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1.
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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Basis of Consolidation and Variable Interest Entities
The condensed consolidated financial statements of the Company include, after eliminating intercompany balances and transactions, the accounts of the parent holding company and each of its subsidiaries, including Consolidated SCE&G. Accordingly, discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.
SCE&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and, accordingly, Consolidated SCE&G's condensed consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s condensed consolidated financial statements.
GENCO owns a coal-fired electric generating station with a
605
MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately
$485 million
) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.
Income Statement Presentation
Revenues and expenses arising from regulated businesses and, in the case of the Company, the retail natural gas marketing business (including those activities of segments described in Note 10) are presented within Operating Income, and all other activities are presented within Other Income (Expense).
Asset Management and Supply Service Agreement
PSNC Energy, a subsidiary of SCANA, utilizes an asset management and supply service agreement with a counterparty for certain natural gas storage facilities. Such counterparty held, through an agency relationship,
40%
and
40%
of PSNC Energy’s natural gas inventory at June 30, 2017 and December 31, 2016, respectively, with a carrying value of
$9.5 million
and
$9.8 million
, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees
of which
75%
are credited to rate payers. This agreement expires on March 31, 2019.
Earnings Per Share
The Company computes basic earnings per share by dividing net income by the weighted average number of common shares outstanding for the period. When applicable, the Company computes diluted earnings per share using this same formula, after giving effect to securities considered to be dilutive potential common stock utilizing the treasury stock method.
New Accounting Matters
In May 2014, the FASB issued accounting guidance for revenue arising from contracts with customers that supersedes most earlier revenue recognition guidance, including industry-specific guidance. This new revenue recognition model calls for a five-step analysis in determining when and how revenue is recognized, and will require revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, the new guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The Company and Consolidated SCE&G have not determined the impact this guidance will have on their respective financial statements. However, the analysis of contracts with customers to which the guidance might be applicable has begun. Activities of the FASB's Transition Resource Group for Revenue Recognition are being monitored, particularly as they relate to the treatment of contributions in aid of construction, alternative revenue programs and the collectability of revenue of utilities subject to rate regulation. An evaluation of the enhanced disclosure requirements is also underway, including identifying performance obligations, determining the appropriate disaggregation of revenue and assessing the availability of information necessary to comply with the requirements. The Company and Consolidated SCE&G expect to adopt this guidance using the modified retrospective method and will recognize a cumulative effect adjustment, if any, to retained earnings on January 1, 2018 upon adoption. Comparative periods will not be restated.
In July 2015, the FASB issued accounting guidance intended to simplify the measurement of inventory cost by requiring most inventory to be measured at the lower of cost and net realizable value. The Company and Consolidated SCE&G adopted this guidance in the first quarter of 2017 and the adoption of this guidance did not have any impact on their respective financial statements.
In January 2016, the FASB issued accounting guidance that will change how entities measure certain equity investments and financial liabilities, among other things. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that adoption of this guidance will have a significant impact on their respective financial statements.
In February 2016, the FASB issued accounting guidance related to the recognition, measurement and presentation of
leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be
recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,
and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. The guidance will be effective for years beginning in 2019. The Company and Consolidated SCE&G have not determined what impact this guidance will have on their respective financial statements. However, the identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered.
In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and is intended to result in certain impairment losses being recognized earlier than under current guidance. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted in 2019. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective financial statements.
In August 2016, the FASB issued accounting guidance to reduce diversity in cash flow classification related to certain transactions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will impact their respective financial statements.
In October 2016, the FASB issued accounting guidance related to the tax effects of intra-entity asset transfers of assets other than inventory. An entity will be required to recognize the income tax consequences of such a transfer in the period it occurs. The Company and Consolidated SCE&G adopted this guidance in the first quarter 2017 and it had no impact on their respective financial statements.
In November 2016, the FASB issued accounting guidance related to the presentation of restricted cash on the statement of cash flows. The guidance is effective for years beginning in 2018, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements.
In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company and Consolidated SCE&G have not determined when this guidance will be adopted but do not anticipate that its adoption will have a material impact on their respective financial statements.
In March 2017, the FASB issued accounting guidance to change the required presentation of net periodic pension and postretirement benefit cost. Under the new guidance, the net periodic pension and postretirement benefit cost are to be separated into their service cost components and other components. The service cost components are to be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components are to be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component is eligible for capitalization in assets. This guidance is required to be applied on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. The Company and Consolidated SCE&G will adopt the guidance when required in the first quarter of 2018, and due to regulatory overlay, they do not anticipate that its adoption will have a material impact on their respective financial statements.
2.
RATE AND OTHER REGULATORY MATTERS
Rate Matters
Electric - Cost of Fuel
By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and to recover related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G will, among other things, implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately
84.5
MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity.
By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, ORS and SCEUC, to increase the total fuel cost component of retail electric rates. SCE&G agreed to set its base fuel component to produce a projected under recovery of
$61.0 million
over a 12-month period beginning with the first billing cycle of May 2017. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2017, projected DER program costs of approximately
$16.5 million
. Additionally, deferral of carrying cost will be allowed for base fuel component under-collected balances as they occur.
Electric - Base Rates
Pursuant to an SCPSC order, SCE&G removes from rate base certain deferred income tax assets arising from capital expenditures related to the New Units and accrues carrying costs 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 debt borrowing rate and are recorded as a regulatory asset and other income. Carrying costs during the three and six months ended June 30, 2017 totaled
$4.3 million
and
$8.6 million
. During the three and six months ended June 30, 2016, carrying costs totaled
$3.5 million
and
$6.6 million
. 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. See also Note 9.
By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider will decrease annual revenue by approximately
$11.9 million
. The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017.
In January 2017, SCE&G requested in its annual DSM Programs filing to recover
$37.0 million
of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. On April 27, 2017, the SCPSC approved SCE&G's request effective beginning with the first billing cycle in May 2017.
On June 22, 2017, the Friends of the Earth and the Sierra Club filed a complaint against SCE&G with the SCPSC, requesting that the SCPSC initiate a formal proceeding to direct SCE&G to immediately cease and desist from expending any further capital costs related to the construction of the New Units; to determine the prudence of acts and omissions by SCE&G in connection with the construction of the New Units; to review and determine the prudence of abandonment of the New Units and of the available least cost efficiency and renewable energy alternatives; and to remedy, abate and make due reparations for the rates charged to ratepayers related to the construction of the New Units. SCE&G’s answer to the complaint was filed with the SCPSC on July 19, 2017. A hearing in this matter has been scheduled for October 2, 2017.
Electric - BLRA
SCE&G filed the August 1, 2017 Petition with the SCPSC seeking recovery of costs expended on the construction of the New Units, including certain costs incurred subsequent to SCE&G's last revised rates update, other costs under the abandonment provisions of the BLRA, and affirmation of SCE&G's decision to abandon construction of the New Units, among other things. See additional discussion at Note 9.
Gas - SCE&G
On June 15, 2017, SCE&G filed with the SCPSC its quarterly monitoring report for the 12-month period ended March 31, 2017 and proposed an approximately
$9.0 million
, or
2.34%
, overall increase to its natural gas rates under the terms of the RSA. The ORS is expected to issue an audit report by September 1, 2017, and the SCPSC is expected to issue its order by October 15, 2017. If approved, the rate adjustment will be effective for the first billing cycle in November 2017.
Gas - PSNC Energy
PSNC Energy was authorized to implement a tracker that provides for biannual rate adjustments to recover the revenue requirement associated with integrity management plant investment and associated costs incurred from prevailing federal standards for pipeline integrity and safety that are not otherwise included in current base rates. On February 15, 2017, PSNC Energy filed its first biannual application for an adjustment to its rates under the Integrity Management Tracker, requesting recovery of an annual revenue requirement of
$1.9 million
. The NCUC approved this request and the revised rates became effective for service rendered on and after March 1, 2017.
Regulatory Assets and Regulatory Liabilities
Rate-regulated utilities recognize in their financial statements certain revenues and expenses in different periods than do other enterprises. As a result, the Company and Consolidated SCE&G have recorded regulatory assets and regulatory liabilities which are summarized in the following tables. Other than unrecovered plant, substantially all regulatory assets are either explicitly excluded from rate base or are effectively excluded from rate base due to their being offset by related liabilities.
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The Company
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Consolidated SCE&G
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Millions of dollars
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June 30,
2017
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December 31,
2016
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June 30,
2017
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December 31,
2016
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Regulatory Assets:
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Accumulated deferred income taxes
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$
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321
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$
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316
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$
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313
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$
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307
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AROs and related funding
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423
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|
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425
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|
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400
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|
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403
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Deferred employee benefit plan costs
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331
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|
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342
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|
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299
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|
|
309
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Deferred losses on interest rate derivatives
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630
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|
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620
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630
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620
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Unrecovered plant
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111
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117
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111
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117
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DSM Programs
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59
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59
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59
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59
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Carrying costs on deferred tax assets related to nuclear construction
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41
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32
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41
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32
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Pipeline integrity management costs
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42
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33
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7
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6
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Environmental remediation costs
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31
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32
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25
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26
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Deferred storm damage costs
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20
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20
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20
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20
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Deferred costs related to uncertain tax position
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23
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|
15
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23
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15
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Other
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140
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119
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140
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|
116
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Total Regulatory Assets
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$
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2,172
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$
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2,130
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$
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2,068
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$
|
2,030
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Regulatory Liabilities:
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Asset removal costs
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$
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761
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$
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755
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$
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533
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$
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529
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Deferred gains on interest rate derivatives
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138
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151
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138
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151
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Other
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23
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|
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24
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16
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15
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Total Regulatory Liabilities
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$
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922
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$
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930
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$
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687
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$
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695
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Accumulated deferred income tax liabilities that arise from utility operations that have not been included in customer rates are recorded as a regulatory asset. A substantial portion 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
85
years. Similarly, accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
AROs and related funding represents the regulatory asset associated with the legal obligation to decommission and dismantle Unit 1 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
110
years.
Employee benefit plan costs of the regulated utilities have historically been recovered as they have been recorded under GAAP. 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 2013, SCE&G began recovering through utility rates approximately
$63 million
of deferred pension costs for electric operations over approximately
30
years and approximately
$14 million
of deferred pension costs for gas operations 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
11
years.
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 through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when, in the case of deferred gains, such amounts are applied otherwise at the direction of the SCPSC.
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 SCE&G's deferred costs associated with such programs, and such deferred costs are currently being recovered over approximately
five
years through an approved rate rider.
Carrying costs on deferred tax assets related to nuclear construction are calculated on accumulated deferred income tax assets associated with the New Units which are not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs will be amortized over
ten
years beginning when these deferred tax assets are fully offset by related deferred tax liabilities. See also Note 9.
Pipeline integrity management costs represent costs incurred to comply with regulatory requirements related to natural gas pipelines. PSNC Energy will recover costs totaling
$20.3 million
over a
five
-year period beginning November 2016, and remaining costs of
$16.0 million
have been deferred pending future approval of rate recovery. SCE&G amortizes
$1.9 million
of such costs annually.
Environmental remediation costs represent costs associated with the assessment and clean-up of sites currently or formerly owned by SCE&G or PSNC Energy, and are expected to be recovered over periods of up to approximately
18
years.
Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G’s SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.
Deferred costs related to uncertain tax position primarily represent the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs are expected to be recovered through utility rates following ultimate resolution of the claims. See also Note 5.
Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.
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, 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. 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 or Consolidated SCE&G could be required to write off all or a portion of its regulatory assets and liabilities. Such an event could have a material effect on the Company's and Consolidated SCE&G's financial statements in the period the write-off would be recorded.
3.
COMMON EQUITY
SCANA had
200 million
shares of common stock authorized as of June 30, 2017 and December 31, 2016.
Authorized shares of SCE&G common stock were
50 million
as of June 30, 2017 and December 31, 2016. Authorized shares of SCE&G preferred stock were
20 million
, of which
1,000
shares, no par value, were issued and outstanding as of June 30, 2017 and December 31, 2016. All issued and outstanding shares of SCE&G's common and preferred stock are held by SCANA.
4. LONG-TERM DEBT AND LIQUIDITY
Long-term Debt
In June 2017, PSNC Energy issued
$150 million
of
4.18%
senior notes due June 30, 2047. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.
In June 2016, SCE&G issued
$425
million of
4.1%
first mortgage bonds due June 15, 2046. In addition, SCE&G issued
$75
million of
4.5%
first mortgage bonds due June 1, 2064, which constituted a reopening of
$300
million of
4.5%
first
mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.
In June 2016, PSNC Energy issued
$100
million of
4.13%
senior notes due June 22, 2046. Proceeds from this sale were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.
Substantially all electric utility plant is pledged as collateral in connection with long-term debt.
Liquidity
Credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. Committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Committed LOC, outstanding LOC advances, commercial paper, and LOC-supported letter of credit obligations were as follows:
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June 30, 2017
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Millions of dollars
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Total
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SCANA
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Consolidated SCE&G
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PSNC Energy
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Lines of credit:
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Five-year, expiring December 2020
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$
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1,300.0
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$
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400.0
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$
|
700.0
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$
|
200.0
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Fuel Company five-year, expiring December 2020
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500.0
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—
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500.0
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—
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Three-year, expiring December 2018
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200.0
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—
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200.0
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—
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Total committed long-term
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2,000.0
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400.0
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1,400.0
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|
200.0
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Outstanding commercial paper (270 or fewer days)
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|
1,129.0
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49.8
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|
1,079.2
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—
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Weighted average interest rate
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|
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1.64
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%
|
|
1.48
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%
|
|
—
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Letters of credit supported by LOC
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|
3.3
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|
|
3.0
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|
0.3
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—
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Available
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|
$
|
867.7
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|
|
$
|
347.2
|
|
|
$
|
320.5
|
|
|
$
|
200.0
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
December 31, 2016
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Millions of dollars
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Total
|
|
SCANA
|
|
Consolidated SCE&G
|
|
PSNC Energy
|
Lines of credit:
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Five-year, expiring December 2020
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|
$
|
1,300.0
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$
|
400.0
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|
$
|
700.0
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|
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$
|
200.0
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Fuel Company five-year, expiring December 2020
|
|
500.0
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—
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|
|
500.0
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—
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Three-year, expiring December 2018
|
|
200.0
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|
|
—
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|
|
200.0
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|
|
—
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Total committed long-term
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|
2,000.0
|
|
|
400.0
|
|
|
1,400.0
|
|
|
200.0
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Outstanding commercial paper (270 or fewer days)
|
|
940.5
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|
|
64.4
|
|
|
804.3
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|
|
71.8
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Weighted average interest rate
|
|
|
|
1.43
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%
|
|
1.04
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%
|
|
1.07
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%
|
Letters of credit supported by LOC
|
|
3.3
|
|
|
3.0
|
|
|
0.3
|
|
|
—
|
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Available
|
|
$
|
1,056.2
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|
|
$
|
332.6
|
|
|
$
|
595.4
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|
|
$
|
128.2
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|
Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of
$67.8 million
of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.
Consolidated SCE&G participates in a utility money pool with SCANA and another regulated subsidiary of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of
$28 million
at June 30, 2017, and
$29 million
at December 31, 2016. On its balance sheet, Consolidated SCE&G includes such amounts within Affiliated payables.
The Company files consolidated federal income tax returns which include Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.
The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2007 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.
During 2013 and 2014, SCANA amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In September 2016, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the New Units, in its 2015 income tax returns. These claims followed the issuance of final IRS regulations in 2014 regarding such treatment with respect to expenditures related to the design and construction of pilot models.
The IRS examined the claims in the amended returns, and as the examination progressed without resolution, the Company and Consolidated SCE&G evaluated and recorded adjustments to unrecognized tax benefits; however, none of these changes materially affected the Company's and Consolidated SCE&G's effective tax rate. In October 2016, the examination of the amended tax returns progressed to the IRS Office of Appeals. In addition, the IRS has begun an examination of SCANA's 2013 through 2015 income tax returns.
These income tax deductions and credits are considered to be uncertain tax positions, and under relevant accounting guidance, estimates of the amounts of related tax benefits which may not be sustained upon examination by the taxing authorities are required to be recorded as unrecognized tax benefits in the financial statements. As of June 30, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of
$443 million
(
$268 million
and
$389 million
for the Company and Consolidated SCE&G, respectively, net of the impact of state deductions on federal returns, and net of certain operating loss and tax credit carryforwards and, for the Company, receivables related to the uncertain tax positions). If recognized,
$17 million
of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rate (see discussion below regarding deferral of benefits related to 2015 forward). These unrecognized tax benefits are not expected to increase significantly within the next 12 months, although other uncertain tax positions may be identified or taken, particularly with respect to the abandonment of the construction of the New Units during 2017. It is reasonably possible that these known unrecognized tax benefits may decrease by
$443 million
within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through June 30, 2017.
In connection with the research and experimentation deduction and credit claims reflected on the 2015 income tax returns and the expectation of similar claims to be made in determining 2016 and 2017’s taxable income, the Company and Consolidated SCE&G have recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, and expect that such (net) deferred costs, along with any interest (see below) and other related deferred costs, will be recoverable through customer rates in future years. SCE&G's current customer rates reflect the availability of domestic production activities deductions (see Note 2).
Estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns has been deferred as a regulatory asset and is expected to be recoverable through customer rates in future years. See also Note 2. Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.
Effective January 1, 2017, the State of North Carolina reduced its corporate income tax rate from
4%
to
3%
. During the second quarter of 2017, the State of North Carolina passed legislation that will lower the state corporate income tax rate from
3%
to
2.5%
effective January 1, 2019. In connection with these changes in tax rates, related state deferred taxes were remeasured, with the change in their balances being credited to a regulatory liability. These changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.
|
|
6.
|
DERIVATIVE FINANCIAL INSTRUMENTS
|
Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation.
Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.
Commodity Derivatives
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions. Cash settlements of commodity derivatives are classified as operating activities in the condensed consolidated statements of cash flows.
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging. PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs. These derivative financial instruments are not designated as hedges for accounting purposes.
Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI. When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas. The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.
As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives. These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.
Interest Rate Swaps
Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances. In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.
Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt. Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.
Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated as cash flow hedges, and fair value changes and settlement amounts related to them are recorded as regulatory assets and
liabilities. Settlement losses on swaps will be amortized over the lives of subsequent debt issuances, and gains may be amortized to interest expense or may be applied as otherwise directed by the SCPSC.
Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.
Quantitative Disclosures Related to Derivatives
The Company was party to natural gas derivative contracts outstanding in the following quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity and Other Energy Management Contracts (in MMBTU)
|
Hedge designation
|
|
Gas Distribution
|
|
Gas Marketing
|
|
Total
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
7,140,000
|
|
|
13,982,000
|
|
|
21,122,000
|
|
Energy management contracts
(a)
|
|
—
|
|
|
47,924,643
|
|
|
47,924,643
|
|
Total
(a)
|
|
7,140,000
|
|
|
61,906,643
|
|
|
69,046,643
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
4,510,000
|
|
|
11,947,000
|
|
|
16,457,000
|
|
Energy management contracts
(a)
|
|
—
|
|
|
67,447,223
|
|
|
67,447,223
|
|
Total
(a)
|
|
4,510,000
|
|
|
79,394,223
|
|
|
83,904,223
|
|
(a)
Includes amounts related to basis swap contracts totaling
7,301,669
MMBTU in 2017 and
730,721
MMBTU in 2016.
The aggregate notional amounts of the interest rate swaps were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Swaps
|
|
|
|
|
|
|
|
|
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
June 30, 2017
|
|
December 31, 2016
|
|
June 30, 2017
|
|
December 31, 2016
|
Designated as hedging instruments
|
|
$
|
111.2
|
|
|
$
|
115.6
|
|
|
$
|
36.4
|
|
|
$
|
36.4
|
|
Not designated as hedging instruments
|
|
1,285.0
|
|
|
1,285.0
|
|
|
1,285.0
|
|
|
1,285.0
|
|
The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Instruments
|
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
Balance Sheet Location
|
|
Asset
|
|
Liability
|
|
Asset
|
|
Liability
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
$
|
3
|
|
|
—
|
|
|
$
|
1
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
25
|
|
|
—
|
|
|
9
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
Derivative financial instruments
|
|
$
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
1
|
|
|
$
|
30
|
|
|
—
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
Other deferred debits and other assets
|
|
$
|
59
|
|
|
—
|
|
|
$
|
59
|
|
|
—
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
$
|
38
|
|
|
—
|
|
|
$
|
38
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Energy management contracts
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
|
Other current assets
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Other deferred debits and other assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
Total
|
|
|
|
$
|
65
|
|
|
$
|
47
|
|
|
$
|
59
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
$
|
4
|
|
|
—
|
|
|
$
|
1
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
24
|
|
|
—
|
|
|
8
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
$
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Other current assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
6
|
|
|
$
|
28
|
|
|
—
|
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
Other deferred debits and other assets
|
|
$
|
71
|
|
|
—
|
|
|
$
|
71
|
|
|
—
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
$
|
27
|
|
|
—
|
|
|
$
|
27
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Energy management contracts
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
6
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
|
Other current assets
|
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
Other deferred debits and other assets
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Derivative financial instruments
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
|
Other deferred credits and other liabilities
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total
|
|
|
|
$
|
84
|
|
|
$
|
39
|
|
|
$
|
71
|
|
|
$
|
30
|
|
The effect of derivative instruments on the condensed consolidated statements of income is as follows:
Derivatives in Cash Flow Hedging Relationships
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company and Consolidated SCE&G:
|
|
|
|
|
|
|
|
|
Loss Deferred in Regulatory Accounts
|
|
|
|
Loss Reclassified from Deferred Accounts into Income
|
|
|
|
|
|
Millions of dollars
|
|
2017
|
|
|
2016
|
|
|
Location
|
|
2017
|
|
|
2016
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
|
Interest expense
|
|
—
|
|
|
—
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(1
|
)
|
|
$
|
(5
|
)
|
|
Interest expense
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in OCI, net of tax
|
|
|
|
Gain (Loss) Reclassified from AOCI into Income, net of tax
|
|
|
|
|
|
Millions of dollars
|
|
2017
|
|
|
2016
|
|
|
Location
|
|
2017
|
|
|
2016
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
|
Interest expense
|
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
Commodity contracts
|
|
(2
|
)
|
|
4
|
|
|
Gas purchased for resale
|
|
—
|
|
|
(1
|
)
|
Total
|
|
$
|
(3
|
)
|
|
$
|
2
|
|
|
|
|
$
|
(2
|
)
|
|
$
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(1
|
)
|
|
$
|
(5
|
)
|
|
Interest expense
|
|
$
|
(4
|
)
|
|
$
|
(4
|
)
|
Commodity contracts
|
|
(4
|
)
|
|
2
|
|
|
Gas purchased for resale
|
|
2
|
|
|
(6
|
)
|
Total
|
|
$
|
(5
|
)
|
|
$
|
(3
|
)
|
|
|
|
$
|
(2
|
)
|
|
$
|
(10
|
)
|
As of June 30, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately
$0.6 million
as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately
$7.2 million
as an increase to interest expense. As of June 30, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2020.
As of June 30, 2017, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately
$1.7 million
as an increase to interest expense.
Hedge Ineffectiveness
For the Company and Consolidated SCE&G, ineffectiveness on interest rate hedges designated as cash flow hedges was
insignificant
during all periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives Not designated as Hedging Instruments
|
|
|
|
|
|
|
|
The Company and Consolidated SCE&G:
|
|
|
|
|
|
|
Loss Deferred in Regulatory Accounts
|
|
|
|
Loss Reclassified from Deferred Accounts into Income
|
Millions of dollars
|
|
2017
|
|
|
2016
|
|
|
Location
|
|
2017
|
|
|
2016
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(35
|
)
|
|
$
|
(100
|
)
|
|
Interest Expense
|
|
—
|
|
|
—
|
|
Six Months Ended June 30,
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
(24
|
)
|
|
$
|
(244
|
)
|
|
Interest Expense
|
|
$
|
(1
|
)
|
|
—
|
|
As of June 30, 2017, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from derivatives not designated as hedges will include
$2.5 million
as an increase to interest expense.
Credit Risk Considerations
Certain derivative contracts contain contingent credit features. These features may include (i) material adverse change clauses or payment acceleration clauses that could result in immediate payments or (ii) the posting of letters of credit or termination of the derivative contract before maturity if specific events occur, such as a credit rating downgrade below investment grade or failure to post collateral.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts with Credit Contingent Features
|
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
June 30, 2017
|
|
December 31, 2016
|
|
June 30, 2017
|
|
December 31, 2016
|
in Net Liability Position
|
|
|
|
|
|
|
|
|
|
|
Aggregate fair value of derivatives in net liability position
|
|
$
|
64.7
|
|
|
$
|
50.3
|
|
|
$
|
44.2
|
|
|
$
|
30.3
|
|
Fair value of collateral already posted
|
|
32.5
|
|
|
29.2
|
|
|
11.6
|
|
|
9.2
|
|
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
|
|
$
|
32.2
|
|
|
$
|
21.1
|
|
|
$
|
32.6
|
|
|
$
|
21.1
|
|
|
|
|
|
|
|
|
|
|
in Net Asset Position
|
|
|
|
|
|
|
|
|
Aggregate fair value of derivatives in net asset position
|
|
$
|
52.0
|
|
|
$
|
62.9
|
|
|
$
|
52.0
|
|
|
$
|
62.0
|
|
Fair value of collateral already posted
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
|
|
$
|
52.0
|
|
|
$
|
62.9
|
|
|
$
|
52.0
|
|
|
$
|
62.0
|
|
In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of
$1.7 million
related to
$5.0 million
in commodity derivatives that are in a net asset position at June 30, 2017, compared to letters of credit in the amount of
$1.5 million
related to derivatives of
$9.0 million
at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered.
Information related to the offsetting of derivative assets and derivative liabilities follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
Interest Rate Contracts
|
|
Commodity Contracts
|
|
Energy Management Contracts
|
|
Total
|
|
Interest Rate Contracts
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of Recognized Assets
|
|
$
|
59
|
|
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
66
|
|
|
$
|
59
|
|
Gross Amounts Offset in Statement of Financial Position
|
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(3
|
)
|
|
—
|
|
Net Amounts Presented in Statement of Financial Position
|
|
59
|
|
|
1
|
|
|
3
|
|
|
63
|
|
|
59
|
|
Gross Amounts Not Offset - Financial Instruments
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
Gross Amounts Not Offset - Cash Collateral Received
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net Amount
|
|
$
|
52
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
56
|
|
|
$
|
52
|
|
Balance sheet location
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
|
|
|
|
|
|
$
|
1
|
|
|
—
|
|
Other current assets
|
|
|
|
|
|
|
|
2
|
|
|
—
|
|
Other deferred debits and other assets
|
|
|
|
|
|
|
|
60
|
|
|
$
|
59
|
|
Total
|
|
|
|
|
|
|
|
$
|
63
|
|
|
$
|
59
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of Recognized Assets
|
|
$
|
71
|
|
|
$
|
9
|
|
|
$
|
10
|
|
|
$
|
90
|
|
|
$
|
71
|
|
Gross Amounts Offset in Statement of Financial Position
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|
—
|
|
Net Amounts Presented in Statement of Financial Position
|
|
71
|
|
|
9
|
|
|
6
|
|
|
86
|
|
|
71
|
|
Gross Amounts Not Offset - Financial Instruments
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
Gross Amounts Not Offset - Cash Collateral Received
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net Amount
|
|
$
|
62
|
|
|
$
|
9
|
|
|
$
|
6
|
|
|
$
|
77
|
|
|
$
|
62
|
|
Balance sheet location
|
|
|
|
|
|
|
|
|
|
|
Prepayments
|
|
|
|
|
|
|
|
$
|
9
|
|
|
—
|
|
Other current assets
|
|
|
|
|
|
|
|
5
|
|
|
—
|
|
Other deferred debits and other assets
|
|
|
|
|
|
|
|
72
|
|
|
$
|
71
|
|
Total
|
|
|
|
|
|
|
|
$
|
86
|
|
|
$
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
Interest Rate Contracts
|
|
Commodity Contracts
|
|
Energy Management Contracts
|
|
Total
|
|
Interest Rate Contracts
|
As of June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of Recognized Liabilities
|
|
$
|
70
|
|
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
77
|
|
|
$
|
52
|
|
Gross Amounts Offset in Statement of Financial Position
|
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(3
|
)
|
|
—
|
|
Net Amounts Presented in Statement of Financial Position
|
|
70
|
|
|
1
|
|
|
3
|
|
|
74
|
|
|
52
|
|
Gross Amounts Not Offset - Financial Instruments
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
Gross Amounts Not Offset - Cash Collateral Posted
|
|
(31
|
)
|
|
—
|
|
|
(2
|
)
|
|
(33
|
)
|
|
(12
|
)
|
Net Amount
|
|
$
|
32
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
34
|
|
|
$
|
33
|
|
Balance sheet location
|
|
|
|
|
|
|
|
|
|
|
Other deferred debits and other assets
|
|
|
|
|
|
|
|
$
|
1
|
|
|
—
|
|
Derivative financial instruments
|
|
|
|
|
|
|
|
43
|
|
|
$
|
39
|
|
Other deferred credits and other liabilities
|
|
|
|
|
|
|
|
30
|
|
|
13
|
|
Total
|
|
|
|
|
|
|
|
$
|
74
|
|
|
$
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
Gross Amounts of Recognized Liabilities
|
|
$
|
58
|
|
|
—
|
|
|
$
|
9
|
|
|
$
|
67
|
|
|
$
|
39
|
|
Gross Amounts Offset in Statement of Financial Position
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
Net Amounts Presented in Statement of Financial Position
|
|
58
|
|
|
—
|
|
|
6
|
|
|
64
|
|
|
39
|
|
Gross Amounts Not Offset - Financial Instruments
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
Gross Amounts Not Offset - Cash Collateral Posted
|
|
(29
|
)
|
|
—
|
|
|
—
|
|
|
(29
|
)
|
|
(9
|
)
|
Net Amount
|
|
$
|
20
|
|
|
—
|
|
|
$
|
6
|
|
|
$
|
26
|
|
|
$
|
21
|
|
Balance sheet location
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments
|
|
|
|
|
|
|
|
$
|
35
|
|
|
$
|
28
|
|
Other deferred credits and other liabilities
|
|
|
|
|
|
|
|
29
|
|
|
11
|
|
Total
|
|
|
|
|
|
|
|
$
|
64
|
|
|
$
|
39
|
|
|
|
7.
|
FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
|
The Company values available for sale securities using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. The Company’s and Consolidated SCE&G's interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy
in which the measurements fall, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2017
|
|
As of December 31, 2016
|
|
|
The Company
|
|
Consolidated SCE&G
|
|
The Company
|
|
Consolidated SCE&G
|
Millions of dollars
|
|
Level 1
|
|
Level 2
|
|
Level 2
|
|
Level 1
|
|
Level 2
|
|
Level 2
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for sale securities
|
|
$
|
18
|
|
|
—
|
|
|
—
|
|
|
$
|
14
|
|
|
—
|
|
|
—
|
|
Held to maturity securities
|
|
—
|
|
|
$
|
7
|
|
|
—
|
|
|
—
|
|
|
$
|
7
|
|
|
—
|
|
Interest rate contracts
|
|
—
|
|
|
59
|
|
|
$
|
59
|
|
|
—
|
|
|
71
|
|
|
$
|
71
|
|
Commodity contracts
|
|
1
|
|
|
1
|
|
|
—
|
|
|
8
|
|
|
1
|
|
|
—
|
|
Energy management contracts
|
|
2
|
|
|
3
|
|
|
—
|
|
|
6
|
|
|
4
|
|
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
—
|
|
|
70
|
|
|
52
|
|
|
—
|
|
|
58
|
|
|
39
|
|
Commodity contracts
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Energy management contracts
|
|
2
|
|
|
6
|
|
|
—
|
|
|
2
|
|
|
10
|
|
|
—
|
|
The Company had no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented. Consolidated SCE&G had no Level 1 or Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.
Financial instruments for which the carrying amount may not equal estimated fair value were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
|
June 30, 2017
|
|
December 31, 2016
|
Millions of dollars
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
|
Carrying
Amount
|
|
Estimated
Fair Value
|
The Company
|
|
$
|
6,632.6
|
|
|
$
|
7,310.3
|
|
|
$
|
6,489.8
|
|
|
$
|
7,183.3
|
|
Consolidated SCE&G
|
|
5,162.9
|
|
|
5,735.2
|
|
|
5,166.0
|
|
|
5,752.3
|
|
Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.
Carrying values of short-term borrowings approximate fair value, and are based on quoted prices from dealers in the commercial paper market. The resulting fair value is considered to be Level 2.
|
|
8.
|
EMPLOYEE BENEFIT PLANS
|
Components of net periodic benefit cost recorded by the Company and Consolidated SCE&G were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Three months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
5.3
|
|
|
$
|
5.5
|
|
|
$
|
1.2
|
|
|
$
|
1.3
|
|
Interest cost
|
|
9.4
|
|
|
9.9
|
|
|
2.9
|
|
|
3.0
|
|
Expected return on assets
|
|
(13.8
|
)
|
|
(14.1
|
)
|
|
—
|
|
|
—
|
|
Prior service cost amortization
|
|
0.4
|
|
|
1.0
|
|
|
—
|
|
|
0.1
|
|
Amortization of actuarial losses
|
|
3.9
|
|
|
3.7
|
|
|
0.4
|
|
|
0.1
|
|
Net periodic benefit cost
|
|
$
|
5.2
|
|
|
$
|
6.0
|
|
|
$
|
4.5
|
|
|
$
|
4.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
10.5
|
|
|
$
|
11.0
|
|
|
$
|
2.3
|
|
|
$
|
2.5
|
|
Interest cost
|
|
18.9
|
|
|
19.8
|
|
|
5.9
|
|
|
6.0
|
|
Expected return on assets
|
|
(27.6
|
)
|
|
(28.1
|
)
|
|
—
|
|
|
—
|
|
Prior service cost amortization
|
|
0.8
|
|
|
2.0
|
|
|
—
|
|
|
0.2
|
|
Amortization of actuarial losses
|
|
7.9
|
|
|
7.4
|
|
|
0.7
|
|
|
0.2
|
|
Net periodic benefit cost
|
|
$
|
10.5
|
|
|
$
|
12.1
|
|
|
$
|
8.9
|
|
|
$
|
8.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated SCE&G
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Three months ended June 30,
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
4.4
|
|
|
$
|
4.5
|
|
|
$
|
1.0
|
|
|
$
|
1.0
|
|
Interest cost
|
|
8.1
|
|
|
8.4
|
|
|
2.4
|
|
|
2.5
|
|
Expected return on assets
|
|
(11.8
|
)
|
|
(11.9
|
)
|
|
—
|
|
|
—
|
|
Prior service cost amortization
|
|
0.3
|
|
|
0.8
|
|
|
—
|
|
|
0.1
|
|
Amortization of actuarial losses
|
|
3.4
|
|
|
3.1
|
|
|
0.3
|
|
|
0.1
|
|
Net periodic benefit cost
|
|
$
|
4.4
|
|
|
$
|
4.9
|
|
|
$
|
3.7
|
|
|
$
|
3.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30,
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
8.8
|
|
|
$
|
9.0
|
|
|
$
|
1.9
|
|
|
$
|
2.0
|
|
Interest cost
|
|
16.1
|
|
|
16.8
|
|
|
4.8
|
|
|
5.0
|
|
Expected return on assets
|
|
(23.6
|
)
|
|
(23.8
|
)
|
|
—
|
|
|
—
|
|
Prior service cost amortization
|
|
0.7
|
|
|
1.7
|
|
|
—
|
|
|
0.1
|
|
Amortization of actuarial losses
|
|
6.7
|
|
|
6.2
|
|
|
0.6
|
|
|
0.2
|
|
Net periodic benefit cost
|
|
$
|
8.7
|
|
|
$
|
9.9
|
|
|
$
|
7.3
|
|
|
$
|
7.3
|
|
No
significant contribution to the pension trust is expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply. SCE&G recovers current pension costs through either a rate rider that may be adjusted annually for retail electric operations or through cost of service rates for gas operations. PSNC Energy recovers pension costs through cost of service rates.
|
|
9.
|
COMMITMENTS AND CONTINGENCIES
|
Nuclear Insurance
Under Price-Anderson, SCE&G (for itself and on behalf of Santee Cooper, a one-third owner of Unit 1) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at SCE&G's nuclear power plant. Price-Anderson provides funds up to
$13.4 billion
for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of
$450 million
by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to
$127.3 million
per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than
$18.9 million
of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be
$84.8 million
per incident, but not more than
$12.6 million
per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every
five
years.
SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to
$2.75 billion
resulting from an event of nuclear origin and up to
$2.33 billion
resulting from an event of a non-nuclear origin. In addition, a builder's risk insurance policy has been purchased from NEIL for the New Units. This policy provides the owners of the New Units up to
$500 million
of total coverage for accidental property damage occurring at the New Units. The NEIL policies, in the aggregate, are subject to a maximum loss of
$2.75 billion
for any single loss occurrence. The NEIL policies permit retrospective assessments under certain conditions to cover insurer’s losses. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed
$45.4 million
. SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to
$415 million
resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed
$1.9 million
.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.
New Nuclear Construction
SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of the New Units. SCE&G's ownership share in the New Units is
55%
. As discussed below, various difficulties have been encountered in connection with the project. The ability to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the construction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments
to them within projected timeframes, the availability of labor and materials at estimated costs, the efficiency of project labor and weather. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters, and others as more fully discussed below, have resulted in the Company’s determination on July 31, 2017, after a comprehensive analysis, to abandon the construction of the New Units and to seek recovery under the abandonment provisions of the BLRA of costs expended on them.
EPC Contract and BLRA Matters
The construction of the New Units and SCE&G’s related recovery of financing costs through rates has been subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC has approved, among other things, a milestone schedule and a capital costs estimates schedule for the New Units. This approval constitutes a final and binding determination that the New Units are used and useful for utility purposes, and that the capital costs associated with the New Units are prudent utility costs and expenses and are properly included in rates, so long as the New Units are constructed or are being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the New Units. As of June 30, 2017, SCE&G’s investment in the New Units, including related transmission, totaled
$4.9 billion
, for which the financing costs on
$3.8 billion
have been reflected in rates under the BLRA.
The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued COLs in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. As further discussed below, approval by the SCPSC of cost recovery under the abandonment provisions of the BLRA will be required as a consequence of the Company’s determination on July 31, 2017 to cease construction of the New Units.
October 2015 Amendment and WEC's Engagement of Fluor
On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The October 2015 Amendment became effective in December 2015, upon the consummation of the acquisition by WEC of the stock of Stone & Webster from CB&I. Following that acquisition, WECTEC remained a member of the Consortium as a subsidiary of WEC, and Fluor has served as a subcontracted construction manager.
The October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at
$6.082 billion
(SCE&G’s 55% portion being approximately
$3.345 billion
). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, executed the fixed price option, subject to SCPSC approval, on July 1, 2016.
Among other things the October 2015 Amendment revised the contractual guaranteed substantial completion dates of Unit 2 and Unit 3 to August 31, 2019 and 2020, respectively, and provided for development of a revised construction milestone payment schedule. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 2019 and 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, would not be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020.
November 2016 SCPSC Order
In May 2016, SCE&G petitioned the SCPSC for approval of the updated construction and capital cost schedules for the New Units which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option.
The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively, and the approved capital cost schedule included incremental capital costs totaling
$831 million
. Under such approved capital cost schedule, SCE&G’s total project capital cost would be approximately
$6.8 billion
including owner’s costs and transmission, or
$7.7 billion
with
escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for new nuclear construction from
10.5%
to
10.25%
, with this revised ROE being applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017.
On February 28, 2017, the SCPSC issued its order denying Petitions for Rehearing which had been filed by certain parties that were not included in the settlement. The time period to appeal the SCPSC’s decision expired with no appeal having been filed.
Contractor Bankruptcy Proceedings and Related Uncertainties
On March 29, 2017, WEC and WECTEC, the two members of the Consortium, and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code, citing a liquidity crisis arising from project contract losses attributable to the New Units and the Vogtle Units as a material factor that caused them to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete the New Units under the terms of the EPC Contract and their need to reject the obligations thereunder. In connection with the bankruptcy filing, SCE&G, Santee Cooper, WEC and WECTEC entered into an Interim Assessment Agreement under which all parties continued to perform under the EPC Contract and under which SCE&G and Santee Cooper were provided the right to discuss project status with Fluor and other subcontractors and vendors and to obtain relevant project information and documents from them in order for SCE&G and Santee Cooper to perform comprehensive analyses regarding whether or how to proceed with the project. As part of the Interim Assessment Agreement, and to avoid an immediate rejection of the EPC Contract upon the filing of the bankruptcy case, WEC and WECTEC required SCE&G and Santee Cooper to make up front cash payments to WEC, WECTEC, subcontractors and vendors, irrespective of the fixed price provisions of the EPC Contract, to permit the time to conduct analyses. SCE&G and Santee Cooper paid all costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remained in effect.
During the period of the Interim Assessment Agreement, as amended and extended, SCE&G and Santee Cooper evaluated the various elements of the project, including forecasted costs and completion dates, while construction continued and SCE&G and Santee Cooper continued to make payments for such work.
As part of its evaluation, SCE&G considered that, as a result of the bankruptcy process (including WEC and WECTEC's public announcements that they could not perform under the terms of the EPC Contract), the EPC Contract would likely be rejected and that the benefit of the fixed-price terms provided by the EPC Contract would be lost. As such the cost overruns expected to be incurred by the Consortium would become the responsibility of SCE&G and Santee Cooper. Additionally, these cost increases and other costs identified by SCE&G would not be fully recoverable from the Consortium or from Toshiba under its payment guaranty or the related Toshiba Settlement Agreement, discussed below, and such costs would likely substantially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba. SCE&G also considered that even the newly revised substantial completion dates identified by WEC of April and December 2020 for Unit 2 and Unit 3, respectively, would not be met.
Toshiba Settlement Agreement
Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations.
In April of 2017, following WEC’s and WECTEC’s bankruptcy petitions, Toshiba announced that it had recorded an impairment charge of approximately
$6.2
billion relating to its nuclear power systems business, leaving it with negative shareholders’ equity. Toshiba also disclosed that, although these conditions and events raised substantial doubt, it believed that its responses to such conditions, including the sale of a portion of its computer memory business as then anticipated by Toshiba, would enable it to continue to operate as a going concern. However, there can be no assurance that such sales or other actions will be successful. As such, there can be no assurance that Toshiba will fulfill its payment guaranty obligations under the Toshiba Settlement Agreement discussed below.
As discussed above, Toshiba provided a parental guaranty for WEC’s payment obligations under the EPC Contract. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement Agreement was executed under which Toshiba is to begin making periodic payments from October 2017 through September 2022 in the total amount of approximately
$2.2
billion (
$1.2
billion for SCE&G’s 55% share), including certain amounts with respect to contractor liens discussed below. Certain of these payments may be satisfied by distributions from WEC through the bankruptcy process. These payments are payable even though the project has been abandoned.
A number of subcontractors and vendors to the Consortium, including Fluor, have alleged non-payment by the Consortium for amounts owed for work performed on the New Units. SCE&G is contesting the filed liens. SCE&G estimates that the aggregate amount of claims for which subcontractor and vendor liens have been filed is approximately
$258 million
(SCE&G’s 55% portion being approximately
$142 million
), of which
$50 million
(SCE&G’s 55% share being
$27.5 million
) have been paid. The settlement payments above are subject to reduction if WEC pays creditors holding these liens directly.
SCE&G will continue to evaluate the issues relating to these claims.
Determination to Abandon Construction
Based on the thorough evaluation previously discussed, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to abandon the construction of the New Units and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement, and notified WEC of its determination to abandon construction of the New Units.
On August 1, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the project and this decision, and SCE&G also filed the August 1, 2017 Petition with the SCPSC which included its plan of abandonment and also certain proposed actions which would mitigate related customer rate increases. Among the mitigation actions proposed in the August 1, 2017 Petition are the return to customers through a decrement rider of the net value of the payments to be made by Toshiba under the Toshiba Settlement Agreement as and to the extent those funds are received by SCE&G.
The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs may be recoverable through rates, so long as SCE&G demonstrates by a preponderance of the evidence that its decision to abandon the New Units was prudent. Through the petition filed on August 1, 2017, SCE&G has sought recovery of such costs expended on the construction of the New Units, including certain costs incurred subsequent to SCE&G's last revised rates update, and other costs under the abandonment provisions of the BLRA; however, the ability of SCE&G to recover such costs, and a reasonable return on them, through rates will be subject to review and approval by the SCPSC. While the Company's decision to abandon the New Units is expected to result in the reclassification in the third quarter of total construction work in progress related to the New Units into a regulatory asset, no impairment exists as of the filing date of this Form 10-Q.
Nuclear Production Tax Credits
In August 2014, the IRS notified SCE&G that, subject to a national megawatt capacity limitation, the electricity to be produced by each of the New Units would qualify for nuclear production tax credits under Section 45J of the IRC to the extent that such New Unit was operational before January 1, 2021 and other eligibility requirements were met. These nuclear production tax credits (related to SCE&G's 55% share of both New Units) could have totaled as much as approximately
$1.4 billion
. Due to the Company's determination to abandon the construction of the New Units, which determination was based in part on the expectation that the New Units would not be placed in service before January 2021, no such production tax credits will be earned.
Environmental
On August 3, 2015, the EPA issued its final rule on emission guidelines for states to follow in developing plans to address GHG emissions from existing units. The rule includes state-specific goals for reducing national CO
2
emissions by
32%
from 2005 levels by 2030. The rule establishes a phased-in compliance approach beginning in 2022. The rule gives each state from one to three years to issue its SIP, which will ultimately define the specific compliance methodology that will be applied to existing units in that state. On February 9, 2016, the Supreme Court stayed the rule pending disposition of a petition of review of the rule in the Court of Appeals. As a result of an Executive Order on March 28, 2017, the EPA is reconsidering the rule and the Court of Appeals agreed to hold the case in abeyance. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.
In July 2011, the EPA issued the CSAPR to reduce emissions of SO
2
and NO
X
from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of
28
states to reduce annual SO
2
emissions and annual and ozone season NO
X
emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO
2
and NO
X
and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control
installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.
In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.
The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits. As a facility’s NPDES permit is renewed (every
five
years), any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016. After this date, state regulators will modify facility NPDES permits to match more restrictive standards, thus requiring facilities to retrofit with new wastewater treatment technologies. Compliance dates will vary by type of wastewater, and some will be based on a facility's five-year permit cycle and thus may range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The Company and Consolidated SCE&G expect that wastewater treatment technology retrofits will be required at Williams and Wateree Stations. Any costs incurred to comply with the ELG Rule are expected to be recoverable through rates.
The CWA Section 316(b) Existing Facilities Rule became effective in October 2014. This rule establishes national requirements for the location, design, construction and capacity of cooling water intake structures at existing facilities that reflect the best technology available for minimizing the adverse environmental impacts of impingement and entrainment. SCE&G and GENCO are conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications to ensure compliance with this rule. Any costs incurred to comply with this rule are expected to be recoverable through rates.
The EPA's final rule for CCR became effective in the fourth quarter of 2015. This rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act and imposes certain requirements on ash storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. The Company and Consolidated SCE&G do not expect the incremental compliance costs associated with this rule to be significant and expect to recover such costs in future rates.
SCE&G is responsible for
four
decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. These sites are in various stages of investigation, remediation and monitoring under work plans approved by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2018 and will cost an additional
$9.9 million
, which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At June 30, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled
$25.0 million
and are included in regulatory assets.
|
|
10.
|
SEGMENT OF BUSINESS INFORMATION
|
Regulated operations measure profitability using operating income; therefore, net income is not allocated to the Electric Operations and Gas Distribution segments. The Gas Marketing segment measures profitability using net income.
The Company's Gas Distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy which meet the criteria for aggregation. All Other includes the parent company, a services company and other nonreportable segments that were insignificant for all periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company
|
|
|
|
|
|
|
|
|
Millions of dollars
|
|
External
Revenue
|
|
Intersegment Revenue
|
|
Operating
Income (Loss)
|
|
Net
Income
|
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
679
|
|
|
$
|
2
|
|
|
$
|
245
|
|
|
n/a
|
|
Gas Distribution
|
|
140
|
|
|
1
|
|
|
3
|
|
|
n/a
|
|
Gas Marketing
|
|
182
|
|
|
34
|
|
|
n/a
|
|
|
$
|
1
|
|
All Other
|
|
—
|
|
|
102
|
|
|
—
|
|
|
(7
|
)
|
Adjustments/Eliminations
|
|
—
|
|
|
(139
|
)
|
|
1
|
|
|
127
|
|
Consolidated Total
|
|
$
|
1,001
|
|
|
$
|
—
|
|
|
$
|
249
|
|
|
$
|
121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
1,256
|
|
|
$
|
3
|
|
|
$
|
423
|
|
|
n/a
|
|
Gas Distribution
|
|
461
|
|
|
1
|
|
|
116
|
|
|
n/a
|
|
Gas Marketing
|
|
456
|
|
|
58
|
|
|
n/a
|
|
|
$
|
16
|
|
All Other
|
|
—
|
|
|
196
|
|
|
—
|
|
|
(7
|
)
|
Adjustments/Eliminations
|
|
—
|
|
|
(258
|
)
|
|
26
|
|
|
283
|
|
Consolidated Total
|
|
$
|
2,173
|
|
|
$
|
—
|
|
|
$
|
565
|
|
|
$
|
292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
625
|
|
|
$
|
2
|
|
|
$
|
222
|
|
|
n/a
|
|
Gas Distribution
|
|
127
|
|
|
—
|
|
|
(1
|
)
|
|
n/a
|
|
Gas Marketing
|
|
153
|
|
|
26
|
|
|
n/a
|
|
|
—
|
|
All Other
|
|
—
|
|
|
104
|
|
|
—
|
|
|
$
|
(7
|
)
|
Adjustments/Eliminations
|
|
—
|
|
|
(132
|
)
|
|
—
|
|
|
112
|
|
Consolidated Total
|
|
$
|
905
|
|
|
$
|
—
|
|
|
$
|
221
|
|
|
$
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
1,217
|
|
|
$
|
3
|
|
|
$
|
420
|
|
|
n/a
|
|
Gas Distribution
|
|
426
|
|
|
1
|
|
|
93
|
|
|
n/a
|
|
Gas Marketing
|
|
434
|
|
|
48
|
|
|
n/a
|
|
|
$
|
24
|
|
All Other
|
|
—
|
|
|
202
|
|
|
—
|
|
|
(7
|
)
|
Adjustments/Eliminations
|
|
—
|
|
|
(254
|
)
|
|
38
|
|
|
264
|
|
Consolidated Total
|
|
$
|
2,077
|
|
|
$
|
—
|
|
|
$
|
551
|
|
|
$
|
281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated SCE&G
|
|
|
|
|
|
|
Millions of dollars
|
|
External Revenue
|
|
Operating Income
|
|
Earnings Available to
Common Shareholder
|
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
680
|
|
|
$
|
246
|
|
|
n/a
|
|
Gas Distribution
|
|
76
|
|
|
—
|
|
|
n/a
|
|
Adjustments/Eliminations
|
|
—
|
|
|
—
|
|
|
$
|
123
|
|
Consolidated Total
|
|
$
|
756
|
|
|
$
|
246
|
|
|
$
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
1,259
|
|
|
$
|
424
|
|
|
n/a
|
|
Gas Distribution
|
|
217
|
|
|
44
|
|
|
n/a
|
|
Adjustments/Eliminations
|
|
—
|
|
|
—
|
|
|
$
|
231
|
|
Consolidated Total
|
|
$
|
1,476
|
|
|
$
|
468
|
|
|
$
|
231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
627
|
|
|
$
|
222
|
|
|
n/a
|
|
Gas Distribution
|
|
65
|
|
|
—
|
|
|
n/a
|
|
Adjustments/Eliminations
|
|
—
|
|
|
—
|
|
|
$
|
110
|
|
Consolidated Total
|
|
$
|
692
|
|
|
$
|
222
|
|
|
$
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
Electric Operations
|
|
$
|
1,220
|
|
|
$
|
420
|
|
|
n/a
|
|
Gas Distribution
|
|
189
|
|
|
38
|
|
|
n/a
|
|
Adjustments/Eliminations
|
|
—
|
|
|
—
|
|
|
$
|
223
|
|
Consolidated Total
|
|
$
|
1,409
|
|
|
$
|
458
|
|
|
$
|
223
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets
|
|
The Company
|
|
Consolidated SCE&G
|
|
|
June 30,
|
|
December 31,
|
|
June 30,
|
|
December 31,
|
Millions of dollars
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Electric Operations
|
|
$
|
12,377
|
|
|
$
|
11,929
|
|
|
$
|
12,377
|
|
|
$
|
11,929
|
|
Gas Distribution
|
|
3,032
|
|
|
2,892
|
|
|
848
|
|
|
825
|
|
Gas Marketing
|
|
195
|
|
|
230
|
|
|
n/a
|
|
|
n/a
|
|
All Other
|
|
1,031
|
|
|
1,124
|
|
|
n/a
|
|
|
n/a
|
|
Adjustments/Eliminations
|
|
2,421
|
|
|
2,532
|
|
|
3,259
|
|
|
3,337
|
|
Consolidated Total
|
|
$
|
19,056
|
|
|
$
|
18,707
|
|
|
$
|
16,484
|
|
|
$
|
16,091
|
|
11. AFFILIATED TRANSACTIONS
The Company and Consolidated SCE&G:
SCE&G owns
40%
of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. Consolidated SCE&G’s total purchases from this affiliate were
$52.8 million
and
$44.0 million
for the three months ended June 30, 2017 and 2016, respectively, and
$97.4 million
and
$96.8 million
for the six months ended June 30, 2017 and 2016, respectively. Consolidated SCE&G’s total sales to this affiliate were
$52.5 million
and
$43.8 million
for the three months ended June 30, 2017 and 2016, respectively, and
$96.8 million
and
$96.2 million
for the six months ended June 30, 2017 and 2016, respectively. The net of the total purchases and total sales are recorded in Other expenses on the condensed consolidated statements of income (for the Company) and of comprehensive income (for Consolidated SCE&G). Consolidated SCE&G’s receivable from this affiliate was
$17.4 million
at June 30, 2017 and
$16.0 million
at December 31, 2016. Consolidated SCE&G’s payable to this affiliate was
$17.6 million
at June 30, 2017 and
$16.1 million
at December 31, 2016.
Consolidated SCE&G:
SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and certain electric generation requirements. Such purchases totaled approximately
$34.3 million
and
$25.9 million
for the three months ended June 30, 2017 and 2016, respectively, and
$58.2 million
and
$48.3 million
for the six months ended June 30, 2017 and 2016, respectively. SCE&G’s payables to SCANA Energy for such purchases were
$10.5 million
at June 30, 2017 and
$8.8 million
at December 31, 2016.
SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services, including amounts capitalized, totaled
$82.9 million
and
$80.5 million
for the three months ended June 30, 2017 and 2016, respectively, and
$155.4 million
and
$156.1 million
for the six months ended June 30, 2017 and 2016, respectively. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the condensed consolidated
statements of comprehensive income. Consolidated SCE&G's payables to SCANA Services for these services were
$50.8 million
at June 30, 2017 and
$63.5 million
at December 31, 2016.
Consolidated SCE&G's money pool borrowings from an affiliate are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.