RATE AND OTHER REGULATORY MATTERS

9 Months Ended

Sep. 30, 2014

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 connection with its annual review of base rates for fuel costs, and by order dated April 30, 2013, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to reduce its environmental fuel cost component effective with the first billing cycle of May 2013. The order also provided for the accrual of certain debt-related carrying costs on a portion of SCE&G's under-collected balance of fuel costs, and approved SCE&G's total fuel cost component.

By order dated April 29, 2014, the SCPSC approved a settlement agreement among SCE&G, the ORS and the SCEUC in which SCE&G agreed to increase its base fuel cost component by approximately $10.3 million for the 12-month period beginning with the first billing cycle of May 2014. The SCPSC's order also provided for, among other things, the application of approximately $46 million in deferred gains from the late 2013 settlement of certain interest rate swaps, previously recorded as regulatory liabilities, to reduce the under-collected balance of fuel costs in April 2014 and the accrual of certain debt-related carrying costs on its under-collected balance of base fuel costs during the period May 1, 2014 through April 30, 2015.

The increase to the base fuel cost component was offset by a reduction in SCE&G’s rate rider related to pension costs, which was approved by the SCPSC in March 2014. The reduction was requested by SCE&G as a result of lower net periodic benefit costs in 2014. See also Note 8.

The cost of fuel includes amounts paid by SCE&G pursuant to the Nuclear Waste Act for the disposal of spent nuclear fuel. As a result of a November 2013 decision by the Court of Appeals, the DOE set the Nuclear Waste Act fee to zero effective May 16, 2014. By order of the SCPSC, the impact of this action will be considered in future cost of fuel rate adjustments.

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. During the three and nine months ended September 30, 2014, $1.6 million and $4.1 million, respectively, 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 deferred income tax 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.

SCE&G files an IRP with the SCPSC annually which evaluates future electric generation needs based on several 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 retired or intends to retire by 2018, subject to future developments in environmental regulations, among other matters. Three of these units had been retired by December 31, 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. See also Note 1.

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 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 margin revenues, program costs, incentives and net program benefits. The SCPSC approved the following rate increases pursuant to annual DSM Programs filings, which went into effect as indicated:



Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

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


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

•

In April 2014 the SCPSC approved SCE&G’s 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 late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described.

•

In addition, in April 2014 the SCPSC, upon recommendation of the ORS, reduced by 25%, or $6.6 million, the amount of net lost margin revenues SCE&G expects to experience over the 12-month period beginning with the first billing cycle of May 2014, and ordered that the $6.6 million be applied to decrease the amount of program costs deferred for recovery. Actual net lost margin revenues not collected in the current DSM Programs rate rider are subject to true up in the following program year.

Electric – BLRA

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 retail electric rate changes under the BLRA effective for bills rendered on and after October 30 in the years indicated:



Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
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
2014	0.6	%	Decrease	$2.6 million
2013	No change			-
2012	2.1	%	Increase	$7.5 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, and its gas purchasing policies and practices are reviewed annually by the SCPSC. The annual review conducted for the 12-month period ended July 31, 2013 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during the review period were reasonable and prudent. SCE&G's 2014 annual PGA hearing was held on November 6, 2014 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 2014, in connection with PSNC Energy's 2014 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, 2014.

During the third quarter of 2013, the State of North Carolina passed legislation that changed statutes covering gross receipts, sales and use, excise, franchise and income taxes. On December 6, 2013, 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. On May 13, 2014, the NCUC issued an order requiring utilities to adjust rates to reflect changes in the state corporate income tax rate and to file a proposal to refund amounts collected on a provisional basis. Pursuant to the order, PSNC Energy lowered its rates effective July 1, 2014, and notwithstanding a subsequent reversal of the NCUC's order, PSNC Energy expects to refund amounts collected on a provisional basis through the normal operation of the Rider D rate mechanism. At September 30, 2014, these amounts were not material.

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 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, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	254	$	259
Under-collections - electric fuel adjustment clause	38		18
Environmental remediation costs	40		41
AROs and related funding	378		368
Franchise agreements	27		31
Deferred employee benefit plan costs	222		238
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	52		48
Total Regulatory Assets	$	1,564	$	1,360



Regulatory Liabilities:
Accumulated deferred income taxes	$	22	$	24
Asset removal costs	719		695
Storm damage reserve	6		27
Monetization of bankruptcy claim	27		29
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	857	$	966

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 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, distribution and other 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 an SCPSC order, SCE&G is recovering these amounts through cost of service rates through 2021.

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, as well as costs deferred pursuant to specific SCPSC regulatory orders. In connection with a 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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance, and collects and accrues $17.2 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 made or 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 over periods up to approximately 50 years except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC. Also, in 2014, as discussed at Rate Matters - Electric - Cost of Fuel and Rate Matters - Electric - Base Rates, certain of these deferred amounts were applied to offset under-collected fuel balances and unrecorded net lost margin revenues related to DSM Programs.

Deferred pollution control costs represent deferred depreciation and operating and maintenance costs associated with the scrubbers installed at certain coal-fired generating plants pursuant to specific regulatory orders. Such costs are being recovered through utility rates through 2045.

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 through approximately 2025. Unamortized amounts are included in rate base and are earning a current return.

DSM Programs represent deferred costs associated with such programs. As a result of an April 2014 SCPSC order, deferred costs are currently being recovered over approximately ten years through an approved rate rider. See Rate Matters - Electric - Base Rates above for details regarding the 2014 filing with the SCPSC regarding recovery of these deferred costs.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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. In 2014, $16.2 million of the reserve was applied to offset incremental storm damage costs. Also, as discussed at Rate Matters - Electric - Base Rates, in April 2014 $5.0 million of the reserve was applied to offset unrecovered net lost margin revenues related to DSM Programs.

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

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 margin revenues 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 margin revenues, program costs, incentives and net program benefits. The SCPSC approved the following rate increases pursuant to annual DSM Programs filings, which went into effect as indicated:



Year	Effective	Amount
2014	First billing cycle of May	$15.4 million
2013	First billing cycle of May	$16.9 million
2012	First billing cycle of May	$19.6 million

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


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

•

In April 2014 the SCPSC approved SCE&G’s 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 late 2013 settlement of certain interest rate derivative instruments, previously deferred as regulatory liabilities, to offset a portion of the net lost margin revenues component of SCE&G’s DSM Programs rider, and (3) apply $5.0 million of its storm damage reserve and $5.0 million of the gains from the settlement of certain interest rate derivative instruments, to the remaining balance of deferred net lost margin revenues as of April 30, 2014, which had been deferred within regulatory assets resulting from the May 2013 order previously described.

•

Electric – BLRA



Year	Action			Amount
2014	2.8	%	Increase	$66.2 million
2013	2.9	%	Increase	$67.2 million
2012	2.3	%	Increase	$52.1 million

Gas



Year	Action			Amount
2014	0.6	%	Decrease	$2.6 million
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. Other than unrecovered plant, 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, 2014		December 31, 2013
Regulatory Assets:
Accumulated deferred income taxes	$	250	$	256
Under collections – electric fuel adjustment clause	38		18
Environmental remediation costs	36		37
AROs and related funding	359		350
Franchise agreements	27		31
Deferred employee benefit plan costs	201		215
Planned major maintenance	7		—
Deferred losses on interest rate derivatives	318		124
Deferred pollution control costs	36		37
Unrecovered plant	139		145
DSM Programs	53		51
Other	42		39
Total Regulatory Assets	$	1,506	$	1,303



Regulatory Liabilities:
Accumulated deferred income taxes	$	17	$	19
Asset removal costs	509		495
Storm damage reserve	6		27
Deferred gains on interest rate derivatives	83		181
Planned major maintenance	—		10
Total Regulatory Liabilities	$	615	$	732

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.

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, distribution and other properties. 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.

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 and accrues $18.4 million annually for fossil fueled turbine/generation equipment maintenance and collects and accrues $17.2 million annually for nuclear-related refueling charges.

Various other regulatory assets are expected to be recovered in rates over periods of up to approximately 33 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.