secresponse2009.htm

April 26, 2010

Mr. Andrew Mew

Accounting Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Re: SCANA Corporation (SCANA)

Form 10-K for Fiscal Year Ended December 31, 2009

Filed March 1, 2010

File No. 1-8809

South Carolina Electric & Gas Company (SCE&G)

Form 10-K for Fiscal Year Ended December 31, 2009

Filed March 1, 2010

File No. 1-3375

Dear Mr. Mew:

We respectfully provide the following responses to the comments arising from your review of the above filings, as described in your letter of April 16, 2010. For ease of reference, we have reproduced and italicized your comment language.

Form 10-K for Fiscal Year Ended December 31, 2009

General

Our review encompassed the parent company, and the subsidiary registrant listed on the facing page of your Form 10-K. In the interests of reducing the number of comments, we have not addressed each registrant with a separate comment. To the extent a comment is applicable to more than one registrant, please address the issue separately.

Response (SCANA and SCE&G): In our responses, we have indicated the registrants to which they apply.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 28

Pension Cost (Income), page 32

Explain to us and revise your disclosure to indicate how you have historically recovered pension and other postretirement costs for your rate-regulated subsidiaries. In this regard, please also explain to us how you concluded the probability of recovery threshold has been met pursuant to FASB ASC 980 with respect to the regulatory asset recorded for your deferred employee benefit costs.

Mr. Andrew Mew

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April 26, 2010

Response (SCANA and SCE&G): We have historically recovered pension and other postretirement costs for our rate-regulated subsidiaries as they have been recorded under generally accepted accounting principles (e.g., as determined under SFAS 87 and SFAS 106). As such, and based upon guidance issued by the Federal Energy Regulatory Commission (FERC) on March 29, 2007 (Docket No. A1087-1-000), upon the implementation of SFAS 158 as of December 31, 2006, we have recorded the amounts which otherwise would have been recorded within accumulated other comprehensive income to regulatory asset accounts. Our conclusion that recovery of these costs was probable was based upon the prior actions of the regulators in allowing actuarially determined pension and postretirement costs to be recovered, and upon the FERC guidance.

Further, upon receipt of specific accounting orders of the South Carolina Public Service Commission (SCPSC) in early 2009, and as described on page 32 and in footnote 1.B. to the financial statements, we deferred certain pension costs which otherwise would have been recorded within operating costs into the regulatory asset accounts. Our conclusion that recovery of these pension costs was probable was based upon these specific orders of the SCPSC.

We propose to include the above additional information surrounding the recoverability of pension and other postretirement benefit costs in future filings rather than in a revision of the 2009 Form 10-K. The disclosure revision provided in response to comment 7 below includes our proposed language with respect to this issue.

Resolution of EIZ Tax Credit Uncertainty, page 35

3.	Please explain to us why the interest income portion of the refund associated with the settlement of the EIZ state income tax credit issue was taken immediately to income as opposed to being deferred as a regulatory liability.

Response (SCANA and SCE&G): We followed the instructions within the FERC Uniform Systems of Accounts which have been adopted by the SCPSC for use by jurisdictional utilities (electric and gas) in recording the interest income we received. Those instructions require that interest and dividend income, specifically including interest income related to tax refunds and all other interest bearing assets, be recorded within account 419. This treatment as interest income is consistent with treatment under generally accepted accounting principles. Further, the SCPSC does not include interest income (account 419) as a reduction of allowable costs when setting SCE&G’s rates, either as a component of cost of capital or otherwise. We have no regulatory order which would allow or require treatment otherwise. As such, we do not believe that deferral of the interest income as a regulatory liability would have been proper.

Consolidated Balance Sheets, page 50

Refer to page 58 where you state that the Company considered amounts categorized by FERC as “acquisition adjustments” to be goodwill. We assume the acquisition adjustments are not recoverable. In this regard, it does not appear these acquisition

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adjustments have been amortized. If our assumption is correct, then please revise your balance sheet to reclassify these amounts as goodwill, or advise. Please refer to FASB ASC 980-350-35-2. Please also refer to Item 13b of Rule 5-02 of Regulation S-X and the accounting guidance issued by the FERC with regard to this issue.

Response (SCANA): As described in footnote 1.F., SCANA’s acquisition adjustments relate primarily to PSNC Energy, with a small amount also being related to CGT. In both cases, the acquisition adjustments are not recoverable through amortization as an allowable cost for rate-making purposes and are considered to be goodwill. Also in both cases, these amounts were amortized under generally accepted accounting principles until the implementation of FAS 142 which was effective on January 1, 2002. At that time, particularly with respect to the PSNC Energy acquisition adjustment, an impairment charge of $230 million was recorded as the cumulative effect of an accounting change, and amortization of both of the amounts ceased.

In accordance with FASB ASC 980-350-35-2, we have not amortized the acquisition adjustments since 2002, and we have accounted for them in accordance with Topic 350. Specifically, we have subjected their carrying amounts to annual impairment testing, and while we have not used the specific caption of “goodwill” on our balance sheet, we have referred to the amounts as goodwill within footnote 1.F. and have presented the aggregate amount as a separate line item in accordance with FASB ASC 350-20-45-1. In order to improve clarity, we propose to re-caption the acquisition adjustments as “goodwill” in future filings. In addition, in compliance with Item 13b of Rule 5-02 of Regulation S-X, we will parenthetically disclose the sum of the prior amortization and write-down amounts in those future filings.

5.	Please tell us and expand your footnote disclosure to indicate how you evaluate acquisition adjustments for impairment.

Response (SCANA): As described in footnote 1.F., SCANA’s acquisition adjustments are subjected to annual impairment evaluations, and any indicated write-down in the future arising from those evaluations would be recorded as an operating expense.

In performing these annual impairment evaluations, we have used a valuation date of January 1, and have followed the requirements of FASB ASC 350-20-35, utilizing the two-step approach described therein. In Step 1, we determine the fair value of the reporting unit (PSNC Energy (gas distribution) or CGT (gas transmission), as applicable), and we compare that fair value to the carrying value of the reporting unit. In all years since the impairment charge was taken in 2002, the fair value has exceeded carrying value; therefore, no impairment has been indicated, and Step 2 (measuring a loss) has been unnecessary.

In all our assessments through January 1, 2007, we have estimated CGT’s fair value by utilizing a discounted cash flow modeling technique. Because those fair value estimates all have significantly exceeded the $20 million carrying value, beginning January 1, 2008, we

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have considered and met the criteria in FASB ASC 350-20-35-29 for carrying forward the fair value determination to later years.

In the case of PSNC Energy, the fair value as of January 1, 2002 was determined based upon an independent appraisal. Similar independent appraisals were obtained as of January 1, 2005, 2009 and 2010. For other annual valuation dates (January 1, 2003, 2004, 2006, 2007 and 2008), we determined the estimated fair value internally, utilizing two valuation methodologies which were consistent with those employed by the independent appraiser. Specifically, we averaged a value computed using a discounted cash flow modeling technique and a value computed utilizing a guideline company approach based upon the application of valuation multiples of publicly traded companies considered to be similar to PSNC. In the years that we performed the valuation analysis internally, we obtained the then-current market multiples, weighted average cost of capital and control premium information from the appraiser. Both of these modeling techniques, and the averaging of their results, were consistent with the approach used by the independent appraiser.

We propose to include the following language referencing the evaluation methods in future annual filings, rather than in a revision of the 2009 Form 10-K:

SCANA

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Goodwill

The Company considers amounts categorized by FERC as “acquisition adjustments” (with carrying values of $210 million re: PSNC Energy (gas distribution segment) and $20 million re: CGT (gas transmission segment)) to be goodwill. The Company tests these goodwill amounts for impairment annually as of January 1 each year, 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 the 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 evaluations of PSNC Energy, estimated fair value has been obtained from either an independent appraisal or from internally prepared cash flow and guideline company analyses using methodologies similar to those used by the appraiser, and with certain input data having been provided by the appraiser. 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.

1. Summary of Significant Accounting Policies, page 55

General

Please consider providing an accounting policy with regard to your income statement classification and presentation of revenues and expenses. Please tell us what consideration was given to utilizing a cost of service format for SCE&G. In this regard, we note you do not classify income taxes as an operating expense on your consolidated statements of income for your rate regulated utility SCE&G, although it appears income taxes are being recovered in rates.

Mr. Andrew Mew

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Response (SCANA and SCE&G): Neither the FERC, the SCPSC nor the North Carolina Utilities Commission require a particular utility format for the presentation of our consolidated financial statements prepared under generally accepted accounting principles. In the absence of such a requirement, we have elected to utilize a presentation format for consolidated income statements for each of SCANA and SEC&G which we believe provides the users meaningful information while following the rules contained in Regulation S-X. We believe that the majority of registrants in the utility industry utilize a similar commercial presentation format for their income statements.

We propose to include the following disclosure within our accounting policies in future annual filings:

SCANA

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Income statement presentation

In its consolidated statements of income, the Company presents the activities of its primary regulated and non-regulated businesses (including those activities of segments described in Note 12) within operating income, and it presents the activities of incidental non-utility and non-regulated activities within other income (expense).

SCE&G

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Income statement presentation

In its consolidated statements of income, SCE&G presents the activities of its primary regulated businesses (including those activities of segments described in Note 12) within operating income, and it presents the activities of incidental non-utility activities within other income (expense).

B. Basis of Accounting, page 55

7.	Please revise your disclosure to clarify which regulatory assets are included in your rate base. Further, please disclose the recovery period for those assets not earning a return. See FASB ASC 980-340-50-1.

Response (SCANA and SCE&G): Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities. We propose to modify footnote 1.B. in future filings as follows, to include this statement and the requested information regarding expected recovery periods of regulatory assets:

SCANA

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

B. Basis of Accounting

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 liabilities which are summarized in the

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following tables. Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	March 31,		December 31,
Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	173	$	173
Under-collections - electric fuel adjustment clause		45		55
Environmental remediation costs		27		26
Asset retirement obligations and related funding		283		279
Franchise agreements		49		50
Deferred employee benefit plan costs		325		325
Planned major maintenance		4		5
Other		75		72
Total Regulatory Assets	$	981	$	985

Regulatory Liabilities:
Accumulated deferred income taxes	$	30	$	30
Other asset removal costs		733		733
Storm damage reserve		45		44
Monetization of bankruptcy claim		40		40
Other		33		32
Total Regulatory Liabilities	$	881	$	879

Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Substantially all of these regulatory assets 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. These amounts are expected to be recovered in retail electric rates during the period May 2011 through April 2012. SCE&G is allowed to collect interest on the deferred balance through the recovery period.

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 14 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 95 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. These deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years.

Various other regulatory assets are expected to be recovered in rates over periods of up to 30 years.

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Other 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, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates. During the three months ended March 31, 2010 and 2009, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.

Planned major maintenance related to certain fossil hydro turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved through specific SCPSC orders. SCE&G is collecting $8.5 million annually, ending December 2013, through electric rates to offset turbine maintenance expenditures. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which will be amortized into operating revenue through the year 2024.

The SCPSC or the NCUC (collectively, state commissions) or the FERC have reviewed and approved, through specific orders, most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by a state commission or by FERC. In recording these 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. In addition, the Company has deferred in utility plant in service approximately $76.9 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of SCR technology at its Cope Station generating facility. See Note 7B. These costs are not currently being recovered, but are expected to be recovered through rates in future periods over the lives of the related properties. 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 adverse effect on the Company’s results of operations, liquidity or financial position in the period the write-off would be recorded.

SCE&G

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

B. Basis of Accounting

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, SCE&G has recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Substantially all of our regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.

	March 31,		December 31,
Millions of dollars	2010		2009
Regulatory Assets:
Accumulated deferred income taxes	$	167	$	167
Under collections – electric fuel adjustment clause		45		55
Environmental remediation costs		20		19
Asset retirement obligations and related funding		269		265
Franchise agreements		49		50
Deferred employee benefit plan costs		307		306
Planned major maintenance		4		5
Other		71		69
Total Regulatory Assets	$	932	$	936

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Regulatory Liabilities:
Accumulated deferred income taxes	$	28	$	29
Other asset removal costs		535		535
Storm damage reserve		45		44
Other		34		31
Total Regulatory Liabilities	$	642	$	639

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 . These amounts are expected to be recovered in retail electric rates during the period May 2011 through April 2012. SCE&G is allowed to collect interest on the deferred balance through the recovery period.

Various other regulatory assets are expected to be recovered in rates over periods of up to 30 years.

Other 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, certain transmission and distribution insurance premiums and certain tree trimming expenditures in excess of amounts included in base rates. During the three months ending March 31, 2010 and 2009, SCE&G applied costs of $0.8 million and $0.7 million, respectively, to the reserve.

The FERC or the SCPSC have reviewed and approved, through specific orders, most of the items shown as regulatory assets. Other regulatory assets include certain costs which have not been approved for recovery by the SCPSC or by FERC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied

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in rate orders received by SCE&G. In addition, SCE&G has deferred in utility plant in service approximately $76.9 million of unrecovered costs related to the Lake Murray backup dam project and $70.1 million of costs related to the installation of SCR technology at its Cope Station generating facility. See Note 7B. These costs are not currently being recovered, but are expected to be recovered through rates in future periods over the lives of the related properties. In the future, as a result of deregulation or other changes in the regulatory environment or changes in accounting requirements, SCE&G could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on SCE&G’s results of operations, liquidity or financial position in the period the write-off would be recorded.

8.	Please disclose a description of the regulatory treatment of your OPEB costs and the period over which any deferred amounts are expected to be recovered in rates. Refer to FASB ASC 980-715-50-1.

Response (SCANA and SCE&G): As described in response to comment 2 above, we have historically recovered other postretirement costs for our rate-regulated subsidiaries as they have been recorded under generally accepted accounting principles (e.g., as determined under SFAS 106). As such, and based upon guidance issued by FERC on March 29, 2007 (Docket No. A107-1-000), upon the implementation of SFAS 158 as of December 31, 2006, we recorded the amounts which otherwise would have been recorded within accumulated other comprehensive income to regulatory asset accounts. These amounts will be recovered in rates as such costs are amortized into actuarially determined postretirement amounts in the future, over the average service periods of participating employees.

We have included this disclosure within the proposed disclosure for future filings provided in response to comment 7 above.

3. Employee Benefit Plans and Equity Compensation Plan, page 62

Stock Based Compensation, page 67

Tell us if any of your unvested share-based payment awards have non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) when dividends are paid to common stockholders, irrespective of whether the award ultimately vests. Please be advised that such share-based awards are participating securities and should be included in the computation of basic EPS using the two-class method. Reference is made to FASB ASC 260-10-45-61A.

Response (SCANA and SCE&G): The Company’s share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest.

6. Common Equity, page 69.

10.	Tell us and disclose the circumstances in which SCE&G’s bond indenture could limit the payment of cash dividends on SCE&G’s common stock.

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Response (SCANA): SCE&G’s bond indenture dated April 1, 1993 states that SCE&G “will declare and pay dividends in cash or property on any shares of its common stock only either (1) out of its Surplus or (2) in case there shall be no Surplus, out of its net profits for the fiscal year in which the divided is declared and/or the preceding fiscal year.” At December 31, 2009, SCE&G’s Surplus (as defined in the indenture) totaled approximately $2.6 billion. For the dividend restrictions to apply, SCE&G would have to incur losses of approximately $2.6 billion, and it would have to incur a net loss in both the current and the preceding fiscal years. We believe the likelihood of such an occurrence is remote; as such, we believe that the current disclosure is appropriate.

Derivative Financial Instruments, page 72

11.	Please expand to disclose, identify and quantify the hybrid securities referred to on page 17 that SCANA would be required to redeem if the ratings declined below investment grade.

Response (SCANA): Please note that on March 3, 2010, we filed an amendment to our Form 10-K which removed the above statement (an inadvertent typographical mistake) from page 17. There is no such requirement to redeem the $150 million of Junior Subordinated Notes (hybrid securities) listed in footnote 4 to the financial statements.

11. Commitments and Contingencies, page 75

B. Environmental, page 76

12.	Please confirm for us environmental liabilities are evaluated independently from potential claims for recovery. In this regard, it is not appropriate to present the environmental liabilities net of potential recovery.

Response (SCANA and SCE&G): We confirm that our environmental liabilities are evaluated independently of any consideration of potential recoveries from others and that our liabilities are reported “gross,” with no offsetting of any potential recoveries. If and when recoveries are received, they are credited to the regulatory assets.

South Carolina Electric and Gas, page 99

Consolidated Balance Sheets, page 99

13.	Refer to the presentation of assets held in trust, net – nuclear decommissioning. Please explain what is netted against the assets of the trust. We note the disclosure beginning on page 106.

Response (SCANA and SCE&G): Trust assets at December 31, 2009, which include the cash surrender values of life insurance policies and a small amount of cash, are shown net of approximately $35 million of loans that are collateralized by the insurance policies. Additionally, an advance to the trust from SCE&G of approximately $27 million has been netted against these assets.

Mr. Andrew Mew

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Company Acknowledgement

SCANA and SCE&G acknowledge that (i) we are responsible for the adequacy and accuracy of the disclosure in our filings under the Exchange Act, (ii) staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to our filings, and (iii) we may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We appreciate your assistance in our compliance with the applicable disclosure requirements and in enhancing the overall disclosure of our filings. Should you have any further questions, please call me at 803-217-6017, or Jimmy Addison, our Senior Vice President and Chief Financial Officer, at 803-217-9391.

Very truly yours,

/s/James E. Swan, IV

James E. Swan, IV

Controller