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RATE AND OTHER REGULATORY MATTERS

12 Months Ended

Dec. 31, 2011

2. RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

SCE&G’s retail electric rates are established in part by using 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. Effective with the first billing cycle of May 2010, the SCPSC approved a settlement agreement authorizing SCE&G to decrease the fuel cost portion of its electric rates. The settlement agreement incorporated SCE&G’s proposal to accelerate the recognition of $17.4 million of previously deferred state income tax credits and record an offsetting reduction to the recovery of fuel costs. In addition, SCE&G agreed to defer recovery of its actual undercollected base fuel costs as of April 30, 2010 until May 2011. SCE&G was allowed to charge and accrue carrying costs monthly on the actual base fuel costs undercollected balance as of the end of each month during this deferral period. In February 2011, SCE&G requested authorization to increase the cost of fuel component of its retail electric rates to be effective with the first billing cycle of May 2011. On March 17, 2011, SCE&G, ORS and SCEUC entered into a settlement agreement in which SCE&G agreed to recover its actual base fuel under-collected balance as of April 30, 2011 over a two-year period commencing with the first billing cycle of May 2011. The settlement agreement also provided that SCE&G would be allowed to charge and accrue carrying costs monthly on the deferred balance. By order dated April 26, 2011, the SCPSC approved the settlement agreement. In February 2012, SCE&G requested authorization to decrease the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2012. The next annual hearing to review base rates for fuel costs is scheduled for March 22, 2012.

On July 15, 2010, the SCPSC issued an order approving a 4.88% overall increase in SCE&G’s retail electric base rates and authorized an allowed return on common equity of 10.7%. Among other things, the SCPSC’s order (1) included implementation of an eWNA for SCE&G’s electric customers, which began in August 2010, (2) provided for a $25 million credit, over one year, to SCE&G’s customers to be offset by amortization of weather-related revenues which were deferred in the first quarter of 2010 pursuant to a stipulation between SCE&G and the ORS, (3) provided for a $48.7 million credit to SCE&G’s customers over two years to be offset by accelerated recognition of previously deferred state income tax credits and (4) provided for the recovery of certain federally-mandated capital expenditures that had been included in utility plant but were not being depreciated.

On July 15, 2010, the SCPSC issued an order approving the implementation by SCE&G of certain DSM Programs, including the establishment of an annual rider to allow recovery of the costs and lost net margin revenue associated with DSM Programs, along with an incentive for investing in such programs. The SCPSC’s order approved various settlement agreements among SCE&G, the ORS and other intervening parties. On July 27, 2010, SCE&G filed the rate rider tariff sheet for DSM Programs with the SCPSC. The tariff rider was applied to bills rendered on or after October 30, 2010. The order requires that SCE&G submit annual filings to the SCPSC regarding the DSM Programs, net lost revenues, program costs, incentives and net program benefits. In January 2011, SCE&G submitted to the SCPSC its annual update on DSM Programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net margin revenue, and the approved shared savings incentive for investing in such DSM Programs. By order dated May 24, 2011, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates for DSM Programs as set forth in its petition. The increase became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC its annual update on DSM programs. Included in the filing was a petition to update the rate rider to provide for the recovery of costs, lost net revenue, and the approved shared savings incentive for investing in such DSM Programs.

Electric - BLRA

In January 2010, the SCPSC approved SCE&G’s request for an order pursuant to the BLRA to approve an updated construction and capital cost schedule for the construction of two new nuclear generating units at Summer Station. The updated schedule provides details of the construction and capital cost schedule beyond what was proposed and included in the original BLRA filing described below.

In February 2009, the SCPSC approved SCE&G’s combined application pursuant to the BLRA seeking a certificate of environmental compatibility and public convenience and necessity and for a base load review order relating to the proposed construction and operation by SCE&G and Santee Cooper of the New Units at Summer Station. Under the BLRA, the SCPSC conducted a full pre-construction prudency review of the proposed units and the engineering, procurement, and construction contract under which they are being built. The SCPSC prudency finding is binding on all future related rate proceedings so long as the construction proceeds in accordance with schedules, estimates and projections, as approved by the SCPSC.

In May 2009, two intervenors filed separate appeals of the SCPSC order with the South Carolina Supreme Court. With regard to the first appeal, which challenged the SCPSC’s prudency finding, the South Carolina Supreme Court issued an opinion on April 26, 2010, affirming the decision of the SCPSC. As for the second appeal, the South Carolina Supreme Court reversed the SCPSC’s decision to allow SCE&G to include a pre-approved cost contingency fund and associated inflation (contingency reserve) as part of its anticipated capital costs allowed under the BLRA. SCE&G’s share of the project, as originally approved by the SCPSC, was $4.5 billion in 2007 dollars. Approximately $438 million represented contingency costs associated with the project. Without the pre-approved contingency reserve, SCE&G must seek SCPSC approval for the recovery of any additional capital costs. The Court’s ruling, however, did not affect the project schedule or disturb the SCPSC’s issuance of a certificate of environmental compatibility and public convenience and necessity, which is required to construct the New Units. On November 15, 2010, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost schedule that reflected the removal of the contingency reserve and incorporated then identifiable capital costs of $173.9 million (in 2007 dollars), and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as outlined in the petition.

On February 29, 2012, SCE&G filed a petition with the SCPSC seeking an order approving a further updated capital cost and construction schedule that incorporates additional identifiable capital costs of approximately $6 million (SCE&G’s portion in 2007 dollars) related to new federal healthcare laws, information security measures and certain minor design modifications. That petition also includes increased capital costs of approximately $12 million (SCE&G’s portion in 2007 dollars) related to transmission infrastructure. Finally, that petition includes amounts of approximately $137 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, facilities and information technology systems required to support the New Units and their personnel. Future petitions would be filed for any costs arising from the resolution of the commercial claims discussed in Note 1 to the consolidated financial statements (e.g., 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).

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%. The SCPSC has approved the following rate changes under the BLRA effective for bills rendered on and after October 30 in the following years:

Year	Increase		Amount
2011	2.4	%	$	52.8 million
2010	2.3	%	$	47.3 million
2009	1.1	%	$	22.5 million

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 billing cycle of November in the following years:

Year	Action			Amount
2011	2.1	%	Increase	$	8.6 million
2010	2.1	%	Decrease	$	10.4 million
2009	2.5	%	Increase	$	13.0 million

SCE&G’s natural gas tariffs include a PGA clause that provides for the recovery of actual gas costs incurred, including costs related to hedging natural gas purchasing activities. 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 conducted in November 2011 before the SCPSC. The SCPSC issued an order in January 2012 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2010 through July 31, 2011, were reasonable and prudent and authorized the suspension of SCE&G’s natural gas hedging program.

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 it 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 adjusted periodically 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-collections 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 January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in February 2012.

In December 2011, in connection with PSNC Energy’s 2011 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, 2011. On February 2, 2012, the Public Staff of the NCUC filed a motion requesting the NCUC reconsider and modify its order by reassigning certain charges (totaling approximately $0.4 million) from the cost of gas. PSNC Energy cannot predict the outcome of this matter, but the Company does not believe it will have a material effect on the Company’s results of operations, cash flows, or financial condition.

In October 2011, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2011. In October 2010, the NCUC approved a 12.5 cent per therm decrease in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in November 2010. In February 2010, the NCUC approved a ten cent per therm increase in the cost of gas component of PSNC Energy’s rates. The rate adjustment was effective with the first billing cycle in March 2010.

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 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.

	December 31,
Millions of dollars	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	243	$	210
Under-collections—electric fuel adjustment clause	28		25
Environmental remediation costs	30		32
AROs and related funding	316		298
Franchise agreements	40		45
Deferred employee benefit plan costs	392		326
Planned major maintenance	6		6
Deferred losses on interest rate derivatives	154		83
Deferred pollution control costs	25		13
Other	45		23
Total Regulatory Assets	$	1,279	$	1,061
Regulatory Liabilities:
Accumulated deferred income taxes	$	23	$	26
Asset removal costs	662		780
Storm damage reserve	32		38
Monetization of bankruptcy claim	34		37
Deferred gains on interest rate derivatives	24		26
Other	3		6
Total Regulatory Liabilities	$	778	$	913

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 which are expected to be recovered in retail electric rates in future periods. These amounts are expected to be recovered in retail electric rates during the period January 2013 through April 2013. SCE&G is allowed to recover interest on actual base fuel deferred balances 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 23 years.

ARO and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Summer Station Unit 1 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. A significant majority of these deferred costs are expected to be recovered through utility rates over average service periods of participating employees, or up to approximately 14 years, although recovery periods could become longer at the election of the SCPSC.

Planned major maintenance related to certain fossil fuel turbine/generation equipment and nuclear refueling outages is accrued in periods other than when incurred, as approved pursuant to specific SCPSC orders. SCE&G collected $8.5 million annually through July 15, 2010, through electric rates, to offset certain turbine maintenance expenditures. After July 15, 2010, SCE&G began collecting $18.4 million annually for this purpose. Nuclear refueling charges are accrued during each 18-month refueling outage cycle as a component of cost of service.

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 swaps 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 installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.4 million at December 31, 2011 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station, for which the Company will seek recovery in future proceedings before the SCPSC. SCE&G is allowed to accrue interest on deferred costs related to Wateree Station.

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, certain transmission and distribution insurance premiums and certain tree trimming and vegetation management expenditures in excess of amounts included in base rates. During the years ended December 31, 2011 and 2010, SCE&G applied costs of $6.4 million and $9.5 million, respectively, to the reserve. Pursuant to SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of the storm damage reserve indefinitely pending future SCPSC action.

The monetization of bankruptcy claim represents proceeds from the sale of a bankruptcy claim which are expected to be amortized into operating revenue through February 2024.

The SCPSC, the NCUC or the FERC have 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 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. 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.