SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2011

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Principles of Consolidation

SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company also conducts other energy-related business and provides fiber optic communications in South Carolina.

The accompanying Consolidated Financial Statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and two other wholly-owned subsidiaries liquidated in 2011.

Regulated businesses	Nonregulated businesses
South Carolina Electric & Gas Company	SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc.	SCANA Communications, Inc.
South Carolina Generating Company, Inc.	ServiceCare, Inc.
Public Service Company of North Carolina, Incorporated	SCANA Services, Inc.
Carolina Gas Transmission Corporation	SCANA Corporate Security Services, Inc.
	Westex Holdings, LLC

The Company reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable as permitted by accounting guidance.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Utility Plant

Utility plant is stated substantially at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense.

AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 4.7% for 2011, 7.4% for 2010 and 7.5% for 2009. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.

The Company records provisions for depreciation and amortization using the straight-line method based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were as follows:

	2011		2010		2009
SCE&G	2.92	%	2.83	%	2.97	%
GENCO	2.69	%	2.66	%	2.66	%
CGT	2.00	%	1.94	%	1.94	%
PSNC Energy	3.05	%	3.11	%	3.10	%
Aggregate of Above	2.90	%	2.85	%	2.95	%

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in “Fuel used in electric generation” and recovered through the fuel cost component of retail electric rates. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the DOE under a contract for disposal of spent nuclear fuel.

Jointly Owned Utility Plant

SCE&G jointly owns and is the operator of Summer Station Unit 1.  In addition, SCE&G will jointly own and will be the operator of the New Units being designed and constructed at the site of Summer Station.  Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership of a unit.  SCE&G’s share of the direct expenses are included in the corresponding operating expenses on its income statement.

	Unit 1			New Units
As of December 31, 2011
Percent owned	66.7		%	55.0		%
Plant in service	$	1.0 billion		—
Accumulated depreciation	$	545.0 million		—
Construction work in progress	$	62.2 million		$	1.2 billion
As of December 31, 2010
Percent owned	66.7		%	55.0		%
Plant in service	$	1.0 billion		—
Accumulated depreciation	$	548.8 million		—
Construction work in progress	$	40.1 million		$	891.2 million

SCE&G, on behalf of itself and as agent for Santee Cooper, has contracted 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 $6.0 billion for plant costs and for related transmission infrastructure costs, and is projected based on historical one-year and five year escalation rates as required by the SCPSC.

SCE&G’s latest Integrated Resource Plan filed with the SCPSC in February 2011 continues to support SCE&G’s need for 55 percent of the output 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.  Santee Cooper has entered into a letter of intent with Duke that may result in Duke acquiring a portion of Santee Cooper’s ownership interest 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.

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 may impact project budget and schedule, including those related 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.  These issues have resulted in assertions of contractual entitlement to recover additional costs and may result in requests for change orders from the Consortium.  While SCE&G has not accepted the validity of any claims, the total amount of the claims presented (SCE&G’s portion in 2007 dollars) is approximately $188 million.  SCE&G expects to resolve any such disputes through both the informal and formal procedures and anticipates that any additional costs that arise through such dispute resolution processes, as well as other costs identified from time to time (see Note 2 to the consolidated financial statements), will be recoverable through rates.

Included within receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for Summer Station Unit 1 and the New Units. These amounts totaled $63.6 million at December 31, 2011 and $77.9 million at December 31, 2010.

Major Maintenance

               Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSC for such accounting treatment and rate recovery of expenses accrued thereunder. Other planned major maintenance is expensed when incurred. Through 2017, SCE&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures.  For the year ended December 31, 2011, SCE&G incurred $11.5 million for turbine maintenance. Cumulative costs for turbine maintenance in excess of cumulative collections are classified as a regulatory asset on the balance sheet. Nuclear refueling outages are scheduled 18 months apart, and SCE&G begins accruing for each successive scheduled outage upon completion of the preceding scheduled outage. SCE&G accrued $1.2 million per month from July 2008 through July 2011 for its portion of the outages in the fall of 2009 and the spring of 2011. Total costs for the 2009 outage were $32.7 million, of which SCE&G was responsible for $21.8 million.  Total costs for the 2011 outage were $34.1 million, of which SCE&G was responsible for $22.7 million.  In July 2011, SCE&G began accruing $1.2 million per month for its portion of the refueling planned for the fall of 2012.  SCE&G had an accrued balance of $7.2 million at December 31, 2011 and $14.3 million at December 31, 2010.

Goodwill

The Company considers amounts categorized by FERC as “acquisition adjustments” with carrying values of $210 million for PSNC Energy (Gas Distribution segment) and $20 million for CGT (All Other segment) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed.  The goodwill impairment testing is a two-step process which in step one requires estimation of the fair value of the respective reporting unit and the comparison of that amount to the carrying value of the reporting unit. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required.  In the first quarter of 2012, the Company will adopt accounting guidance whereby it will have the option to first perform a qualitative assessment of impairment.  Based on this assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company will not be required to proceed with the two-step quantitative assessment.

In evaluations of PSNC Energy, fair value is estimated using the assistance of an independent appraisal.  In evaluations of CGT, estimated fair value has been obtained from internal analyses. In all evaluations for the periods presented, step one has indicated no impairment, and no impairment charges have been recorded; however, should a write-down be required in the future, such a charge would be treated as an operating expense.

Nuclear Decommissioning

SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Summer Station Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $451.0 million, stated in 2006 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Summer Station Unit 1. The cost estimate assumes that the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.

Under SCE&G’s method of funding decommissioning costs, amounts collected through rates ($3.2 million pre-tax in each of 2011, 2010 and 2009) are invested in insurance policies on the lives of certain Company personnel. SCE&G transfers to an external trust fund the amounts collected through electric rates, insurance proceeds and interest thereon, less expenses. The trusteed asset balance reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Summer Station Unit 1 on an after-tax basis.

Cash and Cash Equivalents

               The Company considers temporary cash investments having original maturities of three months or less at time of purchase to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and notes.

Account Receivable

               Accounts receivable reflect amounts due from customers arising from the delivery of energy or related services and include revenues earned pursuant to revenue recognition practices described below. These receivables include both billed and unbilled amounts. Receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis.

Asset Management and Supply Service Agreements

               PSNC Energy utilizes asset management and supply service agreements with counterparties for certain natural gas storage facilities. At December 31, 2011, such counterparties held 45% of PSNC Energy’s natural gas inventory, with a carrying value of $28.7 million, through either capacity release or agency relationships. Under the terms of the asset management agreements, PSNC Energy receives storage asset management fees.  No fees are received under supply service agreements. The agreements expire at various times through March 31, 2013.

Income Taxes

               The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, they are charged or credited to income tax expense.

Regulatory Assets and Regulatory Liabilities

               The Company’s rate-regulated utilities record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the balance sheet as regulatory assets and regulatory liabilities (See Note 2). The regulatory assets and liabilities are amortized consistent with the treatment of the related costs in the ratemaking process.

Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt

               The Company records long-term debt premium and discount within long-term debt and amortizes them as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.

Environmental

               The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in deferred debits and, if applicable, amortized over approved amortization periods.  Other environmental costs are recorded to expense.

Income Statement Presentation

               In its consolidated statements of income, the Company presents the activities of its regulated and significant nonregulated businesses (including those activities of segments described in Note 12) within operating income, and it presents all other activities within other income (expense).

Revenue Recognition

The Company records revenues during the accounting period in which it provides services to customers and includes estimated amounts for electricity and natural gas delivered, but not yet billed. Unbilled revenues totaled $169.1 million at December 31, 2011 and $221.1 million at December 31, 2010.

Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. This component is established by the SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual hearing.

SCE&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. Any difference between actual gas costs, including the results of its hedging program, and amounts contained in rates is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews.

SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions. In August 2010, SCE&G implemented an eWNA on a one-year pilot basis for its electric customers, and it will continue on a pilot basis unless modified or terminated by the SCPSC.

PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average, per customer consumption, whether impacted by weather or other factors.

Taxes that are billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Accordingly, no such taxes are included in revenues or expenses in the statements of income.

Earnings Per Share

The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. The Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock. The Company has issued no securities that would have an antidilutive effect on earnings per share.

A reconciliation of the weighted average number of common shares for each of the three years ended December 31, 2011 for basic and diluted purposes is as follows:

In Millions	2011	2010	2009
Weighted Average Shares Outstanding—Basic	128.8	125.7	122.1
Net effect of dilutive stock-based compensation plans and equity forward contracts	1.4	0.6	0.1
Weighted Average Shares Outstanding—Diluted	130.2	126.3	122.2