility Plant, Net ($679 and $640 related to VIEs) | 9,802 | 9,375 | ||||||
Nonutility Property and Investments: | ||||||||
Nonutility property, net of accumulated depreciation | 64 | 57 | ||||||
Assets held in trust, net - nuclear decommissioning | 95 | 94 | ||||||
Other investments | 2 | 3 | ||||||
Nonutility Property and Investments, Net | 161 | 154 | ||||||
Current Assets: | ||||||||
Cash and cash equivalents | 50 | 51 | ||||||
Receivables, net of allowance for uncollectible accounts of $2 and $3 | 492 | 483 | ||||||
Affiliated receivables | 12 | 2 | ||||||
Inventories (at average cost): | ||||||||
Fuel and gas supply | 183 | 203 | ||||||
Materials and supplies | 128 | 126 | ||||||
Emission allowances | 1 | 1 | ||||||
Prepayments and other | 161 | 143 | ||||||
Total Current Assets ($181 and $206 related to VIEs) | 1,027 | 1,009 | ||||||
Deferred Debits and Other Assets: | ||||||||
Regulatory assets | 1,352 | 1,377 | ||||||
Other | 190 | 189 | ||||||
Total Deferred Debits and Other Assets ($47 and $54 related to VIEs) | 1,542 | 1,566 | ||||||
Total | $ | 12,532 | $ | 12,104 |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Capitalization and Liabilities | ||||||||
Common equity | $ | 4,234 | $ | 3,929 | ||||
Noncontrolling interest | 116 | 114 | ||||||
Long-Term Debt, net | 4,043 | 3,557 | ||||||
Total Capitalization | 8,393 | 7,600 | ||||||
Current Liabilities: | ||||||||
Short-term borrowings | 238 | 449 | ||||||
Current portion of long-term debt | 16 | 165 | ||||||
Accounts Payable | 269 | 281 | ||||||
Affiliated Payables | 109 | 124 | ||||||
Customer deposits and customer prepayments | 53 | 51 | ||||||
Taxes accrued | 113 | 151 | ||||||
Interest accrued | 64 | 63 | ||||||
Dividends declared | 64 | 46 | ||||||
Derivative financial instruments | 2 | 66 | ||||||
Other | 38 | 50 | ||||||
Total Current Liabilities | 966 | 1,446 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Deferred income taxes, net | 1,506 | 1,479 | ||||||
Deferred investment tax credits | 34 | 36 | ||||||
Asset retirement obligations | 543 | 535 | ||||||
Postretirement benefits | 255 | 254 | ||||||
Regulatory liabilities | 753 | 665 | ||||||
Other | 82 | 89 | ||||||
Total Deferred Credits and Other Liabilities | 3,173 | 3,058 | ||||||
Commitments and Contingencies (Note 9) | — | — | ||||||
Total | $ | 12,532 | $ | 12,104 |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Operating Revenues: | ||||||||||||||||
Electric | $ | 612 | $ | 594 | $ | 1,197 | $ | 1,141 | ||||||||
Gas | 84 | 67 | 227 | 183 | ||||||||||||
Total Operating Revenues | 696 | 661 | 1,424 | 1,324 | ||||||||||||
Operating Expenses: | ||||||||||||||||
Fuel used in electric generation | 189 | 199 | 377 | 382 | ||||||||||||
Purchased power | 9 | 4 | 16 | 10 | ||||||||||||
Gas purchased for resale | 54 | 37 | 131 | 96 | ||||||||||||
Other operation and maintenance | 135 | 134 | 274 | 272 | ||||||||||||
Depreciation and amortization | 79 | 74 | 156 | 147 | ||||||||||||
Other taxes | 50 | 48 | 99 | 96 | ||||||||||||
Total Operating Expenses | 516 | 496 | 1,053 | 1,003 | ||||||||||||
Operating Income | 180 | 165 | 371 | 321 | ||||||||||||
Other Expense: | 156,311 | |||||||||||||||
Other expense | (4 | ) | (3 | ) | (7 | ) | (7 | ) | ||||||||
Interest charges, net of allowance for borrowed funds used during construction of $3, $3, $5 and $4 | (54 | ) | (52 | ) | (108 | ) | (103 | ) | ||||||||
Allowance for equity funds used during construction | 6 | 4 | 9 | 7 | ||||||||||||
Total Other Expense | (52 | ) | (51 | ) | (106 | ) | (103 | ) | ||||||||
Income Before Income Tax Expense | 128 | 114 | 265 | 218 | ||||||||||||
Income Tax Expense | 40 | 36 | 85 | 69 | ||||||||||||
Net Income | 88 | 78 | 180 | 149 | ||||||||||||
Net Income Attributable to Noncontrolling Interest | (3 | ) | (2 | ) | (6 | ) | (6 | ) | ||||||||
Earnings Available to Common Shareholder | $ | 85 | $ | 76 | $ | 174 | $ | 143 | ||||||||
Dividends Declared on Common Stock | $ | 64 | $ | 54 | $ | 128 | $ | 107 |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Net Income | $ | 88 | $ | 78 | $ | 180 | $ | 149 | ||||||||
Other Comprehensive Income, net of tax: | ||||||||||||||||
Amortization of deferred employee benefit plan costs reclassified to net income, net of tax of $-, $-, $- and $- | — | — | — | — | ||||||||||||
Total Comprehensive Income | 88 | 78 | 180 | 149 | ||||||||||||
Comprehensive income attributable to noncontrolling interest | (3 | ) | (2 | ) | (6 | ) | (6 | ) | ||||||||
Comprehensive income available to common shareholder | $ | 85 | $ | 76 | $ | 174 | $ | 143 |
Six Months Ended June 30, | ||||||||
Millions of dollars | 2013 | 2012 | ||||||
Cash Flows From Operating Activities: | ||||||||
Net income | $ | 180 | $ | 149 | ||||
Adjustments to reconcile net income to net cash provided from operating activities: | ||||||||
Losses from equity method investments | 1 | 2 | ||||||
Deferred income taxes, net | 26 | 56 | ||||||
Depreciation and amortization | 156 | 147 | ||||||
Amortization of nuclear fuel | 27 | 26 | ||||||
Allowance for equity funds used during construction | (9 | ) | (7 | ) | ||||
Cash provided (used) by changes in certain assets and liabilities: | ||||||||
Receivables | (12 | ) | 3 | |||||
Inventories | (4 | ) | (50 | ) | ||||
Prepayments and other | (45 | ) | (74 | ) | ||||
Regulatory assets | 9 | 20 | ||||||
Regulatory liabilities | 58 | 29 | ||||||
Accounts payable | (4 | ) | (5 | ) | ||||
Taxes accrued | (38 | ) | (11 | ) | ||||
Interest accrued | 1 | 5 | ||||||
Changes in other assets | (31 | ) | 24 | |||||
Changes in other liabilities | (12 | ) | (45 | ) | ||||
Net Cash Provided From Operating Activities | 303 | 269 | ||||||
Cash Flows From Investing Activities: | ||||||||
Property additions and construction expenditures | (478 | ) | (544 | ) | ||||
Proceeds from investments (including derivative collateral posted) | 132 | 98 | ||||||
Purchase of investments (including derivative collateral posted) | (104 | ) | (121 | ) | ||||
Payments upon interest rate contract settlement | (49 | ) | — | |||||
Proceeds from interest rate contract settlement | 43 | 13 | ||||||
Net Cash Used For Investing Activities | (456 | ) | (554 | ) | ||||
Cash Flows From Financing Activities: | ||||||||
Proceeds from issuance of long-term debt | 451 | 248 | ||||||
Repayment of long-term debt | (218 | ) | (10 | ) | ||||
Dividends | (110 | ) | (92 | ) | ||||
Contributions from parent | 255 | 51 | ||||||
Short-term borrowings –affiliate, net | (15 | ) | 12 | |||||
Short-term borrowings, net | (211 | ) | 74 | |||||
Net Cash Provided From Financing Activities | 152 | 283 | ||||||
Net Decrease In Cash and Cash Equivalents | (1 | ) | (2 | ) | ||||
Cash and Cash Equivalents, January 1 | 51 | 16 | ||||||
Cash and Cash Equivalents, June 30 | $ | 50 | $ | 14 | ||||
Supplemental Cash Flow Information: | ||||||||
Cash paid for– Interest (net of capitalized interest of $5 and $4) | $ | 99 | $ | 92 | ||||
– Income taxes | 24 | — | ||||||
Noncash Investing and Financing Activities: | ||||||||
Accrued construction expenditures | 85 | 51 | ||||||
Capital leases | 3 | 2 | ||||||
Nuclear fuel purchase | 97 | — |
1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
2. | RATE AND OTHER REGULATORY MATTERS |
Year | Effective | Amount | ||
2012 | First billing cycle of May | $19.6 million | ||
2011 | First billing cycle of June | $7.0 million |
Year | Action | Amount | ||||
2012 | 2.3 | % | Increase | $52.1 million | ||
2011 | 2.4 | % | Increase | $52.8 million |
Year | Action | Amount | ||||
2012 | 2.1 | % | Increase | $7.5 million | ||
2011 | 2.1 | % | Increase | $8.6 million |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Regulatory Assets: | ||||||||
Accumulated deferred income taxes | $ | 248 | $ | 248 | ||||
Under collections – electric fuel adjustment clause | 71 | 66 | ||||||
Environmental remediation costs | 38 | 39 | ||||||
AROs and related funding | 311 | 304 | ||||||
Franchise agreements | 33 | 36 | ||||||
Deferred employee benefit plan costs | 393 | 405 | ||||||
Planned major maintenance | — | 6 | ||||||
Deferred losses on interest rate derivatives | 128 | 151 | ||||||
Deferred pollution control costs | 38 | 38 | ||||||
Unrecovered plant | 19 | 20 | ||||||
Other | 73 | 64 | ||||||
Total Regulatory Assets | $ | 1,352 | $ | 1,377 |
Regulatory Liabilities: | ||||||||
Accumulated deferred income taxes | $ | 20 | $ | 21 | ||||
Asset removal costs | 517 | 507 | ||||||
Storm damage reserve | 27 | 27 | ||||||
Deferred gains on interest rate derivatives | 185 | 110 | ||||||
Planned major maintenance | 4 | — | ||||||
Total Regulatory Liabilities | $ | 753 | $ | 665 |
3. | EQUITY |
Millions of dollars | Common Equity | Noncontrolling Interest | Total Equity | |||||||||
Balance at January 1, 2013 | $ | 3,929 | $ | 114 | $ | 4,043 | ||||||
Capital contribution from parent | 255 | — | 255 | |||||||||
Dividends declared | (124 | ) | (4 | ) | (128 | ) | ||||||
Comprehensive income | 174 | 6 | 180 | |||||||||
Balance as of June 30, 2013 | $ | 4,234 | $ | 116 | $ | 4,350 | ||||||
Balance at January 1, 2012 | $ | 3,665 | $ | 108 | $ | 3,773 | ||||||
Capital contribution from parent | 51 | — | 51 | |||||||||
Dividends declared | (103 | ) | (4 | ) | (107 | ) | ||||||
Comprehensive income | 143 | 6 | 149 | |||||||||
Balance as of June 30, 2012 | $ | 3,756 | $ | 110 | $ | 3,866 |
4. | LONG-TERM DEBT AND LIQUIDITY |
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||
Lines of credit: | ||||||||
Total committed long-term | $ | 1,400 | $ | 1,400 | ||||
LOC advances | — | — | ||||||
Weighted average interest rate | — | — | ||||||
Outstanding commercial paper (270 or fewer days) | $ | 238 | $ | 449 | ||||
Weighted average interest rate | 0.30 | % | 0.42 | % | ||||
Letters of credit supported by LOC | $ | 0.3 | $ | 0.3 | ||||
Available | $ | 1,162 | $ | 951 |
5. | INCOME TAXES |
6. | DERIVATIVE FINANCIAL INSTRUMENTS |
Fair Values of Derivative Instruments | ||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
Millions of dollars | Location | Value | Location | Value | ||||||||
As of June 30, 2013 | ||||||||||||
Derivatives designated as hedging instruments | ||||||||||||
Interest rate | Prepayments and other | $ | 72 | Other current liabilities | $ | 2 | ||||||
Other deferred debits and other assets | 34 | Other deferred credits and other liabilities | 3 | |||||||||
Total | $ | 106 | $ | 5 | ||||||||
As of December 31, 2012 | ||||||||||||
Derivatives designated as hedging instruments | ||||||||||||
Interest rate | Prepayments and other | $ | 42 | Other current liabilities | $ | 66 | ||||||
Other deferred debits and other assets | 31 | Other deferred credits and other liabilities | 9 | |||||||||
Total | $ | 73 | $ | 75 |
Derivatives in Cash Flow Hedging Relationships | Gain Deferred in Regulatory Accounts | Loss Reclassified from Deferred Accounts into Income | ||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||
Millions of dollars | 2013 | 2012 | Location | 2013 | 2012 | |||||||||||||
Three Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 61 | $ | (2 | ) | Interest expense | — | — | ||||||||||
Six Months Ended June 30, | ||||||||||||||||||
Interest rate | $ | 96 | $ | 28 | Interest expense | $ | (1 | ) | $ | (1 | ) |
Derivatives not designated as Hedging Instruments | Loss Recognized in Income | ||||||||
Millions of dollars | Location | 2013 | 2012 | ||||||
Three Months Ended June 30, | |||||||||
Commodity | Gas purchased for resale | — | — | ||||||
Six Months Ended June 30, | |||||||||
Commodity | Gas purchased for resale | — | $ | (1 | ) |
Gross Amounts Not Offset in the Statement of Financial Position | |||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Assets | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Received | Net Amount | |||||||||||||||
As of June 30, 2013 | |||||||||||||||||||||
Interest rate | $ | 106 | — | $ | 106 | $ | (5 | ) | — | $ | 101 | ||||||||||
Balance Sheet Location | Prepayments and other | $ | 72 | ||||||||||||||||||
Other deferred debits and other assets | 34 | ||||||||||||||||||||
Total | $ | 106 |
As of December 31, 2012 | |||||||||||||||||||||
Interest rate | $ | 73 | — | $ | 73 | $ | (17 | ) | — | $ | 56 | ||||||||||
Balance Sheet Location | Prepayments and other | $ | 42 | ||||||||||||||||||
Other deferred debits and other assets | 31 | ||||||||||||||||||||
Total | $ | 73 |
Gross Amounts Not Offset in the Statement of Financial Position | ||||||||||||||||||||||
Millions of dollars | Gross Amounts of Recognized Liabilities | Gross Amounts Offset in the Statement of Financial Position | Net Amounts Presented in the Statement of Financial Position | Financial Instruments | Cash Collateral Posted | Net Amount | ||||||||||||||||
As of June 30, 2013 | ||||||||||||||||||||||
Interest rate | $ | 5 | — | $ | 5 | $ | (5 | ) | $ | — | $ | — | ||||||||||
Balance Sheet Location | Other current liabilities | $ | 2 | |||||||||||||||||||
Other deferred credits and other liabilities | 3 | |||||||||||||||||||||
Total | $ | 5 |
As of December 31, 2012 | ||||||||||||||||||||||
Interest rate | $ | 75 | — | $ | 75 | $ | (17 | ) | $ | (35 | ) | $ | 23 | |||||||||
Balance Sheet Location | Other current liabilities | $ | 66 | |||||||||||||||||||
Other deferred credits and other liabilities | 9 | |||||||||||||||||||||
Total | $ | 75 |
7. | FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES |
Fair Value Measurements Using Significant | ||||||||||
Other Observable Inputs (Level 2) | ||||||||||
Millions of dollars | June 30, 2013 | December 31, 2012 | ||||||||
Assets - | Interest rate contracts | $ | 106 | $ | 73 | |||||
Liabilities - | Interest rate contracts | 5 | 75 |
June 30, 2013 | December 31, 2012 | |||||||||||||||
Millions of dollars | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
Long-term debt | $ | 4,058.5 | $ | 4,447.4 | $ | 3,722.0 | $ | 4,543.1 |
8. | EMPLOYEE BENEFIT PLANS |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Three months ended June 30, | ||||||||||||||||
Service cost | $ | 4.8 | $ | 3.8 | $ | 1.3 | $ | 1.0 | ||||||||
Interest cost | 8.0 | 9.1 | 2.2 | 2.3 | ||||||||||||
Expected return on assets | (13.0 | ) | (12.6 | ) | — | — | ||||||||||
Prior service cost amortization | 1.4 | 1.5 | 0.1 | 0.2 | ||||||||||||
Amortization of actuarial losses | 4.6 | 4.0 | 0.7 | 0.1 | ||||||||||||
Net periodic benefit cost | $ | 5.8 | $ | 5.8 | $ | 4.3 | $ | 3.6 |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Millions of dollars | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Six months ended June 30, | ||||||||||||||||
Service cost | $ | 9.6 | $ | 7.7 | $ | 2.5 | $ | 2.0 | ||||||||
Interest cost | 16.0 | 18.2 | 4.4 | 4.7 | ||||||||||||
Expected return on assets | (26.0 | ) | (25.2 | ) | — | — | ||||||||||
Prior service cost amortization | 2.8 | 2.9 | 0.3 | 0.4 | ||||||||||||
Amortization of actuarial losses | 9.2 | 8.0 | 1.3 | 0.2 | ||||||||||||
Net periodic benefit cost | $ | 11.6 | $ | 11.6 | $ | 8.5 | $ | 7.3 |
9. | COMMITMENTS AND CONTINGENCIES |
10. | AFFILIATED TRANSACTIONS |
11. | SEGMENT OF BUSINESS INFORMATION |
External | Operating | Earnings Available to | ||||||||||
Millions of dollars | Revenue | Income | Common Shareholder | |||||||||
Three Months Ended June 30, 2013 | ||||||||||||
Electric Operations | $ | 612 | $ | 178 | n/a | |||||||
Gas Distribution | 84 | 2 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 85 | ||||||||
Consolidated Total | $ | 696 | $ | 180 | $ | 85 |
Six Months Ended June 30, 2013 | ||||||||||||
Electric Operations | $ | 1,197 | $ | 331 | n/a | |||||||
Gas Distribution | 227 | 40 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 174 | ||||||||
Consolidated Total | $ | 1,424 | $ | 371 | $ | 174 |
Three Months Ended June 30, 2012 | ||||||||||||
Electric Operations | $ | 594 | $ | 163 | n/a | |||||||
Gas Distribution | 67 | 2 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 76 | ||||||||
Consolidated Total | $ | 661 | $ | 165 | $ | 76 |
Six Months Ended June 30, 2012 | ||||||||||||
Electric Operations | $ | 1,141 | $ | 290 | n/a | |||||||
Gas Distribution | 183 | 31 | n/a | |||||||||
Adjustments/Eliminations | — | — | $ | 143 | ||||||||
Consolidated Total | $ | 1,324 | $ | 321 | $ | 143 |
June 30, | December 31, | |||||||||
Segment Assets | 2013 | 2012 | ||||||||
Electric Operations | $ | 9,272 | $ | 8,989 | ||||||
Gas Distribution | 673 | 659 | ||||||||
Adjustments/Eliminations | 2,587 | 2,456 | ||||||||
Consolidated Total | $ | 12,532 | $ | 12,104 |
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Net income | $ | 88.0 | 13.3 | % | $ | 77.7 | $ | 179.8 | 20.5 | % | $ | 149.2 |
Declaration Date | Amount | Quarter Ended | Payment Date | |||
February 20, 2013 | $64.0 million | March 31, 2013 | April 1, 2013 | |||
April 25, 2013 | $63.8 million | June 30, 2013 | July 1, 2013 | |||
July 31, 2013 | $67.5 million | September 30, 2013 | October 1, 2013 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 611.6 | 2.9 | % | $ | 594.1 | $ | 1,197.2 | 4.9 | % | $ | 1,141.4 | ||||||||||
Less: Fuel used in generation | 189.2 | (5.0 | )% | 199.2 | 376.9 | (1.3 | )% | 381.9 | ||||||||||||||
Purchased power | 8.8 | 91.3 | % | 4.6 | 15.8 | 53.4 | % | 10.3 | ||||||||||||||
Margin | $ | 413.6 | 6.0 | % | $ | 390.3 | $ | 804.5 | 7.4 | % | $ | 749.2 |
Second Quarter | Year to Date | |||||||||||||||||
Classification | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||
Residential | 1,784 | (0.8 | )% | 1,799 | 3,642 | 4.4 | % | 3,490 | ||||||||||
Commercial | 1,777 | (3.7 | )% | 1,846 | 3,446 | (1.3 | )% | 3,490 | ||||||||||
Industrial | 1,518 | 0.3 | % | 1,514 | 2,921 | 0.8 | % | 2,899 | ||||||||||
Other | 144 | (2.0 | )% | 147 | 279 | (1.1 | )% | 282 | ||||||||||
Total Retail Sales | 5,223 | (1.6 | )% | 5,306 | 10,288 | 1.2 | % | 10,161 | ||||||||||
Wholesale | 228 | (63.4 | )% | 623 | 491 | (60.9 | )% | 1,257 | ||||||||||
Total Sales | 5,451 | (8.1 | )% | 5,929 | 10,779 | (5.6 | )% | 11,418 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Operating revenues | $ | 84.2 | 26.0 | % | $ | 66.8 | $ | 226.9 | 24.3 | % | $ | 182.5 | ||||||||||
Less: Gas purchased for resale | 54.6 | 47.2 | % | 37.1 | 131.7 | 36.8 | % | 96.3 | ||||||||||||||
Margin | $ | 29.6 | (0.3 | )% | $ | 29.7 | $ | 95.2 | 10.4 | % | $ | 86.2 |
Second Quarter | Year to Date | |||||||||||||||||
Classification (in thousands) | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||
Residential | 1,261 | 41.4 | % | 892 | 7,719 | 40.1 | % | 5,511 | ||||||||||
Commercial | 2,644 | 7.3 | % | 2,463 | 6,938 | 14.8 | % | 6,042 | ||||||||||
Industrial | 5,081 | 9.9 | % | 4,625 | 10,450 | 10.4 | % | 9,467 | ||||||||||
Transportation | 1,132 | 1.9 | % | 1,111 | 2,449 | 1.4 | % | 2,416 | ||||||||||
Total | 10,118 | 11.3 | % | 9,091 | 27,556 | 17.6 | % | 23,436 |
Second Quarter | Year to Date | |||||||||||||||||||||
Millions of dollars | 2013 | Change | 2012 | 2013 | Change | 2012 | ||||||||||||||||
Other operation and maintenance | $ | 135.4 | 1.2 | % | $ | 133.8 | $ | 273.8 | 0.6 | % | $ | 272.1 | ||||||||||
Depreciation and amortization | 78.6 | 6.6 | % | 73.7 | 156.2 | 6.4 | % | 146.8 | ||||||||||||||
Other taxes | 49.5 | 2.9 | % | 48.1 | 99.1 | 3.6 | % | 95.7 |
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 4. | CONTROLS AND PROCEDURES |
ITEM 6. | EXHIBITS |
SCANA CORPORATION |
SOUTH CAROLINA ELECTRIC & GAS COMPANY |
(Registrants) |
By: | /s/James E. Swan, IV | |
Date: August 8, 2013 | James E. Swan, IV | |
Controller | ||
(Principal accounting officer) |
Applicable to Form 10-Q of | |||
Exhibit No. | SCANA | SCE&G | Description |
3.01 | X | Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein) | |
3.02 | X | Articles of Amendment dated April 27, 1995 (Filed as Exhibit 4-B to Registration Statement No. 33-62421 and incorporated by reference herein) | |
3.03 | X | Articles of Amendment effective April 25, 2011 (Filed as Exhibit 4.03 to Registration Statement No. 333-174796 and incorporated by reference herein) | |
3.04 | X | Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 (Filed as Exhibit 1 to Form 8-A (File Number 000-53860) and incorporated by reference herein) | |
3.05 | X | By-Laws of SCANA as amended and restated as of February 19, 2009 (Filed as Exhibit 4.04 to Registration Statement No. 333-174796 and incorporated by reference herein) | |
3.06 | X | By-Laws of SCE&G as revised and amended on February 22, 2001 (Filed as Exhibit 3.05 to Registration Statement No. 333-65460 and incorporated by reference herein) | |
31.01 | X | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |
31.02 | X | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |
31.03 | X | Certification of Principal Executive Officer Required by Rule 13a-14 (Filed herewith) | |
31.04 | X | Certification of Principal Financial Officer Required by Rule 13a-14 (Filed herewith) | |
32.01 | X | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |
32.02 | X | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |
32.03 | X | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |
32.04 | X | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350 (Furnished herewith) | |
101. INS* | X | X | XBRL Instance Document |
101. SCH* | X | X | XBRL Taxonomy Extension Schema |
101. CAL* | X | X | XBRL Taxonomy Extension Calculation Linkbase |
101. DEF* | X | X | XBRL Taxonomy Extension Definition Linkbase |
101. LAB* | X | X | XBRL Taxonomy Extension Label Linkbase |
101. PRE* | X | X | XBRL Taxonomy Extension Presentation Linkbase |
1. | I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: August 8, 2013 | |
/s/Kevin B. Marsh | |
Kevin B. Marsh | |
Chairman of the Board, President, Chief Executive Officer and | |
Chief Operating Officer |
1. | I have reviewed this quarterly report on Form 10-Q of SCANA Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: August 8, 2013 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Executive Vice President and Chief Financial Officer |
1. | I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: August 8, 2013 | |
/s/Kevin B. Marsh | |
Kevin B. Marsh | |
Chairman of the Board and Chief Executive Officer |
1. | I have reviewed this quarterly report on Form 10-Q of South Carolina Electric & Gas Company; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: August 8, 2013 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Executive Vice President and Chief Financial Officer |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: August 8, 2013 | |
/s/Kevin B. Marsh | |
Kevin B. Marsh | |
Chairman of the Board, President, Chief Executive Officer | |
and Chief Operating Officer |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: August 8, 2013 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Executive Vice President and Chief Financial Officer | |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: August 8, 2013 | |
/s/Kevin B. Marsh | |
Kevin B. Marsh | |
Chairman of the Board and Chief Executive Officer | |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
Date: August 8, 2013 | |
/s/Jimmy E. Addison | |
Jimmy E. Addison | |
Executive Vice President and Chief Financial Officer | |
W'B&RBUF.Z(-D'MIZH3#%#>_OK>Q@9C%``#T)`Y/?``KE?#7AVXM-5T*XU*2*5+F1[E6M_DD68L M3AFQET]LBBB@#UFO+]?O+BP^*!UJ6WBN8;.`0PQ&4J02O)^Z?[QHHH`Z'QD] MSK7@F"&$)`VI20I("Y(5202,XYZ>E2^.=(\SPPES9L(;K1V2XM7/;9U'T(HH MH`L>'='D1V\0:I(MSJEYN7.R"/J(XP>@]3U)K'\/P7=CX(UO4F:-KZ^FN) M]P8X!/"C..U%%`&3=>'=5\-_#_=I6HJ8[NT"7EO.S%`[CF2,]5//3H:W?$>C MW=MX*TZTL9PEM8^4;N+>R?:(E'S+N`R,T44`9GAY%UWQ';7ND6.GZ?96?+JU 6N/.Z8PK+C.?4_E7HU%%`!1110!__V3\_ ` end
EMPLOYEE BENEFIT PLANS
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Jun. 30, 2013
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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:
No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G continues to defer such costs related to gas operations. Costs totaling $0.6 million and $1.2 million related to gas operations were deferred for the three and six months ended June 30, 2013, respectively. Costs totaling $3.7 million and $7.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. Previously deferred costs related to electric operations are being recovered as described in Note 2. |
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SCEG
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EMPLOYEE BENEFIT PLANS | Pension and Other Postretirement Benefit Plans Consolidated SCE&G participates in SCANA’s noncontributory defined benefit pension plan, which covers substantially all regular, full-time employees, and also participates in SCANA’s unfunded postretirement health care and life insurance programs, which provide benefits to active and retired employees. Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:
No contribution to the pension trust will be necessary until after 2014, nor will limitations on benefit payments apply. As authorized by the SCPSC, prior to January 1, 2013 SCE&G deferred all pension expense related to retail electric and gas operations as a regulatory asset. In connection with the SCPSC's December 2012 rate order, effective January 1, 2013 SCE&G began recovering pension expense related to retail electric operations through a rate rider that is adjusted annually. SCE&G continues to defer such costs related to gas operations. Costs totaling $0.6 million and $1.2 million related to gas operations were deferred for the three and six months ended June 30, 2013, respectively. Costs totaling $3.7 million and $7.4 million related to electric and gas operations were deferred for the corresponding periods in 2012. Previously deferred cost related to electric operations are being recovered as described in Note 2. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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Jun. 30, 2013
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Significant Accounting Policies | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies [Text Block] | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Plant to be Retired In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013. The net carrying value of the remaining units to be retired (including these two units) totaled $351 million at June 30, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. Earnings Per Share The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method. The Company has issued no securities that would have an antidilutive effect on earnings per share. Reconciliations of the weighted average number of common shares for basic and diluted earnings per share computation purposes are as follows:
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 40% and 44% of PSNC Energy’s natural gas inventory at June 30, 2013 and December 31, 2012, respectively, with a carrying value of $14.1 million and $19.6 million, respectively, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees. The agreements expire March 31, 2015. |
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SCEG
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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 Entity SCE&G has determined that it is the primary beneficiary of GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, the accompanying condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. Accordingly, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements. GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $477 million) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission allowances. See also Note 4. Plant to be Retired In 2012, SCE&G announced its intention to retire six coal-fired units by 2018, subject to future developments in environmental regulations, among other matters. These units had an aggregate generating capacity (summer 2012) of 730 MW. One of these units (90 MW) was retired in 2012 and its net carrying value is recorded in regulatory assets as unrecovered plant (see Note 2). In June 2013, SCE&G approved a plan to accelerate the retirement of two more of these units (295 MW) by the end of 2013. The net carrying value of the remaining units to be retired (including these two units) totaled $351 million at June 30, 2013 and is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. |
COMMON EQUITY (Tables)
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Schedule of Stockholders Equity [Table Text Block] | Changes in common equity during the six months ended June 30, 2013 and 2012 were as follows:
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Reclassifications from Other Comprehensive Income [Table Text Block] | Reclassifications of gains (losses) from AOCI into earnings were as follows (amounts are net of taxes):
Reclassifications of the amortization of deferred employee benefit costs were not significant for any period presented. |
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Schedule of Stockholders Equity [Table Text Block] | Changes in common equity during the six months ended June 30, 2013 and 2012 were as follows:
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COMMITMENTS AND CONTINGENCIES
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Jun. 30, 2013
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Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 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. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $40.6 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other costs and expenses, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s results of operations, cash flows and financial position. Environmental On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require 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 plants could be constructed without carbon capture and sequestration capabilities. As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. The Company is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on the Company, if any. The Company expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates. In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. On June 24, 2013, the U.S. Supreme Court agreed to review the lower court's decision. Air quality control installations that SCE&G and GENCO have already completed have allowed the Company to comply with the reinstated CAIR. The Company will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with such regulations are expected to be recoverable through rates. In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for facilities to meet the standards, and the Company's evaluation of the rule is ongoing. The Company's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in the Company's compliance with the EPA's rule. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates. The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates. The Company maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense. SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an additional $21.9 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 June 30, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.9 million and are included in regulatory assets. PSNC Energy is responsible for environmental clean-up at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy’s actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. PSNC Energy has recorded a liability and associated regulatory asset of approximately $3.0 million, the estimated remaining liability at June 30, 2013. PSNC Energy expects to recover through rates any cost allocable to PSNC Energy arising from the remediation of these sites. New Nuclear Construction SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.5 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. Following an examination of this issue, the Consortium has preliminarily indicated that the substantial completion of the first New Unit is expected to be delayed until late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be similarly delayed. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G intends to continue to work with the Consortium to refine this preliminary estimate and expects to have further discussions with the Consortium regarding responsibility for these increased costs. In addition to the above-described project delays, SCE&G has also become aware of recent press reports concerning financial difficulties at a supplier responsible for certain significant components of the project. SCE&G has asked the Consortium to evaluate the potential for disruptions in such equipment fabrication and possible responses. Any disruptions could impact the project's schedule or costs, and such impacts could be material. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing. These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.” This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan for the New Units, which it expects to submit to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material. |
SCEG
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Statement [Line Items] | |
Commitments and Contingencies Disclosure [Text Block] | COMMITMENTS AND CONTINGENCIES Nuclear Insurance Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Summer Station Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the Company's nuclear power plant. Price-Anderson provides funds up to $12.6 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 $117.5 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $17.5 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 $78.3 million per incident, but not more than $11.7 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. In addition, a builder's risk insurance policy has been purchased from NEIL for the construction of the New Units. This policy provides the owners of the New Units up to $500 million in limits of accidental property damage occurring during construction. The NEIL policies, in the aggregate, are subject to a maximum loss of $2.75 billion for any single loss occurrence. All of the NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $40.6 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power or other cost and expenses, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s results of operations, cash flows and financial position. Environmental On April 13, 2012, the EPA issued a proposed rule to establish NSPS for GHG emissions from fossil fuel-fired electric generating units. If finalized as proposed, this rule would establish performance standards for new and modified generating units, along with emissions guidelines for existing generating units. This rule would amend the NSPS for electric generating units and establish the first NSPS for GHG emissions. Essentially, the rule would require 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 plants could be constructed without carbon capture and sequestration capabilities. As part of the President's Climate Action Plan and by Presidential Memorandum issued June 25, 2013, the EPA was directed to issue a revised carbon standard for new power plants by September 20, 2013, to be made final as soon as appropriate. Standards, regulations, or guidelines are also required for existing units by June 1, 2014, to be made final no later than June 1, 2015. Consolidated SCE&G is evaluating the proposed rule, but cannot predict when the rule will become final, if at all, or what conditions it may impose on Consolidated SCE&G, if any. Consolidated SCE&G expects that any costs incurred to comply with GHG emission requirements will be recoverable through rates. In 2005, the EPA issued the CAIR, which required the District of Columbia and 28 states, including South Carolina, to reduce nitrogen oxide and sulfur dioxide emissions in order to attain mandated state levels. CAIR set emission limits to be met in two phases beginning in 2009 and 2015, respectively, for nitrogen oxide and beginning in 2010 and 2015, respectively, for sulfur dioxide. SCE&G and GENCO determined that additional air quality controls would be needed to meet the CAIR requirements. On July 6, 2011 the EPA issued the CSAPR. This rule replaced CAIR and the Clean Air Transport Rule proposed in July 2010 and is aimed at addressing power plant emissions that may contribute to air pollution in other states. CSAPR requires states in the eastern United States to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxide. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued an order staying CSAPR and reinstating CAIR pending resolution of an appeal of CSAPR. On August 21, 2012, the Court of Appeals vacated CSAPR and left CAIR in place. The EPA's petition for rehearing of the Court of Appeals' order has been denied. On March 29, 2013, the U.S. Solicitor General petitioned the U. S. Supreme Court to review the D.C. Circuit Court's decision on CSAPR. On June 24, 2013, the U.S. Supreme Court agreed to review the lower court's decision. Air quality control installations that SCE&G and GENCO have already completed have allowed the Consolidated SCE&G to comply with the reinstated CAIR. Consolidated SCE&G will continue to pursue strategies to comply with all applicable environmental regulations. Any costs incurred to comply with such regulations are expected to be recoverable through rates. In April 2012, the EPA's rule containing new standards for mercury and other specified air pollutants became effective. The rule provides up to four years for facilities to meet the standards, and Consolidated SCE&G's evaluation of the rule is ongoing. Consolidated SCE&G's decision in 2012 to retire certain coal-fired units or convert them to burn natural gas and its project to build the New Units (see Note 1) along with other actions are expected to result in Consolidated SCE&G's compliance with the EPA's rule. Any costs incurred to comply with this rule or other rules issued by the EPA in the future are expected to be recoverable through rates. The EPA is conducting an enforcement initiative against the utilities industry related to the NSR provisions and the NSPS of the CAA. As part of the initiative, many utilities have received requests for information under Section 114 of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though Consolidated SCE&G cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates. Consolidated SCE&G maintains an environmental assessment program to identify and evaluate its current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are recorded to expense. SCE&G is responsible for four decommissioned MGP sites in South Carolina which contain residues of byproduct chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue until 2016 and will cost an additional $21.9 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 June 30, 2013, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $37.9 million and are included in regulatory assets. New Nuclear Construction SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted with the Consortium for the design and construction of the New Units at the site of Summer Station. SCE&G's share of the estimated cash outlays (future value, excluding AFC) totals approximately $5.5 billion for plant and related transmission infrastructure costs, and is projected based on historical one-year and five-year escalation rates as required by the SCPSC. The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for the New Units. Following an examination of this issue, the Consortium has preliminarily indicated that the substantial completion of the first New Unit is expected to be delayed until late 2017 or the first quarter of 2018 and that the substantial completion of the second New Unit is expected to be similarly delayed. The substantial completion dates currently approved by the SCPSC for the first and second New Units are March 15, 2017 and May 15, 2018, respectively. The SCPSC has also approved an 18-month contingency period beyond each of these dates. The preliminary expected new substantial completion dates are within the contingency periods. SCE&G cannot predict with certainty the extent to which the issue with the sub-modules or the delays in the substantial completion of the New Units will result in increased project costs. However, the preliminary estimate of the delay-related costs associated with SCE&G's share of the New Units is approximately $200 million. SCE&G intends to continue to work with the Consortium to refine this preliminary estimate and expects to have further discussions with the Consortium regarding responsibility for these increased costs. In addition to the above-described project delays, SCE&G has also become aware of recent press reports concerning financial difficulties at a supplier responsible for certain significant components of the project. SCE&G has asked the Consortium to evaluate the potential for disruptions in such equipment fabrication and possible responses. Any disruptions could impact the project's schedule or costs, and such impacts could be material. The parties to the EPC Contract have established both informal and formal dispute resolution procedures in order to resolve issues that arise during the course of constructing a project of this magnitude. During the course of activities under the EPC Contract, issues have materialized that impact project budget and schedule. Claims specifically relating to COL delays, design modifications of the shield building and certain pre-fabricated modules for the New Units and unanticipated rock conditions at the site resulted in assertions of contractual entitlement to recover additional costs to be incurred. The resolution of these specific claims is discussed in Note 2. SCE&G expects to resolve any disputes that arise in the future, including any which may arise with respect to the delay-related costs discussed above, through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time, will be recoverable through rates. When the NRC issued the COLs for the New Units, two of the conditions that it imposed were requiring inspection and testing of certain components of the New Units' passive cooling system, and requiring the development of strategies to respond to extreme natural events resulting in the loss of power at the New Units. In addition, the NRC directed the Office of New Reactors to issue to SCE&G an order requiring enhanced, reliable spent fuel pool instrumentation, as well as a request for information related to emergency plant staffing. These conditions and requirements are responsive to the NRC's Near-Term Task Force report titled “Recommendations for Enhancing Reactor Safety in the 21st Century.” This report was prepared in the wake of the March 2011 earthquake-generated tsunami, which severely damaged several nuclear generating units and their back-up cooling systems in Japan. SCE&G continues to evaluate the impact of these conditions and requirements that may be imposed on the construction and operation of the New Units, and SCE&G is preparing an integrated response plan for the New Units, which it expects to submit to the NRC in August 2013. SCE&G cannot predict what additional regulatory or other outcomes may be implemented in the United States, or how such initiatives would impact SCE&G's existing Summer Station or the construction or operation of the New Units. As previously reported, SCE&G has been advised by Santee Cooper that it is reviewing certain aspects of its capital improvement program and long-term power supply plan, including the level of its participation in the New Units. SCE&G is unable to predict whether any change in Santee Cooper's ownership interest or the addition of new joint owners will increase project costs or delay the commercial operation dates of the New Units. Any such project cost increase or delay could be material. |
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Tables)
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Fair Value, Measurement Inputs, Disclosure [Table Text Block] | The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s interest rate swap agreements are valued using discounted cash flow models with independently sourced market data. Fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:
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Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value at June 30, 2013 and December 31, 2012 were as follows:
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SCEG
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Fair Value, Measurement Inputs, Disclosure [Table Text Block] | Consolidated SCE&G’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements based on significant other observable inputs (level 2) were as follows:
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Fair Value, by Balance Sheet Grouping [Table Text Block] | Financial instruments for which the carrying amount may not equal estimated fair value at June 30, 2013 and December 31, 2012 were as follows:
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DERIVATIVE FINANCIAL INSTRUMENTS (Tables)
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Schedule of Derivative Instruments [Table Text Block] | The Company was party to natural gas derivative contracts outstanding in the following quantities:
(a) Includes an aggregate 1,365,752 MMBTU related to basis swap contracts in Energy Marketing. (b) Includes an aggregate 3,500,000 MMBTU related to basis swap contracts in Energy Marketing. |
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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:
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Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | Derivatives in Cash Flow Hedging Relationships
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Offseting Assets [Table Text Block] | Information related to the Company's offsetting of derivative assets follows:
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Offsetting Liabilities [Table Text Block] | Information related to the Company's offsetting of derivative liabilities follows:
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SCEG
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Derivative [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The fair value of interest rate derivatives was reflected in the condensed consolidated balance sheet as follows:
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Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] |
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Offseting Assets [Table Text Block] | Information related to Consolidated SCE&G's derivative assets follows:
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Offsetting Liabilities [Table Text Block] | Information related to Consolidated SCE&G's derivative liabilities follows:
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RATE AND OTHER REGULATORY MATTERS (Details) (USD $)
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6 Months Ended | 12 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | 24 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||||||||
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Jun. 30, 2013
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Dec. 31, 2012
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Dec. 31, 2011
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Dec. 31, 2012
SCEG
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Jun. 30, 2013
SCEG
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Jun. 30, 2012
SCEG
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May 01, 2015
SCEG
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Dec. 31, 2012
SCEG
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Dec. 31, 2011
SCEG
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May 01, 2015
SCEG
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Mar. 31, 2013
SCEG
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Jan. 31, 2013
SCEG
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Mar. 31, 2012
PSNC Energy
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Jun. 30, 2013
PSNC Energy
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Jun. 30, 2013
Deferred Pollution Control Costs
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Dec. 31, 2012
Deferred Pollution Control Costs
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Jun. 30, 2013
Deferred Pollution Control Costs
SCEG
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Dec. 31, 2012
Deferred Pollution Control Costs
SCEG
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Jun. 30, 2013
Franchise agreement Costs
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Dec. 31, 2012
Franchise agreement Costs
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Jun. 30, 2013
Franchise agreement Costs
SCEG
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Dec. 31, 2012
Franchise agreement Costs
SCEG
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Dec. 31, 2012
Utility Plant [Domain]
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Rate Matters [Line Items] | |||||||||||||||||||||||
Regulatory Assets, Noncurrent | $ 1,439,000,000 | $ 1,464,000,000 | $ 1,377,000,000 | $ 1,352,000,000 | $ 1,377,000,000 | $ 3,000,000 | $ 38,000,000 | $ 38,000,000 | $ 38,000,000 | $ 38,000,000 | $ 33,000,000 | $ 36,000,000 | $ 33,000,000 | $ 36,000,000 | |||||||||
Amounts Recovered Through Electric Rates to offset Turbine Expenses | 17,200,000 | ||||||||||||||||||||||
Share in Approved Capital Costs | 8,000,000 | ||||||||||||||||||||||
Undercollected balance fuel | 80,600,000 | ||||||||||||||||||||||
Number of coal fired units to be retired | 6 | 2 | 6 | 6 | |||||||||||||||||||
Public Utilities, Percent Increase (Decrease) in Retail Electric Rates | 4.23% | 2.87% | 2.30% | 2.40% | |||||||||||||||||||
Allowable return on common equity (as a percent) | 10.25% | 11.00% | |||||||||||||||||||||
historical average temperature | 15 | ||||||||||||||||||||||
Demand Side Management Program Costs, Noncurrent | 19,600,000 | 20,600,000 | 19,600,000 | 7,000,000 | 27,200,000 | ||||||||||||||||||
Regulatory Asset Recovery Assessments | 12 | 24 | |||||||||||||||||||||
Public Utilities Property Plant and Equipment Identifiable Capital Costs | 278,000,000 | ||||||||||||||||||||||
Capital Cost Related to New Federal Healthcare Etc | 1,000,000 | ||||||||||||||||||||||
Public Utilities Additional Labor Expenses for Oversight of New Units | 132,000,000 | ||||||||||||||||||||||
Increase (decrease) in retail electric rate requested under the BLRA | 67.2 | 0 | 0 | ||||||||||||||||||||
Public Utilities, Percent Increase (Decrease) in Retail Natural Gas Rates | 2.10% | 2.10% | |||||||||||||||||||||
Public Utilities changes in Retail Natural Gas Rates Requested and Approved under RSA | 0 | 8.6 | |||||||||||||||||||||
Basis for rate calculation | 12-month rolling average | 12 | |||||||||||||||||||||
Regulatory Noncurrent Asset Amortization Period | 30 | 30 | 20 | 14 | |||||||||||||||||||
Public Utilities Base Fuel under Collected Balance Recovery Period | 12 | 12 | 12 | ||||||||||||||||||||
MPG enviromental remediatio | 27 | ||||||||||||||||||||||
Defined Benefit Plan, Deferred Debit Attributable to Share of Regulatory Authority | $ 63,000,000 | $ 63,000,000 |
LONG-TERM AND SHORT-TERM DEBT LONG-TERM AND SHORT-TERM DEBT (Tables)
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Jun. 30, 2013
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Short-term Debt [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt [Text Block] | SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
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SCEG
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Short-term Debt [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt [Text Block] | SCE&G (including Fuel Company) had available the following committed LOC, and had outstanding the following LOC advances, commercial paper, and LOC-supported letter of credit obligations:
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RATE AND OTHER REGULATORY MATTERS
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Jun. 30, 2013
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Rate Matters [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities Disclosure [Text Block] | RATE AND OTHER REGULATORY MATTERS Rate Matters Electric SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012. In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions. In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component. On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order. The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA which may be used to modify or terminate eWNA in the future. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. SCE&G cannot predict what action the SCPSC may take, if any, as a result of this study. In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, in June 2013, SCE&G approved a plan to accelerate the retirement of two of the units to be completed by December 31, 2013. SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:
In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6 million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. On April 30, 2013, the SCPSC approved SCE&G's request to update its DSM Programs rider, as modified by the agreement between ORS and SCE&G, effective for bills rendered on and after the first billing cycle of May 2013. SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs. SCE&G also requested approval to continue the use of an annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs and (ii) modifies the opt-out requirements for industrial customers. SCE&G requested that the proposed DSM Programs rider be effective December 1, 2013. Electric – BLRA In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:
On May 31, 2013, SCE&G filed its annual request for approval of revised rates under the BLRA. On July 30, 2013, ORS filed a report of its review of SCE&G's request. ORS proposes that SCE&G be allowed to increase its rates in the amount of $67.2 million, or 2.87%. If approved, the revised rates will be effective for bills rendered on and after October 30, 2013. 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 years indicated:
On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. Therefore, SCE&G did not request any adjustments to its rates. SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. The next annual PGA hearing is scheduled for November 7, 2013. PSNC Energy PSNC Energy is subject to a Rider D rate mechanism which allows it to recover from customers all prudently incurred gas costs and certain uncollectible expenses related to gas cost. The Rider D rate mechanism also allows PSNC Energy to recover, in any manner authorized by the NCUC, losses on negotiated gas and transportation sales. PSNC Energy’s rates are established using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption. In October 2012, in connection with PSNC Energy's 2012 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, 2012. Regulatory Assets and Regulatory Liabilities The Company’s cost-based, rate-regulated utilities recognize in their financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are not expected to be recovered in retail electric rates within 12 months. Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 27 years. ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years. Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance. Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges. Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs are being recovered through utility rates over periods up to 30 years. Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are being amortized into operating revenue through February 2024. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC, the NCUC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, the Company could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on the Company's results of operations, liquidity or financial position in the period the write-off would be recorded. |
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Public Utilities Disclosure [Text Block] |
Rate Matters Electric SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G. In April 2012, the SCPSC approved SCE&G's request to decrease the total fuel cost component of its retail electric rates, and approved a settlement agreement among SCE&G, the ORS and SCEUC in which SCE&G agreed to recover an amount equal to its actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a 12-month period beginning with the first billing cycle of May 2012. In the December 2012 rate order, the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing so, stated that SCE&G may not adjust its base fuel cost component prior to the last billing cycle of April 2014, except where necessary due to extraordinary unforeseen economic or financial conditions. In February 2013, in connection with its annual review of base rates for fuel costs, SCE&G requested authorization to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. Consistent with the December 2012 rate order, however, SCE&G did not request any adjustment to its base fuel cost component. On March 14, 2013, SCE&G, ORS and the SCEUC entered into a settlement agreement accepting the proposed lower environmental fuel cost component effective with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs.The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component. On December 19, 2012, the SCPSC approved a 4.23% overall increase in SCE&G's retail electric base rates, effective January 1, 2013, and authorized an allowed return on common equity of 10.25%. The SCPSC also approved a mid-period reduction to the cost of fuel component in rates (as discussed above), a reduction in the DSM Programs component rider to retail rates, and the recovery of and a return on the net carrying value of certain retired generating plant assets described below. By order dated February 7, 2013, the SCPSC denied the SCEUC's petition for rehearing of this order. The eWNA is designed to mitigate the efforts of abnormal weather on residential and commercial customers' bills and is based on a 15 year historical average of temperatures. In connection with the December 2012 rate order, SCE&G agreed to perform a study of alternative structures for the eWNA which may be used to modify or terminate eWNA in the future. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. SCE&G cannot predict what action the SCPSC may take, if any, as a result of this study. In February 2013, SCE&G filed an IRP with the SCPSC. The IRP evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. The IRP identified a total of six coal-fired units that SCE&G retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units through rates. In the meantime, these units remain in rate base, and SCE&G continues to depreciate them using composite straight-line rates approved by the SCPSC. As discussed in Note 1, in June 2013, SCE&G approved a plan to accelerate the retirement of two of the units to be completed by December 31, 2013. SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings in January to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. The SCPSC has approved the following rate changes pursuant to annual DSM Programs filings, which changes became effective as indicated:
In January 2013, SCE&G filed its annual update on DSM Programs and a petition for an update to the rate rider, requesting an increase of approximately $27.2 million. On April 1, 2013, ORS filed a report of its review of SCE&G's DSM Programs petition with the SCPSC. ORS proposed that SCE&G recover the net lost revenue component of the rider of $20.6 million over a 24-month period effective for bills rendered on and after the first billing cycle in May 2013. ORS also recommended that SCE&G defer a portion of net lost revenue component in a regulatory asset and recover those amounts over a 12-month period effective for bills rendered on and after the first billing cycle in May 2014. SCE&G agreed with ORS's recommendations. On April 30, 2013, the SCPSC approved SCE&G's request to update its DSM Programs rider, as modified by the agreement between ORS and SCE&G, effective for bills rendered on and after the first billing cycle of May 2013. SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs. SCE&G also requested approval to continue the use of an annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs and (ii) modifies the opt-out requirements for industrial customers. SCE&G requested that the proposed DSM Programs rider be effective December 1, 2013. Electric – BLRA In November 2012, the SCPSC approved an updated construction schedule and additional updated capital costs of $278 million (SCE&G's portion in 2007 dollars). The November 2012 order approved additional identifiable capital costs of approximately $1 million (SCE&G's portion in 2007 dollars) related to new federal healthcare laws, information security measures, and certain minor design modifications; approximately $8 million (SCE&G's portion in 2007 dollars) related to transmission infrastructure; and approximately $132 million (SCE&G's portion in 2007 dollars) related to additional labor for the oversight of the New Units during construction and for preparing to operate the New Units, and facilities and information technology systems required to support the New Units and their personnel. In addition, the order approved revised substantial completion dates for the New Units based on the March 30, 2012 issuance of the COL and the amounts agreed upon by SCE&G and the Consortium in July 2012 to resolve claims for costs related to COL delays, design modifications of the shield building and certain pre-fabricated structural modules for the New Units and unanticipated rock conditions at the site. Thereafter, two parties filed separate petitions requesting that the SCPSC reconsider its November 2012 order. On December 12, 2012, the SCPSC denied both petitions. In March 2013, both parties appealed the SCPSC's order to the South Carolina Supreme Court. SCE&G is unable to predict the outcome of these appeals. Under the BLRA, SCE&G is allowed to file revised rates with the SCPSC each year to incorporate the financing cost of any incremental construction work in progress incurred for new nuclear generation. Requested rate adjustments are based on SCE&G’s updated cost of debt and capital structure and on an allowed return on common equity of 11.0%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:
On May 31, 2013, SCE&G filed its annual request for approval of revised rates under the BLRA. On July 30, 2013, ORS filed a report of its review of SCE&G's request. ORS proposes that SCE&G be allowed to increase its rates in the amount of $67.2 million, or 2.87%. If approved, the revised rates will be effective for bills rendered on and after October 30, 2013. 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 years indicated:
On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. Therefore, SCE&G did not request any adjustments to its rates. SCE&G's natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average. The annual PGA hearing to review SCE&G's gas purchasing policies and procedures was held in November 2012 before the SCPSC. The SCPSC issued an order in December 2012 finding that SCE&G's gas purchasing policies and practices during the review period of August 1, 2011 through July 31, 2012, were reasonable and prudent. The next annual PGA hearing is scheduled for November 7, 2013. Regulatory Assets and Regulatory Liabilities Consolidated SCE&G has significant cost-based, rate-regulated operations and recognizes in its financial statements certain revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, Consolidated SCE&G has recorded regulatory assets and regulatory liabilities, which are summarized in the following tables. Substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
Accumulated deferred income tax liabilities that arose from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to approximately 70 years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability. Under-collections - electric fuel adjustment clause represent amounts due from customers pursuant to the fuel adjustment clause as approved by the SCPSC during annual hearings which are not expected to be recovered in retail electric rates within 12 months. Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by SCE&G. These regulatory assets are expected to be recovered over periods of up to approximately 27 years. ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station and conditional AROs. These regulatory assets are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 90 years. Franchise agreements represent costs associated with electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina. Based on an SCPSC order, SCE&G began amortizing these amounts through cost of service rates in February 2003 over approximately 20 years. Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under generally accepted accounting principles. Deferred employee benefit plan costs represent amounts of pension and other postretirement benefit costs which were accrued as liabilities and treated as regulatory assets pursuant to FERC guidance, and costs deferred pursuant to specific SCPSC regulatory orders. In connection with the December 2012 rate order, approximately $63 million of deferred pension costs for electric operations are to be recovered through utility rates over approximately 30 years. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees, or up to approximately 12 years. Planned major maintenance related to certain fossil fueled turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collects $18.4 million annually for fossil fueled turbine/generation equipment maintenance. Through December 31, 2012, nuclear refueling charges were accrued during each 18-month refueling outage cycle as a component of cost of service. In connection with the December 2012 rate order, effective January 1, 2013, SCE&G began to collect and accrue $17.2 million annually for nuclear-related refueling charges. Deferred losses or gains on interest rate derivatives represent the effective portions of changes in fair value and payments made or received upon termination of certain interest rate derivatives designated as cash flow hedges. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs are being recovered through utility rates over periods up to 30 years. Unrecovered plant represents the net book value of a coal-fired generating unit retired from service prior to being fully depreciated. Pursuant to the December 2012 rate order, SCE&G is amortizing these amounts over the unit's original remaining useful life of approximately 14 years. Unamortized amounts are included in rate base. Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 30 years. Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future. The storm damage reserve represents an SCPSC-approved collection through SCE&G electric rates, capped at $100 million, which can be applied to offset incremental storm damage costs in excess of $2.5 million in a calendar year. Pursuant to specific regulatory orders, SCE&G has suspended storm damage reserve collection through rates indefinitely. The SCPSC or the FERC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been approved for recovery by the SCPSC or by the FERC. In recording such costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by SCE&G. The costs are currently not being recovered, but are expected to be recovered through rates in future periods. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, Consolidated SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material effect on Consolidated SCE&G's results of operations, liquidity or financial position in the period the write-off would be recorded. |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | |
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Jun. 30, 2013
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Jun. 30, 2012
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Interest Paid, Capitalized | $ 5 | $ 4 |
SCEG
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Interest Paid, Capitalized | $ 5 | $ 4 |
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES (Details 2) (USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Carrying Amount
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Financial instruments for which the carrying amount may not equal estimated fair value | ||
Long-term debt | $ 5,454.6 | $ 5,121.0 |
Estimated Fair Value
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Financial instruments for which the carrying amount may not equal estimated fair value | ||
Long-term debt | 5,961.3 | 6,115.0 |
SCEG | Carrying Amount
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Financial instruments for which the carrying amount may not equal estimated fair value | ||
Long-term debt | 4,058.5 | 3,722.0 |
SCEG | Estimated Fair Value
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Financial instruments for which the carrying amount may not equal estimated fair value | ||
Long-term debt | $ 4,447.4 | $ 4,543.1 |
EMPLOYEE BENEFIT PLANS (Tables)
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Pension and Other Postretirement Benefit Plans | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs [Table Text Block] | urance programs, which provide benefits to active and retired employees. Components of net periodic benefit cost recorded by Consolidated SCE&G were as follows:
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RATE AND OTHER REGULATORY MATTERS (Details 2) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | 6 Months Ended | 24 Months Ended | 6 Months Ended | 6 Months Ended | 6 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 6 Months Ended | 6 Months Ended | ||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
|
Dec. 31, 2012
|
Jun. 30, 2013
SCEG
|
Jul. 31, 2012
SCEG
|
Dec. 31, 2012
SCEG
|
Jun. 30, 2013
Deferred Income Tax Charges [Member]
|
Dec. 31, 2012
Deferred Income Tax Charges [Member]
|
Jun. 30, 2013
Deferred Income Tax Charges [Member]
SCEG
|
Dec. 31, 2012
Deferred Income Tax Charges [Member]
SCEG
|
Jun. 30, 2013
Regulatory Clause Revenues, under-recovered [Member]
|
Dec. 31, 2012
Regulatory Clause Revenues, under-recovered [Member]
|
Jun. 30, 2013
Regulatory Clause Revenues, under-recovered [Member]
SCEG
|
Dec. 31, 2012
Regulatory Clause Revenues, under-recovered [Member]
SCEG
|
Jun. 30, 2013
Environmental Restoration Costs [Member]
|
Dec. 31, 2012
Environmental Restoration Costs [Member]
|
Jun. 30, 2013
Environmental Restoration Costs [Member]
SCEG
|
Dec. 31, 2012
Environmental Restoration Costs [Member]
SCEG
|
Jun. 30, 2013
Asset Retirement Obligation Costs [Member]
|
Dec. 31, 2012
Asset Retirement Obligation Costs [Member]
|
Jun. 30, 2013
Asset Retirement Obligation Costs [Member]
SCEG
|
Dec. 31, 2012
Asset Retirement Obligation Costs [Member]
SCEG
|
Jun. 30, 2013
Franchise agreement Costs
|
Dec. 31, 2012
Franchise agreement Costs
|
Jun. 30, 2013
Franchise agreement Costs
SCEG
|
Dec. 31, 2012
Franchise agreement Costs
SCEG
|
Jun. 30, 2013
Pension Costs [Member]
|
Dec. 31, 2012
Pension Costs [Member]
|
Mar. 31, 2013
Pension Costs [Member]
SCEG
|
Jun. 30, 2013
Pension Costs [Member]
SCEG
|
Dec. 31, 2012
Pension Costs [Member]
SCEG
|
Jun. 30, 2013
Planned major maintenance [Member]
|
Dec. 31, 2012
Planned major maintenance [Member]
|
Jun. 30, 2013
Planned major maintenance [Member]
SCEG
|
Dec. 31, 2012
Planned major maintenance [Member]
SCEG
|
Jun. 30, 2013
Deferred Losses On Interest Rate Derivatives [Member]
|
Dec. 31, 2012
Deferred Losses On Interest Rate Derivatives [Member]
|
Jun. 30, 2013
Deferred Losses On Interest Rate Derivatives [Member]
SCEG
|
Dec. 31, 2012
Deferred Losses On Interest Rate Derivatives [Member]
SCEG
|
Jun. 30, 2013
Deferred Pollution Control Costs
|
Dec. 31, 2012
Deferred Pollution Control Costs
|
Jun. 30, 2013
Deferred Pollution Control Costs
SCEG
|
Dec. 31, 2012
Deferred Pollution Control Costs
SCEG
|
Jun. 30, 2013
unrecovered plant [Member]
|
Dec. 31, 2012
unrecovered plant [Member]
|
Jun. 30, 2013
unrecovered plant [Member]
SCEG
|
Jun. 30, 2013
Other Regulatory Assets [Member]
|
Dec. 31, 2012
Other Regulatory Assets [Member]
|
Jun. 30, 2013
Other Regulatory Assets [Member]
SCEG
|
Dec. 31, 2012
Other Regulatory Assets [Member]
SCEG
|
|
Regulatory Assets | |||||||||||||||||||||||||||||||||||||||||||||||||
MPG enviromental remediatio | 27 | ||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Noncurrent Asset, Amortization Period | 30 | 30 | 70 | 70 | 90 | 20 | 12 | 30 | 30 | 30 | |||||||||||||||||||||||||||||||||||||||
Regulatory Assets, Noncurrent | $ 1,439.0 | $ 1,464.0 | $ 1,352.0 | $ 1,377.0 | $ 253.0 | $ 254.0 | $ 248.0 | $ 248.0 | $ 71.0 | $ 66.0 | $ 71.0 | $ 66.0 | $ 42.0 | $ 44.0 | $ 38.0 | $ 39.0 | $ 328.0 | $ 319.0 | $ 311.0 | $ 304.0 | $ 33.0 | $ 36.0 | $ 33.0 | $ 36.0 | $ 445.0 | $ 460.0 | $ 393.0 | $ 405.0 | $ 0 | $ 6.0 | $ 0 | $ 6.0 | $ 128.0 | $ 151.0 | $ 128.0 | $ 151.0 | $ 38.0 | $ 38.0 | $ 38.0 | $ 38.0 | $ 19.0 | $ 20.0 | $ 19.0 | $ 82.0 | $ 70.0 | $ 73.0 | $ 64.0 | ||
Amounts Recovered through Electric Rates to offset Turbine Expense | $ 18.4 |