RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2013

Public Utilities Disclosure [Text Block]

RATE AND OTHER REGULATORY MATTERS

Rate Matters

Electric - Cost of Fuel

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 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.

This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing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 cost component prior to the last billing cycle of April 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, 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 with the first billing cycle of May 2013, and providing for the accrual of certain debt-related carrying costs on a portion of the undercollected balance of fuel costs. The SCPSC issued an order dated April 30, 2013, adopting and approving the settlement agreement and approving SCE&G's total fuel cost component.

Electric - Base Rates

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 (as discussed above), 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 and the order was not appealed.

The eWNA is designed to mitigate the effects of abnormal weather on residential and commercial customers' bills 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 the eWNA. The study was completed and filed with the SCPSC on June 28, 2013. In the study, SCE&G proposed that no adjustment or modification to the eWNA be made at this time. On November 1, 2013, the ORS filed a report with the SCPSC recommending that the eWNA be terminated with the last billing cycle for December 2013. SCE&G will be working with the ORS to address its recommendation. SCE&G cannot predict what action the SCPSC may take, if any.

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 retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. One of these units was retired in 2012, and its net carrying value is recorded in regulatory assets as unrecovered plant and is being amortized over its previously estimated remaining useful life. The net carrying value of the remaining units is included in Plant to be Retired, Net in the consolidated financial statements. In connection with their retirement, SCE&G expects to be allowed a recovery of and a return on the net carrying value of these remaining units 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. As discussed in Note 1, SCE&G approved a plan to accelerate the retirement of two of the units by the end of 2013 and has received SCPSC approval to record the net carrying value of these units in regulatory assets as unrecovered plant once they are retired.

SCE&G's DSM Programs for electric customers provide for an annual rider, approved by the SCPSC, to allow recovery of the costs and net lost revenue associated with the DSM Programs, along with an incentive for investing in such programs. SCE&G submits annual filings 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 became effective as indicated:



Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

In addition, the SCPSC approved the deferral of an additional $10.3 million of net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.

SCE&G's initial authorization to operate its DSM Programs expires November 30, 2013. On May 31, 2013, SCE&G filed a request with the SCPSC for approval to extend the operation of its portfolio of DSM Programs. SCE&G also requested approval to continue the use of the annual rate rider which (i) maintains the same terms and conditions currently in effect for the recovery of costs associated with the proposed DSM Programs, the net lost revenue associated with its DSM Programs, and an appropriate incentive for investing in such programs, and (ii) modifies the opt-out requirements for industrial customers. SCE&G requested that the proposed DSM Programs and rate rider authorization be effective December 1, 2013.

On October 21, 2013, SCE&G entered into a Settlement Agreement with ORS, Wal-Mart Stores East, LP, Sam’s East, Inc. and the SCEUC. Under the Settlement Agreement, the settling parties agreed that SCE&G’s revised portfolio of DSM Programs should be approved as filed by SCE&G. As for the annual rate rider, the settling parties agreed that SCE&G should be allowed to (i) continue to defer and amortize all prudently incurred costs for the DSM Programs over five years with carrying costs, (ii) calculate the net lost revenues component of the DSM Programs rider utilizing a rolling three year period of program history, and (iii) continue to recover a shared savings incentive, among other things. The settling parties also agreed that SCE&G’s DSM Programs should continue for six years. Two other parties in the case did not execute the Settlement Agreement. A public hearing on this matter was held on October 24, 2013, and the SCPSC's ruling is pending.

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. For further discussion of new nuclear construction matters, see Note 9.

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
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas

SCE&G

The RSA is designed to reduce the volatility of costs charged to customers by allowing for 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
2013	No change			-
2012	2.1	%	Increase	$7.5 million

On June 5, 2013, SCE&G submitted its annual RSA filing with the SCPSC for the 12-month period ending March 31, 2013. SCE&G earned a return on its gas distribution operations, after proforma adjustments, that is within the range of its allowable rate of return on common equity. The SCPSC approved SCE&G’s annual RSA filing on October 9, 2013, with no change in rates.

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 2012 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. SCE&G’s 2013 annual PGA hearing was held on November 7, 2013, and the SCPSC's ruling is pending.

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 September 2013, in connection with PSNC Energy's 2013 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, 2013.

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 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	September 30, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	254
Under-collections - electric fuel adjustment clause	52		66
Environmental remediation costs	42		44
AROs and related funding	359		319
Franchise agreements	32		36
Deferred employee benefit plan costs	319		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	93		70
Total Regulatory Assets	$	1,333	$	1,464



Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	718		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	30		32
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	1,007	$	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 26 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 90 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. In connection with the October 2013 RSA order, approximately $14 million of deferred pension costs for gas operations are to be recovered through utility rates over approximately 14 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 generally represent the unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

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 are being recovered through utility rates over periods up to approximately 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 previously estimated 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 - Cost of Fuel

Electric - Base Rates



Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

Electric – BLRA



Year	Action			Amount
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas



Year	Action			Amount
2013	No change			-
2012	2.1	%	Increase	$7.5 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	September 30, 2013		December 31, 2012
Regulatory Assets:
Accumulated deferred income taxes	$	248	$	248
Under collections – electric fuel adjustment clause	52		66
Environmental remediation costs	37		39
AROs and related funding	342		304
Franchise agreements	32		36
Deferred employee benefit plan costs	284		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	126		151
Deferred pollution control costs	37		38
Unrecovered plant	19		20
Other	82		64
Total Regulatory Assets	$	1,259	$	1,377



Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	522		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	203		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	781	$	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 26 years.

Deferred losses or gains on interest rate derivatives generally represent unrealized losses or gains from fair value adjustments and payments made or received upon termination of certain interest rate derivatives. These amounts are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years, unless, in the case of gains, such amounts are applied otherwise at the direction of regulators.

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.