RATE AND OTHER REGULATORY MATTERS

12 Months Ended

Dec. 31, 2013

Schedule of Regulatory Assets and Liabilities [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 actual under-collected balance of base fuel and variable environmental costs as of April 30, 2012, or $80.6 million, over a twelve 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This April 2012 order was superseded, in part, by a December 2012 rate order in which the SCPSC authorized SCE&G to reduce the base fuel cost component of its retail electric rates and, in doing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. In March 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 under-collected 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. A public hearing for the annual review of base rates for fuel costs has been scheduled for April 3, 2014.

Pursuant to a November 2013 SCPSC accounting order, the Company's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. See also Note 6.

Electric - Base Rates

In October 2013, SCE&G received an accounting order from the SCPSC directing it to remove from rate base deferred income tax assets arising from capital expenditures related to the New Units and to accrue carrying costs (recorded as a regulatory asset) on those amounts during periods in which they are not included in rate base. Such carrying costs are determined at SCE&G’s weighted average long-term borrowing rate, and during 2013, $2.9 million of such carrying costs were accrued within other income. SCE&G anticipates that when the New Units are placed in service and accelerated tax deprecation is recognized on them, these deferred income tax assets will decline. When these assets are fully offset by related deferred income tax liabilities, the carrying cost accruals will cease, and the regulatory asset will begin to be amortized.

In December 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. In February 2013, the SCPSC denied the SCEUC's petition for rehearing and the denial was not appealed.

The eWNA was designed to mitigate the effects of abnormal weather on residential and commercial customers' bills and had been in use since August 2010. In connection with the December 2012 order, SCE&G agreed to perform a study of alternative structures for eWNA. 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. On November 26, 2013, SCE&G, ORS and certain other parties filed a joint petition with the SCPSC requesting, among other things, that the SCPSC discontinue the eWNA effective with bills rendered on or after the first billing cycle of January 2014. On December 20, 2013, the SCPSC granted the relief requested in the joint petition.

In connection with the above termination of the eWNA program effective December 31, 2013, electric revenues were reduced to reverse the prior accrual of an under-collected balance of $8.5 million. Pursuant to the SCPSC accounting order granting the above relief and terminating the eWNA, such revenue reduction was fully offset by the recognition within other income of $8.5 million of gains realized upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on a variety of factors, including customer energy demands, EPA regulations, reserve margins and fuel costs. SCE&G's 2012 IRP identified six coal-fired units that SCE&G has subsequently 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 two others were retired in the fourth quarter of 2013. The net carrying value of these retired units is recorded in regulatory assets as unrecovered plant and is being amortized over the units' previously estimated remaining useful lives as approved by the SCPSC. 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.

In a July 2010 order, the SCPSC 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. These tax credits were fully amortized in 2012.

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 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 went into effect as indicated below:



Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

Other activity related to SCE&G’s DSM Programs is as follows:


•	In May 2013 the SCPSC ordered the deferral of one-half of the net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.


•	In November 2013 the SCPSC approved SCE&G’s continued use of DSM programs for another six years, including approval of the rate rider mechanism and a revised portfolio of DSM programs.

•

In January 2014 SCE&G submitted its annual DSM Programs filing to the SCPSC, which included, among other things, a request to (1) recover one-half of the balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2014 and to recover the remaining balance of allowable costs beginning with bills rendered on and after the first billing cycle of May 2015, (2) utilize approximately $17.8 million of the gains from the recent settlement of certain interest rate derivative instruments to offset a portion of the net lost revenues component of SCE&G’s DSM Programs rider, and (3) apply $5 million of its storm damage reserve and a portion of the gains from the recent settlement of certain interest rate derivative instruments, currently estimated to be $5.5 million, to the remaining balance of deferred net lost revenue as of April 30, 2014, deferred within regulatory assets resulting from the May 2013 order previously described.

Electric - BLRA

In May 2011, the SCPSC approved an updated capital cost schedule sought by SCE&G that, among other matters, incorporated then-identifiable additional capital costs of $173.9 million (SCE&G's portion in 2007 dollars).

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 following years:



Year	Increase	Amount
2013	2.90%	$	67.2	million
2012	2.30%	$	52.1	million
2011	2.40%	$	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 following years:



Year	Action			Amount
2013	No change
2012	2.10	%	Increase	$	7.5	million
2011	2.10	%	Increase	$	8.6	million

SCE&G's natural gas tariffs include a PGA 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual reviews conducted for each of the 12-month periods ended July 31, 2013 and 2012 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each review period 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 2013, in connection with PSNC Energy's 2013 Annual Prudence Review, the NCUC issued an order finding that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2013.

During the third quarter of 2013, the State of North Carolina passed legislation that makes changes to statutes covering gross receipts, sales and use, excise, franchise and income taxes. In the fourth quarter, in response to this legislation, the NCUC initiated a proceeding to investigate how it should proceed in response to the enactment of such legislation. Because the investigation was not completed before January 1, 2014, the NCUC issued an order notifying utilities that the incremental revenue requirement impact associated with the change in the level of state income tax expense included in each utility’s cost of service would be deemed to be collected on a provisional basis (subject to refund) beginning January 1, 2014.

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. Other than unrecovered plant, 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	2013		2012
Regulatory Assets:
Accumulated deferred income taxes	$	259	$	254
Under-collections—electric fuel adjustment clause	18		66
Environmental remediation costs	41		44
AROs and related funding	368		319
Franchise agreements	31		36
Deferred employee benefit plan costs	238		460
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	124		151
Deferred pollution control costs	37		38
Unrecovered plant	145		20
DSM Programs	51		27
Other	48		43
Total Regulatory Assets	$	1,360	$	1,464



Regulatory Liabilities:
Accumulated deferred income taxes	$	24	$	21
Asset removal costs	695		692
Storm damage reserve	27		27
Monetization of bankruptcy claim	29		32
Deferred gains on interest rate derivatives	181		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	966	$	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 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 sites currently or formerly owned by the Company, and 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 related to generation, transmission and distribution properties, including gas pipelines. 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 a 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 being 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 being 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 such 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 collects and accrues $16.8 million annually for nuclear-related refueling charges.

Deferred losses or gains on interest rate derivatives represent (i) the effective portions of changes in fair value and payments made or received upon settlement of certain interest rate derivatives designated as cash flow hedges and (ii) the changes in fair value and payments received upon settlement of certain other interest rate derivatives not so designated. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt, up to approximately 30 years. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.

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 are being recovered through utility rates over periods up to 30 years.

Unrecovered plant represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. Pursuant to SCPSC approval, SCE&G is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives, or up to approximately 14 years. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represents deferred costs and certain unrecovered lost revenue associated with SCE&G’s Demand Side Management programs. Deferred costs are currently being recovered over 5 years through a SCPSC approved rider. Unrecovered lost revenue is to be recovered over periods not to exceed 24 months from date of deferral. See Rate Matters - Electric Base Rates above for details regarding a 2014 filing with the SCPSC regarding recovery of these deferred costs and unrecovered lost revenue.

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 non-legal obligation to remove 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 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 specifically 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.

SCE&G

Rate Matters [Line Items]

Schedule of Regulatory Assets and Liabilities [Text Block]

RATE AND OTHER REGULATORY MATTERS

Electric - Cost of Fuel

Pursuant to a November 2013 SCPSC accounting order, Consolidated SCE&G's electric revenue for 2013 was reduced for adjustments to the fuel cost component and related under-collected fuel balance of $41.6 million. Such adjustments are fully offset by the recognition within other income, also pursuant to that accounting order, of gains realized upon the settlement of certain interest rate derivatives which had been entered into in anticipation of the issuance of long-term debt, which gains had been deferred as a regulatory liability. See also Note 6.

Electric - Base Rates



Year	Effective	Amount
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million
2011	First billing cycle of June	$7.0 million

Other activity related to SCE&G’s DSM Programs is as follows:


•	In May 2013 the SCPSC ordered the deferral of one-half of the net lost revenues and provided for their recovery over a 12-month period beginning with the first billing cycle in May 2014.


•	In November 2013 the SCPSC approved SCE&G’s continued use of DSM programs for another six years, including approval of the rate rider mechanism and a revised portfolio of DSM programs.

•

Electric - BLRA



Year	Increase	Amount
2013	2.90%	$	67.2	million
2012	2.30%	$	52.1	million
2011	2.40%	$	52.8	million

Gas



Year	Action			Amount
2013	No change
2012	2.10	%	Increase	$	7.5	million
2011	2.10	%	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. Other than unrecovered plant, 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	2013		2012
Regulatory Assets:
Accumulated deferred income taxes	$	256	$	248
Under-collections-electric fuel adjustment clause	18		66
Environmental remediation costs	37		39
AROs and related funding	350		304
Franchise agreements	31		36
Deferred employee benefit plan costs	215		405
Planned major maintenance	—		6
Deferred losses on interest rate derivatives	124		151
Deferred pollution control costs	37		38
Unrecovered Plant	145		20
DSM Programs	51		27
Other	39		37
Total Regulatory Assets	$	1,303	$	1,377



Regulatory Liabilities:
Accumulated deferred income taxes	$	19	$	21
Asset removal costs	495		507
Storm damage reserve	27		27
Deferred gains on interest rate derivatives	181		110
Planned major maintenance	10		—
Total Regulatory Liabilities	$	732	$	665

Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G and are expected to be recovered over periods of up to approximately 26 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 non-legal obligation to remove 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 specifically 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.