RATE AND OTHER REGULATORY MATTERS

3 Months Ended

Mar. 31, 2013

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 component prior to April 1, 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 the first billing cycle of May 2013. By not adjusting SCE&G's base fuel component, the settlement also provided for carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC approved this settlement agreement on April 10, 2013.

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, 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 reduce volatility of costs charged to residential and commercial customers due to abnormal weather 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 eWNA by June 30, 2013, which may be used to modify or terminate eWNA in the future.

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 intends to retire by 2018, subject to future developments in environmental regulations, among other matters. The net carrying value of a unit that has been retired is recorded in regulatory assets as unrecovered plant and is being amortized over its original remaining useful life as further described below. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. SCE&G plans to request recovery of and a return on the net carrying value of these remaining units in future rate proceedings in connection with their retirement, and expects that such deferred amounts will be recovered 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.

SCE&G's DSM Programs for electric customers provide for 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 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 went into effect as indicated below:



Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

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. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

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:



Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 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 first billing cycle of November in the years indicated:



Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

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.

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 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.



Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	75		66
Environmental remediation costs	43		44
AROs and related funding	324		319
Franchise agreements	34		36
Deferred employee benefit plan costs	452		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	70		70
Total Regulatory Assets	$	1,451	$	1,464



Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	701		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	31		32
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	917	$	882

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 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. 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 will be 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.

SCEG

Rate Matters [Line Items]

Public Utilities Disclosure [Text Block]


	RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric



Year	Effective	Amount
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

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. In April 2013, the SCPSC approved SCE&G's request to update its rider as modified by the agreement between ORS and SCE&G.

Electric – BLRA



Year	Action			Amount
2012	2.3	%	Increase	$52.1 million
2011	2.4	%	Increase	$52.8 million

Gas



Year	Action			Amount
2012	2.1	%	Increase	$7.5 million
2011	2.1	%	Increase	$8.6 million

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.



Millions of dollars	March 31, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	75		66
Environmental remediation costs	38		39
AROs and related funding	307		304
Franchise agreements	34		36
Deferred employee benefit plan costs	399		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	141		151
Deferred pollution control costs	38		38
Unrecovered plant	20		20
Other	65		64
Total Regulatory Assets	$	1,365	$	1,377



Regulatory Liabilities:
Accumulated deferred income taxes	$	20	$	21
Asset removal costs	512		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	137		110
Planned major maintenance	1		—
Total Regulatory Liabilities	$	697	$	665

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 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.