RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2012

Public Utilities Disclosure [Text Block]

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. In February 2012, SCE&G requested authorization to decrease the total fuel cost component of its retail electric rates to be effective the first billing cycle of May 2012. In March 2012, SCE&G, the ORS and SCEUC entered into a settlement agreement 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 in the next rate period beginning with the first billing cycle of May 2012. In April 2012, the SCPSC approved the settlement agreement and ruled among other matters that SCE&G's fuel purchasing practices and policies were reasonable and prudent for the period January 1, 2011, through December 31, 201l.

On June 29, 2012, SCE&G filed an application with the SCPSC requesting an increase in retail revenues of approximately $151.5 million or 6.61%. SCE&G also requested a mid-period reduction to the cost of fuel component in rates, as well as a reduction in the DSM component rider to retail rates. These adjustments will reduce the overall revenue increase requested to 3.75%. In addition, SCE&G requested recovery of and a return on the net carrying value of certain generating plant assets described below. SCE&G has requested that the proposed increase be effective January 1, 2013. A public hearing on this matter has been scheduled to begin on November 26, 2012; a decision from the SCPSC is expected in late December 2012.

On May 30, 2012, SCE&G filed its annual 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 plans to retire by 2018, subject to future developments in environmental regulations, among other matters. These units have an aggregate generating capacity (summer 2012) of 730 MW. The net carrying value of these units totaled $418 million at September 30, 2012, and is identified as Plant to be Retired, Net in the condensed consolidated financial statements. Included in this amount is approximately $23 million related to a unit that SCE&G plans to retire by the end of 2012. In its June 29, 2012 application with the SCPSC, described above, SCE&G has requested recovery of and a return on the net carrying value of this unit. SCE&G plans to make similar requests for the remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered through rates. SCE&G continues to depreciate these units using composite straight-line rates approved by the SCPSC while the assets are in use.

In July 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%. The SCPSC’s order adopted various stipulations among SCE&G, the ORS and other intervening parties. Among other matters, the SCPSC’s order 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.

The SCPSC has approved DSM Programs for SCE&G's customers, including the establishment of an annual rider, approved by the SCPSC, to allow recovery of the costs and lost net margin revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G must 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 an annual update on DSM Programs and rate rider. In May 2011, the SCPSC approved the updated rate rider, which became effective the first billing cycle of June 2011. In January 2012, SCE&G submitted to the SCPSC another annual update on DSM Programs and rate rider. In April 2012, the SCPSC approved the updated rate rider and authorized SCE&G to increase its rates to recover approximately $19.6 million related to DSM Programs as set forth in its petition. The increase became effective the first billing cycle of May 2012.

Electric – BLRA

The SCPSC has 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 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable capital costs of $173.9 million (SCE&G's portion in 2007 dollars). On May 15, 2012, SCE&G filed a petition with the SCPSC seeking an order approving an updated capital cost and construction schedule for the New Units. This petition replaced a February 29, 2012 petition, which was withdrawn. The updated capital cost schedule in this petition reflects an increase of $283 million (SCE&G's portion in 2007 dollars) over the cost approved in the May 2011 order. This petition includes 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; 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, this petition includes 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 (which claims are discussed in Note 9). The SCPSC approved the updated construction schedule and substantially all of the capital costs in this petition on November 7, 2012.

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 following years:



Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years:



Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 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. The next annual PGA hearing is scheduled for November 8, 2012.

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 March 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 April 2012. In addition, in January 2012, the NCUC approved a five cent per therm decrease in the cost of gas component of PSNC Energy's rates. This rate adjustment was effective with the first billing cycle in February 2012.

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 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.



Millions of dollars	September 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	244	$	243
Under-collections - electric fuel adjustment clause	—		28
Environmental remediation costs	44		30
AROs and related funding	321		316
Franchise agreements	37		40
Deferred employee benefit plan costs	390		392
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	60		45
Total Regulatory Assets	$	1,290	$	1,279



Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	688		662
Storm damage reserve	27		32
Monetization of bankruptcy claim	32		34
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	2		1
Total Regulatory Liabilities	$	863	$	778

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 expected to be recovered in retail electric rates over periods exceeding 12 months.

Environmental remediation costs represent costs associated with the assessment and clean-up of MGP sites currently or formerly owned by the Company. These regulatory assets are expected to be recovered over periods of up to approximately 28 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. 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 12 years.

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 pursuant to specific SCPSC orders. SCE&G collects $18.4 million annually for fossil hydro turbine/generation equipment maintenance. 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 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 installation of scrubbers at Wateree and Williams Stations pursuant to specific regulatory orders. Such costs related to Williams Station amount to $9.1 million at September 30, 2012 and are being recovered through utility rates over approximately 30 years. The remaining costs relate to Wateree Station and SCE&G is allowed to accrue interest on these deferred costs until such costs are approved for recovery by the SCPSC.

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 nine months ended September 30, 2012 and 2011, SCE&G applied costs of $4.6 million and $3.6 million, respectively, to the reserve. Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended storm damage reserve collection through rates indefinitely.

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 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 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.

SCE&G

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric

Electric – BLRA



Year	Increase	Amount (Millions)
2012	2.3%	$52.1
2011	2.4%	$52.8

Gas



Year	Action			Amount (Millions)
2012	2.1	%	Increase	$7.5
2011	2.1	%	Increase	$8.6

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 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.



Millions of dollars	September 30, 2012		December 31, 2011
Regulatory Assets:
Accumulated deferred income taxes	$	238	$	238
Under collections – electric fuel adjustment clause	—		28
Environmental remediation costs	39		25
AROs and related funding	305		301
Franchise agreements	37		40
Deferred employee benefit plan costs	347		348
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	159		154
Deferred pollution control costs	35		25
Other	56		41
Total Regulatory Assets	$	1,216	$	1,206



Regulatory Liabilities:
Accumulated deferred income taxes	$	21	$	23
Asset removal costs	507		493
Storm damage reserve	27		32
Deferred gains on interest rate derivatives	85		26
Planned major maintenance	8		—
Other	1		1
Total Regulatory Liabilities	$	649	$	575

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 28 years.

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 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 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.