RATE AND OTHER REGULATORY MATTERS

6 Months Ended

Jun. 30, 2011

RATE AND OTHER REGULATORY MATTERS

RATE AND OTHER REGULATORY MATTERS

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 is 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 and authorized SCE&G to adjust the cost of fuel component of its retail electric rates effective with the first billing cycle of May 2011.

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

In December 2009, SCE&G submitted to the FERC revised tariff sheets to change the network and point to point transmission rates under SCE&G’s OATT. This initial request, if approved, would result in an annual revenue increase of approximately $5.6 million. On February 26, 2010, the FERC accepted SCE&G’s initial filing and set the filing for hearing and settlement procedures.  In compliance with the OATT, on March 1, 2010 pursuant to an order issued by the FERC, SCE&G implemented, subject to refund, the proposed tariff sheets.   On May 12, 2011, SCE&G filed a motion to implement interim rates pending FERC action on a full settlement agreement, which the Chief Administrative Law Judge granted on May 13, 2011. On the same day, SCE&G filed a full settlement agreement.  As required by SCE&G’s protocols, on May 16, 2011, SCE&G submitted to the FERC as an informational filing its recalculated Annual Transmission Revenue Requirement or “Annual Update” which conforms to the settlement agreement, effective for the period June 1, 2011 through May 31, 2012.  The settlement agreement was certified as an uncontested settlement on June 30, 2011 and is pending final consideration by FERC.

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.  The revised schedule does not change the previously announced completion date for the New Units or the originally announced cost.

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, including contingencies, as approved by the SCPSC.

In May 2009, two intervenors filed separate appeals of the 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, is $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, does 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 reflects the removal of the contingency reserve and incorporates presently identifiable capital costs of $173.9 million, and by order dated May 16, 2011, the SCPSC approved the updated capital costs schedule as  outlined in the petition.

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%. In September 2009, the SCPSC approved SCE&G’s annual revised rate request under the BLRA which constituted a $22.5 million or 1.1% increase to retail electric rates. In October 2010, the SCPSC approved an increase of $47.3 million or 2.3%, under the BLRA for the annual revised rates adjustment filing. The new retail electric rates were effective for bills rendered on and after October 30, 2010.  On May 27, 2011, SCE&G filed with the SCPSC its annual request for revised rates under the BLRA seeking authorization to revise its retail electric rates so as to recover the costs of capital associated with the construction of the new nuclear units during the 12 months ended June 30, 2011.  If approved, SCE&G expects this request will constitute a $58.5 million or 2.7% increase to retail electric rates effective for bills rendered on or after October 30, 2011.

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.  On October 15, 2010, pursuant to the annual RSA filing, the SCPSC approved a decrease in retail natural gas rates of $10.4 million or approximately 2.1%.  The rate adjustment was effective with the first billing cycle of November 2010.  On June 15, 2011, SCE&G filed an application with the SCPSC requesting an increase in retail natural gas rates of $8.64 million or 2.14% under the terms of the RSA.  If approved, the new rates would become effective with the first billing cycle of November 2011.

SCE&G’s natural gas tariffs include a PGA 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 adjusts 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 2010, before the SCPSC. The SCPSC issued an order in December 2010 finding that SCE&G’s gas purchasing policies and practices during the review period of August 1, 2009, through July 31, 2010, were reasonable and prudent.  The next annual PGA hearing before the SCPSC has been scheduled for November 10, 2011.

In February 2011, the ORS submitted a request to the SCPSC to suspend SCE&G’s natural gas hedging program.  SCE&G responded in March 2011 indicating no objection to the ORS’s request.  The SCPSC issued an order directing staff to schedule an Oral Argument Information Briefing regarding this matter, which was held in April 2011.  In May 2011, the SCPSC directed its staff to schedule a hearing so that the SCPSC could receive testimony from electric and gas utilities concerning the market for natural gas and the need for natural gas hedging.  In June 2011, the ORS withdrew its petition requesting that the SCPSC suspend 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 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 modified 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 defers any over- or under-collections of the delivered cost of gas 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 2010, in connection with PSNC Energy’s 2010 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, 2010.

CGT

On April 29, 2011 CGT filed for a rate increase with the FERC.  The filing was in the form of a settlement agreement negotiated by CGT and its customers.  On July 5, 2011 the FERC approved the settlement agreement with minimal changes. The order approved the new rates to be effective November 1, 2011, as requested.

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.

	June 30,		December 31,
Millions of dollars	2011		2010
Regulatory Assets:
Accumulated deferred income taxes	$	210	$	210
Under-collections - electric fuel adjustment clause	59		25
Environmental remediation costs	31		32
AROs and related funding	310		298
Franchise agreements	42		45
Deferred employee benefit plan costs	321		326
Planned major maintenance	19		6
Deferred losses on interest rate derivatives	90		83
Other	46		36
Total Regulatory Assets	$	1,128	$	1,061
Regulatory Liabilities:
Accumulated deferred income taxes	$	25	$	26
Asset removal costs	804		780
Storm damage reserve	36		38
Monetization of bankruptcy claim	36		37
Deferred gains on interest rate derivatives	25		26
Other	5		6
Total Regulatory Liabilities	$	931	$	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 July 2012 through April 2013.  SCE&G is allowed to accrue interest on the 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 18 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 14 years, although recovery periods could become longer at the direction of the SCPSC.

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 collected $8.5 million annually through July 15, 2010, through electric rates, to offset 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 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.

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 six months ended June 30, 2011 and 2010, SCE&G applied costs of $1.8 million and $1.5 million, respectively, to the reserve.  Pursuant to the SCPSC’s July 2010 retail electric rate order approving an electric rate increase, SCE&G suspended collection of storm damage reserve funds 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.   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 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.