| • | A $114 million increase in conjunction with Item 8. Financial Statements and Supplementary Data. Consolidated SCE&G makes no representation as to information relating solely to SCANA and its subsidiaries (other than Consolidated SCE&G).
RESULTS OF OPERATIONS
| | | | | | | | | | 2018 | | 2017 | The Company | | | | Loss per share | $ | (3.70 | ) | | $ | (0.83 | ) | Cash dividends declared per share | $ | 0.98 |
| | $ | 2.45 |
| | | | | Consolidated SCE&G | | | | Net loss (millions of dollars) | $ | (589.3 | ) | | $ | (171.9 | ) |
2018 vs 2017
The Company's loss per share and Consolidated SCE&G's net loss reflect impairment losses taken in each period related to the abandoned Nuclear Project. Results in 2018 also reflect an electric rate reduction made effective as of the second quarter of 2018 and significant legal and other costs incurred in connection with the Nuclear Project. For the Company, 2018's results also reflect costs associated with the merger with Dominion Energy. These and other results are discussed below.
Electric Operations
Electric Operations for the Company and for Consolidated SCE&G is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric Operations operating loss (including transactions with affiliates) was as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Operating revenues | | $ | 2,326.6 |
| | $ | 2,664.4 |
| | $ | 2,326.6 |
| | $ | 2,664.4 |
| Fuel used in electric generation | | 671.3 |
| | 593.6 |
| | 671.3 |
| | 593.6 |
| Purchased power | | 91.9 |
| | 80.1 |
| | 91.9 |
| | 80.1 |
| Other operation and maintenance | | 546.4 |
| | 512.0 |
| | 559.8 |
| | 526.4 |
| Impairment loss | | 1,376.0 |
| | 1,118.1 |
| | 1,376.0 |
| | 1,118.1 |
| Depreciation and amortization | | 307.4 |
| | 294.7 |
| | 296.4 |
| | 282.8 |
| Other taxes | | 227.4 |
| | 220.3 |
| | 225.0 |
| | 217.8 |
| Operating Loss | | $ | (893.8 | ) | | $ | (154.4 | ) | | $ | (893.8 | ) | | $ | (154.4 | ) |
Electric operations can be significantly impacted by the effects of weather. SCE&G estimates the effects on its electric business of actual temperatures in its service territory as compared to historical averages to approximate electric revenue and fuel costs attributable to the effects of abnormal weather. Results in both 2018 and 2017 reflect milder than normal weather in
the first quarter, with 2017 being significantly milder than 2018, and warmer than normal weather in the second, third and fourth quarters, with 2018 being warmer than 2017 in each period.
2018 vs 2017
| | Ÿ | Operating revenues decreased in 2018 by $113.7 million pursuant to an SCPSCa South Carolina Commission order whereby fuel cost recovery was substantially offset with gains realized upon the settlement of certain interest rate derivative contracts in 2018, as further described in Other Income (Expense) below. Operating revenue also decreased by $300.4 million due to the enactment and implementation of Act 258, by $69.2 million due to the recognition of estimated amounts to be refunded to customers as a result of the Tax Act and by lower residential and commercial average use of $48.6 million. The downward reserve adjustment related to fuel cost recovery had no effect on net income as it was fully offset by the recognition within other income of gains realized upon the settlement of certain derivative interest rate contracts. These revenue decreases were partially offset by the effects of weather of $100.4 million, residential and commercial growth of $22.4 million and higher fuel cost recovery of $65.6 million.(expense) below. |
| | Ÿ | Fuel used in electric generation and purchased power expenses increased due to higher fuel prices of $65.6 million, increased sales volumes associated with residential and commercial customer growth of $5.2 million and higher sales volumes associated with the effects of weather of $24.3 million. These increases were partially offset by lower residential and commercial average use of $12.7 million. In 2018, purchased power expenses were lower and expenses for fuel used in electric generation were higher due to SCE&G's purchase of CEC and the termination of a related purchase power agreement. |
| | Ÿ | Other operation and maintenance expenses increased due to higher legal and other costs arising from the abandonment of the Nuclear Project of approximately $25.6 million and increases in non-labor costs associated with the purchase of CEC of $8.5 million. These increases were partially offset by lower labor costs of $9.4Other operations and maintenance was substantially consistent as a charge related to a voluntary retirement program ($51 million) was substantially offset by lower non-labor electric generation expenses ($19 million), lower legal and NND Project wind down costs ($17 million) and lower property insurance expenses ($4 million). Impairment of assets and other charges decreased 49%, primarily due to the absence of $1.4 billion of impairment charges recorded in 2018 related to the NND Project, partially offset by $590 million of charges related to litigation and a $105 million charge for utility plant for which DESC committed to forgo recovery. Depreciation and amortization increased 38%, primarily reflecting the amortization of NND Project costs. Other income decreased $162 million, primarily due to the absence of Nuclear Project severance accruals in 2018. |
Impairment loss in each period represents probable disallowances of cost recovery associated with the abandoned Nuclear Project.
| | Ÿ | Depreciation and amortization increased primarily due to net plant additions. |
| | Ÿ | Other taxes increased primarily due to higher property taxes associated with net plant additions. |
Sales volumes (in GWh) related to the electric operations above, by class, were as follows:
| | | | | | | | | Classification | | 2018 | | 2017 | | Residential | | 8,366 |
| | 7,782 |
| | Commercial | | 7,446 |
| | 7,372 |
| | Industrial | | 6,250 |
| | 6,212 |
| | Other | | 583 |
| | 584 |
| | Total retail sales | | 22,645 |
| | 21,950 |
| | Wholesale | | 1,014 |
| | 916 |
| | Total Sales | | 23,659 |
| | 22,866 |
| |
2018 vs 2017
Retail and wholesale sales volumes increased primarily due to the effects of weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G, and for the Company, also includes PSNC Energy. Gas Distribution operating income (including transactions with affiliates) was as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Operating revenues | | $ | 935.1 |
| | $ | 876.0 |
| | $ | 435.1 |
| | $ | 405.8 |
| Gas purchased for resale | | 449.3 |
| | 393.0 |
| | 239.0 |
| | 205.9 |
| Other operation and maintenance | | 172.6 |
| | 167.9 |
| | 71.2 |
| | 70.6 |
| Depreciation and amortization | | 93.6 |
| | 84.9 |
| | 30.5 |
| | 29.0 |
| Other taxes | | 46.9 |
| | 42.5 |
| | 31.4 |
| | 28.5 |
| Operating Income | | $ | 172.7 |
| | $ | 187.7 |
| | $ | 63.0 |
| | $ | 71.8 |
|
The effect of abnormal weather conditions on gas distribution operating income is mitigated by the WNA at SCE&G and the CUT at PSNC Energy as further described in Note 3 of the consolidated financial statements in Item 8. Financial Statements and Supplementary Data. The WNA and CUT do not affect sales volumes.
2018 vs 2017
| | Ÿ | Operating revenues increased at SCE&G primarily due to higher gas cost recovery of $23.5 million, customer growth of $9.7 million and higher average use of $1.7 million. These increases were partially offset by a decrease of $7.5 million due to the deferral of estimated amounts to be refunded to customers as a result of the Tax Act. In addition to these factors, operating revenues for the Company increased due to weather at PSNC Energy of $63.6 million, customer growth of $12.3 million and an increased adjustment related to integrity management of $11.9 million. These increases were partially offset by a CUT adjustment of $34.3 million, decreased gas cost recoveries of $14.7 million and $14.8 million due to deferred revenues related to the Tax Act. |
| | Ÿ | Gas purchased for resale increased at SCE&G due to increased sales volumes due to weather of $14.5 million, higher gas prices of $9.0 million, higher average use of $4.8 million and firm customer growth of $4.7 million. In addition to these factors, gas purchased for resale at the Company reflects increased sales volumes due to weather at PSNC Energy of $32.1 million and customer growth of $4.6 million. These increases were partially offset by decreased gas costs of $14.7 million and the effect of a CUT adjustment of $3.9 million. |
| | Ÿ | Other operation and maintenance expenses increased primarily due to higher labor costs. |
| | Ÿ | Depreciation and amortization increased primarily due to net plant additions. |
| | Ÿ | Other taxes increased primarily due to higher property taxes associated with net plant additions. |
Sales volumes (in MMBTU) related to gas distribution by class, including transportation, were as follows:
| | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Classification (in thousands) | | 2018 | | 2017 | | 2018 | | 2017 | Residential | | 45,477 |
| | 37,251 |
| | 14,082 |
| | 11,285 |
| Commercial | | 31,640 |
| | 28,429 |
| | 13,344 |
| | 12,565 |
| Industrial | | 21,543 |
| | 20,108 |
| | 19,037 |
| | 18,091 |
| Transportation gas | | 57,867 |
| | 51,587 |
| | 6,401 |
| | 6,229 |
| Total | | 156,527 |
| | 137,375 |
| | 52,864 |
| | 48,170 |
|
2018 vs 2017
Residential, commercial and industrial sales volumes at the Company and Consolidated SCE&G increased due to the effects of weather and customer growth. Transportation volumes increased at the Company primarily due to a significant customer expansion and increased natural gas fired electric generation within PSNC Energy's territory.
Gas Marketing
Gas Marketing is comprised of the Company’s nonregulated marketing operation, SCANA Energy, which operates in the southeast and includes Georgia’s retail natural gas market. Gas Marketing operating revenues and net income were as follows:
| | | | | | | | | | | Millions of dollars | | 2018 | | 2017 | | Operating revenues | | $ | 935.1 |
| | $ | 1,001.4 |
| | Net Income | | 43.2 |
| | 26.9 |
| |
2018 vs 2017
Operating revenues decreased primarily due to the impact of adopting revenue recognition guidance (see Note 3 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data), whereby certain pass through charges are no longer classified as revenues. Net income increased due to the effects of weather.
Other Operating Expenses
Other operating expenses were as follows:
| | | | | | | | | | | | | | | | | | | | The Company | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Other operation and maintenance | | $ | 835.3 |
| | $ | 727.7 |
| | $ | 631.0 |
| | $ | 597.0 |
| Impairment loss | | 1,376.0 |
| | 1,118.1 |
| | 1,376.0 |
| | 1,118.1 |
| Depreciation and amortization | | 402.7 |
| | 381.6 |
| | 326.8 |
| | 311.8 |
| Other taxes | | 276.1 |
| | 264.2 |
| | 256.4 |
| | 246.4 |
|
Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in those discussions. In addition, other operation and maintenance expense includes certain legal and other costs arising from the abandonment of the Nuclear Project and the merger with Dominion Energy. Increases in such costs at the Company totaled approximately $81.1 million (including $25.6 million attributable to Consolidated SCE&G). The increases attributable to Consolidated SCE&G are included in amounts described in electric operations.
Net Periodic Pension Benefit Cost
Other operation and maintenance expense includes net periodic pension benefit cost, which was recorded on the income statements and balance sheets as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Income Statement Impact: | | | | | | | | | Employee benefit costs | | $ | 10.3 |
| | $ | 15.3 |
| | $ | 8.4 |
| | $ | 12.3 |
| Other expense | | 0.1 |
| | 0.5 |
| | 0.1 |
| | 0.3 |
| Balance Sheet Impact: | | | | | | | | | Increase in capital expenditures | | 2.5 |
| | 5.2 |
| | 2.0 |
| | 4.7 |
| Component of amount receivable from Summer Station co-owner | | 0.7 |
| | 2.1 |
| | 0.7 |
| | 2.1 |
| Decrease in regulatory assets | | (1.9 | ) | | (0.8 | ) | | (1.9 | ) | | (0.8 | ) | Net periodic benefit cost | | $ | 11.7 |
| | $ | 22.3 |
| | $ | 9.3 |
| | $ | 18.6 |
|
Pursuant to regulatory orders, SCE&G recovers current pension expense through a rate rider (for retail electric operations) and through cost of service rates (for gas operations), and amortizes pension costs previously deferred in regulatory assets as further described in Note 2 and Note 9 to the consolidated financial statements. Amounts amortized were $2.0 million for retail electric operations and $1.0 million for gas operations for each period presented. Pursuant to regulatory orders, PSNC Energy recovers current pension expense through cost of service rates.
Other Income (Expense)
Other income (expense), net includes the results of certain incidental non-utility activities of regulated subsidiaries, the activities of certain non-regulated subsidiaries, governance activities of SCANA and AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits), both of which have the effect of increasing reported net income. Components of other income (expense), net were as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Other income | | $ | 200.7 |
| | $ | 78.4 |
| | $ | 146.8 |
| | $ | 44.9 |
| Other expense | | (46.0 | ) | | (55.2 | ) | | (28.2 | ) | | (31.9 | ) | AFC - equity funds | | 18.7 |
| | 23.2 |
| | 10.8 |
| | 14.8 |
|
2018 vs 2017
Other income at the Company and Consolidated SCE&G increased primarily due to the recognition of $113.7 million of gains realized upon the settlement of certain interest rate derivative contracts and $6.9 million of gains from land sales. The gains related to the settlement of interest rate derivative contractsin 2018 ($115 million) that were fullymostly offset by downward adjustments to electric revenues pursuant to a previously received SCPSCSouth Carolina Commission order related to fuel cost recovery, a charge related to a voluntary retirement program ($24 million), lower AFUDC ($10 million) and as such, had no effect on net income. These increases werepenalties related to unrecognized tax benefits in the current year ($7 million), partially offset by $10.9 million due to the absencea gain on sale of accrual of carrying costs on unrecovered Nuclear Project costs in 2018 and by $17.5 millioncertain warranty service contracts ($7 million).Interest charges decreased 14%, primarily due to lower carrying cost accrual on certain other deferred items. Other expense at the Company and Consolidated SCE&G decreased $2.9 million and $1.9 million, respectively, due to changes in non-service cost components of pension and other postretirement benefit expense recognized within other expense. At the Company, the decreases also include lower expenses related to other benefit programs. Equity AFC decreased primarily due to the abandonment of the Nuclear Project in 2017.
Interest Expense
Components of interest expense, net of the debt component of AFC, were as follows: | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Interest on long-term debt, net | | $ | 357.7 |
| | $ | 346.7 |
| | $ | 271.0 |
| | $ | 266.1 |
| Other interest expense | | 26.3 |
| | 16.7 |
| | 32.7 |
| | 21.5 |
| Total | | $ | 384.0 |
| | $ | 363.4 |
| | $ | 303.7 |
| | $ | 287.6 |
|
Interest charges increased primarily due to the issuance of long-term debt at SCE&G and PSNC Energy in 2018, the accrual of interest related to uncertain tax positions and lower debt AFC due to the abandonment of the Nuclear Project. These increases were partially offset by the repayment of long-term debt at GENCO with short-term borrowings at lower rates.
Income Tax Benefit
At the Company and Consolidated SCE&G, income tax benefit increasedprincipal balances primarily due to higher losses before taxes as a result of the increased impairment loss recognizeddebt tender offers completed in 2018 and the effect of the electric rate change effective2019 ($62 million), partially offset by interest charges on unrecognized tax benefits in the second quarter.
ITEMcurrent year ($10 million).16
Income tax benefit decreased $404 million, primarily due to a tax charge related to regulatory assets for which DESC committed to forgo recovery ($194 million), the absence of 2017 Tax Reform Act impacts ($176 million) and changes in unrecognized tax benefits ($66 million). Item 7A. QUANTITATIVEQuantitative and Qualitative Disclosures About Market Risk The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact DESC. MARKET RISK SENSITIVE INSTRUMENTS AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK All MANAGEMENTDESC’s financial instruments described in this sectionand related financial derivative instruments are held for purposes other than trading. Interest Rate Risk
The tables below provide information about long-term debt issued by the Company and Consolidated SCE&G and other financial instruments that are sensitiveexposed to potential losses due to adverse changes in interest rates as described below. Management believes that DESC is not subject to material commodity price risk. Interest rate risk is generally related to DESC’s outstanding debt and future issuances of debt. In addition, DESC is exposed to investment price risk through various portfolios of equity and debt securities.The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in interest rates. Interest Rate Risk DESC manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. For variable rate debt obligations, the tables present principal cash flows and related weighted averageoutstanding, a hypothetical 10% increase in market interest rates by expected maturity dates. Forwould not have resulted in a material change in earnings at December 31, 2019 or December 31, 2018. DESC also uses interest rate derivatives, including forward-starting swaps and interest rate swaps the figures shown reflect
to manage interest rate risk. As of December 31, 2019, DESC had $71 million in aggregate notional amounts weighted averageof these interest rates and related maturities. Fair values for debt represent quoted market prices. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data.
| | | | | | | | | | | | | | | | | | | | | | | | | The Company | | | | | | | | | | | | | | | | December 31, 2018 | Expected Maturity Date | Millions of dollars | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total | | Fair Value | Long-Term Debt: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Fixed Rate ($) | 54.3 |
| | 363.8 |
| | 792.3 |
| | 261.3 |
| | 9.8 |
| | 5,175.2 |
| | 6,656.7 |
| | 7,048.3 |
| Average Fixed Interest Rate (%) | 3.94 |
| | 6.30 |
| | 4.21 |
| | 5.24 |
| | 4.69 |
| | 5.58 |
| | 5.42 |
| | — |
| Variable Rate ($) | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 116.2 |
| | 138.2 |
| | 132.5 |
| Average Variable Interest Rate (%) | 3.44 |
| | 3.44 |
| | 3.44 |
| | 3.44 |
| | 3.44 |
| | 2.41 |
| | 1.39 |
| | — |
| Interest Rate Swaps: | | | | | | | | | | | | | | | | Pay Fixed/Receive Variable ($) | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 119.8 |
| | 146.2 |
| | (24.4 | ) | Average Pay Interest Rate (%) | 6.17 |
| | 6.17 |
| | 6.17 |
| | 6.17 |
| | 6.17 |
| | 4.45 |
| | 4.76 |
| | — |
| Average Receive Interest Rate (%) | 3.44 |
| | 3.44 |
| | 3.44 |
| | 3.44 |
| | 3.44 |
| | 2.41 |
| | 2.59 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2017 | Expected Maturity Date | Millions of dollars | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | Fair Value | Long-Term Debt: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Fixed Rate ($) | 722.5 |
| | 12.0 |
| | 361.5 |
| | 490.2 |
| | 259.3 |
| | 4,683.9 |
| | 6,529.4 |
| | 7,261.8 |
| Average Fixed Interest Rate (%) | 6.01 |
| | 4.31 |
| | 6.31 |
| | 4.63 |
| | 5.26 |
| | 5.71 |
| | 5.68 |
| | — |
| Variable Rate ($) | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 120.6 |
| | 142.6 |
| | 137.8 |
| Average Variable Interest Rate (%) | 2.18 |
| | 2.18 |
| | 2.18 |
| | 2.18 |
| | 2.18 |
| | 1.64 |
| | 1.72 |
| | — |
| Interest Rate Swaps: | | | | | | | | | | | | | | | | Pay Fixed/Receive Variable ($) | 554.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 4.4 |
| | 124.2 |
| | 696.2 |
| | 20.4 |
| Average Pay Interest Rate (%) | 2.14 |
| | 6.17 |
| | 6.17 |
| | 6.17 |
| | 6.17 |
| | 4.51 |
| | 2.66 |
| | — |
| Average Receive Interest Rate (%) | 1.48 |
| | 2.18 |
| | 2.18 |
| | 2.18 |
| | 2.18 |
| | 1.91 |
| | 1.58 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Consolidated SCE&G | | | | | | | | | | | | | | | | December 31, 2018 | Expected Maturity Date | Millions of dollars | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total | | Fair Value | Long-Term Debt: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Fixed Rate ($) | 13.8 |
| | 13.3 |
| | 341.8 |
| | 10.8 |
| | 9.5 |
| | 4,725.3 |
| | 5,114.5 |
| | 5,406.8 |
| Average Fixed Interest Rate (%) | 4.18 |
| | 4.23 |
| | 3.52 |
| | 4.53 |
| | 5.23 |
| | 5.64 |
| | 5.48 |
| | — |
| Variable Rate ($) | — |
| | — |
| | — |
| | — |
| | — |
| | 67.8 |
| | 67.8 |
| | 63.0 |
| Average Variable Interest Rate (%) | — |
| | — |
| | — |
| | — |
| | — |
| | 1.67 |
| | 1.67 |
| | — |
| Interest Rate Swaps: | | | | | | | | | | | | | | | | Pay Fixed/Receive Variable ($) | — |
| | — |
| | — |
| | — |
| | — |
| | 71.4 |
| | 71.4 |
| | (11.2 | ) | Average Pay Interest Rate (%) | — |
| | — |
| | — |
| | — |
| | — |
| | 3.29 |
| | 3.29 |
| | — |
| Average Receive Interest Rate (%) | — |
| | — |
| | — |
| | — |
| | — |
| | 1.67 |
| | 1.67 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2017 | | Expected Maturity Date | Millions of dollars | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total | | Fair Value | Long-Term Debt: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Fixed Rate ($) | | 722.5 |
| | 12.0 |
| | 11.5 |
| | 40.2 |
| | 9.3 |
| | 4,333.9 |
| | 5,129.4 |
| | 5,726.8 |
| Average Fixed Interest Rate (%) | | 6.01 |
| | 4.31 |
| | 4.38 |
| | 3.58 |
| | 4.74 |
| | 5.76 |
| | 5.77 |
| | — |
| Variable Rate ($) | | — |
| | — |
| | — |
| | — |
| | — |
| | 67.8 |
| | 67.8 |
| | 63.5 |
| Average Variable Interest Rate (%) | | — |
| | — |
| | — |
| | — |
| | — |
| | 1.21 |
| | 1.21 |
| | — |
| Interest Rate Swaps: | | | | | | | | | | | | | | | | | Pay Fixed/Receive Variable ($) | | 550.0 |
| | — |
| | — |
| | — |
| | — |
| | 71.4 |
| | 621.4 |
| | 37.4 |
| Average Pay Interest Rate (%) | | 2.10 |
| | — |
| | — |
| | — |
| | — |
| | 3.29 |
| | 2.24 |
| | — |
| Average Receive Interest Rate (%) | | 1.48 |
| | — |
| | — |
| | — |
| | — |
| | 1.71 |
| | 1.51 |
| | — |
|
While aderivatives outstanding. A hypothetical 10% decrease in market interest rates would increasehave resulted in a decrease of $2 million in the fair value of debt,DESC’s interest rate derivatives at December 31, 2019. As of December 31, 2018, DESC had $71 million in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $1 million in the fair value of DESC’s interest rate derivatives at December 31, 2018.The impact of a change in interest rates on DESC’s interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction. Investment Price Risk DESC is subject to investment price risk due to securities held as investments in nuclear decommissioning trust funds which primarily hold insurance contracts that are reported in the Consolidated Balance Sheets at fair value. DESC recognized net investment gains (including investment income) on nuclear decommissioning trust investments of $24 million and less than $1 million for the year ended December 31, 2019 and 2018, respectively. DESC participates in SCANA sponsored pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. DESC’s pension and other postretirement plan assets experienced aggregate actual returns (losses) $149 million and $(43) million in 2019 and 2018, respectively, versus expected returns of $40 million and $48 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. A hypothetical 0.25% decrease in the assumed long-term rates of return on DESC’s plan assets would result in an increase in net periodic cost of $2 million at both December 31, 2019 and 2018, for pension benefits. Risk Management Policies DESC has established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion Energy has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies of all subsidiaries, including DESC. Dominion Energy maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion Energy also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and DESC’s December 31, 2019 provision for credit losses, management believes that it is unlikely that events whicha material adverse effect on DESC’s financial position, results of operations or cash flows would occur as a result in a realized loss will occur.
For further discussion of long-term debt and interest rate derivatives, see Note 5 and Note 7 to the consolidated financial statements in counterparty nonperformance.17
Item 8. Financial Statements and Supplementary Data.Data
Commodity Price Risk
The following table provides information about the Company’s financial instruments, which are limited to financial positions of Energy Marketing and PSNC Energy, that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 MMBTU. Fair value represents quoted market prices.
| | | | | | | | | | | | Expected Maturity | | 2019 | | 2020 | | 2021 | | Futures - Long | | | | | | | | Settlement Price (a) | | 2.85 |
| | 2.82 |
| | 2.81 |
| | Contract Amount (b) | | 82.2 |
| | 12.3 |
| | 0.2 |
| | Fair Value (b) | | 69.8 |
| | 12.4 |
| | 0.2 |
| | | | | | | | | | Futures - Short | | | | | | | | Settlement Price (a) | | 2.90 |
| | — |
| | — |
| | Contract Amount (b) | | 31.9 |
| | — |
| | — |
| | Fair Value (b) | | 20.8 |
| | — |
| | — |
| | | | | | | | | | Options - Purchased Call (Long) | | | | | | | | Strike Price (a) | | 2.58 |
| | 3.54 |
| | — |
| | Contract Amount (b) | | 17.5 |
| | 2.3 |
| | — |
| | Fair Value (b) | | 1.6 |
| | 0.1 |
| | — |
| | | | | | | | | | Options - Sold Call (Short) | | | | | | | | Strike Price (a) | | 0.39 |
| | — |
| | — |
| | Contract Amount (b) | | 0.4 |
| | — |
| | — |
| | Fair Value (b) | | 0.5 |
| | — |
| | — |
| | | | | | | | | | Swaps - Commodity | | |
| | |
| | |
| | Pay fixed/receive variable (b) | | 6.1 |
| | 3.8 |
| | 0.9 |
| | Average pay rate (a) | | 2.92 |
| | 2.85 |
| | 2.73 |
| | Average received rate (a) | | 2.80 |
| | 2.69 |
| | 2.74 |
| | Fair Value (b) | | 5.8 |
| | 3.5 |
| | 0.9 |
| | Pay variable/receive fixed (b) | | 26.4 |
| | 8.2 |
| | 0.8 |
| | Average pay rate (a) | | 2.80 |
| | 2.70 |
| | 2.79 |
| | Average received rate (a) | | 2.90 |
| | 2.80 |
| | 2.77 |
| | Fair Value (b) | | 27.3 |
| | 8.5 |
| | 0.7 |
| | | | | | | | | | Swaps - Basis | | |
| | |
| | |
| | Pay variable/receive variable (b) | | 15.9 |
| | — |
| | — |
| | Average pay rate (a) | | 3.14 |
| | — |
| | — |
| | Average received rate (a) | | 3.15 |
| | — |
| | — |
| | Fair Value (b) | | 16.0 |
| | — |
| | — |
| |
(a)Weighted average, in dollars
(b)Millions of dollars
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 7 to the consolidated financial statements in Item 8. Financial Statements and Supplementary Data.
PSNC Energy utilizes futures, options and swaps to hedge gas purchasing activities. PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy defers premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program for subsequent recovery from customers.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
18
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholder of SCANA Corporation
Cayce,Dominion Energy South Carolina,
Inc.Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of SCANA CorporationDominion Energy South Carolina, Inc. (an indirect, wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (the "Company"affiliates (“DESC”) as ofat December 31, 20182019 and 2017,2018, the related consolidated statements of operations, comprehensive income (loss),loss, changes in common equity, and cash flows, for each of the three years in the period ended December 31, 2018,2019, and the related notes and the financial statement schedule listed in the Part IV at Item 15 (collectively referred to as the "financial"consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as ofDESC at December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2019, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on the Company's internal control over financial reporting.
TheseThe consolidated financial statements are the responsibility of the Company'sDESC's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
| | | /s/DELOITTE & TOUCHE LLP | | Charlotte, North Carolina | | February 28, 2019 | |
We have served as the Company's auditor since 1945.
SCANA Corporation and Subsidiaries
Consolidated Balance Sheets
| | | | | | | | | | December 31, (Millions of dollars) | | 2018 | | 2017 | Assets | | |
| | |
| Utility Plant in Service | | $ | 15,171 |
| | $ | 14,370 |
| Accumulated Depreciation and Amortization | | (5,109 | ) | | (4,611 | ) | Construction Work in Progress | | 527 |
| | 471 |
| Nuclear Fuel, Net of Accumulated Amortization | | 211 |
| | 208 |
| Goodwill | | 210 |
| | 210 |
| Utility Plant, Net | | 11,010 |
| | 10,648 |
| Nonutility Property and Investments: | | |
| | |
| Nonutility property, net of accumulated depreciation of $143 and $133 | | 267 |
| | 270 |
| Assets held in trust, net-nuclear decommissioning | | 190 |
| | 136 |
| Other investments | | 22 |
| | 68 |
| Nonutility Property and Investments, Net | | 479 |
| | 474 |
| Current Assets: | | |
| | |
| Cash and cash equivalents | | 389 |
| | 409 |
| Receivables: | | | | | Customer, net of allowance for uncollectible accounts of $7 and $6 | | 632 |
| | 665 |
| Income taxes | | — |
| | 198 |
| Other | | 88 |
| | 105 |
| Inventories: | | |
| | |
| Fuel | | 153 |
| | 143 |
| Materials and supplies | | 170 |
| | 161 |
| Prepayments | | 105 |
| | 99 |
| Other current assets | | 12 |
| | 71 |
| Total Current Assets | | 1,549 |
| | 1,851 |
| Deferred Debits and Other Assets: | | |
| | | Regulatory assets | | 4,380 |
| | 5,580 |
| Other | | 236 |
| | 186 |
| Total Deferred Debits and Other Assets | | 4,616 |
| | 5,766 |
| Total | | $ | 17,654 |
| | $ | 18,739 |
|
See Notes to Consolidated Financial Statements.
| | | | | | | | | | December 31, (Millions of dollars) | | 2018 | | 2017 | Capitalization and Liabilities | | |
| | |
| Common Stock - no par value, 143 million shares outstanding for all periods presented | | $ | 2,389 |
| | $ | 2,390 |
| Retained Earnings | | 2,247 |
| | 2,915 |
| Accumulated Other Comprehensive Loss | | (34 | ) | | (50 | ) | Total Common Equity | | 4,602 |
| | 5,255 |
| Long-Term Debt, Net | | 6,695 |
| | 5,906 |
| Total Capitalization | | 11,297 |
| | 11,161 |
| Current Liabilities: | | |
| | |
| Short-term borrowings | | 173 |
| | 350 |
| Current portion of long-term debt | | 59 |
| | 727 |
| Accounts payable | | 430 |
| | 438 |
| Customer deposits and customer prepayments | | 114 |
| | 112 |
| Revenue subject to refund | | 77 |
| | — |
| Taxes accrued | | 245 |
| | 214 |
| Interest accrued | | 89 |
| | 87 |
| Dividends declared | | 17 |
| | 86 |
| Other | | 72 |
| | 99 |
| Total Current Liabilities | | 1,276 |
| | 2,113 |
| Deferred Credits and Other Liabilities: | | |
| | |
| Deferred income taxes, net | | 1,112 |
| | 1,261 |
| Asset retirement obligations | | 577 |
| | 568 |
| Pension and postretirement benefits | | 376 |
| | 360 |
| Unrecognized tax benefits | | 38 |
| | 19 |
| Regulatory liabilities | | 2,789 |
| | 3,059 |
| Other | | 189 |
| | 198 |
| Total Deferred Credits and Other Liabilities | | 5,081 |
| | 5,465 |
| Commitments and Contingencies (Note 11) | |
| |
|
| Total | | $ | 17,654 |
| | $ | 18,739 |
|
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Operations
| | | | | | | | | | | | | | Years Ended December 31, (Millions of dollars, except per share amounts) | | 2018 | | 2017 | | 2016 | Operating Revenues: | | |
| | |
| | |
| Electric | | $ | 2,322 |
| | $ | 2,659 |
| | $ | 2,614 |
| Gas-regulated | | 934 |
| | 874 |
| | 788 |
| Gas-nonregulated | | 796 |
| | 874 |
| | 825 |
| Total Operating Revenues | | 4,052 |
| | 4,407 |
| | 4,227 |
| | | | | | | | Operating Expenses: | | |
| | |
| | |
| Fuel used in electric generation | | 671 |
| | 594 |
| | 576 |
| Purchased power | | 92 |
| | 80 |
| | 64 |
| Gas purchased for resale | | 1,128 |
| | 1,156 |
| | 1,054 |
| Other operation and maintenance | | 835 |
| | 728 |
| | 741 |
| Impairment loss | | 1,376 |
| | 1,118 |
| | — |
| Depreciation and amortization | | 403 |
| | 382 |
| | 371 |
| Other taxes | | 276 |
| | 264 |
| | 254 |
| Total Operating Expenses | | 4,781 |
| | 4,322 |
| | 3,060 |
| Operating Income (Loss) | | (729 | ) | | 85 |
| | 1,167 |
| | | | | | | | Other Income (Expense), net | | 173 |
| | 47 |
| | 41 |
| Interest charges, net of allowance for borrowed funds used during construction of $12, $18 and $19 | | (384 | ) | | (363 | ) | | (342 | ) | | | | | | | | Income (Loss) Before Income Tax Expense (Benefit) | | (940 | ) | | (231 | ) | | 866 |
| Income Tax Expense (Benefit) | | (412 | ) | | (112 | ) | | 271 |
| Net Income (Loss) | | $ | (528 | ) | | $ | (119 | ) | | $ | 595 |
| | | | | | | | Earnings (Loss) Per Share of Common Stock | | $ | (3.70 | ) | | $ | (0.83 | ) | | $ | 4.16 |
| Weighted Average Common Shares Outstanding (millions) | | 143 |
| | 143 |
| | 143 |
| | | | | | | |
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
| | | | | | | | | | | | | | Years Ended December 31, (Millions of dollars) | | 2018 | | 2017 | | 2016 | Net Income (Loss) | | $ | (528 | ) | | $ | (119 | ) | | $ | 595 |
| Other Comprehensive Income (Loss), net of tax: | | | | | | | Unrealized Gains (Losses) on Cash Flow Hedging Activities: | | | | | | | Arising during period, net of tax of $(1), $(4) and $2 | | (2 | ) | | (7 | ) | | 4 |
| Reclassified as interest expense, net of tax of $2, $4 and $4 | | 9 |
| | 7 |
| | 7 |
| Reclassified as gas purchased for resale, net of tax of $2, $- and $4 | | 7 |
| | (1 | ) | | 6 |
| Net unrealized gains (losses) on cash flow hedging activities | | 14 |
| | (1 | ) | | 17 |
| Deferred Costs of Employee Benefit Plans (Note 9): | | | | | | | Gains arising during the period, net of tax of $1, $- and $- | | 2 |
| | — |
| | — |
| Reclassified to net income, net of tax of $-, $- and $- | | — |
| | — |
| | (1 | ) | Net deferred gains (costs) of employee benefit plans | | 2 |
| | — |
| | (1 | ) | Other Comprehensive Income (Loss) | | 16 |
| | (1 | ) | | 16 |
| Total Comprehensive Income (Loss) | | $ | (512 | ) | | $ | (120 | ) | | $ | 611 |
|
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Cash Flows
| | | | | | | | | | | | | | For the Years Ended December 31, (Millions of dollars) | | 2018 | | 2017 | | 2016 | Cash Flows From Operating Activities: | | |
| | |
| | |
| Net Income (Loss) | | $ | (528 | ) | | $ | (119 | ) | | $ | 595 |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | | | | | Impairment loss | | 1,376 |
| | 1,118 |
| | — |
| Gain on sale of investments | | (30 | ) | | — |
| | — |
| Deferred income taxes, net | | (151 | ) | | (911 | ) | | 242 |
| Depreciation and amortization | | 434 |
| | 406 |
| | 389 |
| Amortization of nuclear fuel | | 47 |
| | 44 |
| | 57 |
| Allowance for equity funds used during construction | | (19 | ) | | (23 | ) | | (29 | ) | Carrying cost recovery | | (6 | ) | | (34 | ) | | (17 | ) | Changes in certain assets and liabilities: | | | | | | | Receivables | | 37 |
| | (56 | ) | | (112 | ) | Income tax receivable | | 198 |
| | (56 | ) | | (142 | ) | Inventories | | (88 | ) | | (93 | ) | | (43 | ) | Prepayments | | (4 | ) | | (5 | ) | | 11 |
| Regulatory assets | | (199 | ) | | 181 |
| | (114 | ) | Regulatory liabilities | | (350 | ) | | 1,051 |
| | (2 | ) | Accounts payable | | 61 |
| | 24 |
| | 44 |
| Revenue subject to refund | | 77 |
| | — |
| | — |
| Unrecognized tax benefits | | 19 |
| | (224 | ) | | 175 |
| Taxes accrued | | 31 |
| | 13 |
| | (41 | ) | Pension and other postretirement benefits | | 16 |
| | (20 | ) | | 51 |
| Other assets | | 61 |
| | (47 | ) | | (44 | ) | Other liabilities | | (18 | ) | | (80 | ) | | 72 |
| Net Cash Provided From Operating Activities | | 964 |
| | 1,169 |
| | 1,092 |
| Cash Flows From Investing Activities: | | |
| | |
| | |
| Property additions and construction expenditures | | (890 | ) | | (1,225 | ) | | (1,579 | ) | Proceeds from monetization of guaranty settlement | | — |
| | 1,096 |
| | — |
| Proceeds from investments (including derivative collateral returned) | | 227 |
| | 145 |
| | 860 |
| Purchase of investments (including derivative collateral posted) | | (155 | ) | | (143 | ) | | (788 | ) | Payments upon interest rate derivative contract settlement | | — |
| | (39 | ) | | (113 | ) | Proceeds from interest rate derivative contract settlement | | 115 |
| | — |
| | — |
| Net Cash Used For Investing Activities | | (703 | ) | | (166 | ) | | (1,620 | ) | Cash Flows From Financing Activities: | | |
| | |
| | |
| Proceeds from issuance of long-term debt | | 935 |
| | 150 |
| | 592 |
| Repayments of long-term debt | | (830 | ) | | (17 | ) | | (117 | ) | Dividends | | (209 | ) | | (344 | ) | | (325 | ) | Short-term borrowings, net | | (177 | ) | | (591 | ) | | 410 |
| Net Cash Provided From (Used For) Financing Activities | | (281 | ) | | (802 | ) | | 560 |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (20 | ) | | 201 |
| | 32 |
| Cash and Cash Equivalents, January 1 | | 409 |
| | 208 |
| | 176 |
| Cash and Cash Equivalents, December 31 | | $ | 389 |
| | $ | 409 |
| | $ | 208 |
| Supplemental Cash Flow Information: | | |
| | |
| | |
| Cash for—Interest paid (net of capitalized interest of $12, $18 and $19) | | $ | 356 |
| | $ | 346 |
| | $ | 328 |
| —Income taxes paid | | 4 |
| | 2 |
| | 229 |
| —Income taxes received | | 206 |
| | 184 |
| | 166 |
| Noncash Investing and Financing Activities: | | | | | | | Accrued construction expenditures | | 85 |
| | 139 |
| | 109 |
| Capital leases | | 11 |
| | 8 |
| | 15 |
| Contributed construction | | 6 |
| | — |
| | — |
|
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
Consolidated Statements of Changes in Common Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | | Millions | | Shares | | Outstanding Amount | | Treasury Amount | | Retained Earnings | | Gains (Losses) on Cash Flow Hedges | | Deferred Costs of Employee Benefit Plans | | Total AOCI | | Total | Balance as of January 1, 2016 | | 143 |
| | $ | 2,402 |
| | $ | (12 | ) | | $ | 3,118 |
| | $ | (53 | ) | | $ | (12 | ) | | $ | (65 | ) | | $ | 5,443 |
| Net Income | | | | | | | | 595 |
| | | | | | | | 595 |
| Other Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | Gains (Losses) arising during the period | | | | | | | | | | 4 |
| | (1 | ) | | 3 |
| | 3 |
| Losses/amortization reclassified from AOCI | | | | | | | | | | 13 |
| | — |
| | 13 |
| | 13 |
| Total Comprehensive Income (Loss) | | | | | | | | 595 |
| | 17 |
| | (1 | ) | | 16 |
| | 611 |
| Dividends Declared | | | | | | | | (329 | ) | | | | | | | | (329 | ) | Balance as of December 31, 2016 | | 143 |
| | 2,402 |
| | (12 | ) | | 3,384 |
| | (36 | ) | | (13 | ) | | (49 | ) | | 5,725 |
| Net Loss | | | | | | | | (119 | ) | | | | | | | | (119 | ) | Other Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | Losses arising during the period | | | | | | | | | | (7 | ) | | — |
| | (7 | ) | | (7 | ) | Losses/amortization reclassified from AOCI | | | | | | | | | | 6 |
| | — |
| | 6 |
| | 6 |
| Total Comprehensive Income (Loss) | | | | | | | | (119 | ) | | (1 | ) | | — |
| | (1 | ) | | (120 | ) | Dividends Declared | | | | | | | | (350 | ) | | | | | | | | (350 | ) | Balance as of December 31, 2017 | | 143 |
| | 2,402 |
| | (12 | ) | | $ | 2,915 |
| | $ | (37 | ) | | $ | (13 | ) | | $ | (50 | ) | | $ | 5,255 |
| Net Loss | | | | | | | | (528 | ) | | | | | | | | (528 | ) | Other Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | Gains (losses) arising during the period | | | | | | | | | | (2 | ) | | 2 |
| | — |
| | — |
| Losses/amortization reclassified from AOCI | | | | | | | | | | 16 |
| | — |
| | 16 |
| | 16 |
| Total Comprehensive Income (Loss) | | | | | | | | (528 | ) | | 14 |
| | 2 |
| | 16 |
| | (512 | ) | Purchase of Treasury Stock | | | | | | (1 | ) | | | | | | | | | | (1 | ) | Dividends Declared | | | | | | | | (140 | ) | | | | | | | | (140 | ) | Balance as of December 31, 2018 | | 143 |
| | $ | 2,402 |
| | $ | (13 | ) | | $ | 2,247 |
| | $ | (23 | ) | | $ | (11 | ) | | $ | (34 | ) | | $ | 4,602 |
|
Dividends declared per share of common stock were $0.98, $2.45 and $2.30 for 2018, 2017 and 2016, respectively.
See Notes to Consolidated Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
South Carolina Electric & Gas Company
Cayce, South Carolina
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of South Carolina Electric & Gas Company and affiliates (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of comprehensive income (loss), changes in equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and the financial statement schedule listed in the Part IV at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company'sDESC's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the CompanyDESC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The CompanyDESC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’sDESC’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/DELOITTE Deloitte & TOUCHETouche LLP Charlotte, North Carolina
2020We have served as the Company'sDESC’s auditor since 1945.
19
Dominion Energy South Carolina, Electric & Gas Company and Affiliates Inc.Consolidated Balance Sheets At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | ASSETS | | | | | | | | | Utility plant in service | | $ | 13,208 | | | $ | 12,803 | | Accumulated depreciation and amortization | | | (4,851 | ) | | | (4,581 | ) | Construction work in progress | | | 339 | | | | 350 | | Nuclear fuel, net of accumulated amortization | | | 219 | | | | 211 | | Utility plant, net ($727 and $711 related to VIEs) | | | 8,915 | | | | 8,783 | | Nonutility Property and Investments: | | | | | | | | | Nonutility property, net of accumulated depreciation | | | 69 | | | | 72 | | Assets held in trust, nuclear decommissioning | | | 214 | | | | 190 | | Other investments | | | — | | | | 1 | | Nonutility property and investments, net | | | 283 | | | | 263 | | Current Assets: | | | | | | | | | Cash and cash equivalents | | | 4 | | | | 377 | | Receivables: | | | | | | | | | Customer, net of allowance for uncollectible accounts of $3 and $4 | | | 320 | | | | 331 | | Affiliated and related party | | | 14 | | | | 359 | | Other | | | 119 | | | | 68 | | Inventories (at average cost): | | | | | | | | | Fuel | | | 104 | | | | 89 | | Materials and supplies | | | 168 | | | | 158 | | Prepayments | | | 91 | | | | 82 | | Regulatory assets | | | 271 | | | | 224 | | Other current assets | | | 27 | | | | 1 | | Total current assets ($143 and $96 related to VIEs) | | | 1,118 | | | | 1,689 | | Deferred Debits and Other Assets: | | | | | | | | | Regulatory assets | | | 3,892 | | | | 4,060 | | Other | | | 93 | | | | 168 | | Total deferred debits and other assets ($32 and $34 related to VIEs) | | | 3,985 | | | | 4,228 | | Total assets | | $ | 14,301 | | | $ | 14,963 | |
| | | | | | | | | | December 31, (Millions of dollars) | | 2018 | | 2017 | Assets | | |
| | |
| Utility Plant in Service | | $ | 12,803 |
| | $ | 12,161 |
| Accumulated Depreciation and Amortization | | (4,581 | ) | | (4,124 | ) | Construction Work in Progress | | 350 |
| | 375 |
| Nuclear Fuel, Net of Accumulated Amortization | | 211 |
| | 208 |
| Utility Plant, Net ($711 and $711 related to VIEs) | | 8,783 |
| | 8,620 |
| Nonutility Property and Investments: | | |
| | |
| Nonutility property, net of accumulated depreciation | | 72 |
| | 71 |
| Assets held in trust, net-nuclear decommissioning | | 190 |
| | 136 |
| Other investments | | 1 |
| | 2 |
| Nonutility Property and Investments, Net | | 263 |
| | 209 |
| Current Assets: | | |
| | |
| Cash and cash equivalents | | 377 |
| | 395 |
| Receivables: | | | | | Customer, net of allowance for uncollectible accounts of $4 and $4 | | 344 |
| | 390 |
| Affiliated companies | | 359 |
| | 32 |
| Income taxes | | — |
| | 198 |
| Other | | 68 |
| | 85 |
| Inventories: | | |
| | |
| Fuel | | 89 |
| | 90 |
| Materials and supplies | | 158 |
| | 149 |
| Prepayments | | 82 |
| | 82 |
| Other current assets | | 1 |
| | 56 |
| Total Current Assets ($96 and $191 related to VIEs) | | 1,478 |
| | 1,477 |
| Deferred Debits and Other Assets: | | |
| | |
| Regulatory assets | | 4,256 |
| | 5,476 |
| Other | | 183 |
| | 164 |
| Total Deferred Debits and Other Assets ($34 and $50 related to VIEs) | | 4,439 |
| | 5,640 |
| Total | | $ | 14,963 |
| | $ | 15,946 |
|
See Notes to Consolidated Financial Statements.
At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | CAPITALIZATION AND LIABILITIES | | | | | | | | | Common Stock - no par value, 40.3 million shares outstanding | | $ | 3,695 | | | $ | 2,860 | | Retained earnings | | | 20 | | | | 1,279 | | Accumulated other comprehensive loss | | | (3 | ) | | | (3 | ) | Total common equity | | | 3,712 | | | | 4,136 | | Noncontrolling interest | | | 180 | | | | 179 | | Total Equity | | | 3,892 | | | | 4,315 | | Long-term debt, net | | | 3,358 | | | | 5,132 | | Affiliated long-term debt | | | 230 | | | | — | | Finance leases | | | 20 | | | | — | | Total long-term debt | | | 3,608 | | | | 5,132 | | Total capitalization | | | 7,500 | | | | 9,447 | | Current Liabilities: | | | | | | | | | Short-term borrowings | | | — | | | | 73 | | Securities due within one year | | | 7 | | | | 14 | | Accounts payable | | | 245 | | | | 267 | | Affiliated and related party payables | | | 624 | | | | 347 | | Customer deposits and customer prepayments | | | 76 | | | | 73 | | Revenue subject to refund | | | 4 | | | | 77 | | Taxes accrued | | | 218 | | | | 228 | | Interest accrued | | | 88 | | | | 72 | | Regulatory liabilities | | | 256 | | | | 126 | | Reserves for litigation and regulatory proceedings | | | 492 | | | | 11 | | Other | | | 56 | | | | 42 | | Total current liabilities | | | 2,066 | | | | 1,330 | | Deferred Credits and Other Liabilities: | | | | | | | | | Deferred income taxes and investment tax credits | | | 629 | | | | 1,008 | | Asset retirement obligations | | | 489 | | | | 542 | | Pension and other postretirement benefits | | | 203 | | | | 232 | | Regulatory liabilities | | | 3,210 | | | | 2,264 | | Affiliated liabilities | | | 15 | | | | 16 | | Other | | | 189 | | | | 124 | | Total deferred credits and other liabilities | | | 4,735 | | | | 4,186 | | Commitments and Contingencies (see Note 12) | | | | | | | | | Total capitalization and liabilities | | $ | 14,301 | | | $ | 14,963 | |
| | | | | | | | | | December 31, (Millions of dollars) | | 2018 | | 2017 | Capitalization and Liabilities | | |
| | |
| Common Stock - no par value, 40.3 million shares outstanding for all periods presented | | $ | 2,860 |
| | $ | 2,860 |
| Retained Earnings | | 1,279 |
| | 1,982 |
| Accumulated Other Comprehensive Loss | | (3 | ) | | (4 | ) | Total Common Equity | | 4,136 |
| | 4,838 |
| Noncontrolling interest | | 179 |
| | 142 |
| Total Equity | | 4,315 |
| | 4,980 |
| Long-Term Debt, net | | 5,132 |
| | 4,441 |
| Total Capitalization | | 9,447 |
| | 9,421 |
| Current Liabilities: | | |
| | |
| Short-term borrowings | | 73 |
| | 252 |
| Current portion of long-term debt | | 14 |
| | 723 |
| Accounts payable | | 267 |
| | 251 |
| Affiliated payables | | 347 |
| | 102 |
| Customer deposits and customer prepayments | | 83 |
| | 70 |
| Revenue subject to refund | | 77 |
| | — |
| Taxes accrued | | 239 |
| | 208 |
| Interest accrued | | 72 |
| | 67 |
| Dividends declared | | 10 |
| | 82 |
| Other | | 32 |
| | 49 |
| Total Current Liabilities | | 1,214 |
| | 1,804 |
| Deferred Credits and Other Liabilities: | | |
| | |
| Deferred income taxes, net | | 989 |
| | 1,173 |
| Asset retirement obligations | | 542 |
| | 529 |
| Pension and postretirement benefits | | 232 |
| | 217 |
| Unrecognized tax benefits | | 38 |
| | 19 |
| Regulatory liabilities | | 2,380 |
| | 2,667 |
| Other | | 105 |
| | 97 |
| Other - affiliate | | 16 |
| | 19 |
| Total Deferred Credits and Other Liabilities | | 4,302 |
| | 4,721 |
| Commitments and Contingencies (Note 11) | |
|
| |
|
| Total | | $ | 14,963 |
| | $ | 15,946 |
|
See Notes to Consolidated Financial Statements.
21
Dominion Energy South Carolina, Electric & Gas Company and Affiliates Inc.Consolidated Statements of Comprehensive Income (Loss)Loss Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | Operating Revenue(1) | | $ | 1,929 | | | $ | 2,762 | | | $ | 3,070 | | Operating Expenses: | | | | | | | | | | | | | Fuel used in electric generation(1) | | | 573 | | | | 671 | | | | 594 | | Purchased power(1) | | | 54 | | | | 92 | | | | 80 | | Gas purchased for resale(1) | | | 216 | | | | 239 | | | | 206 | | Other operations and maintenance | | | 388 | | | | 449 | | | | 417 | | Other operations and maintenance – affiliated suppliers | | | 244 | | | | 182 | | | | 180 | | Impairment of assets and other charges | | | 695 | | | | 1,376 | | | | 1,118 | | Depreciation and amortization | | | 450 | | | | 327 | | | | 312 | | Other taxes(1) | | | 250 | | | | 257 | | | | 246 | | Total operating expenses | | | 2,870 | | | | 3,593 | | | | 3,153 | | Operating loss | | | (941 | ) | | | (831 | ) | | | (83 | ) | Other income (expense), net | | | (33 | ) | | | 129 | | | | 28 | | Interest charges, net of allowance for funds used during construction of $5, $9 and $15(1) | | | 260 | | | | 303 | | | | 288 | | Loss before income tax benefit | | | (1,234 | ) | | | (1,005 | ) | | | (343 | ) | Income tax benefit | | | (12 | ) | | | (416 | ) | | | (171 | ) | Net Loss | | | (1,222 | ) | | | (589 | ) | | | (172 | ) | Other Comprehensive Income: | | | | | | | | | | | | | Deferred cost of employee benefit plans, net of tax of $-, $- and $- | | | 1 | | | | 1 | | | | — | | Total Comprehensive Loss | | | (1,221 | ) | | | (588 | ) | | | (172 | ) | Comprehensive Income Attributable to Noncontrolling Interest | | | 18 | | | | 25 | | | | 13 | | Comprehensive Loss Attributable to Common Shareholder | | $ | (1,239 | ) | | $ | (613 | ) | | $ | (185 | ) |
(1) | See Note 16 for amounts attributable to affiliates. |
| | | | | | | | | | | | | | For the Years Ended December 31, (Millions of dollars) | | 2018 | | 2017 | | 2016 | Operating Revenues: | | |
| | |
| | |
| Electric | | $ | 2,322 |
| | $ | 2,659 |
| | $ | 2,614 |
| Electric - nonconsolidated affiliate | | 5 |
| | 5 |
| | 5 |
| Gas | | 434 |
| | 405 |
| | 366 |
| Gas - nonconsolidated affiliate | | 1 |
| | 1 |
| | 1 |
| Total Operating Revenues | | 2,762 |
| | 3,070 |
| | 2,986 |
| Operating Expenses: | | |
| | |
| | |
| Fuel used in electric generation | | 531 |
| | 465 |
| | 472 |
| Fuel used in electric generation - nonconsolidated affiliate | | 140 |
| | 129 |
| | 104 |
| Purchased power | | 92 |
| | 80 |
| | 64 |
| Gas purchased for resale | | 239 |
| | 206 |
| | 174 |
| Gas purchased for resale - nonconsolidated affiliate | | — |
| | — |
| | 9 |
| Other operation and maintenance | | 449 |
| | 417 |
| | 403 |
| Other operation and maintenance - nonconsolidated affiliate | | 182 |
| | 180 |
| | 199 |
| Impairment loss | | 1,376 |
| | 1,118 |
| | — |
| Depreciation and amortization | | 327 |
| | 312 |
| | 302 |
| Other taxes | | 251 |
| | 241 |
| | 227 |
| Other taxes - nonconsolidated affiliate | | 6 |
| | 5 |
| | 7 |
| Total Operating Expenses | | 3,593 |
| | 3,153 |
| | 1,961 |
| Operating Income (Loss) | | (831 | ) | | (83 | ) | | 1,025 |
| Other Income (Expense), net | | 129 |
| | 28 |
| | 19 |
| Interest charges, net of allowance for borrowed funds used during construction of $9, $15 and $18 | | (303 | ) | | (288 | ) | | (270 | ) | Income (Loss) Before Income Tax Expense | | (1,005 | ) | | (343 | ) | | 774 |
| Income Tax Expense (Benefit) | | (416 | ) | | (171 | ) | | 248 |
| Net Income (Loss) | | (589 | ) | | (172 | ) | | 526 |
| Other Comprehensive Income | | | | | | | Deferred cost of employee benefit plans, net of tax of $-, $- and $- | | 1 |
| | — |
| | — |
| Total Comprehensive Income (Loss) | | (588 | ) | | (172 | ) | | 526 |
| Less Comprehensive Income Attributable to Noncontrolling Interest | | 25 |
| | 13 |
| | 13 |
| Comprehensive Income Available (Loss Attributable) to Common Shareholder | | $ | (613 | ) | | $ | (185 | ) | | $ | 513 |
| | | | | | | |
See Notes to Consolidated Financial Statements.
22
Dominion Energy South Carolina, Electric & Gas Company and Affiliates Inc.Consolidated Statements of Cash Flow FlowsYear Ended December 31, | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | Operating Activities | | | | | | | | | | | | | Net loss | | $ | (1,222 | ) | | $ | (589 | ) | | $ | (172 | ) | Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | | Impairment of assets and other charges | | | 576 | | | | 1,376 | | | | 1,118 | | Provision for refunds to electric customers | | | 800 | | | | — | | | | — | | Gain on sale of assets | | | (7 | ) | | | — | | | | — | | Deferred income taxes, net | | | (379 | ) | | | (184 | ) | | | (780 | ) | Depreciation and amortization | | | 464 | | | | 342 | | | | 323 | | Amortization of nuclear fuel | | | 53 | | | | 47 | | | | 44 | | Other adjustments | | | (7 | ) | | | (17 | ) | | | (49 | ) | Changes in certain assets and liabilities: | | | | | | | | | | | | | Receivables | | | (33 | ) | | | 50 | | | | (32 | ) | Receivables – affiliated and related party | | | 1 | | | | (2 | ) | | | 12 | | Income tax receivable | | | — | | | | 198 | | | | (145 | ) | Inventories | | | (76 | ) | | | (54 | ) | | | (60 | ) | Prepayments | | | (9 | ) | | | — | | | | 6 | | Regulatory assets | | | (20 | ) | | | (179 | ) | | | 185 | | Regulatory liabilities | | | 265 | | | | (360 | ) | | | 899 | | Accounts payable | | | (54 | ) | | | 61 | | | | 20 | | Accounts payable – affiliated and related party | | | (15 | ) | | | — | | | | (28 | ) | Revenue subject to refund | | | (73 | ) | | | 77 | | | | — | | Unrecognized tax benefits | | | 52 | | | | 19 | | | | (241 | ) | Taxes accrued | | | (10 | ) | | | 31 | | | | 13 | | Pension and other postretirement benefits | | | (27 | ) | | | 15 | | | | (21 | ) | Other assets and liabilities | | | 169 | | | | 96 | | | | (86 | ) | Net cash provided by operating activities | | | 448 | | | | 927 | | | | 1,006 | | Investing Activities | | | | | | | | | | | | | Property additions and construction expenditures | | | (497 | ) | | | (633 | ) | | | (928 | ) | Proceeds from monetization of guaranty settlement | | | — | | | | — | | | | 1,096 | | Proceeds from investments and sales of assets | | | 39 | | | | 40 | | | | 118 | | Purchase of investments | | | (54 | ) | | | (29 | ) | | | (122 | ) | Purchase of investments – affiliate | | | — | | | | (111 | ) | | | — | | Payments upon interest rate derivative contract settlement | | | — | | | | — | | | | (39 | ) | Proceeds from interest rate derivative contract settlement | | | — | | | | 115 | | | | — | | Investment in affiliate, net | | | 344 | | | | (214 | ) | | | (28 | ) | Net cash provided by (used in) investing activities | | | (168 | ) | | | (832 | ) | | | 97 | | Financing Activities | | | | | | | | | | | | | Proceeds from issuance of debt | | | — | | | | 795 | | | | — | | Proceeds from issuance of affiliated debt | | | 230 | | | | — | | | | — | | Repayment of long-term debt, including redemption premiums | | | (1,890 | ) | | | (825 | ) | | | (12 | ) | Dividend to parent | | | (30 | ) | | | (173 | ) | | | (319 | ) | Short-term borrowings, net | | | (73 | ) | | | (179 | ) | | | (552 | ) | Short-term borrowings – affiliated, net | | | 292 | | | | — | | | | — | | Money pool borrowings, net | | | — | | | | 245 | | | | 8 | | Contribution from parent | | | 838 | | | | 24 | | | | 3 | | Contribution returned to parent | | | (20 | ) | | | — | | | | — | | Net cash used in financing activities | | | (653 | ) | | | (113 | ) | | | (872 | ) | Net increase (decrease) in cash, restricted cash and equivalents | | | (373 | ) | | | (18 | ) | | | 231 | | Cash, restricted cash and equivalents at beginning of period(1) | | | 377 | | | | 395 | | | | 164 | | Cash, restricted cash and equivalents at end of period(1) | | $ | 4 | | | $ | 377 | | | $ | 395 | | Supplemental Cash Flow Information | | | | | | | | | | | | | Cash for: | | | | | | | | | | | | | Interest paid (net of capitalized interest of $5, $9 and $15) | | | 220 | | | | 264 | | | | 269 | | Income taxes paid | | | 13 | | | | 3 | | | | 47 | | Income taxes received | | | — | | | | 216 | | | | 145 | | Noncash investing and financing activities:(2) | | | | | | | | | | | | | Accrued construction expenditures | | | 120 | | | | 69 | | | | 99 | | Leases(3) | | | 12 | | | | 8 | | | | 8 | | Contributed capital | | | 1 | | | | 6 | | | | — | |
(1) | For the years ended December 31, 2019, 2018 and 2017 there were 0 restricted cash and equivalent balances. |
| | | | | | | | | | | | | | For the Years Ended December 31, (Millions of dollars) | | 2018 | | 2017 | | 2016 | Cash Flows From Operating Activities: | | |
| | |
| | |
| Net income (Loss) | | $ | (589 | ) | | $ | (172 | ) | | $ | 526 |
| Adjustments to reconcile net income to net cash provided from operating activities: | | | | | | | Impairment loss | | 1,376 |
| | 1,118 |
| | — |
| Deferred income taxes, net | | (184 | ) | | (780 | ) | | 207 |
| Depreciation and amortization | | 342 |
| | 323 |
| | 310 |
| Amortization of nuclear fuel | | 47 |
| | 44 |
| | 57 |
| Allowance for equity funds used during construction | | (11 | ) | | (15 | ) | | (26 | ) | Carrying cost recovery | | (6 | ) | | (34 | ) | | (17 | ) | Changes in certain assets and liabilities: | | | | | | | Receivables | | 50 |
| | (32 | ) | | (47 | ) | Receivables - affiliate | | (2 | ) | | 12 |
| | (3 | ) | Income tax receivable | | 198 |
| | (145 | ) | | (53 | ) | Inventories | | (54 | ) | | (60 | ) | | (35 | ) | Prepayments | | — |
| | 6 |
| | (4 | ) | Regulatory assets | | (179 | ) | | 185 |
| | (94 | ) | Other regulatory liabilities | | (360 | ) | | 899 |
| | (5 | ) | Accounts payable | | 61 |
| | 20 |
| | 8 |
| Accounts payable - affiliate | | — |
| | (28 | ) | | 13 |
| Revenue subject to refund | | 77 |
| | — |
| | — |
| Unrecognized tax benefits | | 19 |
| | (241 | ) | | 192 |
| Taxes accrued | | 31 |
| | 13 |
| | (104 | ) | Pension and other postretirement benefits | | 15 |
| | (21 | ) | | 39 |
| Other assets | | 77 |
| | (46 | ) | | (99 | ) | Other liabilities | | 22 |
| | (43 | ) | | 58 |
| Other liabilities - affiliate | | (3 | ) | | 3 |
| | (1 | ) | Net Cash Provided From Operating Activities | | 927 |
| | 1,006 |
| | 922 |
| Cash Flows From Investing Activities: | | |
| | |
| | |
| Property additions and construction expenditures | | (633 | ) | | (928 | ) | | (1,399 | ) | Proceeds from monetization of guaranty settlement | | — |
| | 1,096 |
| | — |
| Proceeds from investments and sales of assets (including derivative collateral returned) | | 40 |
| | 118 |
| | 794 |
| Purchase of investments (including derivative collateral posted) | | (29 | ) | | (122 | ) | | (740 | ) | Purchase of investments - affiliate | | (111 | ) | | — |
| | — |
| Payments upon interest rate derivative contract settlement | | — |
| | (39 | ) | | (113 | ) | Proceeds from interest rate derivative contract settlement | | 115 |
| | — |
| | — |
| Proceeds from investments - affiliate | | 111 |
| | — |
| | 9 |
| Investment in affiliate | | (325 | ) | | (28 | ) | | — |
| Net Cash Provided From (Used For) Investing Activities | | (832 | ) | | 97 |
| | (1,449 | ) | Cash Flows From Financing Activities: | | |
| | |
| | |
| Proceeds from issuance of debt | | 795 |
| | — |
| | 494 |
| Repayment of long-term debt | | (825 | ) | | (12 | ) | | (112 | ) | Dividends | | (173 | ) | | (319 | ) | | (301 | ) | Short-term borrowings, net | | (179 | ) | | (552 | ) | | 384 |
| Money pool borrowings, net | | 245 |
| | 8 |
| | (4 | ) | Contribution from parent | | 24 |
| | 3 |
| | 100 |
| Net Cash Provided From (Used For) Financing Activities | | (113 | ) | | (872 | ) | | 561 |
| Net Increase (Decrease) in Cash and Cash Equivalents | | (18 | ) | | 231 |
| | 34 |
| Cash and Cash Equivalents, January 1 | | 395 |
| | 164 |
| | 130 |
| Cash and Cash Equivalents, December 31 | | $ | 377 |
| | $ | 395 |
| | $ | 164 |
| Supplemental Cash Flow Information: | | |
| | |
| | |
| Cash for—Interest paid (net of capitalized interest of $9, $15 and $18) | | $ | 264 |
| | $ | 269 |
| | $ | 251 |
| —Income taxes paid | | 3 |
| | 47 |
| | 289 |
| —Income taxes received | | 216 |
| | 145 |
| | 189 |
| Noncash Investing and Financing Activities: | | | | | | | Accrued construction expenditures | | 69 |
| | 99 |
| | 95 |
| Capital leases | | 8 |
| | 8 |
| | 14 |
| Contributed construction | | 6 |
| | — |
| | — |
|
(2) | See Note 2 for noncash investing and financing activities related to the adoption of a new accounting standard for leasing arrangements. |
(3) | Includes $4 million of financing leases and $8 million of operating leases for the year ended December 31, 2019 and $8 million of capital leases for both years ended December 31, 2018 and 2017. |
See Notes to Consolidated Financial Statements.
23
Dominion Energy South Carolina, Electric & Gas Company and Affiliates Inc.Consolidated Statements of Changes in Common Equity | | Common Stock | | | | | | | | | | | | | | | | | | (millions) | | Shares | | | Amount | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Non- controlling Interest | | | Total Equity | | December 31, 2016 | | | 40 | | | $ | 2,860 | | | $ | 2,481 | | | $ | (3 | ) | | $ | 134 | | | $ | 5,472 | | Total comprehensive income (loss) available (attributable) to common shareholder | | | | | | | | | | | (185 | ) | | | (1 | ) | | | 13 | | | | (173 | ) | Capital contribution from parent | | | | | | | | | | | | | | | | | | | 3 | | | | 3 | | Dividend to parent | | | | | | | | | | | (314 | ) | | | | | | | (8 | ) | | | (322 | ) | December 31, 2017 | | | 40 | | | | 2,860 | | | | 1,982 | | | | (4 | ) | | | 142 | | | | 4,980 | | Total comprehensive income (loss) available (attributable) to common shareholder | | | | | | | | | | | (614 | ) | | | 1 | | | | 25 | | | | (588 | ) | Capital contribution from parent | | | | | | | | | | | | | | | | | | | 24 | | | | 24 | | Dividend to parent | | | | | | | | | | | (89 | ) | | | | | | | (12 | ) | | | (101 | ) | December 31, 2018 | | | 40 | | | | 2,860 | | | | 1,279 | | | | (3 | ) | | | 179 | | | | 4,315 | | Cumulative-effect of change in accounting principle | | | | | | | | | | | 1 | | | | (1 | ) | | | | | | | — | | Total comprehensive income (loss) available (attributable) to common shareholder | | | | | | | | | | | (1,240 | ) | | | 1 | | | | 18 | | | | (1,221 | ) | Capital contribution from parent | | | | | | 835 | | | | | | | | | | | | 3 | | | | 838 | | Capital contribution returned to parent | | | | | | | | | | | | | | | | | | | (20 | ) | | | (20 | ) | Dividend to parent | | | | | | | | | | | (20 | ) | | | | | | | | | | | (20 | ) | December 31, 2019 | | | 40 | | | $ | 3,695 | | | $ | 20 | | | $ | (3 | ) | | $ | 180 | | | $ | 3,892 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Non-controlling Interest | | | Millions | | Shares | | Amount | | Retained Earnings | | | | Total Equity | Balance at January 1, 2016 | | 40 |
| | $ | 2,760 |
| | $ | 2,265 |
| | $ | (3 | ) | | $ | 129 |
| | $ | 5,151 |
| Earnings (Loss) Available for (Attributable to) Common Shareholder | | |
| | |
| | 513 |
| | |
| | 13 |
| | 526 |
| Deferred Cost of Employee Benefit Plans, net of tax $- | | |
| | |
| | |
| | — |
| | |
| | — |
| Total Comprehensive Income | | | | | | 513 |
| | — |
| | 13 |
| | 526 |
| Capital contributions from parent | | |
| | 100 |
| | |
| | |
| | — |
| | 100 |
| Cash dividends declared | | |
| | |
| | (297 | ) | | |
| | (8 | ) | | (305 | ) | Balance at December 31, 2016 | | 40 |
| | 2,860 |
| | 2,481 |
| | (3 | ) | | 134 |
| | 5,472 |
| Earnings (Loss) Available for (Attributable to) Common Shareholder | | |
| | |
| | (185 | ) | | |
| | 13 |
| | (172 | ) | Deferred Cost of Employee Benefit Plans, net of tax $- | | |
| | |
| | |
| | (1 | ) | | |
| | (1 | ) | Total Comprehensive Income | | | | | | (185 | ) | | (1 | ) | | 13 |
| | (173 | ) | Capital contributions from parent | | |
| | — |
| | |
| | |
| | 3 |
| | 100 |
| Cash dividends declared | | |
| | |
| | (314 | ) | | |
| | (8 | ) | | (322 | ) | Balance at December 31, 2017 | | 40 |
| | 2,860 |
| | 1,982 |
| | (4 | ) | | 142 |
| | 4,980 |
| Earnings (Loss) Available for (Attributable to) Common Shareholder | | |
| | |
| | (614 | ) | | |
| | 25 |
| | (589 | ) | Deferred Cost of Employee Benefit Plans, net of tax $- | | |
| | |
| | |
| | 1 |
| | | | 1 |
| Total Comprehensive Income (Loss) | | | | | | (614 | ) | | 1 |
| | 25 |
| | (588 | ) | Capital contributions from parent | | |
| | — |
| | |
| | |
| | 24 |
| | 24 |
| Cash dividends declared | | |
| | |
| | (89 | ) | | |
| | (12 | ) | | (101 | ) | Balance at December 31, 2018 | | 40 |
| | $ | 2,860 |
| | $ | 1,279 |
| | $ | (3 | ) | | $ | 179 |
| | $ | 4,315 |
|
See Notes to Consolidated Financial Statements.
SCANA Corporation and Subsidiaries
24
Dominion Energy South Carolina, Electric & Gas Company and Affiliates Inc.Notes to Consolidated Financial Statements
The following notes to the consolidated financial statements are1. NATURE OF OPERATIONS DESC is a combined presentation. Except as otherwise indicated herein, each note applies to the Company and Consolidated SCE&G; however, Consolidated SCE&G makes no representation as to information relating solely towholly-owned subsidiary of SCANA Corporation or its subsidiaries (other than Consolidated SCE&G).
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Principles of Consolidation
Effectivewhich, effective January 1, 2019, SCANA becameis a wholly-owned subsidiary of Dominion Energy under the terms of the Merger Agreement. See additional discussion in Note 2 and Note 11.
The Company
SCANA, a South Carolina corporation,Energy.DESC is a holding company created in 1984. The Company primarily engagesengaged in the generation, transmission and saledistribution of electricity in the central, southern and southwestern portions of South Carolina. Additionally, DESC sells natural gas to wholesaleresidential, commercial and retailindustrial customers in South Carolina,Carolina. Beginning in December 2019, DESC manages its daily operations through 1 primary operating segment: Dominion Energy South Carolina. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General DESC makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of the financial statements and the purchase, salereported amounts of revenues, expenses and transportation of natural gas to wholesalecash flows for the periods presented. Actual results may differ from those estimates. DESC’s Consolidated Financial Statements include, after eliminating intercompany balances and retail customers in South Carolina, North Carolina and Georgia. The accompanying consolidated financial statements reflecttransactions, the accounts of SCANADESC, GENCO and the following wholly-owned subsidiaries.
| | | | Regulated businesses | | Nonregulated businesses | South Carolina Electric & Gas Company | | SCANA Energy Marketing, Inc. | South Carolina Fuel Company, Inc. | | SCANA Services, Inc. | South Carolina Generating Company, Inc. | | SCANA Corporate Security Services, Inc. | Public Service Company of North Carolina, Incorporated | | SCANA Communications Holdings, Inc. |
SCANA reports certain investments using the cost or equity method of accounting, as appropriate. Intercompany balances and transactions have been eliminated in consolidation, with the exception of profits on intercompany sales to regulated affiliates if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable, as permitted by accounting guidance. Discussions regarding the Company's financial results necessarily include the results of Consolidated SCE&G.
Consolidated SCE&G
SCE&G, a public utility, is a South Carolina corporation organized in 1924 and a wholly-owned subsidiary of SCANA. Consolidated SCE&G primarily engages in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
SCE&GFuel Company. DESC has determinedconcluded that it has a controlling financial interest in GENCO and Fuel Company (which are consideredVIE’s due to be VIEs) and accordingly, Consolidated SCE&G's consolidatedthe members lacking the characteristics of a controlling financial statements includeinterest. DESC is the accountsprimary beneficiary of SCE&G, GENCO and Fuel Company.Company and therefore is required to consolidate the VIE’s. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’sDESC’s parent. As a result, GENCO’sGENCO and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in the Consolidated SCE&G’s consolidated financial statements.
Financial Statements.GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold exclusively to DESC, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of aFERC approved 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 $500$508 million) servespreviously served as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’sDESC's nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 5.
Use6.Additionally, DESC purchases shared services from DESS, an affiliated VIE that provides accounting, legal, finance and certain administrative and technical services to all SCANA subsidiaries, including DESC. DESC has determined that it is not the primary beneficiary of Estimates The preparation of financial statementsDESS as it does not have either the power to direct the activities that most significantly impact its economic performance or an obligation to absorb losses and benefits which could be significant to it. See Note 16 for amounts attributable to affiliates.DESC reports certain contracts and instruments at fair value. See Note 9 for further information on fair value measurements. DESC maintains pension and other postretirement benefit plans. See Note 11 for further information on these plans. Certain amounts in conformity with GAAP requires managementthe 2018 and 2017 Consolidated Financial Statements and Notes have been reclassified to make estimates and assumptions thatconform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect the reported amounts ofDESC’s net income, total assets, and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
No estimate is made for legal costs expected to be incurred in connection with loss contingencies. Such costs are recorded when incurred.
equity or cash flows.Utility Plant Utility plant is stated at original cost. The costs of additions, replacements and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and AFC,AFUDC, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged to accumulated depreciation. The costs of repairs and replacements of items of property determined to be less than a unit of property or that do not increase the asset’s life or functionality are charged to expense. AFCAFUDC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFCAFUDC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiariesDESC calculated AFCAFUDC using average composite rates of 7.7% for 2018, 5.6% for 2017,4.3%, 7.0% and 5.3% for 2016. Consolidated SCE&G calculated AFC using average composite rates of 7.0% for 2018, 3.9% for 2019, 2018 and 2017, and 4.7% for 2016.respectively. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&GDESC capitalizes interest on nuclear fuel in process at the actual interest cost incurred. 25
For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from utility plant-in-service when it becomes probable it will be abandoned and recorded as a regulatory asset for amounts expected to be collected through future rates. Provisions for depreciation and amortization are recorded using the straight-line method based on the estimated service lives of the various classes of property, and in most cases, include provisions for future cost of removal. The 2018 composite weighted average depreciation rates for utility plant by function were as follows: | | 2019 | | | 2018 | | Generation | | | 2.50 | % | | | 2.61 | % | Transmission | | | 2.57 | % | | | 2.74 | % | Distribution | | | 2.41 | % | | | 2.41 | % | Storage | | | 2.74 | % | | | 2.71 | % | General and other | | | 3.22 | % | | | 3.18 | % |
| | | | | | | | | | The Company | | Consolidated SCE&G | Generation | | 2.61 | % | | 2.61 | % | Transmission | | 2.47 | % | | 2.74 | % | Distribution | | 2.48 | % | | 2.41 | % | Storage | | 2.48 | % | | 2.71 | % | General and other | | 5.64 | % | | 3.18 | % |
SCE&GDESC records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortizationmethod, which is included in Fuelfuel used in electric generation and recovered through the fuel cost component of retail electric rates.
Planned major maintenance costs related to certain fossil fuel turbine equipment and nuclear refueling outages are accrued in periods other than when incurred in accordance with approval by the SCPSCSouth Carolina Commission for such accounting treatment and rate recovery of expenses accrued thereunder. The difference between such cumulative major maintenance costs and cumulative collections is classified as a regulatory asset or regulatory liability on the consolidated balance sheet. Other planned major maintenance is expensed when incurred. SCE&GDESC is authorized to collect $18.4$18 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2019 and 2018, and 2017, SCE&GDESC incurred $16.3$10 million and $26.1$16 million, respectively, for turbine maintenance.
Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&GSouth Carolina Commission, DESC accrues $17.2$17 million annually for its portion of the nuclear refueling outages scheduled from the spring of 2014 through the spring of 2020. Refueling outage costs incurred for which SCE&GDESC was responsible totaled $28.6$2 million in 20182019 and $23.2$29 million in 2017.
Goodwill
The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company has tested goodwill for impairment annually as of January 1, unless indicators, events or circumstances required interim testing to be performed. The Company performed its test on January 1, 2019 and intends to test goodwill annually on April 1, effective April 1, 2019. Under current accounting guidance, the Company may perform a qualitative assessment of impairment. Based on this assessment, if the Company determines that it is not more likely than not that the2018.Asset Retirement Obligations DESC recognizes AROs at fair value ofas incurred or when sufficient information becomes available to determine a reporting unit is less than its carrying amount, the Company is not required to make a quantitativereasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the reporting unit and to compare that amount to its carrying value. If the Companyrelated tangible long-lived assets. Since relevant market information is required to make a quantitative assessment or if it chooses to do so without first performing a qualitative one, and if the quantitative assessment indicates a carrying value in excess ofnot available, fair value an impairment charge would be required. Any such charge would be treatedis estimated using discounted cash flow analyses. Periodically, DESC assesses its AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. DESC reports accretion of AROs and depreciation on asset retirement costs as an operating expense.
For each period presented, assets with a carrying value of $210 million for PSNC Energy (Gas Distribution segment), net of a writedown of $230 million taken in 2002, were classified as goodwill. The Company performed a quantitative assessment of goodwill in its evaluation as of January 1, 2019 and performed a qualitative assessment of goodwill in its evaluation as of January 1, 2018. No impairment of goodwill was required based on these evaluations.
adjustment to regulatory assets.Nuclear Decommissioning
Based on a decommissioning cost study SCE&G’scompleted in 2016, DESC’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1,Summer, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $625.8$646 million, stated in 20182019 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1.Summer. The cost estimate assumes that the site will be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use. Under SCE&G’sDESC’s method of funding decommissioning costs, SCE&GDESC transfers to an external trust fund the amounts collected through rates ($3.23 million pre-tax in each period presented), less expenses. The trust invests the amounts transferred into insurance policies on the lives of certain company personnel. Insurance proceeds are reinvested in insurance policies. The asset balance held in trust reflects the net cash surrender value of the insurance policies and cash held by the trust. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1Summer on an after-tax basis. 26
Cash, Restricted Cash and Equivalents Cash, Equivalents Temporaryrestricted cash and equivalents include cash on hand, cash in banks and temporary investments havingpurchased with an original maturitiesmaturity of three months or less at time of purchase are considered to beless. At December 31, 2019, there were 0 restricted cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.equivalent balances. At December 31, 2018, cash and cash equivalents at the Company and Consolidated SCE&GDESC included approximately $115.3$115 million held in escrow pending a settlement which was contingent on the consummation of the merger with Dominion Energy and final approval of a legal settlement in the SCE&G Ratepayer Case.Energy. As such, the Company and Consolidated SCE&GDESC did not consider these amountsthis amount to be restricted at December 31, 2018. See Claims and Litigation in Note 11 for additional discussion.
Customer receivables reflect amounts due from customers arising from the delivery of energy or related services and include both billed and unbilled amounts earned pursuant to revenue recognition practices described in Note 3.4. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $217.5$114 million and $129 million at December 31, 2019 and 2018, respectively. DESC sells electricity and $220.9 million at December 31, 2017 fornatural gas and provides distribution and transmission services to customers in South Carolina. Management believes that this geographic concentration risk is mitigated by the Company. Unbilled revenues totaled $129.3 million at December 31, 2018diversity of DESC’s customer base, which includes a large number of residential, commercial and $140.3 million at December 31, 2017 for Consolidated SCE&G. Other receivables consistindustrial customers. Credit risk associated with accounts receivable is limited due to the large number of customers. DESC’s exposure to potential concentrations of credit risk results primarily offrom amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.
Summer. Such receivables represented approximately 10% of DESC’s accounts receivable balance at December 31, 2019.Inventories
Materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when used. Fuel inventory includes the average cost of coal, natural gas, fuel oil and emission allowances. Fuel is charged to
inventory when purchased and is expensed, at weighted average cost, as used and recovered through fuel cost recovery rates approved by the SCPSC or NCUC, as applicable.
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, 46% and 39% of PSNC Energy’s natural gas inventory at December 31, 2018 and December 31, 2017, respectively, with a carrying value of $13.9 million and $11.5 million, respectively. Under the terms of this agreement, PSNC Energy receives storage asset management feesof which 75% are credited to customers. This agreement has been extended and expires October 31, 2020.
South Carolina Commission.Income Taxes SCANA filesA consolidated federal income tax returns. Under a jointreturn was filed for SCANA, including DESC for years through 2018. Beginning in 2019, SCANA and DESC are part of Dominion Energy’s consolidated federal income tax allocation agreement, each subsidiary’sreturn. In addition, where applicable, combined income tax returns for Dominion Energy, including DESC, are filed in various states including South Carolina; otherwise, separate state income tax returns are filed. DESC participated in intercompany tax sharing agreements with SCANA through the SCANA Combination, and currently participates in similar agreements with Dominion Energy. Under both SCANA and Dominion Energy’s tax sharing agreements, current income taxes are based on taxable income or loss and credits determined on a separate company basis. Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other SCANA or Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax expense is computed onasset until realized. The 2017 Tax Reform Act included a stand-alone basis.broad range of tax reform provisions affecting DESC, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the tax effects of all significant temporary differences betweenperiod in which the book basis and tax basis oflaw is enacted, even if the assets and liabilities at currently enactedrelate to other components of the financial statements, such as items of accumulated other comprehensive income. DESC, as a rate-regulated utility, was required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates will be recovered or shared with customers in future rates, DESC recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense. Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are adjustedprovided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. DESC establishes a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. DESC did not have any valuation allowances recorded for the periods presented. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities. DESC recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2019, DESC had $132 million of unrecognized tax benefits. 27
If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in taxes accrued on the Consolidated Balance Sheets. DESC recognizes interest on underpayments and overpayments of income taxes in interest expense and interest income, respectively. Penalties are also recognized in other expenses. Interest expense for DESC was $18 million, $8 million and less than $1 million in 2019, 2018, and 2017, respectively. Interest income for DESC was $2 million in 2019 and 2018, and less than $1 million in 2017. DESC also recorded penalty expenses of $7 million in 2019. At December 31, 2019, DESC had an income tax-related affiliated receivable of $21 million from Dominion Energy. This balance is expected to be received from Dominion Energy. At DESC investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold. Regulatory Assets and Liabilities The accounting for DESC’s regulated gas and regulated electric operations differs from the accounting for nonregulated operations in that DESC is required to reflect the effect of rate regulation in its Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. DESC evaluates whether or not recovery of its regulatory assets through future rates is probable as well as whether a regulatory liability due to customers is probable and makes various assumptions in its analyses. These analyses are generally based on: | • | Orders issued by regulatory commissions, legislation and judicial actions; |
| • | Discussions with applicable regulatory authorities and legal counsel; |
| • | Forecasted earnings; and |
| • | Considerations around the likelihood of impacts from events such as unusual weather conditions, extreme weather events and other natural disasters and unplanned outages of facilities. |
Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. A regulatory liability, if considered probable, will be recorded in the period such assessment is made or reversed into earnings if no longer probable. See Note 3 to the Consolidated Financial Statements for additional information. Derivative Instruments DESC uses derivative instruments such as swaps to manage interest rate risks of its business operations. Derivatives are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. DESC does not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. DESC had margin assets of $19 million and $11 million associated with cash collateral at December 31, 2019 and 2018, respectively. DESC had 0 margin liabilities associated with cash collateral at December 31, 2019 and 2018. See Note 8 for further information about derivatives. Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings. All income statement activity, including amounts realized upon settlement, is presented in interest charges based on the nature of the underlying risk. DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS In accordance with accounting guidance pertaining to derivatives and hedge accounting, DESC designates a portion of their derivative instruments as cash flow hedges for accounting purposes. For derivative instruments that are accounted for as cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows. Cash Flow Hedges- DESC uses interest rate swaps to hedge its exposure to variable interest rates on long-term debt. For transactions in which the Company is hedging the variability of cash flows, changes in the fair value of the derivatives are reported in regulatory 28
assets or credits toliabilities. Any derivative gains or losses reported in regulatory assets or liabilities if such impacts are expectedreclassified to be recovered from, or passed through to, customers ofearnings when the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 6 for a discussion of the impact of adjustments recorded in connection with enactment of the Tax Act.
Consolidated SCE&Gforecasted item is included in earnings. For cash flow hedge transactions, hedge accounting is discontinued if the consolidated federal income tax returns of SCANA for all periods presented. Also, under provisions of an income tax allocation agreement, certain tax benefitsoccurrence of the parent holding company are distributed inforecasted transaction is no longer probable.Pursuant to regulatory orders, interest rate derivatives entered into by DESC after October 2013 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to tax paying affiliates, including Consolidated SCE&G, in the form of capital contributions. Regulatory Assets and Regulatory Liabilities
The Company’s rate-regulated utilities, including Consolidated SCE&G, record costs thatthem have been or are expected to be allowed in the ratemaking process in periods that differ from those in which the costs would be charged to expense, or record revenues in periods that differ from those in which the revenues would be recorded by a nonregulated enterprise. These expenses deferred for future recovery from customers or obligations for refunds to customers are primarily classified on the balance sheet as regulatory assets and regulatory liabilities (seeliabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest charges or have been applied as otherwise directed by the South Carolina Commission. See Note 2)3 and are amortized consistent withNote 17 regarding the treatmentsettlement gains realized in the first quarter of 2018.Debt Issuance Costs DESC defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified on the balance sheet as Receivables - Customer or Customer depositsrespective debt issues, considering maturity dates and, customer prepayments, respectively. Debt Issuance Premiums, Discounts and Other Costs
Premiums, discounts andif applicable, redemption rights held by others. Deferred debt issuance costs are presented withinrecorded as a reduction in long-term debt and are amortized as components of interest charges overin the termsConsolidated Balance Sheets. Amortization of the respective debt issues. For regulated subsidiaries,issuance costs is reported as interest charges. As permitted by regulatory authorities, gains or losses on reacquiredresulting from the refinancing or redemption of debt that is refinanced are recorded in other deferred credits or debits and are amortized over the term of the replacement debt, also as interest charges.
An environmental assessment program is maintained to identify and evaluate current and former operations sites that could require environmental clean-up. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. Environmental remediation liabilities are accrued when the criteria for loss contingencies are met. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Probable and estimable costs are accrued related to environmental sites on an undiscounted basis. Amounts estimated and accrued to date for site assessments and clean-up relate solely to regulated operations. Amounts expected to be recovered through rates are recorded in regulatory assets and, if applicable, amortized over approved amortization periods. Other environmental costs are expensed as incurred.
Statement of Operations 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 12) are presented within Operating Income (Loss), and all other activities are presented within Other Income (Expense).
, net.Operating Revenue Recognition Revenues Operating revenue is recorded on the basis of services rendered, commodities delivered, or contracts settled and includes amounts yet to be billed to customers. DESC collects sales, consumption, consumer utility taxes and sales taxes; however, these amounts are excluded from revenue and are recorded duringas liabilities until they are remitted to the accounting period in which servicesrespective taxing authority. The primary types of sales and service activities reported as operating revenue for DESC, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are providedas follows: Revenue from Contracts with Customers | • | Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; |
| • | Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services; and |
| • | Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities. |
Other Revenue | • | Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues. |
DESC records refunds to customers as required by the South Carolina Commission as a reduction to regulated electric sales or regulated gas sales, as applicable. Revenues from electric and include estimated amountsgas sales are recognized over time, as the customers of DESC consume gas and electricity as it is delivered. Sales of products and services, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for electricitymost sales and natural gas deliveredservices varies by contract type, but not billed.
Fuel costs, emission allowances and certain environmental reagent costs for electric generation are collected through the fuel cost component in retail electric rates. The SCPSC establishes this component during fuel cost proceedings. Any difference between actual fuel costs and amounts contained in the fuel cost component is adjusted through revenue and is deferred and included when determining the fuel cost component during subsequent proceedings.
SCE&Gtypically due within a month of billing.DESC customers subject to an electric fuel cost recovery component or a PGA are billed based on a fuel or cost of gas factor calculated in accordance with a gas cost recovery procedureprocedures approved by the SCPSCSouth Carolina Commission and subject to adjustment monthly.periodically. Any difference between actual gas costs and amounts contained in rates is adjusted through revenue and is deferred and included when making the next adjustment to the cost of gas factor. PSNC Energy’s PGA mechanism authorized by the NCUC allows the recovery of all prudently incurred gas costs, including the results of its hedging program, from customers. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during subsequent PGA filings or in annual prudence reviews. Taxes billed to and collected from customers are recorded as liabilities until they are remitted to the respective taxing authority. Such taxes are not included in revenues or expenses in the statements of operations. factors.
Earnings (Loss) Per Share
The Company computes basic earnings (loss) per share by dividing net income (loss) by the weighted average number of common shares outstandingCertain amounts deferred for the period. When applicable, the Company computes diluted earnings (loss) 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
Recently Adopted
In the first quarter of 2018, the CompanyWNA arise under specific arrangements with regulators rather than customers and Consolidated SCE&G adopted the following accounting guidance,are accounted for as applicable, issued by the FASB. The adoption of this guidance had no impact or no significant impact on their respective financial statements except as indicated.
Goodwill impairment guidance, issued in January 2017, removed Step 2 of the goodwill impairment test.
Guidance foran alternative revenue program. This alternative revenue is included within Other operating revenues, separate from revenue arising from contracts with customers, uses a five-step analysis in determining when and how revenue is recognized, and requires that revenue recognition depict the transfer of control of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. As permitted, this guidance was adopted using the modified retrospective method whereby amounts and disclosures for prior periods were not restated. Revenue recognition patterns did not change as a result of adopting this guidance, and no cumulative effect adjustment to Retained Earnings was required. For additional required disclosures, see Note 3.
The required presentation of net periodic pension and postretirement benefit costs has been changed to distinguish between service cost components and non-service cost components. Service cost components continue to be included within operating income and are presented in the same line item as other compensation costs arising from services rendered by employees. Non-service cost componentsmonth such adjustments are now excluded from operating income. This guidance has been applied retrospectively for the presentation of the service cost components and other components, and resulted in the following changes to amounts reported in 2017 and 2016.
| | | | | | | | | | | | | | | | | | Increase (Decrease) Millions of dollars | | The Company | | Consolidated SCE&G | Year Ended December 31 | | 2017 | | 2016 | | 2017 | | 2016 | Other operation and maintenance | | $ | (9 | ) | | $ | (14 | ) | | $ | (7 | ) | | $ | (12 | ) | Total Operating Expenses | | (9 | ) | | (14 | ) | | (7 | ) | | (12 | ) | Operating Income | | 9 |
| | 14 |
| | 7 |
| | 12 |
| Other Income (Expense), Net | | (9 | ) | | (14 | ) | | (7 | ) | | (12 | ) |
In addition, this guidance limits eligibility for capitalization of net periodic pension and postretirement benefit costs to only the service cost component, and requires this change to be applied prospectively. Accordingly, no reclassifications were made related to the capitalization of service costs. Effective January 1, 2018, amounts which otherwise would have been capitalized to plant accounts under prior guidance are now being deferred within regulatory assets.
Guidance issued in January 2016 changed how entities measure certain equity investments and financial liabilities, among other things.
Guidance issued in August 2016 is intendedaccounts. As permitted, DESC has elected to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented.
Guidance issued in November 2016 clarified how restricted cash should be presented on the statement of cash flows, and entities were to apply the guidance retrospectively to all periods presented.
Pending Adoption
The Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB when indicated below.
In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.
The guidance is effective for the Company's and Consolidated SCE&G's interim and annual reporting periods beginning January 1, 2019. This revised accounting guidance will be adopted using a modified-retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Company and Consolidated SCE&G are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Company and Consolidated SCE&G will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. The Company and Consolidated SCE&G anticipate that the adoption of this guidance will result in approximately $30 million to $35 million and $15 million to $20 million, respectively, of offsetting right-of-use assets and liabilities added to their consolidated balance sheets for operating leases in effect at the adoption date. No material changes are expected to the Company's and Consolidated SCE&G's results of operations.
In August 2017, the FASB issued accounting guidance intended to simplify the application of hedge accounting. Among other things, the new guidance will enable more hedging strategies to qualify for hedge accounting, will allow entities more time to perform an initial assessment of hedge effectiveness, and will permit an entity to perform a qualitative assessment of effectiveness for certain hedges instead of a quantitative one. For cash flow hedges that are highly effective, all changes in the fair value of the derivative hedging instrument will be recorded in other comprehensive income and will be reclassified to earnings in the same period that the hedged item impacts earnings. Fair value hedges will continue to be recorded in current earnings, and any ineffectiveness will impact the income statement. In addition, changes in the fair value of a derivative will be recorded in the same income statement line as the earnings effect of the hedged item, and additional disclosures will be required related to the effect of hedging on individual income statement line items. The guidance must be applied to all outstanding instruments using a modified retrospective method, with any cumulative effect adjustment recorded to opening retained earnings as of the beginning of the first period in which the guidance becomes effective. The Company and
Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 and do not expect it to have a significant impact on their respective financial statements.
In February 2018, the FASB issued accounting guidance allowing entities to reclassify from AOCI to retained earnings any amounts for stranded tax effects resulting from the Tax Act. The guidance must be applied eitherregulatory accounts in the period of adoption or retrospectively to each period in which the effect of the change was recognized. The Company and Consolidated SCE&G will adopt this guidance when required in the first quarter of 2019 on a prospective basis. Upon adoption, the Company and Consolidated SCE&G expect to record cumulative effect adjustments to retained earnings and AOCI in their statements of changes in common equity (in the amount of $8 million and $1 million at the Company and Consolidated SCE&G, respectively) and do not expect any other significant impact on their financial statements. The amounts to be reclassified reflect the impact of the reduction in the federal income tax rate arising from the Tax Act, and the related federal benefit of state income taxes, on the components of the Company’s and Consolidated SCE&G’s AOCI.
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 in certain instances may result in 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. A modified-retrospective approach is required upon adoption, whereby a cumulative-effect adjustment to retained earnings is made as of the beginning of the first reporting period in which the guidance is effective. 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 2018, the FASB issued accounting guidance to modify the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance must be applied retrospectively to all periods presented. The Company and Consolidated SCE&G must adopt this guidance beginning in 2020, including interim periods, though the guidance may be adopted earlier. The Company and Consolidated SCE&G have not determined when this guidance will be adopted or what impact it will have on their respective statements of financial position.
2. RATE AND OTHER REGULATORY MATTERS
Rate Matters
Tax Act Regulatory Proceedings
The Tax Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the SCPSC and NCUC have required SCE&G and PSNC Energy to track and defer impacts related to the Tax Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act. Certain of thesesuch amounts are protected under normalization rules and will be amortized over the remaining regulatory life of the property, and certain of these amounts will be amortized to the benefit of customers, as instructed by regulators, which ranges from 5 years to 50 years.
As of December 31, 2018, SCE&G has recorded approximately $73.7 million as Revenue subject to refund and approximately $3.7 million as Regulatory liabilitiesreflected on the consolidated balance sheet for the Company and Consolidated SCE&G, and PSNC Energy has recorded approximately $15.4 million of such deferrals within Regulatory liabilities on the consolidated balance sheet for the Company. These amounts were collected through customer rates in 2018 and include the accrual of estimated carrying costs. In addition, the Company and Consolidated SCE&G have recorded amounts related to excess deferred income taxes arising from the Tax Act within Regulatory liabilities. For a discussion of related actions taken by the SCPSC and NCUC, see Electric - Other, Gas - SCE&G, and Gas - PSNC Energy below.
Electric - BLRA and Merger Approval Order
In 2016, the SCPSC approved revised rates under the BLRA to incorporate financing cost of SCE&G's incremental construction work in progress incurred for the Nuclear Project. Rate adjustments resulted in approximately $64.4 million in additional revenue on an annual basis and were effective for bills rendered on and after November 27, 2016. Such rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE of 10.5% applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016. No revised rates filings were pursued after this 2016 approval.
In May 2016, SCE&G petitioned the SCPSC for approval of updated construction and capital cost schedules for Unit 2 and Unit 3 which had been developed in connection with the October 2015 Amendment. On November 9, 2016, the SCPSC approved a settlement agreement among SCE&G, the ORS and certain other parties concerning this petition. The SCPSC also approved SCE&G's election of the fixed price option included in that October 2015 contract amendment. By order dated February 28, 2017, the SCPSC denied Petitions for Rehearing filed by certain parties that were not included in the settlement, and that denial was not appealed.
On July 2 and 3, 2018, the SCPSC issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from customers under the BLRA. These orders reduced the portion of SCE&G's retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer's bill to approximately 3.2%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019 pursuant to the Merger Approval Order.
On December 21, 2018, the SCPSC issued the Merger Approval Order. The order adopted Dominion Energy's Plan-B Levelized Customer Benefits Plan whereby the average bill for an SCE&G residential electric customer would approximate that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSC retroactive to April 1, 2018. The Merger Approval Order established an allowed ROE of 9.9% on unrecovered Nuclear Project costs, and resulted in the following findings and conditions:
No capital costs related to the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G.
SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years.
Except for rate adjustments for fuel and environmental costs, demand side management costs, and other rates routinely adjusted on an annual or biannual basis, SCE&G will freeze retail electric base rates at current levels until January 1, 2021.
SCE&G's natural gas customers will receive a refund totaling $2.45 million in 2019, 2020 and 2021 combined.
Corporate giving will increase above historical levels by $1 million per year for at least five years.
SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger.
Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters. See also Note 11.
Electric - Cost of Fuel
SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.
By order dated April 29, 2016, the SCPSC approved a settlement agreement among SCE&G, ORS and certain other parties to decrease the total fuel cost component of retail electric rates. SCE&G reduced the total fuel cost component of retail electric rates to reflect lower projected fuel costs and to eliminate over-collected balances of approximately $61 million for base fuel and environmental costs over a 12-month period beginning with the first billing cycle of May 2016. SCE&G also began to recover projected DER program costs of approximately $6.9 million beginning with the first billing cycle of May 2016.
By order dated April 27, 2017, the SCPSC approved a settlement agreement among SCE&G, the ORS and the 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 costs would be allowed for base fuel component under-collected balances as they occurred.
On April 25, 2018, the SCPSC approved SCE&G’s proposal to increase the total fuel cost component of retail electric rates. Specifically, the SCPSC approved an increase to certain environmental, avoided capacity and DER program cost
components and SCE&G’s agreement to maintain its base fuel component to produce a projected under-recovered balance of approximately $1.3 million at the end of the 12-month period beginning with the first billing cycle of May 2018. This projected under-recovered balance includes the effect of offsetting fuel cost recovery with gains realized from the settlement of certain interest rate derivatives in 2018. SCE&G also agreed to recover, over a 12-month period beginning with the first billing cycle of May 2018, projected DER program costs of approximately $29.3 million. Petitions for rehearing and reconsideration were filed by various parties, and on October 30, 2018, the SCPSC issued an order granting one such petition related to SCE&G supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that SCE&G is required to pay to solar energy developers, and these appeals are pending. The Company and Consolidated SCE&G cannot predict the outcome of these matters.
On February 8, 2019, SCE&G filed with the SCPSC a proposal to decrease the total fuel cost component of retail electric rates. In the filing, SCE&G proposed to maintain its base fuel component at the current level to produce a projected under-recovered balance of approximately $35.4 million at the end of the 12-month period beginning with the first billing cycle of May 2019, and requested carrying costs for any base fuel under-collected balances, should they occur. SCE&G also proposed to reduce its variable environmental component and maintain or reduce its DER components. A public hearing on this matter is scheduled to be held in April 2019.
Electric - Base Rates
Pursuant to an SCPSC order, SCE&G removed from rate base certain deferred income tax assets arising from capital expenditures related to Unit 2 and Unit 3 and accrued carrying costs on those amounts during periods in which they were not included in rate base. Such carrying costs were determined at SCE&G’s weighted average long-term debt borrowing rate and were recorded as a regulatory asset and other income. Carrying costs totaled $18.8 million during 2017 and $14.0 million during 2016. As part of the Nuclear Project impairment loss described in Note 11, accumulated carrying costs related to these deferred income tax assets totaling $51.0 million were written off in 2017.
Electric - Other
The SCPSC has approved a suite of DSM Programs for development and implementation. SCE&G offers to its retail electric customers several distinct programs designed to assist customers in reducing their demand for electricity and improving their energy efficiency. SCE&G submits annual filings to the SCPSC related to these programs which include actual program costs, net lost revenues (both forecasted and actual), customer incentives, and net program benefits, among other things. As actual DSM Program costs are incurred, they are deferred as regulatory assets and recovered through a rate rider approved by the SCPSC. The rate rider also provides for recovery of net lost revenues and for a shared savings incentive. The SCPSC approved the following rate riders pursuant to the annual DSM Programs filings, which went into effect as indicated below:
| | | | | | Year | | Effective | | Amount | 2018 | | First billing cycle of May | | $33.0 million | 2017 | | First billing cycle of May | | $37.0 million | 2016 | | First billing cycle of May | | $37.6 million |
In January 2019, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of approximately $30.3 million of costs and net lost revenues associated with DSM Programs, along with an incentive to invest in such programs.
SCE&G utilizes a pension costs rider approved by the SCPSC which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. In 2017, this rider was adjusted to decrease annual revenue by approximately $11.9 million. No adjustment was made in 2018. No adjustment has been proposed in 2019.
As part of the Merger Approval Order, the SCPSC approved refunds of approximately $100 million by SCE&G for the impact of the lower federal tax rate resulting from the Tax Act. The refunds include amounts which had been collected through customer rates in 2018 and January 2019 and also include the effects of the amortization of certain excess deferred taxes during the same period. At December 31, 2018, amounts to be refunded to electric customers totaled approximately $91 million, and were comprised of approximately $70 million included within Revenue subject to refund and approximately $21 million included within Regulatory liabilities. These refunds have been included in bills rendered on and after the first billing cycle of
February 2019. In addition, the SCPSC approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act will be amortized to the benefit of customers. This tax rider is expected to reduce base rates to customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings.
Gas - SCE&G
The RSA is designed to reduce the volatility of costs charged to customers by allowing for more timely recovery of the costs that regulated utilities incur related to natural gas infrastructure. The SCPSC has approved the following rate changes pursuant to annual RSA filings effective with the first billing cycle of November in the following years:
| | | | | | | | | | Year | | Action | | Amount | | 2018 | | 4.6 | % | | Decrease | | $19.7 million | * | 2017 | | 2.2 | % | | Increase | | $8.6 million | | 2016 | | 1.2 | % | | Increase | | $4.1 million | |
*Includes the impact of the lower federal corporate tax rate resulting from the Tax Act. The SCPSC also approved revised rate schedules for natural gas service that include a rider to refund certain amounts previously collected from customers for SCE&G's income taxes.
SCE&G's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. SCE&G's gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the SCPSC.
Gas - PSNC Energy
PSNC Energy's Rider D rate mechanism allows it to recover from customers all prudently incurred gas costs and certain related uncollectible expenses as well as losses on negotiated gas and transportation sales.
PSNC Energy establishes rates using a benchmark cost of gas approved by the NCUC, which may be periodically adjusted to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs as necessary to track these changes and accounts for any over- or under-collection of the delivered cost of gas in deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.
On October 28, 2016, the NCUC granted PSNC Energy a net annual increase of approximately $19.1 million, or 4.39%, in rates and charges to customers, and set PSNC Energy's authorized ROE at 9.7%. In addition, the NCUC has authorized PSNC Energy to use a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy files biannual applications to adjust its rates for this purpose. The NCUC has approved those applications for the incremental increase to annual revenue requirements, as follows:
| | | | | | Rates Effective | | 2018 | | 2017 | March 1 | | $14.7 million | | $1.9 million | September 1 | | $1.1 million | | $0.7 million |
On February 15, 2019, PSNC Energy submitted its biannual application to adjust rates associated with its pipeline integrity tracker. As approved by the NCUC, the filing increases PSNC Energy's allowed recovery by approximately $1.7 million effective March 1, 2019.
On November 19, 2018, the NCUC issued an order approving the SCANA Combination subject to a stipulation agreement with the following provisions: (1) customer bill credits of $1.25 million in each of January 2019, 2020 and 2021; (2) a rate moratorium until November 1, 2021 other than for rate adjustments pursuant to the CUT, the Integrity Management Tracker and the PGA; and (3) an agreement that direct merger-related expenses will be excluded from PSNC Energy regulated expenses for ratemaking purposes.
On December 17, 2018, the NCUC issued an order approving PSNC Energy's proposed adjustments to customer rates to reflect the reduction in the federal corporate tax rate arising from the Tax Act. These lower rates became effective for service
rendered on and after January 1, 2019. The impact of the lower tax rate collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC Energy's next general rate case proceeding or in three years, whichever is sooner (i.e., no later than October 25, 2021). The reduction in the federal corporate tax rate and its impact on PSNC Energy's various rate riders will be addressed in future proceedings related to those riders.
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. Except for certain unrecovered nuclear project costs and other 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.
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | | | December 31, | | December 31, | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Regulatory Assets: | | | | |
| | | | | Unrecovered Nuclear Project costs | | $ | 2,768 |
| | 3,976 |
| | $ | 2,768 |
| | 3,976 |
| AROs and related funding | | 406 |
| | 434 |
| | 380 |
| | 410 |
| Deferred employee benefit plan costs | | 302 |
| | 305 |
| | 272 |
| | 273 |
| Deferred losses on interest rate derivatives | | 448 |
| | 456 |
| | 448 |
| | 456 |
| Other unrecovered plant | | 93 |
| | 105 |
| | 93 |
| | 105 |
| DSM Programs | | 65 |
| | 59 |
| | 65 |
| | 59 |
| Pipeline integrity management costs | | 73 |
| | 51 |
| | 9 |
| | 8 |
| Environmental remediation costs | | 27 |
| | 30 |
| | 24 |
| | 25 |
| Deferred storm damage costs | | 35 |
| | 24 |
| | 35 |
| | 24 |
| Deferred transmission operating costs | | 15 |
| | — |
| | 15 |
| | — |
| Other | | 148 |
| | 140 |
| | 147 |
| | 140 |
| Total Regulatory Assets | | $ | 4,380 |
| | $ | 5,580 |
| | $ | 4,256 |
| | $ | 5,476 |
|
| | | | | | | | | | | | | | | | | | Regulatory Liabilities: | | | | |
| | | | | Monetization of guaranty settlement | | $ | 1,098 |
| | 1,095 |
| | $ | 1,098 |
| | 1,095 |
| Accumulated deferred income taxes | | 814 |
| | 1,076 |
| | 659 |
| | 914 |
| Asset removal costs | | 779 |
| | 757 |
| | 541 |
| | 527 |
| Deferred gains on interest rate derivatives | | 77 |
| | 131 |
| | 77 |
| | 131 |
| Other | | 21 |
| | — |
| | 5 |
| | — |
| Total Regulatory Liabilities | | $ | 2,789 |
| | $ | 3,059 |
| | $ | 2,380 |
| | $ | 2,667 |
|
The carrying amount of the regulatory asset for unrecovered Nuclear Project costs has been recorded based on such amount not being probable of loss in accordance with the accounting guidance on abandonments, whereas the other regulatory assets have been recorded based on the probability of their recovery. All regulatory assets represent incurred costs that may be deferred under applicable GAAP for regulated operations. The SCPSC, the NCUC or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including deferred transmissionwithout affecting operating costs that are the subject of regulatory proceedings as further discussed above and in Note 11. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts embodied in rate orders or applicable state law. 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, changes in state law, other changes in the regulatory environment or changes in accounting requirements or other adverse legislative or regulatory developments, 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.
Unrecovered Nuclear Project costs represents expenditures by SCE&G that have been reclassified from construction work in progress and, pursuant to the Merger Approval Order and subsequent SCANA Combination, are to be recovered over a
20-year period ending in 2039. In 2017, such amounts were recorded pending a final determination by the SCPSC. See Note 11 for a discussion of impairment charges related to the Nuclear Project.
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 106 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. SCE&G recovers deferred pension costs through utility rates of approximately $2 million annually for electric operations, which will end in 2044, and approximately $1 million annually for gas operations, which will end in 2027. The remainder of the deferred benefit costs are expected to be recovered through utility rates, primarily over average service periods of participating employees 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. Such deferred amounts are expected to be amortized to interest expense over the lives of the underlying debt which, with respect to (i), is through 2043, and with respect to (ii), is through 2065.
Other 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 electric demand reduction programs, and such deferred costs are being recovered over approximately five years through an approved rate rider.
Pipeline integrity management costs represent operating costs expended to comply with federal regulatory requirements related to natural gas pipelines. PSNC Energy is recovering costs totaling $4.1 million annually through 2021. PSNC Energy is continuing to defer pipeline integrity costs, and as of December 31, 2018 costs of $51.3 million have been deferred pending future approval of rate recovery. Effective November 2018, SCE&G began amortizing deferred pipeline integrity costs at an annual rate of $3.2 million. Prior to November 2018, such costs were amortized at an annual rate of $1.9 million 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. SCE&G's remediation costs are expected to be recovered over periods of up to approximately 16 years, and PSNC Energy's remediation costs of $3.8 million are being recovered over a period that will end in 2021.
Deferred storm damage costs represent storm restoration costs for which SCE&G expects to receive future recovery through customer rates.
Deferred transmission operating costs include deferred depreciation and property taxes associated with certain transmission assets for which SCE&G expects recovery from customers through future rates. See also Note 11.
Various other regulatory assets are expected to be recovered through rates over varying periods through 2047.
Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement. In accordance with the Merger Approval Order, this balance, net of amounts that may be required to satisfy liens described in Note 11, will be refunded to electric customers over a period ending in 2039.
Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the Tax Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been
included in customer rates (a portion of which 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). See also Note 6.
Asset removal costs represent estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future.
3. REVENUE RECOGNITION
Identifying Revenue Streams and Related Performance Obligations
Operating Revenues
Operating revenues arise primarily from the sale and transmission of electricity and the sale and transportation of natural gas. Electric and Gas regulated revenues consist primarily of retail sales to residential, commercial and industrial customers under various tariff rates approved by state regulatory commissions. These tariff rates generally include charges for the energy consumed and a standard basic facilities or demand charge designed to recover certain fixed costs incurred to provide service to the customer. Tariff rates also include commission-approved regulatory mechanisms in the form of adjustments or riders, such as for weather normalization, fuel and environmental cost recovery, energy conservation programs, interruptible service and real time pricing provisions, among others. Electric revenues also include wholesale sales and transmission service, primarily to municipal customers and other service providers, under contracts or tariffs approved by the FERC.
Gas nonregulated revenues arise from natural gas sales at market-based rates. Such sales to residential and certain commercial customers include charges for natural gas delivered, at either variable or fixed prices, together with any applicable customer service charges, charges originating from an interstate pipeline company, and other incidental charges. The Company has determined that its gas marketing subsidiary serves as an agent for distribution services provided by a nonaffiliated company in its retail market. Accordingly, the pass-through charges to customers related to such services are not considered revenues. Sales to other commercial and to industrial customers include commodity and transportation charges for natural gas delivered at contracted rates, together with applicable fees for storage, injection, demand, and charges originating from one or more interstate pipeline companies.
Performance obligations which have not been satisfied by the Company or Consolidated SCE&GDESC relate primarily to demand or standby service for natural gas. Demand or standby charges for natural gas arise when an industrial customer reserves capacity on assets controlled by the service provider and may use that capacity to move natural gas it has acquired from other suppliers. For all periods presented, the amount of revenue recognized by the Company and Consolidated SCE&GDESC for these charges is equal to the amount of consideration they haveDESC has a right to invoice and corresponds directly to the value transferred to the customer. As Leases DESC leases certain assets including vehicles, real estate, office equipment and other assets under both operating and finance leases. For operating leases, rent expense is recognized on a result, amounts related to performance obligations that have not been fully satisfied are not disclosed.
Contracts governingstraight-line basis over the transactions above do not have a significant financing component. Also, due to the natureterm of the commodities underlying these transactions, no performance obligations arise for returns, refunds or warranties. In addition, taxes billedlease agreement, subject to customers are excluded fromregulatory framework. Rent expense associated with operating leases, short-term leases and variable leases is primarily recorded in other operations and maintenance expense in the transaction price. Such amountsConsolidated Statements of Comprehensive Loss. Rent expense associated with finance leases results in the separate presentation of interest expense on the lease liability and amortization expense of the related right-of-use asset in the Consolidated Statements of Comprehensive Loss. Amortization expense and interest charges associated with finance leases are recorded as liabilities until they are remittedin depreciation and amortization and interest charges, respectively, in the Consolidated Statements of Comprehensive Loss or deferred within regulatory assets in the Consolidated Balance Sheets.Certain leases include one or more options to renew, with renewal terms that can extend the respective taxing authoritylease from one to 70 years. The exercise of renewal options is solely at DESC's discretion and is included in the lease term if the option is reasonably certain to be exercised. A right-of-use asset and corresponding lease liability for leases with original lease terms of one year or less are not included in revenues or expensesthe Consolidated Balance Sheets, unless such leases contain renewal options that DESC is reasonably certain will be exercised. The determination of the discount rate utilized has a significant impact on the calculation of the present value of the lease liability included in the statements of operations.
Non-Operating Revenues
Non-operating revenues are derived fromConsolidated Balance Sheets. For DESC’s leased assets, the sale of appliances and water heaters, as well as from contracts coveringdiscount rate implicit in the repair of certain appliances, wiring, plumbing and similar systems and fees received for such repairs from customers not under a repair contract. In addition, the portion of fees received under asset management agreements that regulators have recognizedlease isgenerally unable to be incentives fordetermined from a lessee perspective. As such, DESC uses internally-developed incremental borrowing rates as a discount rate in the Company and Consolidated SCE&G to engage in such transactions is recorded as non-operating revenues.
Revenues from sales are recorded when the appliance or water heater is delivered to the customer. Repair contract coverage fees are recorded when invoiced, generally on a monthly basis in advancecalculation of the periodpresent value of coverage. Additional charges for service calls and non-covered repairsthe lease liability. The incremental borrowing rates are billed and collected at thedetermined based on an analysis of DESC's publicly available secured borrowing rates over various lengths of time service is rendered. Revenues from asset management agreements are recorded when the related fixed monthly amounts are due, whichthat most closely corresponds to timing ofDESC's lease maturities.New Accounting Standards REVENUE RECOGNITION In May 2014, the value received by the customer.
The point at which the customer controls the use of a purchased product or has obtained substantially all of the benefits from repair services, corresponds to when revenues are recorded and performance obligations are fulfilled. Contract assets arising from invoicing repair contract fees in advance of the coverage period are not material. Income earned from financing sales of appliances and other products is recorded within interest income. Any performance obligations arising from returns, refunds or warranties are not material.
Non-operating revenues also arise from sources unrelated to contracts with customers, such as carrying costs recorded on certain regulatory assets, gains from property sales and income from rentals and from equity method investments, among others. In 2018, such amounts include gains realized upon the settlement of certain interest rate swaps (see Note 15). Such revenues are outside the scope of revenuesFASB issued revised accounting guidance for revenue recognition from contracts with customers.
Non-operating revenues DESC adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. No cumulative effect adjustment was recognized upon adoption. For additional required disclosures, see Note 4.LEASES In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are further described in Note 15. Such revenues arising from contracts with customers were not material for any period presented, and accordingly, detailed disclosures regarding these revenues are not provided.
Significant Judgments and Estimates
Electricity and natural gas are sold and delivered torecorded on the customer for immediate consumption and the customer controls the use of, and obtains substantially all of the benefits from, the energy and related services as they are delivered. As such, the related performance obligations are satisfied over time and revenue is recognized over the same period. The Company and Consolidated SCE&G have determined that their right to consideration from a customer directly corresponds to the value of the performance completed at the date each customer invoice is rendered. As a result, the Company and Consolidated SCE&G recognize revenue in the amounts for which they have a right to invoice. This includes estimated amounts unbilled at a balance sheet date, but which are to be invoiced in the normal cycle.
Regulatory mechanisms exist within electric and gas tariffs or orders from regulators that result in adjustments to customer bills. These regulatory mechanisms are designed:
To recover costs related to fuel, pension, pipeline integrity and energy conservation, among others;
To recover carrying costs associated with debt-based financing;
To replace revenues lost as a result of the utility implementing DER programs and DSM Programs; and
For gas revenues, to achieve weather normalization or to decouple gas revenues from weather and other factors through the WNA at SCE&G or the CUT at PSNC Energy.
Recovery of deferred costs and carrying costs and the replacement of lost revenues are components of approved tariffs, and therefore, adjustments to customer bills occur as electricity or natural gas is sold and delivered to the customer. As such, the Company and Consolidated SCE&G have concluded that performance obligations related to these adjustments are not capable of being distinct from the underlying tariff based sales. Accordingly, revenues arising from these adjustments are recorded within Operating Revenues - Electric or Gas - regulated on the statements of operations, consistent with revenues from underlying tariff based sales.
Adjustments for SCE&G’s WNA increase gas customer bills when weather is milder than normal and decrease gas customer bills when weather is colder than normal. These adjustments are made during the same period that the underlying natural gas is sold and delivered to the customer, and the performance obligations associated with these adjustments are not capable of being distinct from tariff based sales. Such adjustments are recorded within Operating Revenues - Gas - regulated on the statements of operations. When weather is significantly milder than normal, SCE&G limits such adjustments on a gas customer’s bill to an amount that would be added if weather were 50% milder than normal. Adjustments exceeding this limit, though still recordedall leases, including those leases classified as operating revenue, are deferred within regulatory assets until customers are subsequently billed forleases, while also refining the excess with the approvaldefinition of the SCPSC.
PSNC Energy’s CUT is a decoupling mechanism that adjusts bills for residential and commercial customers based on per customer average consumption. When average consumption exceeds actual usage, PSNC Energy records increased revenue associated with this undercollection and defers it within regulatory assets. Likewise, when actual usage exceeds average consumption, a decrementlease. In addition, lessees will be required to revenue associated with this overcollection is recorded and deferred within regulatory liabilities. PSNC Energy’s tariff based rates are adjusted semiannually, with the approval of the NCUC, to collect or refund these deferred amounts over the subsequent 12 month period.
Amounts deferred for the WNA and the CUT arise under specific arrangements with regulators rather than customers. As a result, the Company and Consolidated SCE&G have concluded that these arrangements represent alternative revenue programs. Revenue from alternative revenue programs is included within Operating Revenues - Gas - regulated on the statements of operations in the month such adjustments are deferred within regulatory accounts and is shown as Other
operating revenues when disaggregated in the table below. As permitted, the Company and Consolidated SCE&G have elected to reduce the regulatory accounts in the period when such amounts are reflected on customer bills without affecting operating revenues.
Disaggregation of Revenues
The impact of several factors ondisclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.The guidance became effective for DESC's interim and annual reporting periods beginning January 1, 2019. DESC adopted this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, DESC utilized the transition practical expedient to maintain historical presentation for periods before January 1, 2019. DESC also applied the other practical expedients, which required no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no evaluation of existing or expired land easements that were not previously accounted for as leases. In connection with the adoption of this revised accounting guidance, DESC recorded $19 million of offsetting right-of-use assets and liabilities for operating leases in effect at the adoption date. See Note 13 for additional information. NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for DESC beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic 30
benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. TAX REFORM In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. DESC adopted this guidance for interim and annual reporting periods beginning January 1, 2019 on a prospective basis. In connection with the adoption of this guidance, DESC reclassified a benefit of $1 million from AOCI to retained earnings. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of DESC’s AOCI. 3. RATE AND OTHER REGULATORY MATTERS Regulatory Matters Involving Potential Loss Contingencies As a result of issues generated in the ordinary course of business, DESC is involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for DESC to estimate a range of possible loss. For regulatory matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that DESC is able to estimate a range of possible loss. For regulatory matters that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently available information, involves elements of judgment and significant uncertainties and may not represent DESC’s maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below, management does not anticipate that the outcome from such matters would have a material effect on DESC’s financial position, liquidity or results of operations. FERC In June 2019, DESC submitted the 2015 Task Order as a stand-alone rate schedule, which governs DESC’s provision of retail service to the DOE at the Savannah River Site. The 2015 Task Order also includes provisions that govern the operations and maintenance of certain transmission facilities, which DESC had determined to be services that are likely subject to FERC’s jurisdiction. DESC requested that FERC accept the 2015 Task Order for filing to become effective in August 2019 and accept the refund analysis included in the filing for amounts collected under the 2015 Task Order as well as under two prior task orders commencing in 1995 and each covering ten-year periods. During the second quarter of 2019, DESC recorded a $6 million ($4 million after-tax) charge primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Loss. In August 2019, DESC submitted a motion to withdraw the 2015 Task Order filing and related refund analysis as requested by FERC staff. As a result, DESC recorded a $10 million ($7 million after-tax) benefit, primarily within interest charges in DESC’s Consolidated Statements of Comprehensive Loss during the third quarter of 2019, to remove previously recorded reserves. 2017 Tax Reform Act The 2017 Tax Reform Act lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. In response, the South Carolina Commission has required DESC to track and defer impacts related to the 2017 Tax Reform Act arising from customer rates in 2018 as subject to refund. In addition, as further discussed under Regulatory Assets and Regulatory Liabilities below, certain accumulated deferred income taxes contained within regulatory liabilities represent excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act. Certain of these amounts are protected under normalization rules and will be amortized at the weighted average tax rate used to build the reserves over the remaining regulatory life of the property. Other, non-plant related regulatory liabilities will be amortized to the benefit of customers, as instructed by our regulators. As part of the SCANA Combination, the South Carolina Commission approved credits of approximately $100 million by DESC for the impact of the lower federal tax rate resulting from the 2017 Tax Reform Act. The credits included amounts which had been collected through customer rates in 2018 and January 2019 and also included the effects of the amortization of certain excess deferred taxes during the same period. These credits were included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved the implementation of a tax rider whereby amounts collected though customer rates effectively would be reduced and excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the 2017 Tax Reform Act will be amortized to the benefit of customers. This tax rider reduced base rates to customers by approximately $63 million in 2019 and is expected to reduce these rates by $67 million in 2020. Unamortized excess deferred income taxes that remain at the end of 2020 will be considered in future rate proceedings. DESC’s provision of electric transmission service is pursuant to a FERC approved formula rate. In December 2019, FERC issued an order requiring transmission providers with transmission formula rates to account for the impacts of the 2017 Tax Reform Act on rates charged to customers. The order requires companies to include a mechanism to decrease or increase their income tax allowances to account for the 2017 Tax Reform Act and any other future changes in tax law, and to submit annual information reflecting the amortization of these excess deferred income taxes. DESC will make such changes to its formula rate as part of its annual update in May 2020. 31
In January 2020, GENCO filed to modify its formula rate to incorporate a mechanism to decrease or increase its income tax allowances by any excess deferred income taxes resulting from the 2017 Tax Reform Act, and future changes in tax laws. These modifications are expected to decrease charges to DESC for the power it purchases from GENCO. Electric – BLRA In July 2018, the South Carolina Commission issued orders implementing a legislatively-mandated temporary reduction in revenues that could be collected by DESC from customers under the BLRA. These orders reduced the portion of DESC’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer's bill to approximately 3%, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. As a result, in 2018 DESC recorded a charge of $109 million ($82 million after-tax) to operating revenues in DESC’s Consolidated Statements of Comprehensive Loss. The temporary rate reduction remained in effect until February 2019 when rates pursuant to the SCANA Merger Approval Order became effective. Other Regulatory Matters Electric – Cost of Fuel DESC’s retail electric rates include a cost of fuel component approved by the South Carolina Commission which may be adjusted periodically to reflect changes in the price of fuel purchased by DESC. In February 2020, DESC filed with the South Carolina Commission a proposal to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by approximately $44 million and cash flows can vary significantlyis projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and DER components. This matter is pending. In April 2019, the South Carolina Commission approved DESC’s proposal to decrease the total fuel cost component of retail electric rates. DESC's proposal included maintaining its base fuel component at the current level to produce a projected under-recovered balance of $35 million at the end of the 12-month period beginning with the first billing cycle of May 2019 and requested carrying costs for any base fuel under-collected balances, should they occur. DESC also proposed reducing its variable environmental component and maintaining or reducing its DER components. Changes in rates became effective beginning with the first billing cycle of May 2019. In April 2018, the South Carolina Commission approved DESC’s proposal to increase the total fuel cost component of retail electric rates. Petitions for rehearing and reconsideration were filed by customer class. Forvarious parties, and on October 30, 2018, the South Carolina Commission issued an order granting 1 such petition related to DESC supplying certain information as in previous years. The other petitions were denied, and certain parties have appealed the decision to deny their petitions to the South Carolina Supreme Court. These appeals primarily relate to avoided cost rates that DESC is required to pay to solar energy developers, and these appeals are pending. DESC cannot predict the outcome of these matters. Electric Transmission Projects In 2020, DESC expects to begin several electric transmission projects in connection with 2 new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 million. This matter is pending. Electric – Other DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, DESC filed an application with the South Carolina Commission seeking approval to recover $30 million of costs incurred and net lost future revenues associated with these programs, along with an incentive to invest in such programs. In April 2019, the South Carolina Commission approved the request for the rate year beginning with the first billing cycle of May 2019. In January 2020, DESC submitted its annual DSM programs filing to the South Carolina Commission. If approved the filing would allow recovery of approximately $40 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs. This matter is pending. DESC utilizes a pension costs rider approved by the South Carolina Commission which is designed to allow recovery of projected pension costs, including under-collected balances or net of over-collected balances, as applicable. The rider is typically reviewed for adjustment every 12 months with any resulting increase or decrease going into effect beginning with the first billing cycle in May. No adjustment was made in 2019. In 2020, DESC requested that the South Carolina Commission approve an adjustment to this rider to decrease annual revenue by approximately $11 million. This matter is pending. 32
Gas In June 2019, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2019 with a total revenue requirement of $437 million. This represents a $7 million overall increase to its natural gas rates under the terms of the RSA effective for the rate year beginning November 2019. In October 2019, the South Carolina Commission approved a total revenue requirement of $436 million effective with the first billing cycle of November 2019. DESC's natural gas tariffs include a PGA that provides for the recovery of actual gas costs incurred, including transportation costs. DESC’s gas rates are calculated using a methodology which may adjust the cost of gas monthly based on a 12-month rolling average, and its gas purchasing policies and practices are reviewed annually by the South Carolina Commission. Regulatory Assets and Regulatory Liabilities Rate-regulated utilities recognize in their financial statements certain revenues and nonregulated gas revenues,expenses in different periods than do other enterprises. As a result, DESC has recorded regulatory assets and regulatory liabilities which do not have weather normalization mechanismsare summarized in place, weatherthe following table. Except for NND Project costs and conservation measures on energy usage typically affect residential and commercialcertain other unrecovered plant costs, 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. At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | Regulatory assets: | | | | | | | | | NND Project costs(1) | | $ | 138 | | | | 127 | | Deferred employee benefit plan costs(2) | | | 13 | | | | 16 | | Other unrecovered plant(3) | | | 14 | | | | 14 | | DSM programs(4) | | | 17 | | | | 14 | | AROs(5) | | | 28 | | | | — | | Cost of fuel under-collections(6) | | | 13 | | | | 13 | | Other | | | 48 | | | | 40 | | Regulatory assets - current | | | 271 | | | | 224 | | NND Project costs(1) | | | 2,503 | | | | 2,641 | | AROs(5) | | | 293 | | | | 380 | | Cost of reacquired debt(7)(8) | | | 259 | | | | 14 | | Deferred employee benefit plan costs(2) | | | 196 | | | | 256 | | Deferred losses on interest rate derivatives(9) | | | 305 | | | | 442 | | Other unrecovered plant(3) | | | 69 | | | | 79 | | DSM programs(4) | | | 54 | | | | 51 | | Environmental remediation costs(10) | | | 22 | | | | 24 | | Deferred storm damage costs(11) | | | 44 | | | | 35 | | Deferred transmission operating costs(12) | | | 37 | | | | 15 | | Other(13) | | | 110 | | | | 123 | | Regulatory assets - noncurrent | | | 3,892 | | | | 4,060 | | Total regulatory assets | | $ | 4,163 | | | $ | 4,284 | | Regulatory liabilities: | | | | | | | | | Monetization of guaranty settlement(14) | | $ | 67 | | | | 61 | | Income taxes refundable through future rates(15) | | | 16 | | | | 52 | | Reserve for refunds to electric utility customers(16) | | | 143 | | | | — | | Other | | | 30 | | | | 13 | | Regulatory liabilities - current | | | 256 | | | | 126 | | Monetization of guaranty settlement(14) | | | 970 | | | | 1,037 | | Income taxes refundable through future rates(15) | | | 948 | | | | 607 | | Asset removal costs(17) | | | 552 | | | | 541 | | Deferred gains on interest rate derivatives(9) | | | 71 | | | | 75 | | Reserve for refunds to electric utility customers(16) | | | 656 | | | | — | | Other | | | 13 | | | | 4 | | Regulatory liabilities – noncurrent | | | 3,210 | | | | 2,264 | | Total regulatory liabilities | | $ | 3,466 | | | $ | 2,390 | |
(1) | Reflects expenditures associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from electric service customers over a 20-year period ending in 2039. See Note 12 for more information. |
(2) | Employee benefit plan costs 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 South Carolina Commission regulatory orders. DESC expects to recover deferred pension costs through utility rates over periods through 2044. DESC expects to recover other deferred benefit costs through utility rates, primarily over average service periods of participating employees up to 11 years. |
(3) | Represents the carrying value of coal-fired generating units, including related materials and supplies inventory, retired from service prior to being fully depreciated. DESC is amortizing these amounts through cost of service rates over the units' previous estimated remaining useful lives through 2025. Unamortized amounts are included in rate base and are earning a current return. |
(4) | Represents deferred costs associated with electric demand reduction programs, and such deferred costs are currently being recovered over five years through an approved rate rider. |
33
(5) | Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately105 years. |
(6) Represents amounts under-collected from customers pursuant to a greater degree than other customer classes. For utilities, revenue requirements result in increases or decreases in tariff ratesthe cost of fuel components approved by regulatory bodiesthe South Carolina Commission. (7) | Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt or over the life of the replacement debt if refinanced. The reacquired debt had a weighted-average life of approximately 26 years as of December 31, 2019. |
(8) During 2019, DESC purchased certain of its first mortgage bonds as discussed in Note 6. As a result of these transactions, DESC incurred net costs, including write-offs of unamortized discount, premium and often vary by customer class. Also, certain cost recovery and other mechanismsdebt issuance costs, of $270 million. (9) | Represents (i) the 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. |
(10) | Reflects amounts associated with the assessment and clean-up of sites currently or formerly owned by DESC. Such remediation costs are expected to be recovered over periods of up to 16 years. See Note 12 for more information. |
(11) | Represents storm restoration costs for which DESC expects to receive future recovery through customer rates. |
(12) | Includes deferred depreciation and property taxes associated with certain transmission assets for which DESC expects recovery from customers through future rates. See Note 12 for more information. |
(13) | Various other regulatory assets are expected to be recovered through rates over varying periods through 2047. |
(14) | Represents proceeds related to the monetization of the Toshiba Settlement. In accordance with the SCANA Merger Approval Order, this balance, net of amounts that may be required to satisfy liens, will be refunded to electric customers over a 20-year period ending in 2039. See Note 12 for more information. |
(15) | Includes (i) excess deferred income taxes arising from the remeasurement of deferred income taxes in connection with the enactment of the 2017 Tax Reform Act (certain of which are protected under normalization rules and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over prescribed periods as instructed by regulators) and (ii) deferred income taxes arising from investment tax credits, offset by (iii) deferred income taxes that arise from utility operations that have not been included in customer rates (a portion of which relate to depreciation and are expected to be recovered over the remaining lives of the related property which may range up to 85 years). See Note 7 for more information. |
(16) | Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited to customers over an estimated 11-year period in connection with the SCANA Merger Approval Order. See Note 12 for more information. |
(17) | Represents estimated net collections through depreciation rates of amounts to be expended for the removal of assets in the future. |
Regulatory assets have an uneven impact on a particular customer class dependingbeen recorded based on the underlying tariffs affected. For nonregulated gas, revenuesprobability of their recovery. All regulatory assets represent incurred costs that may be deferred under GAAP for regulated operations. The South Carolina Commission or the FERC has reviewed and approved through specific orders certain of the items shown as regulatory assets. In addition, regulatory assets include, but are impactednot limited to, certain costs which have not been specifically approved for recovery by competitive marketone of these regulatory agencies, including deferred transmission operating costs that are the subject of regulatory proceedings as discussed in Note 12. While such costs are not currently being recovered, management believes that they would be allowable under existing rate-making concepts embodied in rate orders or applicable state law and expects to recover these costs through rates tailoredin future periods. 4. OPERATING REVENUE The Company’s operating revenue, subsequent to appeal to specific customer classes. The Company and Consolidated SCE&G have disaggregated operating revenues by customer class as follows:the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following: Year Ended December 31, | | 2019 | | | 2018 | | (millions) | | Electric | | | Gas | | | Electric | | | Gas | | Customer class: | | | | | | | | | | | | | | | | | Residential | | $ | 669 | | | $ | 194 | | | $ | 1,054 | | | $ | 208 | | Commercial | | | 507 | | | | 111 | | | | 744 | | | | 117 | | Industrial | | | 224 | | | | 81 | | | | 385 | | | | 92 | | Other | | | 116 | | | | 18 | | | | 132 | | | | 17 | | Revenues from contracts with customers | | | 1,516 | | | | 404 | | | | 2,315 | | | | 434 | | Other revenues | | | 9 | | | | — | | | | 12 | | | | 1 | | Total Operating Revenues | | $ | 1,525 | | | $ | 404 | | | $ | 2,327 | | | $ | 435 | |
| | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | | PSNC Energy | | Total Gas-regulated | | Gas-nonregulated | Millions of dollars | | Electric | | Gas-regulated | | Gas-regulated | | | 2018 | | | | | | | | | | | Customer class: | | | | | | | | | | | Residential | | $ | 1,054 |
| | $ | 208 |
| | $ | 325 |
| | $ | 533 |
| | $ | 244 |
| Commercial | | 744 |
| | 117 |
| | 125 |
| | 242 |
| | 92 |
| Industrial | | 385 |
| | 92 |
| | 15 |
| | 107 |
| | 422 |
| Transportation | | — |
| | 13 |
| | 32 |
| | 45 |
| | — |
| Other | | 132 |
| | 4 |
| | — |
| | 4 |
| | 38 |
| Revenues from contracts with customers | | 2,315 |
| | 434 |
| | 497 |
| | 931 |
| | 796 |
| Other operating revenues | | 12 |
| | 1 |
| | 3 |
| | 4 |
| | — |
| Total Operating Revenues | | $ | 2,327 |
| | $ | 435 |
| | $ | 500 |
| | $ | 935 |
| | $ | 796 |
|
Contract Liabilities
Contract liabilities represent the obligation to transfer goods or services to a customer for which consideration has already been received from the customer. At December 31, 2018 and 2017, the CompanyDESC had contract liability balances of $9.4$9 million and $8.3$4 million respectively,at December 31, 2019 and Consolidated SCE&G had contract liability balances of $3.6 million and $2.9 million,2018, respectively. DuringFor the twelve monthsyears ended December 31, 2019 and 2018, DESC recognized revenue of $3 million and $4 million from the Company and Consolidated SCE&G recognized all amounts from their respective December 31, 2017beginning contract liability balances as each of themDESC fulfilled theirits obligations to provide service to theirits customers. Such obligations at December 31, 2018 are expected to be fulfilled within twelve months. Contract liabilities are recorded in Customercustomer deposits and customer prepayments in the consolidated balance sheets.
Consolidated Balance Sheets.Contract Costs
Costs to obtain contracts are generally expensed when incurred. In limited instances, SCE&GDESC provides economic development grants intended to support economic growth within SCE&G’sDESC’s electric service territory and defers such grants as regulatory assets on the consolidated balance sheet.Consolidated Balance Sheets. Whenever these grants are contingent on a customer entering into a long-term electric supply contract with SCE&G,DESC, they are considered costs to obtain that underlying contract. Such costs that exceed certain thresholds are deferred and amortized on a straight-line basis over the term of the related service contract, which generally ranges from ten to 15 years.
34
Balances and activity related to contract costs deferred as regulatory assets were as follows: | | Regulatory Assets | | (millions) | | 2019 | | | 2018 | | Beginning balance, January 1 | | $ | 15 | | | $ | 16 | | Amortization | | | (2 | ) | | | (1 | ) | Ending balance, December 31 | | $ | 13 | | | $ | 15 | |
| | | | | | The Company and Consolidated SCE&G | | | Millions of dollars | | Regulatory Assets | January 1, 2018 | | $ | 16.3 |
| Additional costs | | — |
| Amortization | | (1.5 | ) | Impairment | | — |
| December 31, 2018 | | $ | 14.8 |
|
AuthorizedFor all periods presented, DESC's authorized shares of SCANA common stock, were 200 million as of December 31, 2018 and 2017. Authorized shares of SCE&G common stockno par value, were 50 million, as of December 31, 2018which 40.3 million were issued and 2017. Authorizedoutstanding, and DESC's authorized shares of SCE&G preferred stock, no par value, were 20 million, of which 1,000 shares no par value, were issued and outstanding. All outstanding shares of common and preferred stock are held by SCANA.In 2019, DESC received equity contributions of $835 million from SCANA as of December 31, 2018 and 2017. As disclosed in Note 1, effective January 1, 2019, all common stock of SCANA is heldwhich were funded by Dominion Energy.
In 2018, SCANA made equity contributions DESC primarily used these funds to GENCOredeem long-term debt and Fuel Company totaling approximately $23 million and $1 million, respectively.
In February 2019, SCANA received an equity contribution of $675 millionto repay intercompany credit agreement borrowings from Dominion Energy, and SCANA made an equity contribution to SCE&G of $675 million. SCE&G used the funds from this equity contribution to reduce long-term debt.Energy. See Note 5.
SCANA’s articles of incorporation do not limit the dividends that may be paid on its common stock, and the articles of incorporation of each of SCANA's subsidiaries contain no such limitations on their respective common stock.
SCE&G’s6.DESC’s bond indenture under which it issues First Mortgage Bondsfirst mortgage bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G'sDESC's bond indenture permits the payment of dividends on SCE&G'sDESC's common stock only either (1) out of its Surplus (as defined in the bond indenture) or (2) in case there is no Surplus, out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. In addition, the Federal Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects. At both December 31, 20182019 and 2017,2018, retained earnings of approximately $115.0$115 million and $93.9 million, respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’sDESC’s common stock. Pursuant In addition, pursuant to the SCANA Merger Approval Order, the amount of any SCE&GDESC dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. ThereAt December 31, 2019, DESC’s retained earnings are below the balance established by the Federal Power Act as a reserve on earnings attributable to hydroelectric generation plants. As a result, DESC is no specific restriction onprohibited from the payment of dividends by SCE&G.
PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limitwithout regulatory approval until the paymentbalance of cash distributions, including dividends, on PSNC Energy's common stock. These agreements generally limit the sum of distributions to an amount that does not exceed $30 million plus 85% of Consolidated Net Income (as therein defined) accumulated after December 31, 2008 plus the net proceeds of issuances by PSNC Energy of equity or convertible debt securities (as therein defined). As of December 31, 2018, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.
The NCUC, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by PSNC Energy to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by PSNC Energy after such date. In addition, notice to the NCUC is required if payment of dividends causes the equity component of PSNC Energy’s capital structure to fall below 45%.
5.increases. 6. LONG-TERM AND SHORT-TERM DEBT Long-term debt by type with related weighted average effective interestweighted-average coupon rates and maturities at December 31, 2019 and 2018 is as follows: At December 31, | | 2019 Weighted- average Coupon(1) | | | 2019 | | | 2018 | | (millions, except percentages) | | | | | | | | | | | | | DESC: | | | | | | | | | | | | | First Mortgage Bonds, 3.22% to 6.625%, due 2021 to 2065(2) | | | 5.42 | % | | $ | 3,267 | | | $ | 4,990 | | Tax-Exempt Financings: | | | | | | | | | | | | | Variable rate due 2038 | | | 1.65 | % | | | 35 | | | | 35 | | 3.625% and 4.00%, due 2028 and 2033 | | | 3.90 | % | | | 54 | | | | 54 | | Other | | | 3.69 | % | | | 1 | | | | — | | GENCO: | | | | | | | | | | | | | Tax-Exempt Financing, variable rate due 2038 | | | 1.65 | % | | | 33 | | | | 33 | | Secured Senior Notes, 5.49% due 2024(3) | | | | | | | — | | | | 40 | | Affiliated note, 3.05% due 2024 | | | 3.05 | % | | | 230 | | | | — | | Total principal | | | | | | | 3,620 | | | | 5,152 | | Securities due within one year | | | | | | | — | | | | (14 | ) | Unamortized discount, premium and debt issuance costs, net | | | | | | | (32 | ) | | | (36 | ) | Finance leases | | | | | | | 20 | | | | 30 | | Total long-term debt | | | | | | $ | 3,608 | | | $ | 5,132 | |
(1) | Represents weighted-average coupon rates for debt outstanding as of December 31, 2019. |
| | | | | | | | | | | | | | | | | | | | The Company | | | | | | | | | | | | | December 31, | | | | | | 2018 | | 2017 | Dollars in millions | | Maturity | | Balance | | Rate | | Balance | | Rate | SCANA Medium Term Notes (unsecured) | | 2020 | - | 2022 | | $ | 800 |
| | 5.42 | % | | $ | 800 |
| | 5.42 | % | SCANA Senior Notes (unsecured) (a) | | 2019 | - | 2034 | | 70 |
| | 3.44 | % | | 75 |
| | 2.18 | % | SCE&G First Mortgage Bonds (secured) | | 2021 | - | 2065 | | 4,990 |
| | 5.52 | % | | 4,840 |
| | 5.80 | % | GENCO Notes (secured) | | 2019 | - | 2024 | | 40 |
| | 5.49 | % | | 207 |
| | 5.94 | % | Industrial and Pollution Control Bonds (b) | | 2028 | - | 2038 | | 122 |
| | 3.52 | % | | 122 |
| | 3.52 | % | PSNC Energy Senior Debentures and Notes | | 2020 | - | 2047 | | 700 |
| | 5.07 | % | | 600 |
| | 5.19 | % | Other | | 2019 | - | 2027 | | 73 |
| | 3.46 | % | | 28 |
| | 2.83 | % | Total debt | | | | | | 6,795 |
| | | | 6,672 |
| | | Current maturities of long-term debt | | | | | | (59 | ) | | | | (727 | ) | | | Unamortized discount, net | | | | | | (2 | ) | | | | (1 | ) | | | Unamortized debt issuance costs | | | | | | (39 | ) | | | | (38 | ) | | | Total long-term debt, net | | | | | | $ | 6,695 |
| | | | $ | 5,906 |
| | |
|
(2) | In February, March and September 2019, DESC purchased certain of its first mortgage bonds having an aggregate purchase price of $1.8 billion pursuant to tender offers. The February and March tender offers expired in the first quarter of 2019 and the September tender offer expired in the third quarter of 2019. |
(3) | In May 2019, GENCO redeemed its 5.49% senior secured notes due in 2024 at the remaining principal outstanding of $33 million plus accrued interest. |
| | | | | | | | | | | | | | | | | | | | Consolidated SCE&G | | | | | | | | | | | | | December 31, | | | | | | 2018 | | 2017 | Dollars in millions | | Maturity | | Balance | | Rate | | Balance | | Rate | First Mortgage Bonds (secured) | | 2021 | - | 2065 | | $ | 4,990 |
| | 5.52 | % | | $ | 4,840 |
| | 5.80 | % | GENCO Notes (secured) | | 2019 | - | 2024 | | 40 |
| | 5.49 | % | | 207 |
| | 5.94 | % | Industrial and Pollution Control Bonds (b) | | 2028 | - | 2038 | | 122 |
| | 3.52 | % | | 122 |
| | 3.52 | % | Other | | 2019 | - | 2027 | | 30 |
| | 2.97 | % | | 28 |
| | 2.83 | % | Total debt | | | | | | 5,182 |
| | | | 5,197 |
| | |
| Current maturities of long-term debt | | | | | | (14 | ) | | | | (723 | ) | | |
| Unamortized premium (discount), net | | | | | | (1 | ) | | | | 1 |
| | |
| Unamortized debt issuance costs | | | | | | (35 | ) | | | | (34 | ) | | | Total long-term debt, net | | | | | | $ | 5,132 |
| | | | $ | 4,441 |
| | |
|
(a) Variable rate notes hedgedBased on stated maturity dates rather than early redemption dates that could be elected by a fixed interest rate swap (fixed rateinstrument holders, the scheduled principal payments of 6.17%).(b) Includes variable ratelong-term debt of $67.8 million at December 31, 2018 (rate of 1.72%) and 2017 (rate of 1.85%) which are hedged by fixed swaps.
In September 2018, SCANA borrowed $40 million under the five-year credit agreement expiring December 2020. The interest rate on this draw at December 31, 2018 was 3.87%. This draw was repaid January 10, 2019. Proceeds from the draw had been used to provide contractually required credit support, and this deposit is reflected within other assets on the consolidated balance sheet.
In August 2018, SCE&G issued $300 million of 3.50% first mortgage bonds due August 15, 2021, and $400 million of 4.25% first mortgage bonds due August 15, 2028. Proceeds from these sales2019, were used on September 28, 2018, to repay prior to maturity $250 million of 5.25% first mortgage bonds and $300 million of 6.50% first mortgage bonds, each due November 1, 2018. In addition, proceeds were used for general corporate purposes.
In June 2018, GENCO redeemed at maturity $160 million of 6.06% secured notes. The repayment was funded using a combination of money pool borrowings and an equity contribution from SCANA.
In June 2018, PSNC Energy issued $100 million of 4.33% senior notes due June 15, 2028. In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. Proceeds from each of these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.
In March 2018, SCE&G borrowed $100 million under the five-year credit agreement expiring December 2020. The proceeds of this draw were deposited with a natural gas supplier to provide contractually required credit support. In September 2018, SCE&G obtained a surety bond to replace this credit support and, as a result, the deposit was returned and this draw was repaid in September 2018. Also, SCANA obtained letters of credit in favor of natural gas suppliers to provide contractually required credit support.follows:35
(millions, except percentages) | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | Thereafter | | | Total | | First Mortgage Bonds | | $ | — | | | $ | 33 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,234 | | | $ | 3,267 | | Tax-Exempt Financings | | | — | | | | — | | | | — | | | | — | | | | — | | | | 122 | | | | 122 | | Other | | | — | | | | — | | | | — | | | | — | | | | 230 | | | | 1 | | | | 231 | | Total | | $ | — | | | $ | 33 | | | $ | — | | | $ | — | | | $ | 230 | | | $ | 3,357 | | | $ | 3,620 | | Weighted-average coupon | | | | | | | 3.25 | % | | | | | | | | | | | 3.05 | % | | | 5.34 | % | | | | |
As of December 31, 2018, the Company's long-term debt maturities are $59 million in 2019, $368 million in 2020, $797 million in 2021, $266 million in 2022 and $14 million in 2023. These amounts include, for Consolidated SCE&G, $14 million in 2019, $13 million in 2020, $342 million in 2021, $11 million in 2022 and $9 million in 2023.
In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any andSubstantially all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of approximately $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer. Substantially allDESC’s electric utility plant is pledged as collateral in connection with long-term debt.
SCE&GDESC is subject to a bond indenture dated April 1, 1993 (Mortgage) covering substantially all of its electric properties under which all of its first mortgage bonds (Bonds) have been issued. Bonds may be issued under the Mortgage in an aggregate principal amount not exceeding the sum of (1) 70% of Unfunded Net Property Additions (as therein defined), (2) the aggregate principal amount of retired Bonds and (3) cash deposited with the trustee. Bonds, other than certain Bonds issued on the basis of retired Bonds, may be issued under the Mortgage only if Adjusted Net Earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice (2.0) the annual interest requirements on all outstanding Bonds and Bonds to be issued (Bond Ratio). For the year ended December 31, 2018,2019, the Bond Ratio was 4.01.6.88. Adjusted Net Earnings, as therein defined, excludes the impairment loss.
LinesLong-Term Debt – Affiliate In May 2019, GENCO issued a $230 million 3.05% promissory note due to Dominion Energy that matures in May 2024. The issuance by GENCO was approved by the South Carolina Commission. Proceeds from the issuance were used to redeem GENCO’s 5.49% senior secured notes due in 2024 at the remaining principal outstanding of Credit$33 million plus accrued interest, repay money pool borrowings and to return $20 million of contributed equity capital to SCANA. Short-Term BorrowingsDebt In March 2019, DESC became a co-borrower under Dominion Energy's $6.0 billion joint revolving credit facility. DESC's short-term financing is supported through its access to this joint revolving credit facility, which can be used for working capital, as support for the combined commercial paper programs of DESC, Dominion Energy and certain other of its subsidiaries (co-borrowers), and for other general corporate purposes. DESC's share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, were as follows: (millions) | | Facility Limit | | | Outstanding Commercial Paper | | | Outstanding Letters of Credit | | At December 31, 2019 | | $ | 1,000 | | | $ | — | | | $ | — | |
A maximum of $1.0 billion of the facility is available to DESC, less any amounts outstanding to co-borrowers. A sub-limit for DESC is set within the facility limit but can be changed at the option of the co-borrowers multiple times per year. At December 31, 20182019, the sub-limit for DESC was $500 million. If DESC has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term borrowings from DESC's parent or from Dominion Energy. This credit facility matures in March 2023 and 2017, SCANA, SCE&G (including Fuel Company)can be used to support bank borrowings and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations andissuance of commercial paper, borrowings: | | | | | | | | | | | | | | | | | | Millions of dollars | | Total | | SCANA | | SCE&G | | PSNC Energy | December 31, 2018 | | | | | | | | | Lines of credit: | | | | |
| | | | | Five-year, expiring December 2020 | | $ | 1,300.0 |
| | $ | 400.0 |
| | $ | 700.0 |
| | $ | 200.0 |
| Fuel Company five-year, expiring December 2020 | | 500.0 |
| | — |
| | 500.0 |
| | — |
| Total committed long-term | | 1,800.0 |
| | 400.0 |
| | 1,200.0 |
| | 200.0 |
| LOC advances | | 40.0 |
| | 40.0 |
| | — |
| | — |
| Weighted average interest rate | | | | 3.87 | % | | | | | Outstanding commercial paper (270 or fewer days) | | 172.9 |
| | 2.0 |
| | 73.2 |
| | 97.7 |
| Weighted average interest rate | | | | 3.65 | % | | 3.82 | % | | 3.49 | % | Letters of credit supported by LOC | | 37.6 |
| | 37.3 |
| | 0.3 |
| | — |
| Available | | $ | 1,549.5 |
| | $ | 320.7 |
| | $ | 1,126.5 |
| | $ | 102.3 |
|
| | | | | | | | | | | | | | | | | | December 31, 2017 | | | | | | | | | Lines of credit: | | | | | | | | | Five-year, expiring December 2020 | | $ | 1,300.0 |
| | $ | 400.0 |
| | $ | 700.0 |
| | $ | 200.0 |
| Fuel Company five-year, expiring December 2020 | | 500.0 |
| | — |
| | 500.0 |
| | — |
| Three-year, expiring December 2018 | | 200.0 |
| | — |
| | 200.0 |
| | — |
| Total committed long-term | | 2,000.0 |
| | 400.0 |
| | 1,400.0 |
| | 200.0 |
| Outstanding commercial paper (270 or fewer days) | | 350.3 |
| | — |
| | 251.6 |
| | 98.7 |
| Weighted average interest rate | | | | | | 1.92 | % | | 1.93 | % | Letters of credit supported by LOC | | 3.3 |
| | 3.0 |
| | 0.3 |
| | — |
| Available | | $ | 1,646.4 |
| | $ | 397.0 |
| | $ | 1,148.1 |
| | $ | 101.3 |
|
At December 31, 2018, SCANA, SCE&G (including Fuel Company) and PSNC Energy were partiesas well as to support up to $1.0 billion (or the sub-limit, whichever is less) of letters of credit.Also in March 2019, DESC canceled its previous committed long-term facility which was a revolving line of credit agreements in the amounts and for the terms described above. Theseunder a credit agreements areagreement with a syndicate of banks. This previous credit agreement was used for general corporate purposes, including liquidity support for each company'sDESC's commercial paper program and working capital needs, and was set to expire in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. These committed long-term facilities are revolving lines of credit under credit agreements with a syndicate of banks. Wells Fargo Bank, National Association, Bank of America, N.A. and Morgan Stanley Bank, N.A. each provide 9.5%December 2020. (millions) | | Facility Limit(1) | | | Outstanding Commercial Paper | | | Outstanding Letters of Credit | | At December 31, 2018 | | $ | 1,200 | | | $ | 73 | | | $ | — | |
(1) | Included $500 million related to Fuel Company. In February 2019, Fuel Company's commercial paper program and its credit facility were terminated. |
The weighted-average interest rate of the aggregate credit facilities, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd., TD Bank N.A., Credit Suisse AG, Cayman Islands Branch, UBS Loan Finance LLC, MUFG Union Bank, N.A., and Branch Banking and Trust Company each provide 7.9%, and Royal Bank of Canada and U.S. Bank National Association each provide 5.5%. Two other banks provide the remaining support. The Company pays fees to the banks as compensation for maintaining the committed lines of credit. Such fees were not material in any period presented.
In December 2018, SCE&G's three-yearoutstanding commercial paper supported by this credit facility expired and was not replaced. 3.82% at December 31, 2018.In FebruaryApril 2019, Fuel Company's commercial paper program andDESC renewed its credit facility were terminated. Fuel Company's financing needs in the future are expected to be met using the money pool described below.
SCE&G has obtained FERC authority through April 2020 to issue short-term indebtedness and to assume liabilities as a guarantor (pursuant to Section 204 of the Federal Power Act). SCE&G may issue unsecured promissory notes, commercial paper and direct loans in amounts not to exceed $1.6$2.2 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreementsless. In addition, in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million.April 2019, GENCO has obtainedrenewed its FERC authority through April 2020 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less. The authority described herein will expire in October 2019, which reflects a one-year authorization period rather than the two-year period SCE&G and GENCO had requested. In granting the authorization for a shorter period, FERC cited several matters which, at the time, were ongoing, including proceedings involving the ORS and Act 258, as well as the merger between SCANA and Dominion Energy, that could affect SCE&G's and GENCO's circumstances. Were adverse developments to occur with respect to uncertainties highlighted elsewhere, the ability of SCE&G or GENCO to secure renewal of this short-term borrowing authority may be adversely impacted. In January 2019, SCE&G2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization, and that application isauthorization. The applications are pending.
Each of the Company and Consolidated SCE&G36
DESC is obligated with respect to an aggregate of $67.8$68 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A. Thecredit. These letters of credit expire, subject to renewal, in the fourth quarter of 2019.
2020.DESC received FERC approval to enter into an inter-company credit agreement in April 2019 with Dominion Energy under which DESC may have short-term borrowings outstanding up to $900 million. At December 31, 2019, DESC had borrowings outstanding under this credit agreement totaling $355 million, which are recorded in affiliated and related party payables in DESC’s Consolidated SCE&G participatesBalance Sheets. For the twelve months ended December 31, 2019, DESC recorded interest charges of $3 million. DESC participated in a utility money pool with SCANA and another regulated subsidiary of SCANA.SCANA through April 2019. Fuel Company and GENCO remain in the utility money pool. Money pool borrowings and investments bear interest at short-term market rates. For the twelve monthsyears ended December 31, 2019 and 2018, Consolidated SCE&GDESC recorded interest income from money pool transactions of $4.1$8 million and $4 million, respectively, and for the same periods DESC recorded interest expense from money pool transactions of $4.1$8 million and $4 million, respectively. Interest incomeDESC had outstanding money pool borrowings due to an affiliate of $219 million and interest expense for periods in 2017 were not significant. Consolidated SCE&Ginvestments due from an affiliate of $9 million at December 31, 2019. At December 31, 2018, DESC had outstanding money pool borrowings due to an affiliate of $282 million and investments due from an affiliate of $353 million at December 31, 2018. At December 31, 2017 Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $37 million and investments due from an affiliate of $28 million. For each period presented, money pool borrowings were made by Fuel Company and GENCO, and money pool investments were made by SCE&G. On its consolidated balance sheet, Consolidated SCE&GBalance Sheets, DESC includes money pool borrowings within Affiliatedaffiliated and related party payables and money pool investments within Affiliated companiesaffiliated and related party receivables.
ComponentsJudgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. DESC is routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. The 2017 Tax Reform Act included a broad range of tax reform provisions. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits. As indicated in Note 2, DESC’s operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential sharing of other deferred taxes will be determined by our regulators. See Note 3 for more information. DESC has completed the accounting for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized, particularly as it relates to the deductibility of interest expense in consolidated groups such as Dominion Energy. In addition, the major states in which DESC operates have addressed conformity with some or all of the provisions of the 2017 Tax Reform Act, although they may have modified certain provisions. Details of income tax expense (benefit) arefor continuing operations including noncontrolling interests were as follows: Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | Current: | | | | | | | | | | | | | Federal | | $ | — | | | $ | (16 | ) | | $ | (410 | ) | State | | | 34 | | | | — | | | | (18 | ) | Total current expense (benefit) | | | 34 | | | | (16 | ) | | | (428 | ) | Deferred: | | | | | | | | | | | | | Federal | | | | | | | | | | | | | Taxes before operating loss carryforwards, investment tax credits and tax reform | | | (90 | ) | | | (216 | ) | | | 262 | | 2017 Tax Reform Act impact | | | — | | | | (176 | ) | | | (1 | ) | Tax utilization expense of operating loss carryforwards | | | 102 | | | | 46 | | | | — | | State | | | (57 | ) | | | (52 | ) | | | (2 | ) | Total deferred expense (benefit) | | | (45 | ) | | | (398 | ) | | | 259 | | Investment tax credit-amortization | | | (1 | ) | | | (2 | ) | | | (2 | ) | Total income tax expense (benefit) | | $ | (12 | ) | | $ | (416 | ) | | $ | (171 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Current taxes (benefit): | | | | | | | | | | | | | Federal | | $ | (8 | ) | | $ | (414 | ) | | $ | 36 |
| | $ | (16 | ) | | $ | (410 | ) | | $ | 50 |
| State | | 5 |
| | 18 |
| | 13 |
| | — |
| | (18 | ) | | 13 |
| Total current taxes (benefit) | | (3 | ) | | (396 | ) | | 49 |
| | (16 | ) | | (428 | ) | | 63 |
| Deferred tax (benefit) expense, net: | | | | | | |
| | | | | | | Federal | | (352 | ) | | 323 |
| | 203 |
| | (346 | ) | | 261 |
| | 167 |
| State | | (55 | ) | | (37 | ) | | 21 |
| | (52 | ) | | (2 | ) | | 20 |
| Total deferred taxes (benefit) | | (407 | ) | | 286 |
| | 224 |
| | (398 | ) | | 259 |
| | 187 |
| Investment tax credits: | | | | | | | | | | | | | Amortization of amounts deferred-federal | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | Total income tax expense (benefit) | | $ | (412 | ) | | $ | (112 | ) | | $ | 271 |
| | $ | (416 | ) | | $ | (171 | ) | | $ | 248 |
|
In DecemberThe 2017 the Tax Reform Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory tax rate. Due to the regulated nature of the Company’s and Consolidated SCE&G’s operations, the effect of this remeasurement is primarily reflected in excess deferred income tax balances within regulatory liabilities (see Note 2).
Included in the Company’s 2018 federal deferred income tax expense was $53 million for the utilization of operating loss carryforwards. Included in Consolidated SCE&G’s 2018 federal deferred income tax expense was $46 million for the utilization of operating loss carryforwards.
The difference between actual income tax expense and the amount calculated from the application ofreduced the statutory federal income tax rate to pre-tax21% beginning in January 2018. Accordingly, current and deferred income is reconciledtaxes are recorded at the new 21% rate.Subsequent to the SCANA Combination, DESC’s annual utilization of its net operating losses are restricted by the tax law, however in certain circumstances the utilization may be increased if SCANA recognizes built-in gains on certain sales of assets. In December 2019, SCANA recognized a gain on the sale of SCANA Energy Marketing, Inc.’s assets to Dominion Energy, which increased the amount of DESC’s 2019 net operating loss utilization by approximately $79 million. 37
For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to DESC’s effective income tax rate as follows: Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | U.S. statutory rate | | | 21.0 | % | | | 21.0 | % | | | 35.0 | % | Increases (reductions) resulting from: | | | | | | | | | | | | | State taxes, net of federal benefit | | | 3.9 | | | | 3.8 | | | | 2.3 | | State investment tax credits | | | — | | | | 0.3 | | | | 1.5 | | AFUDC - equity | | | — | | | | 0.2 | | | | 1.5 | | Amortization of federal investment tax credits | | | 0.1 | | | | 0.2 | | | | 0.6 | | Production tax credits | | | 0.4 | | | | 0.9 | | | | 2.3 | | Domestic production activities deduction | | | — | | | | — | | | | 5.2 | | Reversal of excess deferred income taxes | | | (1.4 | ) | | | — | | | | — | | Federal legislative change | | | — | | | | 17.5 | | | | 0.3 | | NND Project impairment | | | (2.4 | ) | | | (2.3 | ) | | | — | | Write-off of regulatory asset | | | (15.8 | ) | | | — | | | | — | | Changes in unrecognized tax benefits | | | (5.1 | ) | | | — | | | | — | | Other | | | 0.2 | | | | (0.2 | ) | | | 1.2 | | Effective tax rate | | | 0.9 | % | | | 41.4 | % | | | 49.9 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | U.S. statutory rate | | 21 | % | | 35 | % | | 35 | % | | 21 | % | | 35 | % | | 35 | % | Net income (loss) | | $ | (528 | ) | | $ | (119 | ) | | $ | 595 |
| | $ | (614 | ) | | $ | (185 | ) | | $ | 513 |
| Income tax expense (benefit) | | (412 | ) | | (112 | ) | | 271 |
| | (416 | ) | | (171 | ) | | 248 |
| Noncontrolling interest | | — |
| | — |
| | — |
| | 25 |
| | 13 |
| | 13 |
| Total pre-tax income (loss) | | $ | (940 | ) | | $ | (231 | ) | | $ | 866 |
| | $ | (1,005 | ) | | $ | (343 | ) | | $ | 774 |
| | | | | | | | | | | | | | Income taxes (benefit) on above at statutory federal income tax rate | | $ | (197 | ) | | $ | (81 | ) | | $ | 303 |
| | $ | (211 | ) | | $ | (120 | ) | | $ | 271 |
| Increases (decreases) attributed to: | | | | | | |
| | | | | | | State income taxes (less federal income tax effect) | | (37 | ) | | (7 | ) | | 27 |
| | (38 | ) | | (8 | ) | | 26 |
| State investment tax credits (less federal income tax effect) | | (3 | ) | | (5 | ) | | (5 | ) | | (3 | ) | | (5 | ) | | (5 | ) | Allowance for equity funds used during construction | | (4 | ) | | (8 | ) | | (10 | ) | | (2 | ) | | (5 | ) | | (9 | ) | Deductible dividends—401(k) Retirement Savings Plan | | (2 | ) | | (9 | ) | | (10 | ) | | — |
| | — |
| | — |
| Amortization of federal investment tax credits | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | | (2 | ) | Section 45 tax credits | | (9 | ) | | (8 | ) | | (8 | ) | | (9 | ) | | (8 | ) | | (8 | ) | Domestic production activities deduction | | — |
| | (18 | ) | | (23 | ) | | — |
| | (18 | ) | | (23 | ) | Remeasurement of deferred taxes in connection with enactment of Tax Act | | (188 | ) | | 30 |
| | — |
| | (176 | ) | | (1 | ) | | — |
| Nuclear Project impairment | | 23 |
| | — |
| | — |
| | 23 |
| | — |
| | — |
| Nondeductible merger-related costs | | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Other differences, net | | 2 |
| | (4 | ) | | (1 | ) | | 2 |
| | (4 | ) | | (2 | ) | Total income tax expense (benefit) | | $ | (412 | ) | | $ | (112 | ) | | $ | 271 |
| | $ | (416 | ) | | $ | (171 | ) | | $ | 248 |
|
The Company and Consolidated SCE&G have completed their accounting forAt DESC, deferred taxes will reverse at the effectsweighted average rate used to originate the deferred tax liability, which in some cases will be 35%. DESC has recorded an estimate of the Tax Act. portion of excess deferred income tax amortization in 2019, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. See Note 3 for current year developments. In connection with the SCANA Combination, Dominion Energy committed to forgo, or limit, the recovery of certain income tax-related regulatory assets associated with the NND Project. DESC’s effective tax rate reflects deferred income tax expense of $194 million in satisfaction of this commitment. In addition, DESC recorded deferred income tax expense of $30 million with a corresponding increase to regulatory liabilities by $40 million and deferred tax assets by $10 million related to adjustments of amounts probable of return to customers on the nuclear project. In connection with the remeasurement of federal deferred income tax assets and liabilities resulting from the Company recorded additional deferredlower federal income
tax expense of approximately $30 million, and Consolidated SCE&Grate, DESC recorded a deferred income tax benefit of approximately $1 million in their respectivethe statements of operations for the year ended December 31, 2017. As a result of the eventual filing of the Company's 2017 tax return in the fourth quarter of 2018 and the additional impairment charges recorded in 2018, adjustments to such excess deferred income taxes of approximately $188 million at the Company and approximately $176 million at Consolidated SCE&G were recorded. Also in connection with the additional impairment charges, the Company and Consolidated SCE&GDESC recorded additional adjustments to deferred income taxes in the aggregate amount of approximately $23 million. Additional changes could occur as further Tax Act guidance is issued and finalized. In addition, certain states in which the Company and Consolidated SCE&G operateDESC operates may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and such impacts or adjustments could be material. DESC’s deferred income taxes consist of the following: At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | Deferred income taxes: | | | | | | | | | Total deferred income tax assets | | $ | 1,258 | | | $ | 971 | | Total deferred income tax liabilities | | | 1,868 | | | | 1,960 | | Total net deferred income tax liabilities | | $ | 610 | | | $ | 989 | | Total deferred income taxes: | | | | | | | | | Depreciation method and plant basis differences | | $ | 1,007 | | | $ | 998 | | Excess deferred income taxes | | | (231 | ) | | | (148 | ) | Unrecovered nuclear plant cost | | | 553 | | | | 584 | | DESC rate refund | | | (169 | ) | | | (1 | ) | Toshiba settlement | | | (219 | ) | | | (231 | ) | Nuclear decommissioning | | | (43 | ) | | | (9 | ) | Deferred state income taxes | | | 200 | | | | 296 | | Federal benefit of deferred state income taxes | | | (42 | ) | | | (62 | ) | Deferred fuel, purchased energy and gas costs | | | 7 | | | | 1 | | Pension benefits | | | 46 | | | | 46 | | Other postretirement benefits | | | (35 | ) | | | (35 | ) | Loss and credit carryforwards | | | (391 | ) | | | (520 | ) | Other | | | (73 | ) | | | 70 | | Total net deferred income tax liabilities | | $ | 610 | | | $ | 989 | | Deferred Investment Tax Credits-Regulated Operations | | | 19 | | | | 19 | | Total Deferred Taxes and Deferred Investment Tax Credits | | $ | 629 | | | $ | 1,008 | |
The State of North Carolina lowered its corporate income tax rate to 4.0% in 2016, 3.0% in 2017At December 31, 2019, DESC had the following deductible loss and 2.5% effective January 1, 2019. In connection with thesecredit carryforwards: (millions) | | Deductible Amount | | | Deferred Tax Asset | | | Expiration Period | Federal losses | | $ | 1,207 | | | $ | 254 | | | 2037 | Federal production and other credits | | | — | | | | 38 | | | 2031-2038 | State losses | | | 1,849 | | | | 92 | | | 2037 | State investment and other credits | | | — | | | | 31 | | | 2026-2031 | Total | | $ | 3,056 | | | $ | 415 | | | |
A reconciliation of changes in DESC’s unrecognized tax rates, related state deferred tax amounts were remeasured, withbenefits follows: (millions) | | 2019 | | | 2018 | | | 2017 | | Balance at January 1 | | $ | 106 | | | $ | 98 | | | $ | 350 | | Increases-prior period positions | | | 76 | | | | 8 | | | | — | | Decreases-prior period positions | | | (53 | ) | | | — | | | | (273 | ) | Increases-current period positions | | | 3 | | | | — | | | | 21 | | Balance at December 31 | | $ | 132 | | | $ | 106 | | | $ | 98 | |
Throughout 2019, the change in their balances being credited to a regulatory liability. The changes in income tax rates did not and are not expected to have a material impact on the Company’s financial position, resultsevaluation of operations or cash flows.
The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Deferred tax assets: | | | | | | | | | Net operating loss and tax credit carryforward | | $ | 539 |
| | $ | 600 |
| | $ | 493 |
| | $ | 541 |
| Toshiba settlement | | 274 |
| | 273 |
| | 274 |
| | 273 |
| Nondeductible accruals | | 84 |
| | 88 |
| | 40 |
| | 42 |
| Asset retirement obligation, including nuclear decommissioning | | 143 |
| | 141 |
| | 135 |
| | 132 |
| Regulatory liability, non-property accumulated deferred income tax | | — |
| | 54 |
| | — |
| | 54 |
| Financial instruments | | 10 |
| | 15 |
| | — |
| | — |
| Unamortized investment tax credits | | 7 |
| | 8 |
| | 7 |
| | 8 |
| Other | | 4 |
| | 6 |
| | 5 |
| | 5 |
| Total deferred tax assets | | 1,061 |
| | 1,185 |
| | 954 |
| | 1,055 |
| | | | | | | | | | Deferred tax liabilities: | | | | | | | | | Property, plant and equipment | | 1,227 |
| | 1,220 |
| | 1,033 |
| | 1,035 |
| Regulatory asset, unrecovered nuclear plant costs | | 668 |
| | 962 |
| | 668 |
| | 962 |
| Deferred employee benefit plan costs | | 60 |
| | 60 |
| | 53 |
| | 53 |
| Regulatory asset, asset retirement obligation | | 94 |
| | 91 |
| | 88 |
| | 85 |
| Regulatory asset, other unrecovered plant | | 24 |
| | 27 |
| | 24 |
| | 27 |
| Demand side management costs | | 16 |
| | 16 |
| | 16 |
| | 16 |
| Prepayments | | 21 |
| | 21 |
| | 20 |
| | 19 |
| Other | | 63 |
| | 49 |
| | 41 |
| | 31 |
| Total deferred tax liabilities | | 2,173 |
| | 2,446 |
| | 1,943 |
| | 2,228 |
| Net deferred tax liabilities | | $ | 1,112 |
| | $ | 1,261 |
| | $ | 989 |
| | $ | 1,173 |
|
The federal and state income tax creditspositions taken in DESC’s tax returns prior to the SCANA Combination increased unrecognized tax benefits by $79 million and NOL carryforwards are presented below:
| | | | | | | | | | | | | | | | December 31, 2018 | | | | | Millions of dollars | | The Company | | Consolidated SCE&G | | Expiration Year | Federal NOL Carryforwards | | $ | 1,807 |
| | $ | 1,642 |
| | 2037 | Federal Tax Credits | | 83 |
| | 83 |
| | 2035 | - | 2038 | State NOL Carryforwards | | 2,447 |
| | 2,198 |
| | 2037 | State Tax Credits | | 30 |
| | 30 |
| | 2026 | - | 2033 | Total Tax Credits and NOL Carryforwards | | $ | 4,367 |
| | $ | 3,953 |
| | | | |
A valuation allowance is needed when it is more likely than not that all orincreased income tax expense by $67 million. In the fourth quarter of 2019, DESC also remeasured its beginning unrecognized tax benefits by $53 million. These changes were offset by a portion of a$45 million reduction in credit carryforward deferred tax asset will not be realized. In determining whetherassets and a valuation allowance is required, the Company and Consolidated SCE&G consider such factors as prior earnings history, expected future earnings, carryback and carryforward periods, and tax strategies that could
potentially enhance the likelihood of the realization of$7 million increase to accrued taxes resulting in a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed.
The Company files consolidated federal$1 million benefit to income tax returnsexpense.Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitations. If recognized, all the unrecognized tax benefits would impact the effective tax rate. The statute is closed for IRS examination of years prior to 2010, except for certain state returns, including the return for South Carolina, which returns include Consolidated SCE&G. The Company and its subsidiaries file various other applicable state and local income tax returns. Consolidated SCE&G's NOL shown above represents their portion on a stand-alone company basis. There is no material amount due to or from the Company.
outstanding refund claims. The IRS has completed examinations of the Company’sDESC’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment.2012. The IRS is currently examining the Company's openDESC’s federal returns from 2013 through 2017 as a result of claims discussed below.2017. With few exceptions, the Company, including Consolidated SCE&G,DESC is no longer subject to state and local income tax examinations by tax authorities for years before 2010. Changes in Unrecognized Tax Benefits
| | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Unrecognized tax benefits, January 1 | | $ | 98 |
| | $ | 350 |
| | $ | 49 |
| | $ | 98 |
| | $ | 350 |
| | $ | 49 |
| Gross increases—uncertain tax positions in prior period | | 8 |
| | — |
| | 94 |
| | 8 |
| | — |
| | 94 |
| Gross decreases—uncertain tax positions in prior period | | — |
| | (273 | ) | | — |
| | — |
| | (273 | ) | | — |
| Gross increases—current period uncertain tax positions | | — |
| | 21 |
| | 207 |
| | — |
| | 21 |
| | 207 |
| Unrecognized tax benefits, December 31 | | $ | 106 |
| | $ | 98 |
| | $ | 350 |
| | $ | 106 |
| | $ | 98 |
| | $ | 350 |
|
During 2013 and 2014, the Company amended certain of its income tax returnsprior 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). The Company also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, the Company 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 Nuclear Project, in its 2015 and 2016 income tax returns. The Company claimed similar deductions and credits in its 2017 tax return when it was filed in 2018. 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 2017 income tax returns.
These IRC Section 174 income tax deductions and IRC Section 41 credits were 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 were recorded as unrecognized tax benefits in the financial statements. Following the abandonment of the Nuclear Project, the Company and Consolidated SCE&G claimed an abandonment loss deduction under IRC Section 165 on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, are instead expected to be deductible in 2017 under IRC Section 165. The Company received a favorable PLR from the IRS stating the Company has a valid tax deduction for abandonment under IRC Section 165. Although the IRS does not verify the amount of the deduction, there is no reserve against these costs. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, Section 41 credits, and certain unrecognized state tax benefits.
As of December 31, 2018, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $106 million ($38 million net of the impact of state deductions on federal returns, net of NOL and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $106 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. Due to the merger with Dominion Energy, it is reasonably possible that these unrecognized tax benefits could increase within the next 12 months, although such increase cannot be reasonably estimated. 2012.It is reasonably possible that these unrecognized tax benefits may decrease by $11$65 million within the next 12twelve months. NoIf such changes were to occur, other material changes in the statusthan revisions of the Company’s or Consolidated SCE&G'saccrual for interest on tax positions have occurred through December 31, 2018.
The Companyunderpayments and Consolidated SCE&G recognize interest accrued relatedoverpayments, earnings could increase by up to $4 million. Otherwise, with regard to 2019 and prior years, DESC cannot estimate the range of reasonably possible changes to unrecognized tax benefits within interest expense or interest income and recognizethat may occur in 2020.DESC is also obligated to report adjustments resulting from IRS settlements to state tax penalties within other expenses. Amounts recorded for such interest income, interest expenseauthorities. In addition, if DESC utilizes operating losses or tax penalties have not been materialcredits generated in years for any period presented.
7.which the statute of limitations has expired, such amounts are generally subject to examination.8. DERIVATIVE FINANCIAL INSTRUMENTS Derivative instruments are recognized either as assets or liabilities inSee Note 2 for the statement of financial positionCompany’s accounting policies, objectives, and are measured at fair value. Changes in thestrategies for using derivative instruments. See Note 9 for further information about fair value measurements and associated valuation methods for derivatives. Derivative assets and liabilities are presented gross on the Company’s Consolidated Balance Sheets. DESC’s derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter contracts contain contractual rights of derivative instrumentssetoff through master netting arrangements and contract default provisions. In addition, the contracts are recognized either in earnings, as a componentsubject to conditional rights of setoff through counterparty nonperformance, insolvency, or other comprehensive income (loss) or,conditions. In general, most over-the-counter transactions are subject to collateral requirements. Types of collateral for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended useover-the-counter contracts include cash, letters of the derivative and the resulting designation.
Policies and procedures,credit, and, in some cases, risk limits,other forms of security, none of which are establishedsubject to controlrestrictions. Cash collateral is used in the level of market, credit, liquiditytable below to offset derivative assets and operational and administrative risks. Historically, SCANA’s Board of Directors 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 was comprised of certain officers, apprised the Board of Directors with regard to the management of risk and brought 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 usesliabilities.Certain DESC derivative instruments contain credit-related contingent provisions. These provisions require DESC to hedge forward purchases and salesprovide collateral upon the occurrence of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associatedspecific events, primarily a credit rating downgrade. DESC’s derivatives with fixed price obligationscredit-related contingent provisions that were in a volatile marketliability position were fully collateralized with cash at December 31, 2019 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 created2018. 39
The table below presents derivative balances by fixed prices of stored natural gas. The basic typestype 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 activitiesinstrument, if the gross amounts recognized in the consolidated statementsConsolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid: | | December 31, 2019 | | | December 31, 2018 | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | | | | | | Gross Amounts Not Offset in the Consolidated Balance Sheet | | | | | | (millions) | | Gross Liabilities Presented in the Consolidated Balance Sheet | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | | Gross Liabilities Presented in the Consolidated Balance Sheet | | | Financial Instruments | | | Cash Collateral Paid | | | Net Amounts | | Interest rate contracts: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Over-the-counter | | $ | 19 | | | $ | — | | | $ | 19 | | | $ | — | | | $ | 11 | | | $ | — | | | $ | 11 | | | $ | — | | Total derivatives | | $ | 19 | | | $ | — | | | $ | 19 | | | $ | — | | | $ | 11 | | | $ | — | | | $ | 11 | | | $ | — | |
Volumes The following table presents the volume of cash flows.derivative activity at December 31, 2019. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions. | | Current | | | Noncurrent | | Interest rate(1) | | $ | — | | | $ | 71,400,000 | |
(1) | Maturity is determined based on final settlement period. |
Fair Value and Gains and Losses on Derivative Instruments The following table presents the fair values of derivatives and where they are presented in the Consolidated Balance Sheets: (millions) | | Fair Value - Derivatives under Hedge Accounting | | | Fair Value - Derivatives not under Hedge Accounting | | | Total Fair Value | | At December 31, 2019 | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Interest rate | | $ | 1 | | | $ | 1 | | | $ | 2 | | Total current derivative liabilities(1) | | | 1 | | | | 1 | | | | 2 | | Noncurrent Liabilities | | | | | | | | | | | | | Interest rate | | | 11 | | | | 6 | | | | 17 | | Total noncurrent derivative liabilities(2) | | | 11 | | | | 6 | | | | 17 | | Total derivative liabilities | | $ | 12 | | | $ | 7 | | | $ | 19 | | At December 31, 2018 | | | | | | | | | | | | | Current Liabilities | | | | | | | | | | | | | Interest rate | | $ | 1 | | | $ | — | | | $ | 1 | | Total current derivative liabilities(1) | | | 1 | | | | — | | | | 1 | | Noncurrent Liabilities | | | | | | | | | | | | | Interest rate | | | 7 | | | | 3 | | | | 10 | | Total noncurrent derivative liabilities(2) | | | 7 | | | | 3 | | | | 10 | | Total derivative liabilities | | $ | 8 | | | $ | 3 | | | $ | 11 | |
(1) | Current derivative liabilities are presented in other current liabilities in the Consolidated Balance Sheets. |
(2) | Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in the Consolidated Balance Sheets. |
PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options. PSNC Energy’s tariffs include a provision forThe following tables present 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 hedgesderivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements 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 designated as cash flow hedges have been 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 were not designated for accounting purposes as cash flow hedges, and fair value changes and settlement amounts related to them have been recorded as regulatory assets and liabilities. Settlement losses on swaps generally have been amortized over the lives of subsequent debt issuances, and gains have been amortized to interest expense or have been applied as otherwise directed by the SCPSC. See Note 2 and Note 15 regarding the settlement gains realized in the first quarter of 2018.
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 Energy Management Contracts (in bcf) | Hedge designation | | Gas Distribution | | Gas Marketing | | Total | As of December 31, 2018 | | |
| | |
| | |
| Commodity | | 6.4 |
| | 12.9 |
| | 19.3 |
| Energy Management (a) | | — |
| | 46.8 |
| | 46.8 |
| Total (a) | | 6.4 |
| | 59.7 |
| | 66.1 |
| | | | | | | | As of December 31, 2017 | | |
| | |
| | |
| Commodity | | 6.4 |
| | 13.4 |
| | 19.8 |
| Energy Management (a) | | — |
| | 41.9 |
| | 41.9 |
| Total (a) | | 6.4 |
| | 55.3 |
| | 61.7 |
|
(a) Includes amounts related to basis swap contracts totaling 5.1 bcf in 2018 and 2.6 bcf in 2017.
The aggregate notional amounts of the interest rate swaps were as follows:
| | | | | | | | | | | | | | | | | | Interest Rate Swaps | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | December 31, 2018 | | December 31, 2017 | | December 31, 2018 | | December 31, 2017 | Designated as hedging instruments | | $ | 106.8 |
| | $ | 111.2 |
| | $ | 36.4 |
| | $ | 36.4 |
| Not designated as hedging instruments | | 35.0 |
| | 735.0 |
| | 35.0 |
| | 735.0 |
|
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 December 31, 2018 | | |
| | |
| | | | | Designated as hedging instruments | | |
| | |
| | | | | Interest rate contracts | | | | | | | | | | | Other current liabilities | | — |
| | $ | 2 |
| | — |
| | $ | 1 |
| | | Other deferred credits and other liabilities | | — |
| | 19 |
| | — |
| | 7 |
| Commodity contracts | | | | | | | | | | | Prepayments | | — |
| | 1 |
| | — |
| | — |
| Total | | — |
| | $ | 22 |
| | — |
| | $ | 8 |
| | | | | | | | | | | | Not designated as hedging instruments | | |
| | |
| | | | | Interest rate contracts | | | | | | | | | | | Other deferred credits and other liabilities | | — |
| | $ | 3 |
| | — |
| | $ | 3 |
| Commodity contracts | | | | | | | | | | | Prepayments | | $ | 1 |
| | — |
| | — |
| | — |
| Energy management contracts | | | | | | | | | | | Prepayments | | 11 |
| | 12 |
| | — |
| | — |
| | | Other current assets | | 1 |
| | — |
| | — |
| | — |
| | | Other current liabilities | | — |
| | 1 |
| | — |
| | — |
| | | Other deferred debits and other assets | | 1 |
| | — |
| | — |
| | — |
| Total | | | | $ | 14 |
| | $ | 16 |
| | — |
| | $ | 3 |
| | | | | | | | | | | | As of December 31, 2017 | | | | | | | | | Designated as hedging instruments | | | | | | | | | Interest rate contracts | | | | | | | | | | | Other current liabilities | | — |
| | $ | 3 |
| | — |
| | $ | 1 |
| | | Other deferred credits and other liabilities | | — |
| | 24 |
| | — |
| | 9 |
| Commodity contracts | | | | | | | | | | | Prepayments | | — |
| | 2 |
| | — |
| | — |
| | | Other current liabilities | | — |
| | 1 |
| | — |
| | — |
| Total | | — |
| | $ | 30 |
| | — |
| | $ | 10 |
| | | | | | | | | | | | Not designated as hedging instruments | | | | | | | | | Interest rate contracts | | | | | | | | | | | Other current assets and current liabilities | | $ | 54 |
| | $ | 1 |
| | $ | 54 |
| | $ | 1 |
| | | Other deferred credits and other liabilities | | — |
| | 4 |
| | — |
| | 4 |
| Commodity contracts | | | | | | | | | | | Other current assets | | 1 |
| | — |
| | — |
| | — |
| Energy management contracts | | | | | | | | | | | Prepayments | | — |
| | 1 |
| | — |
| | — |
| | | Other current assets | | 3 |
| | — |
| | — |
| | — |
| | | Other deferred debits and other assets | | 1 |
| | — |
| | — |
| | — |
| | | Other current liabilities | | — |
| | 2 |
| | — |
| | — |
| Total | | | | $ | 59 |
| | $ | 8 |
| | $ | 54 |
| | $ | 5 |
|
Derivatives Designated as Fair Value Hedges
The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.
Comprehensive Income (Loss):40
Derivatives in Cash Flow Hedging Relationships (millions) | | Gain (loss) Reclassified from Deferred Accounts into Income | | | Increase (Decrease) in Derivatives Subject to Regulatory Treatment(1) | | Year Ended December 31, 2019 | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | Interest rate(2) | | $ | — | | | $ | 1 | | Total | | $ | — | | | $ | 1 | | Year Ended December 31, 2018 | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | Interest rate(2) | | $ | (1 | ) | | $ | 1 | | Total | | $ | (1 | ) | | $ | 1 | | Year Ended December 31, 2017 | | | | | | | | | Derivative type and location of gains (losses): | | | | | | | | | Interest rate(2) | | $ | (2 | ) | | $ | (2 | ) | Total | | $ | (2 | ) | | $ | (2 | ) |
(1) | Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/ liabilities have no associated effect in the Consolidated Statements of Comprehensive Loss. |
(2) | Amounts recorded in DESC’s Consolidated Statements of Comprehensive Loss are classified in interest charges. |
The effect of derivative instruments on the consolidated statements of operations is as follows:
| | | | | | | | | | | | The Company and Consolidated SCE&G: | | Gain (Loss) Deferred in Regulatory Accounts | | Loss Reclassified from Deferred Accounts into Income (Effective Portion) | Millions of dollars | | (Effective Portion) | | Location | | Amount | Year Ended December 31, 2018 | | |
| | | | |
| Interest rate contracts | | $ | 1 |
| | Interest expense | | $ | (1 | ) | Year Ended December 31, 2017 | | |
| | | | |
| Interest rate contracts | | $ | (2 | ) | | Interest expense | | $ | (2 | ) | Year Ended December 31, 2016 | | |
| | | | | Interest rate contracts | | — |
| | Interest expense | | $ | (2 | ) |
| | | | | | | | | | | | The Company: | | Gain (Loss) Recognized in OCI, net of tax | | Gain (Loss) Reclassified from AOCI into Income, net of tax (Effective Portion) | Millions of dollars | | (Effective Portion) | | Location | | Amount | Year Ended December 31, 2018 | | |
| | | | |
| Interest rate contracts | | $ | 1 |
| | Interest expense | | $ | (9 | ) | Commodity contracts | | (3 | ) | | Gas purchased for resale | | (7 | ) | Total | | $ | (2 | ) | | | | $ | (16 | ) | Year Ended December 31, 2017 | | |
| | | | |
| Interest rate contracts | | — |
| | Interest expense | | $ | (7 | ) | Commodity contracts | | $ | (7 | ) | | Gas purchased for resale | | 1 |
| Total | | $ | (7 | ) | | | | $ | (6 | ) | Year Ended December 31, 2016 | | |
| | | | |
| Interest rate contracts | | $ | (1 | ) | | Interest expense | | $ | (7 | ) | Commodity contracts | | 5 |
| | Gas purchased for resale | | (6 | ) | Total | | $ | 4 |
| | | | $ | (13 | ) |
As of December 31, 2018, the Company expects that during the next 12 months reclassifications from AOCI (loss) to earnings arising from cash flow hedges will include approximately $0.6 million as a decrease to gas cost, assuming natural gas markets remain at their current levels, and approximately $8.7 million as an increase to interest expense. Reclassifications related to commodity and energy management contracts are not expected to be significant. All of the Company’s commodity cash flow hedges settle by their terms before the end of the third quarter of 2021.
As of December 31, 2018, 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 hedgesDerivatives Not designated as hedging instruments will include approximately $0.9 million as an increase 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 for all periods presented.
Derivatives Not Designated as Hedging Instruments (millions) | | Amount of Gain (Loss) Recognized in Income on Derivatives(1) | | Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | Derivative type and location of gains (losses): | | | | | | | | | | | | | Interest rate contracts: | | | | | | | | | | | | | Interest charges | | $ | (1 | ) | | $ | (2 | ) | | $ | (3 | ) | Other income | | | — | | | | 115 | | | | — | | Impairment loss | | | — | | | | — | | | | (173 | ) | Total | | $ | (1 | ) | | $ | 113 | | | $ | (176 | ) |
(1) | Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in the Consolidated Statements of Comprehensive Loss. |
| | | | | | | | | | | | The Company and Consolidated SCE&G: | | Gain (Loss) Deferred in | | Gain (Loss) Reclassified from Deferred Accounts into Income | Millions of dollars | | Regulatory Accounts | | Location | | Amount | Year Ended December 31, 2018 | | |
| | | | | Interest rate contracts | | $ | 64 |
| | Interest Expense | | $ | (2 | ) | Interest rate contracts | | | | Other Income | | 115 |
| Year Ended December 31, 2017 | | |
| | | | | Interest rate contracts | | $ | (32 | ) | | Interest Expense | | $ | (3 | ) | Interest rate contracts | | | | Impairment Loss | | (173 | ) | Year Ended December 31, 2016 | | | | | | | Interest rate contracts | | $ | (34 | ) | | Other income | | $ | (2 | ) |
Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. Loss reclassified to impairment loss is included in the 2017 impairment described in Note 11.
As of December 31, 2018, 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 $2.8 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 | | December 31, 2018 | | December 31, 2017 | | December 31, 2018 | | December 31, 2017 | in Net Liability Position | | |
| | |
| | | | | Aggregate fair value of derivatives in net liability position | | $ | 24.8 |
| | $ | 33.7 |
| | $ | 11.2 |
| | $ | 14.7 |
| Fair value of collateral already posted | | 24.3 |
| | 28.9 |
| | 11.0 |
| | 10.1 |
| Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | | $ | 0.5 |
| | $ | 4.8 |
| | $ | 0.2 |
| | $ | 4.6 |
| | | | | | | | | | in Net Asset Position | | | | | | | | | Aggregate fair value of derivatives in net asset position | | — |
| | $ | 53.5 |
| | — |
| | $ | 53.5 |
| Fair value of collateral already posted | | — |
| | — |
| | — |
| | — |
| Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered | | — |
| | $ | 53.5 |
| | — |
| | $ | 53.5 |
|
In addition, at December 31, 2018, the Company could not call on any letters of credit related to the $1.7 million in commodity derivatives that are in a net asset position. At December 31, 2017, the Company could have called on letters of credit in the amount of $1.2 million related to derivatives of $4.0 million if all the contingent features underlying these instruments had been fully triggered.
Information related to the offsetting derivative assets 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 December 31, 2018 | | |
| | | | |
| | | | | Gross Amounts of Recognized Assets | | — |
| | $ | 1 |
| | $ | 13 |
| | $ | 14 |
| | — |
| Gross Amounts Offset in Statement of Financial Position | | — |
| | — |
| | (11 | ) | | (11 | ) | | — |
| Net Amounts Presented in Statement of Financial Position | | — |
| | 1 |
| | 2 |
| | 3 |
| | — |
| Gross Amounts Not Offset - Financial Instruments | | — |
| | — |
| | — |
| | — |
| | — |
| Gross Amounts Not Offset - Cash Collateral Received | | — |
| | — |
| | — |
| | — |
| | — |
| Net Amount | | — |
| | $ | 1 |
| | $ | 2 |
| | $ | 3 |
| | — |
| Balance sheet location | | | | | | | | | | | Prepayments | | | | | | | | $ | 12 |
| | — |
| Other current assets | | | | | | | | 1 |
| | — |
| Other deferred debits and other assets | | | | | | | | 1 |
| | — |
| Total | | | | | | | | $ | 14 |
| | — |
| | | | | | | | | | | | As of December 31, 2017 | | | | | | | | | | | Gross Amounts of Recognized Assets | | $ | 54 |
| | $ | 1 |
| | $ | 4 |
| | $ | 59 |
| | $ | 54 |
| Gross Amounts Offset in Statement of Financial Position | | — |
| | — |
| | — |
| | — |
| | — |
| Net Amounts Presented in Statement of Financial Position | | 54 |
| | 1 |
| | 4 |
| | 59 |
| | 54 |
| Gross Amounts Not Offset - Financial Instruments | | — |
| | — |
| | — |
| | — |
| | — |
| Gross Amounts Not Offset - Cash Collateral Received | | — |
| | — |
| | — |
| | — |
| | — |
| Net Amount | | $ | 54 |
| | $ | 1 |
| | $ | 4 |
| | $ | 59 |
| | $ | 54 |
| Balance sheet location | | | | | | | | | | | Other current assets | | | | | | | | $ | 58 |
| | $ | 54 |
| Other deferred debits and other assets | | | | | | | | 1 |
| | — |
| Total | | | | | | | | $ | 59 |
| | $ | 54 |
|
Information related to the offsetting of derivative liabilities follows:
| | | | | | | | | | | | | | | | | | | | | | Derivative Liabilities | | The Company | | Consolidated SCE&G | Millions of dollars | | Interest Rate Contracts | | Commodity Contracts | | Energy Management Contracts | | Total | | Interest Rate Contracts | As of December 31, 2018 | | |
| | | | |
| | | | | Gross Amounts of Recognized Liabilities | | $ | 24 |
| | $ | 1 |
| | $ | 13 |
| | $ | 38 |
| | $ | 11 |
| Gross Amounts Offset in Statement of Financial Position | | — |
| | — |
| | (11 | ) | | (11 | ) | | — |
| Net Amounts Presented in Statement of Financial Position | | 24 |
| | 1 |
| | 2 |
| | 27 |
| | 11 |
| Gross Amounts Not Offset - Financial Instruments | | — |
| | — |
| | — |
| | — |
| | — |
| Gross Amounts Not Offset - Cash Collateral Posted | | (24 | ) | | — |
| | — |
| | (24 | ) | | (11 | ) | Net Amount | | — |
| | $ | 1 |
| | $ | 2 |
| | $ | 3 |
| | — |
| Balance sheet location | | | | | | | | | | | Prepayments | | | | | | | | $ | 13 |
| | — |
| Other current liabilities | | | | | | | | 3 |
| | $ | 1 |
| Other deferred credits and other liabilities | | | | | | | | 22 |
| | 10 |
| Total | | | | | | | | $ | 38 |
| | $ | 11 |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Derivative Liabilities | | The Company | | Consolidated SCE&G | Millions of dollars | | Interest Rate Contracts | | Commodity Contracts | | Energy Management Contracts | | Total | | Interest Rate Contracts | As of December 31, 2017 | | | | | | | | | | | Gross Amounts of Recognized Liabilities | | $ | 32 |
| | $ | 3 |
| | $ | 3 |
| | $ | 38 |
| | $ | 15 |
| Gross Amounts Offset in Statement of Financial Position | | — |
| | — |
| | (1 | ) | | (1 | ) | | — |
| Net Amounts Presented in Statement of Financial Position | | 32 |
| | 3 |
| | 2 |
| | 37 |
| | 15 |
| Gross Amounts Not Offset - Financial Instruments | | — |
| | — |
| | — |
| | — |
| | — |
| Gross Amounts Not Offset - Cash Collateral Posted | | (28 | ) | | — |
| | (1 | ) | | (29 | ) | | — |
| Net Amount | | $ | 4 |
| | 3 |
| | $ | 1 |
| | $ | 8 |
| | $ | 15 |
| Balance sheet location | | | | | | | | | | | Other current assets | | | | | | | | $ | 2 |
| | — |
| Other current liabilities | | | | | | | | 7 |
| | $ | 2 |
| Other deferred credits and other liabilities | | | | | | | | 28 |
| | 13 |
| Total | | | | | | | | $ | 37 |
| | $ | 15 |
|
8.9. FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES The Company and Consolidated SCE&GFair value available for sale securities using quoted prices from a national stock exchange, suchis defined as the NASDAQ,price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of DESC’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the securities are actively tradedreporting entity would be able to maximize the amount received or are open-ended mutual funds registered withminimize the SEC and maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy managementamount paid). DESC applies fair value measurements to interest rate 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'sliabilities. DESC’s interest rate swap agreements are valued using discounted cash flow models with independently sourced data. DESC applies credit adjustments to its derivative fair values in accordance with the requirements described above. Inputs and Assumptions Fair value measurements,is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications. The inputs and assumptions used in measuring fair value for interest rate derivative contracts include the following: | • | Credit quality of counterparties and DESC |
41
Levels DESC utilizes the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: | • | Level 1-Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. |
| • | Level 2-Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include interest rate swaps. |
| • | Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. |
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the level withinlowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy in whichhierarchy. In these cases, the measurements fall, were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2018 | | As of December 31, 2017 | | | The Company | | Consolidated SCE&G | | The Company | | Consolidated SCE&G | Millions of dollars | | Level 1 | | Level 2 | | Level 1 | Level 2 | | Level 1 | | Level 2 | | Level 1 | Level 2 | Assets: | |
| | | | |
| | | | | | | | Available for sale securities | | — |
| | — |
| | — |
| — |
| | $ | 119 |
| | — |
| | $ | 100 |
| — |
| Held to maturity securities | | — |
| | $ | 6 |
| | — |
| — |
| | — |
| | $ | 6 |
| | — |
| — |
| Interest rate contracts | | — |
| | — |
| | — |
| — |
| | — |
| | 54 |
| | — |
| $ | 54 |
| Commodity contracts | | $ | 1 |
| | — |
| | — |
| — |
| | 1 |
| | — |
| | — |
| — |
| Energy management contracts | | 11 |
| | 2 |
| | — |
| — |
| | — |
| | 4 |
| | — |
| — |
| Liabilities: | |
| |
| | |
| |
| | | | | | Interest rate contracts | | — |
| | 24 |
| | — |
| $ | 11 |
| | — |
| | 32 |
| | — |
| 15 |
| Commodity contracts | | 1 |
| | — |
| | — |
| — |
| | 2 |
| | 1 |
| | — |
| — |
| Energy management contracts | | 12 |
| | 3 |
| | — |
| — |
| | 1 |
| | 4 |
| | — |
| — |
|
The Company and Consolidated SCE&G had no Level 3lowest level input that is significant to a fair value measurements during either period presented.
Financial instruments for whichmeasurement in its entirety determines the carrying amount may not equal estimated fair value at December 31, 2018 and December 31, 2017 were as follows:
| | | | | | | | | | | | | | | | | | | | As of December 31, 2018 | | As of December 31, 2017 | Millions of dollars | | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value | The Company | | $ | 6,753.9 |
| | $ | 7,180.8 |
| | $ | 6,632.9 |
| | $ | 7,399.7 |
| Consolidated SCE&G | | 5,145.6 |
| | 5,469.7 |
| | 5,163.3 |
| | 5,790.3 |
|
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 dealersapplicable level in the commercial paper market. The resulting fair value is considered to be Level 2.
In connection with the impairment loss described in Note 11, the Company and Consolidated SCE&G determined that the fair value hierarchy. Assessing the significance of certaina particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.Recurring Fair Value Measurements Fair value disclosures for assets held in DESC’s pension and other postretirement benefit plans are presented in Note 11. The following table presents DESC’s liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions: | | Level 1 | | | Level 2 | | | Level 3 | | | Total | | (millions) | | | | | | | | | | | | | | | | | At December 31, 2019 | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Interest rate | | $ | — | | | $ | 19 | | | $ | — | | | $ | 19 | | Total liabilities | | $ | — | | | $ | 19 | | | $ | — | | | $ | 19 | | At December 31, 2018 | | | | | | | | | | | | | | | | | Liabilities | | | | | | | | | | | | | | | | | Interest rate | | $ | — | | | $ | 11 | | | $ | — | | | $ | 11 | | Total liabilities | | $ | — | | | $ | 11 | | | $ | — | | | $ | 11 | |
Fair Value of Financial Instruments Substantially all of DESC’s financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of financial instruments classified within current assets and current liabilities are representative of fair value because of the short-term nature of these instruments. For financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows: At December 31, | | 2019 | | | 2018 | | (millions) | | Carrying Amount | | | Estimated Fair Value(1) | | | Carrying Amount | | | Estimated Fair Value(2) | | Long-term debt(3) | | $ | 3,358 | | | $ | 4,262 | | | $ | 5,146 | | | $ | 5,470 | | Affiliated long-term debt | | | 230 | | | | 230 | | | | — | | | | — | |
(1) | Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
(2) | Fair value is estimated 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. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. |
(3) | Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs and discount or premium. |
10. ASSET RETIREMENT OBLIGATIONS A liability for the present value of an ARO is recognized when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition. The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, development and normal operation relate primarily to DESC’s regulated utility operations. As of December 31, 2019, DESC has recorded AROs of $177 million for nuclear fuel was lower than its carrying amount.plant decommissioning. At December 31, 2018, this nuclear fuel2019, DESC had an estimated fair value$214 million in a trust for its two-thirds share of $40.2 million. This estimate isdecommissioning activities. In addition, DESC has recorded AROs of $312 million for other conditional obligations primarily related to other generation, transmission and distribution properties, including gas pipelines. All of the amounts 42
recorded are based on quoted prices received from vendors of nuclear fuel,upon estimates which are consideredsubject to varying degrees of precision, particularly since such payments will be Level 3 fair value measurements.made many years in the future. A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows: (millions) | | 2019 | | | 2018 | | Beginning balance | | $ | 541 | | | $ | 529 | | Liabilities settled | | | (29 | ) | | | (15 | ) | Accretion expense | | | 23 | | | | 23 | | Revisions in estimated cash flows(1) | | | (46 | ) | | | 4 | | Ending balance | | $ | 489 | | | $ | 541 | |
(1) The Companydecrease in 2019 reflects a change in the estimated timing of cash flows for interim pipeline replacements and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 11 on a quarterly basis.
9.DOE recoveries.11. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN Pension and Other Postretirement Benefit Plans SCANA sponsors a noncontributory defined benefit pension plan covering regular, full-time employees hired before January 1, 2014. SCE&GDESC participates in SCANA's pension plan. SCANA’s policy has been to fund the plan as permitted by applicable federal income tax regulations, as determined by an independent actuary. The pension plan provides benefits under a cash balance formula for employees hired before January 1, 2000 who elected that option and all eligible employees hired subsequently. Under the cash balance formula, benefits accumulate as a result of compensation credits and interest credits. Employees hired before January 1, 2000 who elected to remain under the final average pay formula earn benefits based on years of credited service and the employee’s average annual base earnings received during the last three years of employment. Benefits under the cash balance formula will continue to accrue through December 31, 2020, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits. Benefits under the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued. Once the benefits under SCANA's pension plan no longer accrue, eligible participants will accrue benefits under a cash balance plan sponsored by Dominion Energy. In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&GDESC participates in these programs. Retirees hired before January 1, 2011 share in a portion of their medical care cost, while employees hired subsequently are responsible for the full cost of retiree medical benefits elected by them. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for these benefits.
The same benefit formula applies to all SCANA subsidiaries participating in the parent sponsored plans and, with regard to the pension plan, there are no legally separate asset pools. The postretirement benefit plans are accounted for as multiple employer plans.
Voluntary Retirement Program In March 2019, Dominion Energy announced a voluntary retirement program to employees, including employees of DESC, that meet certain age and service requirements. The voluntary retirement program will not compromise safety or DESC’s ability to comply with applicable laws and regulations. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, DESC recorded a charge of $63 million ($47 million after-tax), of which $51 million was included within other operations and maintenance expense, $3 million within other taxes and $9 million within other income (expense), net. In addition, as a result of the voluntary retirement program, DESC recorded pension plan settlement losses of $16 million within other income (expense), net in 2019. In the second quarter of 2019, DESC remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $16 million and an increase in the accumulated postretirement benefit obligation of $10 million. In addition, the remeasurement resulted in an increase in the fair value of pension plan assets of $27 million. The impact of the remeasurement on net periodic benefit cost was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.07% for the pension plan and 4.08% for the other postretirement benefit plan. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018. In the third quarter of 2019, DESC remeasured a pension plan as a result of a settlement from the voluntary retirement program. The settlement and related remeasurement resulted in an increase in the pension benefit obligation of $25 million and an increase in the fair value of the pension plan assets of $35 million for DESC. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 3.57%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018. 43
Changes in Benefit Obligations The measurement date used to determine pension and other postretirement benefit obligations is December 31. Data related to the changes in the projected benefit obligation for pension benefits and the accumulated benefit obligation for other postretirement benefits are presented below. | | Pension Benefits | | | Other Postretirement Benefits | | (millions) | | 2019 | | | 2018 | | | 2019 | | | 2018 | | Benefit obligation, January 1 | | $ | 732 | | | $ | 793 | | | $ | 187 | | | $ | 217 | | Service cost | | | 15 | | | | 17 | | | | 3 | | | | 4 | | Interest cost | | | 28 | | | | 29 | | | | 9 | | | | 8 | | Plan participants’ contributions | | | — | | | | — | | | | 1 | | | | 1 | | Actuarial (gain) loss | | | 47 | | | | (46 | ) | | | 22 | | | | (31 | ) | Benefits paid | | | (21 | ) | | | (19 | ) | | | (13 | ) | | | (11 | ) | Settlements | | | (80 | ) | | | (42 | ) | | | — | | | | — | | Curtailment | | | 6 | | | | — | | | | 3 | | | | — | | Amounts funded to parent | | | — | | | | — | | | | 2 | | | | (1 | ) | Benefit obligation, December 31 | | $ | 727 | | | $ | 732 | | | $ | 214 | | | $ | 187 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | | | Pension Benefits |
| Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 |
| 2017 |
| 2018 |
| 2017 | | 2018 | | 2017 | | 2018 | | 2017 | Benefit obligation, January 1 | | $ | 933.2 |
| | $ | 904.3 |
| | $ | 289.2 |
| | $ | 274.7 |
| | $ | 793.0 |
| | $ | 768.4 |
| | $ | 216.6 |
| | $ | 207.2 |
| Service cost | | 21.0 |
| | 21.7 |
| | 4.6 |
| | 4.5 |
| | 17.1 |
| | 18.1 |
| | 3.6 |
| | 3.7 |
| Interest cost | | 34.1 |
| | 37.4 |
| | 10.1 |
| | 11.5 |
| | 29.0 |
| | 31.9 |
| | 8.0 |
| | 9.5 |
| Plan participants’ contributions | | — |
| | — |
| | 1.4 |
| | 1.3 |
| | — |
| | — |
| | 1.1 |
| | 1.1 |
| Actuarial (gain) loss | | (53.1 | ) | | 42.2 |
| | (38.4 | ) | | 9.7 |
| | (45.5 | ) | | 36.6 |
| | (30.7 | ) | | 6.8 |
| Benefits paid | | (71.7 | ) | | (72.4 | ) | | (13.2 | ) | | (12.5 | ) | | (61.3 | ) | | (62.0 | ) | | (10.4 | ) | | (10.3 | ) | Amounts funded to parent | | n/a |
| | n/a |
| | n/a |
| | n/a |
| | — |
| | — |
| | (0.8 | ) | | (1.4 | ) | Benefit obligation, December 31 | | $ | 863.5 |
| | $ | 933.2 |
| | $ | 253.7 |
| | $ | 289.2 |
| | $ | 732.3 |
| | $ | 793.0 |
| | $ | 187.4 |
| | $ | 216.6 |
|
The accumulated benefit obligation for pension benefits for the CompanyDESC was $842.4$711 million at the end of 20182019 and $905.8$714 million at the end of 2017. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $714.3 million at the end of 2018 and $769.7 million at the end of 2017.2018. The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels. Significant assumptions used to determine the above benefit obligations are as follows: | | Pension Benefits | | | Other Postretirement Benefits | | | | 2019 | | | 2018 | | | 2019 | | | 2018 | | Annual discount rate used to determine benefit obligation | | | 3.47 | % | | | 4.35 | % | | | 3.52 | % | | | 4.38 | % | Assumed annual rate of future salary increases for projected benefit obligation | | | 3.00 | % | | | 3.00 | % | | N/A | | | N/A | |
| | | | | | | | | | | | | | Pension Benefits | | Other Postretirement Benefits | | 2018 | | 2017 | | 2018 | | 2017 | Annual discount rate used to determine benefit obligation | 4.35 | % | | 3.71 | % | | 4.38 | % | | 3.74 | % | Assumed annual rate of future salary increases for projected benefit obligation | 3.00 | % | | 3.00 | % | | 3.00 | % | | 3.00 | % |
A 6.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018.2019. The rate was assumed to decrease gradually to 5.0% for 2023 and to remain at that level thereafter.
A one percent increase in the assumed health care cost trend rate for the CompanyDESC would increase the postretirement benefit obligation by $0.7less than $1 million at December 31, 20182019 and by $1.6$1 million at December 31, 2017.2018. A one percent decrease in the assumed health care cost trend rate for the CompanyDESC would decrease the postretirement benefit obligation by $0.6less than $1 million at December 31, 20182019 and by $1.4$1 million at December 31, 2017. A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $0.6 million at December 31, 2018 and by $1.3 million at December 31, 2017. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $0.5 million at December 31, 2018 and by $1.1 million at December 31, 2017.
2018.Funded Status | | Pension Benefits | | | Other Postretirement Benefits | | At December 31, | | 2019 | | | 2018 | | | 2019 | | | 2018 | | (millions) | | | | | | | | | | | | | | | | | Fair value of plan assets | | $ | 725 | | | $ | 676 | | | $ | — | | | $ | — | | Benefit obligation | | | 727 | | | | 732 | | | | 214 | | | | 187 | | Funded status | | $ | (2 | ) | | $ | (56 | ) | | $ | (214 | ) | | $ | (187 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | December 31, | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | Fair value of plan assets | | $ | 727.3 |
| | $ | 849.6 |
| | — |
| | — |
| | $ | 676.7 |
| | $ | 781.3 |
| | — |
| | — |
| Benefit obligation | | 863.5 |
| | 933.2 |
| | $ | 253.7 |
| | $ | 289.2 |
| | 732.3 |
| | 793.0 |
| | $ | 187.4 |
| | $ | 216.6 |
| Funded status | | $ | (136.2 | ) | | $ | (83.6 | ) | | $ | (253.7 | ) | | $ | (289.2 | ) | | $ | (55.6 | ) | | $ | (11.7 | ) | | $ | (187.4 | ) | | $ | (216.6 | ) |
Amounts recognized on the consolidated balance sheets were as follows: | | Pension Benefits | | | Other Postretirement Benefits | | At December 31, | | 2019 | | | 2018 | | | 2019 | | | 2018 | | (millions) | | | | | | | | | | | | | | | | | Current liability | | $ | — | | | $ | — | | | $ | (13 | ) | | $ | (11 | ) | Noncurrent liability | | | (2 | ) | | | (56 | ) | | | (201 | ) | | | (177 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | December 31, | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | Current liability | | — |
| | — |
| | $ | (13.3 | ) | | $ | (13.5 | ) | | — |
| | — |
| | $ | (10.5 | ) | | $ | (10.8 | ) | Noncurrent liability | | $ | (136.2 | ) | | $ | (83.6 | ) | | (240.4 | ) | | (275.7 | ) | | $ | (55.6 | ) | | $ | (11.7 | ) | | (176.9 | ) | | (205.8 | ) |
Amounts recognized in accumulated other comprehensive loss were as follows: | | Pension Benefits | | | Other Postretirement Benefits | | At December 31, | | 2019 | | | 2018 | | | 2019 | | | 2018 | | (millions) | | | | | | | | | | | | | | | | | Net actuarial loss | | $ | 2 | | | $ | 3 | | | $ | 2 | | | $ | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | December 31, | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | Net actuarial loss | | $ | 12.8 |
| | $ | 8.8 |
| | $ | 1.1 |
| | $ | 3.5 |
| | $ | 3.4 |
| | $ | 2.1 |
| | $ | 0.5 |
| | $ | 1.5 |
| Prior service cost | | 0.1 |
| | 0.1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Total | | $ | 12.9 |
| | $ | 8.9 |
| | $ | 1.1 |
| | $ | 3.5 |
| | $ | 3.4 |
| | $ | 2.1 |
| | $ | 0.5 |
| | $ | 1.5 |
|
44
Amounts recognized in regulatory assets were as follows: | | | Pension Benefits | | | Other Postretirement Benefits | | | | | The Company | | Consolidated SCE&G | | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | | December 31, | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | At December 31, | | | 2019 | | | 2018 | | | 2019 | | | 2018 | | (millions) | | | | | | | | | | | | | | | | | | Net actuarial loss | | $ | 230.4 |
| | $ | 194.8 |
| | $ | 10.9 |
| | $ | 43.3 |
| | $ | 202.4 |
| | $ | 171.4 |
| | $ | 9.0 |
| | $ | 35.9 |
| | $ | 125 | | | $ | 202 | | | $ | 29 | | | $ | 9 | | Prior service cost | | 0.7 |
| | 1.2 |
| | — |
| | — |
| | 0.6 |
| | 1.0 |
| | — |
| | — |
| | | — | | | | 1 | | | | — | | | | — | | Total | | $ | 231.1 |
| | $ | 196.0 |
| | $ | 10.9 |
| | $ | 43.3 |
| | $ | 203.0 |
| | $ | 172.4 |
| | $ | 9.0 |
| | $ | 35.9 |
| | $ | 125 | | | $ | 203 | | | $ | 29 | | | $ | 9 | |
In connection with the joint ownership of Summer, Station, costs related to the pension benefit obligationpensions attributable to Santee Cooper as of December 31, 2019 and 2018 and 2017 totaled $24.9$19 million and $21.4$25 million, respectively, and were recorded within deferred debits. The unfundedCosts related to other postretirement benefit obligationbenefits attributable to Santee Cooper as of December 31, 2019 and 2018 and 2017 totaled $12.4$15 million and $14.7$12 million, respectively, and was recorded within deferred debits. Changes in Fair Value of Plan Assets Pension Benefits | | | | | | | | | (millions) | | 2019 | | | 2018 | | Fair value of plan assets, January 1 | | $ | 677 | | | $ | 781 | | Actual return (loss) on plan assets | | | 149 | | | | (43 | ) | Benefits paid | | | (21 | ) | | | (61 | ) | Settlements | | | (80 | ) | | | — | | Fair value of plan assets, December 31 | | $ | 725 | | | $ | 677 | |
| | | | | | | | | | | | | | | | | | Pension Benefits
| | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Fair value of plan assets, January 1 | | $ | 849.6 |
| | $ | 793.6 |
| | $ | 781.3 |
| | $ | 732.9 |
| Actual return (loss) on plan assets | | (50.6 | ) | | 128.4 |
| | (43.3 | ) | | 110.4 |
| Benefits paid | | (71.7 | ) | | (72.4 | ) | | (61.3 | ) | | (62.0 | ) | Fair value of plan assets, December 31 | | $ | 727.3 |
| | $ | 849.6 |
| | $ | 676.7 |
| | $ | 781.3 |
|
Investment Policies and Strategies The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the obligations of the pension plan, (2) overseeing the plan's investments in an asset-liability framework that considers the funding surplus (or deficit) between assets and liabilities, and overall risk associated with assets as compared to liabilities, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. SCANADESC uses a dynamic investment strategy for the management of the pension plan assets. This strategy will lead to a reduction in equities and an increase in long duration fixed income allocations over time with the intention of reducing volatility of funded status and pension costs.
The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, levels of diversification, investment managers and performance expectations. The total portfolio is constructed and maintained to provide prudent diversification with regard to the concentration of holdings in individual issues, corporations, or industries.
Transactions involving certain types of investments are prohibited. These include, except where utilized by a hedge fund manager, any form of private equity; commodities or commodity contracts (except for unleveraged stock or bond index futures and currency futures and options); ownership of real estate in any form other than publicly traded securities; short sales, warrants or margin transactions, or any leveraged investments; and natural resource properties. Investments made for the purpose of engaging in speculative trading are also prohibited.
The pension plan asset allocation at December 31, 20182019 and 20172018 and the target allocation for 20192020 are as follows: | | Percentage of Plan Assets | | | | Target Allocation | | | December 31, | | Asset Category | | 2020 | | | 2019 | | | 2018 | | Equity Securities | | | 45 | % | | | 64 | % | | | 55 | % | Fixed Income | | | 50 | % | | | 35 | % | | | 34 | % | Cash | | | 5 | % | | | 1 | % | | | — | % | Hedge Funds | | | — | % | | | — | % | | | 11 | % |
| | | | | | | | | | | | | Percentage of Plan Assets | | | Target Allocation | |
December 31, | Asset Category | | 2019 | | 2018 | | 2017 | Equity Securities | | 58 | % | | 55 | % | | 58 | % | Fixed Income | | 33 | % | | 34 | % | | 31 | % | Hedge Funds | | 9 | % | | 11 | % | | 11 | % |
For 2019,2020, the expected long-term rate of return on assets will be 7%. In developing the expected long-term rate of return assumptions, management evaluates the pension plan’s historical cumulative actual returns over several periods, considers the expected active and passive returns across various asset classes and assumes the target allocation is achieved. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate.
Additional rebalancing may occur subject to funded status improvements as part of the dynamic investment strategy described previously. Assets held by the pension plan are measured at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At December 31, 20182019 and 2017,2018, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows: | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Investments with fair value measure at Level 2: | | | | | | | | | Mutual funds | | $ | 107 |
| | $ | 120 |
| | $ | 99 |
| | $ | 110 |
| Short-term investment vehicles | | 20 |
| | 17 |
| | 19 |
| | 16 |
| US Treasury securities | | 7 |
| | 15 |
| | 7 |
| | 14 |
| Corporate debt instruments | | 92 |
| | 91 |
| | 86 |
| | 84 |
| Government and other debt instruments | | 18 |
| | 17 |
| | 16 |
| | 15 |
| Total assets in the fair value hierarchy | | 244 |
| | 260 |
| | 227 |
| | 239 |
| | | | | | | | | | Investments at net asset value: | | | | | | | | | Common collective trust | | 400 |
| | 498 |
| | 373 |
| | 458 |
| Joint venture interests | | 83 |
| | 92 |
| | 77 |
| | 84 |
| Total investments at fair value | | $ | 727 |
| | $ | 850 |
| | $ | 677 |
| | $ | 781 |
|
At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | Investments with fair value measure at Level 2: | | | | | | | | | Mutual funds | | $ | 152 | | | $ | 99 | | Short-term investment vehicles | | | — | | | | 19 | | US Treasury securities | | | 3 | | | | 7 | | Corporate debt instruments | | | 233 | | | | 86 | | Government and other debt instruments | | | 26 | | | | 16 | | Total assets in the fair value hierarchy | | | 414 | | | | 227 | | Investments at net asset value: | | | | | | | | | Common collective trust | | | 311 | | | | 373 | | Joint venture interests | | | — | | | | 77 | | Total investments | | $ | 725 | | | $ | 677 | |
For all periods presented, assets with fair value measurements classified as Level 1 were insignificant, and there were no assets with fair value measurements classified as Level 3. There were no0 transfers of fair value amounts into or out of Levels 1, 2 or 3 during 20182019 or 2017.
2018.Mutual funds held by the plan are open-end mutual funds registered with the SEC. The price of the mutual funds' shares is based on its NAV, which is determined by dividing the total value of portfolio investments, less any liabilities, by the total number of shares outstanding. For purposes of calculating NAV, portfolio securities and other assets for which market quotes are readily available are valued at market value. Short-term investment vehicles are funds that invest in short-term fixed income instruments and are valued using observable prices of the underlying fund assets based on trade data for identical or similar securities. US Treasury securities are valued using quoted market prices or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Corporate debt instruments and government and other debt instruments are valued based on recently executed transactions, using quoted market prices, or based on models using observable inputs from market sources such as external prices or spreads or benchmarked thereto. Common collective trust assets and limited partnerships are valued at NAV, which has been determined based on the unit values of the trust funds. Unit values are determined by the organization sponsoring such trust funds by dividing the trust funds’ net assets at fair value by the units outstanding at each valuation date. Joint venture interests are invested in a hedge fund of funds partnership that invests directly in multiple hedge fund strategies that are not traded on exchanges and not traded on a daily basis. The valuation of such multi-strategy hedge fund of funds is estimated based on the NAV of the underlying hedge fund strategies using consistent valuation guidelines that account for variations that may influence their fair value. Total benefits expected to be paid from the pension plan or company assets for the other postretirement benefits plan (net of participant contributions), respectively, are as follows:
Expected Benefit Payments (millions) | | Pension Benefits | | | Other Postretirement Benefits | | 2020 | | $ | 70 | | | $ | 13 | | 2021 | | | 37 | | | | 13 | | 2022 | | | 48 | | | | 13 | | 2023 | | | 46 | | | | 13 | | 2024 | | | 46 | | | | 13 | | 2025 - 2029 | | | 210 | | | | 69 | |
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | 2019 | | $ | 71.5 |
| | $ | 13.6 |
| | $ | 71.5 |
| | $ | 10.8 |
| 2020 | | 62.4 |
| | 14.3 |
| | 62.4 |
| | 11.4 |
| 2021 | | 65.6 |
| | 14.9 |
| | 65.6 |
| | 11.8 |
| 2022 | | 69.6 |
| | 15.4 |
| | 69.6 |
| | 12.2 |
| 2023 | | 66.6 |
| | 15.8 |
| | 66.6 |
| | 12.6 |
| 2024-2028 | | 284.9 |
| | 82.3 |
| | 284.9 |
| | 65.4 |
|
Pension Plan Contributions The pension trust is adequately funded under current regulations. No contributions have been required since 1997, and as a result of closing the plan to new entrants and freezing benefit accruals at the end of 2023, no significant contributions to the pension trust are expected for the foreseeable future based on current market conditions and assumptions, nor is a limitation on benefit payments expected to apply.
Net Periodic Benefit Cost Net periodic benefit cost is recorded utilizing beginning of the year assumptions. Disclosures required for these plans are set forth in the following tables. 46
Components of Net Periodic Benefit Cost | | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Service cost | | $ | 15 | | | $ | 17 | | | $ | 18 | | | $ | 3 | | | $ | 4 | | | $ | 4 | | Interest cost | | | 28 | | | | 29 | | | | 32 | | | | 9 | | | | 8 | | | | 9 | | Expected return on assets | | | (40 | ) | | | (48 | ) | | | (46 | ) | | | — | | | | — | | | | — | | Prior service cost amortization | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | | Amortization of actuarial losses | | | 11 | | | | 11 | | | | 14 | | | | — | | | | — | | | | 1 | | Settlement loss | | | 16 | | | | — | | | | — | | | | — | | | | — | | | | — | | Curtailment | | | 6 | | | | — | | | | — | | | | 3 | | | | — | | | | — | | Net periodic benefit cost | | $ | 36 | | | $ | 9 | | | $ | 19 | | | $ | 15 | | | $ | 12 | | | $ | 14 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Service cost | | $ | 21.0 |
| | $ | 21.7 |
| | $ | 20.7 |
| | $ | 4.6 |
| | $ | 4.5 |
| | $ | 4.4 |
| Interest cost | | 34.1 |
| | 37.4 |
| | 39.4 |
| | 10.1 |
| | 11.5 |
| | 12.1 |
| Expected return on assets | | (56.7 | ) | | (54.7 | ) | | (55.9 | ) | | n/a |
| | n/a |
| | n/a |
| Prior service cost amortization | | 0.5 |
| | 1.6 |
| | 3.9 |
| | — |
| | — |
| | 0.3 |
| Amortization of actuarial losses | | 12.8 |
| | 16.3 |
| | 14.8 |
| | 0.7 |
| | 1.0 |
| | 0.5 |
| Net periodic benefit cost | | $ | 11.7 |
| | $ | 22.3 |
| | $ | 22.9 |
| | $ | 15.4 |
| | $ | 17.0 |
| | $ | 17.3 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated SCE&G | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Service cost | | $ | 17.1 |
| | $ | 18.1 |
| | $ | 16.9 |
| | $ | 3.6 |
| | $ | 3.7 |
| | $ | 3.6 |
| Interest cost | | 29.0 |
| | 31.9 |
| | 33.4 |
| | 8.0 |
| | 9.5 |
| | 9.9 |
| Expected return on assets | | (48.1 | ) | | (46.7 | ) | | (47.4 | ) | | n/a |
| | n/a |
| | n/a |
| Prior service cost amortization | | 0.4 |
| | 1.4 |
| | 3.4 |
| | — |
| | — |
| | 0.3 |
| Amortization of actuarial losses | | 10.9 |
| | 13.9 |
| | 12.5 |
| | 0.6 |
| | 0.8 |
| | 0.4 |
| Net periodic benefit cost | | $ | 9.3 |
| | $ | 18.6 |
| | $ | 18.8 |
| | $ | 12.2 |
| | $ | 14.0 |
| | $ | 14.2 |
|
In connection with regulatory orders, SCE&GDESC recovers current pension costs through 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. For retail electric operations, current pension expense is recognized based on amounts collected through a rate rider, and differences between actual pension expense and amounts recognized pursuant to the rider are deferred as a regulatory asset (for under-collections) or regulatory liability (for over-collections) as applicable. In addition, SCE&GDESC amortizes certain previously deferred pension costs. See Note 2.
3.Other changes in plan assets and benefit obligations recognized in OCIother comprehensive income (net of tax) were as follows: | | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Current year actuarial (gain) loss | | $ | (1 | ) | | $ | 1 | | | $ | — | | | $ | 1 | | | $ | (1 | ) | | $ | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Current year actuarial (gain) loss | | $ | 4.5 |
| | $ | (1.0 | ) | | $ | 0.6 |
| | $ | (2.4 | ) | | $ | 1.1 |
| | $ | 0.8 |
| Amortization of actuarial losses | | (0.5 | ) | | (0.6 | ) | | (0.6 | ) | | — |
| | (0.1 | ) | | — |
| Amortization of prior service cost | | — |
| | — |
| | (0.1 | ) | | — |
| | — |
| | — |
| Total recognized in OCI | | $ | 4.0 |
| | $ | (1.6 | ) | | $ | (0.1 | ) | | $ | (2.4 | ) | | $ | 1.0 |
| | $ | 0.8 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated SCE&G | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Current year actuarial loss | | $ | 1.4 |
| | $ | 0.3 |
| | — |
| | $ | (1.0 | ) | | $ | 0.5 |
| | $ | 0.3 |
| Amortization of actuarial losses | | (0.1 | ) | | (0.1 | ) | | $ | (0.1 | ) | | — |
| | — |
| | — |
| Total recognized in OCI | | $ | 1.3 |
| | $ | 0.2 |
| | $ | (0.1 | ) | | $ | (1.0 | ) | | $ | 0.5 |
| | $ | 0.3 |
|
Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows: | | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | | | | | | | | | | | | | Current year actuarial (gain) loss | | $ | (51 | ) | | $ | 41 | | | $ | (25 | ) | | $ | 20 | | | $ | (26 | ) | | $ | 7 | | Amortization of actuarial losses | | | (11 | ) | | | (10 | ) | | | (13 | ) | | | — | | | | (1 | ) | | | — | | Amortization of prior service cost | | | — | | | | — | | | | (1 | ) | | | — | | | | — | | | | — | | Settlement loss | | | (16 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | Total recognized in regulatory assets | | $ | (78 | ) | | $ | 31 | | | $ | (39 | ) | | $ | 20 | | | $ | (27 | ) | | $ | 7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Current year actuarial (gain) loss | | $ | 46.7 |
| | $ | (27.1 | ) | | $ | 29.4 |
| | $ | (31.8 | ) | | $ | 9.4 |
| | $ | 11.1 |
| Amortization of actuarial losses | | (11.1 | ) | | (14.1 | ) | | (12.7 | ) | | (0.6 | ) | | (0.8 | ) | | (0.4 | ) | Amortization of prior service cost | | (0.5 | ) | | (1.4 | ) | | (3.4 | ) | | — |
| | — |
| | (0.3 | ) | Total recognized in regulatory assets | | $ | 35.1 |
| | $ | (42.6 | ) | | $ | 13.3 |
| | $ | (32.4 | ) | | $ | 8.6 |
| | $ | 10.4 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | Consolidated SCE&G | | Pension Benefits | | Other Postretirement Benefits | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Current year actuarial (gain) loss | | $ | 40.7 |
| | $ | (24.8 | ) | | $ | 26.3 |
| | $ | (26.4 | ) | | $ | 7.3 |
| | $ | 9.2 |
| Amortization of actuarial losses | | (9.7 | ) | | (12.5 | ) | | (11.2 | ) | | (0.5 | ) | | (0.7 | ) | | (0.3 | ) | Amortization of prior service cost | | (0.4 | ) | | (1.3 | ) | | (3.0 | ) | | — |
| | — |
| | (0.2 | ) | Total recognized in regulatory assets | | $ | 30.6 |
| | $ | (38.6 | ) | | $ | 12.1 |
| | $ | (26.9 | ) | | $ | 6.6 |
| | $ | 8.7 |
|
Significant Assumptions Usedassumptions used in Determining Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | | | Pension Benefits | | Other Postretirement Benefits | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Discount rate | 3.71 | % | | 4.22 | % | | 4.68 | % | | 3.74 | % | | 4.30 | % | | 4.78 | % | Expected return on plan assets | 7.00 | % | | 7.25 | % | | 7.50 | % | | n/a |
| | n/a |
| | n/a |
| Rate of compensation increase | 3.00 | % | | 3.00 | % | | 3.00 | % | | 3.00 | % | | 3.00 | % | | 3.00 | % | Health care cost trend rate | n/a |
| | n/a |
| | n/a |
| | 7.00 | % | | 6.60 | % | | 7.00 | % | Ultimate health care cost trend rate | n/a |
| | n/a |
| | n/a |
| | 5.00 | % | | 5.00 | % | | 5.00 | % | Year achieved | n/a |
| | n/a |
| | n/a |
| | 2023 |
| | 2021 |
| | 2021 |
|
The estimated amounts to be amortized from accumulated other comprehensive loss intodetermining net periodic benefit cost in 2019 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant:cost: | | Pension Benefits | | | Other Postretirement Benefits | | Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | | 2019 | | | 2018 | | | 2017 | | Discount rate | | 3.57/4.38% | | | | 3.71 | % | | | 4.22 | % | | 4.08/4.41% | | | | 3.74 | % | | | 4.30 | % | Expected return on plan assets | | | 7.00 | % | | | 7.00 | % | | | 7.25 | % | | n/a | | | n/a | | | n/a | | Rate of compensation increase | | | 3.00 | % | | | 3.00 | % | | | 3.00 | % | | n/a | | | n/a | | | n/a | | Health care cost trend rate | | | | | | | | | | | | | | | 6.60 | % | | | 7.00 | % | | | 6.60 | % | Ultimate health care cost trend rate | | | | | | | | | | | | | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | Year achieved | | | | | | | | | | | | | | 2023 | | | 2023 | | | 2021 | |
| | | | | | | | | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | Actuarial loss | | $ | 0.8 |
| | — |
|
The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 20192020 are as follows: (millions) | | Pension Benefits | | | Other Postretirement Benefits | | Actuarial loss | | $ | 6 | | | $ | 1 | |
| | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of Dollars | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Actuarial loss | | $ | 14.7 |
| | — |
| | $ | 12.9 |
| | — |
| Prior service cost | | 0.3 |
| | — |
| | 0.3 |
| | — |
| Total | | $ | 15.0 |
| | — |
| | $ | 13.2 |
| | — |
|
Other postretirement benefit costs are subject to annual per capita limits pursuant to the plan's design. As a result, the effect of a one-percent increase or decrease in the assumed health care cost trend rate on total service and interest cost is not significant. 401(k) Retirement Savings Plan SCANA sponsors a defined contribution plan in which eligible employees may defer up to 75% of eligible earnings subject to certain limits and may diversify their investments. SCE&GDESC participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. SuchThe matching contributions made by the CompanyDESC totaled $24.1$14 million in 2019, $20 million in 2018 $27.9and $23 million in 2017 and $27.5 million in 2016. These matching contributions included those made by Consolidated SCE&G, which totaled $19.6 million in 2018, $23.4 million in 2017 and $22.9 million in 2016.2017. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and non-forfeitable at all times.
10. SHARE-BASED COMPENSATION
The LTECP provided for grants47
12. COMMITMENTS AND CONTINGENCIES As a result of nonqualified and incentive stock options, stock appreciation rights, restricted stock, performance shares, performance units and restricted stock units to certain key employees and non-employee directors. The LTECP authorized the issuance of up to five million shares of SCANA’s common stock, no more than one million of which could be grantedissues generated in the formordinary course of restricted stock. Compensation cost was measuredbusiness, DESC is involved in legal proceedings before various courts and is periodically subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for DESC to estimate a range of possible loss. For such matters that DESC cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that DESC is able to estimate a range of possible loss. For legal proceedings and governmental examinations that DESC is able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent DESC’s maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the grant-date fair value of the instruments issued and was recognized over the period that an employee provided service in exchange for the award. Share-based payment awards didcurrent estimate. For current proceedings not have non-forfeitable rights to dividends or dividend equivalents. To the extentspecifically reported below, management does not anticipate that the awards themselves did not vest, dividends or dividend equivalents whichliabilities, if any, arising from such proceedings would have been paida material effect on those awards did not vest.
For all periods presented, performance cycles provided for performance measurementDESC’s financial position, liquidity or results of operations.Environmental Matters DESC is subject to costs resulting from a number of federal, state and award determination based on performance over a single three-year cycle, with payment of awards being deferred until after the end of the three-year performance cycle. In each of these performance cycles, 30% of the performance awards were granted in the form of restricted share units, which were liability awards payable in cash,local laws and 70% of the awards were granted in performance shares, each of which had a value equalregulations designed to and changed with, the value of a share of SCANA common stock. Dividend equivalents were accrued on the performance sharesprotect human health and the restricted share units. Performance awardsenvironment. These laws and related dividend equivalents were subject to forfeitureregulations affect future planning and existing operations. They can result in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards were determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50%)increased capital, operating and growth in GAAP-adjusted net earnings per share (weighted 50%). Compensation cost of liability awards was recognized over their respective three-year performance periods based on the estimated fair value of the award, which was periodically updated based on expected ultimate cash payout, and was reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $5.5 million in 2018, $28.0 million in 2017 and $18.4 million in 2016 for the Company and approximately $3.5 million in 2018, $20.2 million in 2017 and $13.2 million in 2016 for Consolidated SCE&G.
Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $(1.7) million in 2018, $(9.0) million in 2017 and $25.6 million in 2016 for the Company and approximately $(0.9) million in 2018, $(6.3) million in 2017 and $17.3 million in 2016 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in no capitalized compensationother costs in 2018, $(1.3) million in 2017 and $3.3 million in 2016 for the Company and no capitalized compensation costs in 2018, $(0.9) million in 2017 and $3.1 million in 2016 for Consolidated SCE&G.
In connection with the SCANA Combination, effective January 1, 2019, all grants discussed above were deemed to be vested at their target levels and were converted into the right to receive lump sum amounts based on the value of Dominion Energy stock at that time. As such, additional compensation cost of $28.6 million will be recorded in the first quarter of 2019 as a result of compliance, remediation, containment and monitoring obligations.From a regulatory perspective, DESC and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. DESC and GENCO participate in the merger. Related cash-settlement payments totaling $19.6 million were made in January 2019, SO2 and further lump sum amounts of $6.7 millionNOX emission allowance programs with respect to coal plant emissions and $9.1 millionalso have constructed additional pollution control equipment at their coal-fired electric generating plants. These actions are expected to be paid in 2020address many of the rules and 2021, respectively,regulations discussed herein. Air CAA The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation's air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of DESC’s facilities are subject to the CAA’s permitting and other requirements. MATS In February 2019, the EPA published a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil-fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and DESC is complying with the applicable requirements of the rule and does not expect any adverse impacts to its operations at this time. Ozone Standards The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, DESC is unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on DESC’s results of operations and cash flows. ACE Rule In July 2019, the EPA published the final rule informally referred to as the ACE Rule, as a replacement for the Clean Power Plan. The ACE Rule applies to existing coal-fired power plants. The final rule includes unit-specific performance standards based on the degree of emission reduction levels achievable from unit efficiency improvements to be determined by the permitting agency. The ACE Rule requires states to develop plans by July 2022 to implement these performance standards. These state plans must be approved by the EPA by January 2024. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for DESC. Carbon Regulations In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO2 equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, DESC cannot predict the impact to their results of operations, financial condition and/or cash flows. 48
In December 2018, the EPA proposed revised Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources. The proposed rule would amend the previous determination that the best system of emission reduction for newly constructed coal-fired steam generating units is no longer partial carbon capture and storage. Instead, the proposed revised best system of emission reduction for this source category is the most efficient demonstrated steam cycle (e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. Oil and Gas NSPS In August 2012, the EPA issued an NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued another NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. The amended portions of the 2016 rule were effective immediately upon publication. Until the proposed rule regarding reconsideration is final, DESC is implementing the 2016 regulation. DESC is still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material. Water The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. DESC must comply with applicable aspects of the CWA programs at its operating facilities. Regulation 316(b) In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options,but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above 2 MGD, with a heightened entrainment analysis for those later paymentsfacilities over 125 MGD. DESC has 5 facilities that are not accelerated subject to the final regulations. DESC anticipates that it may have to install impingement control technologies at certain of these stations that have once-through cooling systems. DESC is currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. DESC is conducting studies and implementing plans as required by the rule to determine appropriate intake structure modifications at certain facilities to ensure compliance with this rule. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC. Effluent Limitations Guidelines In September 2015, the EPA released a final rule to revise the ELG Rule. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. In April 2017, the EPA granted two separate petitions for reconsideration of the final ELG Rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the EPA’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates for certain waste streams regulations in the final ELG Rule from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, as DESC expects that wastewater treatment technology retrofits will be required at Williams and Wateree generating stations, the existing regulatory framework in South Carolina provides rate recovery mechanisms that could substantially mitigate any such impacts for DESC. In December 2019, the EPA released proposed revisions to the ELG Rule that, if adopted, could extend the deadlines for compliance with certain standards at several facilities. While the impacts of this rule could be material to DESC’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina provide rate recovery mechanisms that could substantially mitigate any such impacts for the regulated electric utilities. Waste Management and Remediation The operations of DESC are subject to a variety of state and federal laws and regulations governing the management and disposal of solid and hazardous waste, and release of hazardous substances associated with current and/or historical operations. The CERCLA, as amended, and similar state laws, may impose joint, several and strict liability for cleanup on potentially responsible parties who owned, operated or arranged for disposal at facilities affected by a release of hazardous substances. In addition, many states have 49
created programs to incentivize voluntary remediation of sites where historical releases of hazardous substances are identified and property owners or responsible parties decide to initiate cleanups. From time to time, DESC may be identified as a potentially responsible party in connection with employee retirementsthe alleged release of hazardous substances or wastes at a site. Under applicable federal and state laws, DESC could be responsible for costs associated with the investigation or remediation of impacted sites, or subject to contribution claims by other separations priorresponsible parties for their costs incurred at such sites. DESC also may identify, evaluate and remediate other potentially impacted sites under voluntary state programs. Remediation costs may be subject to those dates.
11. COMMITMENTS AND CONTINGENCIES
reimbursement under DESC’s insurance policies, rate recovery mechanisms, or both. Except as described below, DESC does not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.DESC has 4 decommissioned MGP sites in South Carolina that are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. DESC anticipates that activities at these sites will continue through 2024 at an estimated cost of $10 million. In September 2018, DESC submitted an updated remediation work plan for one site to SCDHEC, which if approved, would increase costs by approximately $8 million. DESC expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms and as of December 31, 2019, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23 million and are included in regulatory assets. Due to the uncertainty surrounding the other sites, DESC is unable to make an estimate of the potential financial statement impacts. Ash Pond and Landfill Closure Costs In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. DESC currently has inactive and existing CCR ponds and CCR landfills subject to the final rule at 3 different facilities. This rule created a legal obligation for DESC to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, DESC cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule. In August 2018, the U.S. Court of Appeals for the D.C. Circuit issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Until regulatory action is taken to incorporate the U.S. Court of Appeals for the D.C. Circuit’s decision, DESC is unable to make an estimate of the potential financial statement impacts associated with any future changes to the CCR rule in connection with the court’s remand. Abandoned NuclearNND Project
SCE&G,DESC, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contractan engineering, construction and procurement contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G'sthe NND Project. DESC’s ownership share in these unitsthe NND Project is 55%. Various difficulties were encountered in connection with the project. The ability of the Consortium 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 time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. 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 preceded the filing for bankruptcy protection by the Consortium on March 29, 2017 (see Contractor Bankruptcy Proceedings and Related Uncertaintiesbelow), and were the subject of comprehensive analyses performed by the CompanySCANA, DESC and Santee Cooper.
BasedSantee Cooper decided to suspend construction on the NND Project, on July 31, 2017, and in light of this decision and based on the results of the Company'sSCANA and DESC’s analysis, SCANA and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the CompanyDESC determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the BLRA or through other means. This decision by the CompanySCANA became the focus of numerous legislative, regulatory and legal proceedings, and led to SCE&GDESC recording pre-tax impairment charges in 2017 totaling approximately $1.118$1.1 billion (approximately $690 million net of tax)after-tax). An additional pre-tax impairment loss was recorded in the first quarter of 2018 of approximately $3.6$4 million (approximately $2.7$3 million net of tax)after-tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. See further discussion below under Impairment Considerations.the NND Project. These proceedings continued in 2018, and some of them remain unresolved and are described below and/or inunder Claims and Litigation.
On December 21, 2018, the South Carolina Commission issued the SCANA Merger Approval Order, which, among other things, limited recovery of capital costs related to the NND Project to $2.8 billion. As a result, DESC concluded that the NND Project capital costs exceeding the amounts established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of $1.4 billion ($870 million after-tax) in the fourth quarter of 2018.50
On January 2, 2018, SCANA and Dominion Energy entered into the SCANA Merger Agreement and sought the consents and approvals from governmental entities and the shareholders of SCANA required to consummate the merger. After all consents and approvals were obtained, the SCANA Combination was effective January 1, 2019.
SCANAMerger Approval Order
On December 21, 2018,In accordance with the SCPSC issuedterms of the South Carolina Commission's SCANA Merger Approval Order. The orderOrder, DESC adopted Dominion Energy'sthe Plan-B Levelized Customer Benefits Plan, effective February 2019, whereby the average bill for an SCE&Ga DESC residential electric customer would approximateapproximates that which resulted from the legislatively-mandated temporary reduction that had been put into effect by the SCPSCSouth Carolina Commission in August 2018. Among other things,DESC also recorded a significant impairment charge in the order also sets forthfourth quarter of 2018, which charge resulted from its conclusion that NND Project capital costs exceeding the amount established in the SCANA Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed. In addition, in the first quarter of 2019, DESC recorded the following findingscharges and merger conditions:
No capital costsliabilities which arose from or are related to provisions in the Nuclear Project incurred after March 12, 2015 will be recoverable by SCE&G, which results in rate base associated with the Nuclear Project of $2.768 billion after recording an impairment charge of $1.372 billion (pre-tax, and incremental to impairment losses recorded in 2017).SCANA Merger Approval Order. | • | A charge of $105 million ($79 million after-tax) included within the Corporate and Other segment related to certain assets that had been constructed in connection with the NND Project for which DESC committed to forgo recovery. |
SCE&G will provide refunds and restitution to customers from prior years' revenues totaling an aggregate $2.039 billion, comprised of $1.032 billion to be credited to customers over 20 years and $1.007 billion credited to customers over approximately 11 years. These refunds include amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 2. | • | A regulatory liability for refunds and restitution of amounts previously collected from retail electric customers of $1.0 billion ($756 million after-tax), recorded as a reduction in operating revenue, which will be credited to customers over an estimated 11 years. In addition, a previously existing regulatory liability of $1.0 billion will be credited to customers over 20 years, which reflects amounts to be refunded to customers related to the monetization of guaranty settlement described in Note 3. |
Except | • | A regulatory liability for refunds to natural gas customers totaling $2 million ($2 million after-tax). |
| • | A tax charge of $194 million related to $258 million of regulatory assets for which DESC committed to forgo recovery. |
Further, except for rate adjustments for fuel and environmental costs, demand side managementDSM costs, and other rates routinely adjusted on an annual or biannual basis, SCE&GDESC will freeze retail electric base rates at current levels until January 1, 2021. SCE&G's natural gas customers will receive refunds totaling $2.45 million in 2019, 2020 and 2021 combined.
Corporate giving will increase by $1 million per year for at least five years above historical levels.
SCE&G will not seek to pass on to ratepayers its initial capital investment in CEC, a 540-MW combined-cycle natural gas-fired generating facility, and will not seek to pass on to ratepayers any acquisition premium costs, transition costs, or transaction cost associated with the merger. SCE&G's decision to not seek recovery of the initial capital investment in CEC was included in the determination of impairment charges recorded in 2017.
In addition, the SCPSCThe South Carolina Commission order also approved the removal of SCE&G'sDESC's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018,2019, such investment in these assets included approximately $367$345 million within utility plant, net and approximately $15$37 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC alsoSouth Carolina Commission approved deferral of certainthese operating costs related to the
investment. Recovery investment until recovery of the transmission capital costs and associated deferred operating costs will beis addressed in a future rate proceeding.
Various parties filed petitions for rehearing or reconsideration of the Merger Approval Order. On February 12, 2019, the SCPSC issued a ruling (1) finding that SCE&G was imprudent in its actions by not disclosing material information to the ORS and the SCPSC, and (2) denying the petitions for rehearing or reconsideration as to other issues raised in the various petitions. The Merger Approval Order and the ruling are subject to appeal by various parties. The Company and Consolidated SCE&G cannot predict the outcome of these matters.
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 Nuclear Project and similar units being built for an unaffiliated company as a material factor that caused WEC and WECTEC to seek protection under the bankruptcy laws. As part of such filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the terms of the EPC Contract.
On September 1, 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of WEC and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and asserted against WEC and WECTEC any and all claims that were based thereon or that may have been related thereto. These claims were sold to Citibank on September 27, 2017 as part of a monetization transaction discussed below. Notwithstanding the sale of the claims, SCE&G and Santee Cooper remain responsible for any claims that may be made by WEC and WECTEC against them relating to the EPC Contract.
WEC’s Reorganization Plan was confirmed by the Bankruptcy Court on March 28, 2018, and became effective August 1, 2018. In connection with the effectiveness of the Reorganization Plan, the EPC Contract was deemed rejected. Initially, WEC had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the WEC Subcontractors which have alleged non-payment by the Consortium for amounts owed for work performed on the Nuclear Project and have filed liens on property in Fairfield County, South Carolina, where Unit 2 and Unit 3 were to be located (Unit 2/3 Property). SCE&G is contesting approximately $285 million of filed liens in Fairfield County. Most of these asserted liens are “pre-petition” claims that relate to work performed by WEC Subcontractors before the WEC bankruptcy, although some of them are “post-petition” claims arising from work performed after the WEC bankruptcy.
WEC has indicated that some unsecured creditors have sought or may seek amounts beyond what WEC allocated when it submitted the Reorganization Plan. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the Reorganization Plan allocated by WEC, it is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. See also discussion below regarding limitations with respect to SCE&G’s pre-petition lien obligations arising from its monetization of the Toshiba Settlement.
SCE&G and Santee Cooper are responsible for amounts owed to WEC for valid work performed by WEC Subcontractors on the Nuclear Project after the WEC bankruptcy filing (i.e., post-petition) until termination of the IAA (the IAA Period). While SCE&G and Santee Cooper funded amounts to WEC for such IAA Period obligations on a weekly basis, SCE&G and Santee Cooper undertook a reconciliation to ensure that amounts advanced to WEC for such purposes while the IAA was in effect were paid to WEC Subcontractors. That reconciliation remains ongoing. In the WEC bankruptcy proceeding, deadlines were established for creditors of WEC (including the WEC Subcontractors on the Nuclear Project) to assert the amounts owed to such creditors prior to the WEC bankruptcy filing and during the IAA Period. Many of the WEC Subcontractors have filed such claims. SCE&G does not believe that the claims asserted related to the IAA Period will exceed the amounts previously funded for the currently asserted IAA-related claims, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the IAA. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.
Further, some WEC Subcontractors who have made claims against WEC in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. The WEC Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the IAA. Many of these claimants have also asserted construction liens against the Nuclear Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of WEC Subcontractors during the IAA Period, SCE&G DESC believes there were sufficient amounts previously funded during the IAA Period to pay such validly asserted claims. With respect to the WEC
Subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to WEC’s confirmed Reorganization Plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the WEC Subcontractors may be paid substantially (and potentially in full) from WEC. While SCE&G cannot be assured that it will not have any exposure on account of unpaid WEC Subcontractor claims, which claims SCE&G is presently disputing, SCE&G believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.
Toshiba Settlement and Subsequent Monetization
Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC. In 2015 Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments beginning in October 2017 in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G’s 55% share), subject to certain offsets for payments by WEC in bankruptcy that would have the effect of satisfying the liens discussed above and below.
In September and October 2017, proceeds totaling approximately $1.997 billion were received in full satisfaction of the Toshiba Settlement ($1.098 billion for SCE&G's 55% share). The proceeds were obtained through the receipt of a payment from Toshiba and a payment from Citibank arising from its purchase of all other scheduled payments, including amounts related to the contractor liens discussed above. The purchase agreement with Citibank provides that SCE&G and Santee Cooper (each according to its pro rata share) would indemnify Citibank for its losses arising from misrepresentations or covenant defaults under the purchase agreement. SCE&G and Santee Cooper also assigned their claims under the WEC bankruptcy process to Citibank, and agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. Proceeds received from the Toshiba Settlement are recorded as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be credited to customer bills over 20 years (see Merger Approval Order above).
Several WEC Subcontractors have filed liens against the Unit 2/3 Property, which SCE&G is contesting. Payments under the Toshiba Settlement are subject to reduction if WEC pays WEC Subcontractors holding pre-petition liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for SCE&G's 55% share).
Regulatory, Political and Legal Developments
In connection with the abandonment of the Nuclear Project, various state and local governmental authorities have attempted and may further attempt to challenge, reverse or revoke previously-approved tax or economic development incentives, benefits or exemptions and have attempted and may further attempt to apply such actions retroactively. No assurance can be given as to the timing or outcome of these matters. See Claims and Litigation for a description of specific challenges.
In July 2018, the SCPSC issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the BLRA and altering certain provisions previously applicable under the BLRA, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the Nuclear Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the Nuclear Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 1, 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the Merger Approval Order became effective.
In June 2018, SCE&G filed a lawsuit in the District Court challenging the constitutionality of the rate reductions under the BLRA. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws were unconstitutional. On January 8, 2019, SCE&G voluntarily dismissed this lawsuit without prejudice.
Impairment Considerations
In 2017, the Company and Consolidated SC&G recognized pre-tax impairment losses of approximately $1.118 billion (approximately $690 million net of tax) related to the Nuclear Project. In the first quarter of 2018, the Company and
Consolidated SCE&G recognized a pre-tax impairment loss of approximately $3.6 million (approximately $2.7 million net of tax) in order to further reduce to estimated fair value the carrying value of nuclear fuel which had been acquired for use in Unit 2 and Unit 3. On December 21, 2018, the SCPSC issued the Merger Approval Order which, among other things, limited recovery of capital costs related to the Nuclear Project to $2.768 billion. As a result, the Company and Consolidated SCE&G concluded that Nuclear Project capital costs exceeding the amount established in the Merger Approval Order were probable of loss, regardless of whether the SCANA Combination was completed, and recorded an impairment charge of approximately $1.372 billion (approximately $870.1 million net of tax) in the fourth quarter of 2018.
In addition, the Company and Consolidated SCE&G expect to record additional impairment charges and establish additional liabilities in the first quarter of 2019. These additional amounts arise from or are related to provisions in the Merger Approval Order and an order by the NCUC approving the SCANA Combination that required the successful consummation of the merger before they would become effective. Accordingly, the following impairment charges and liabilities are expected to be recorded by the Company and Consolidated SCE&G (unless otherwise indicated) in the first quarter of 2019:
A pre-tax impairment charge of approximately $105 million (approximately $79 million net of tax) related to certain assets that had been constructed in connection with the Nuclear Project that were not abandoned but were instead transferred to Unit 1.
A regulatory liability for refunds and restitution to electric customers of approximately $1.007 billion pre-tax (approximately $755 million net of tax).
A regulatory liability for refunds to natural gas customers totaling $2.45 million pre-tax (approximately $1.8 million net of tax).
A liability related to charitable contributions in South Carolina of approximately $22 million pre-tax (approximately $16 million net of tax). It is expected that an additional liability related to charitable contributions in North Carolina of approximately $0.7 million pre-tax (approximately $0.5 million net of tax) would be recorded by the Company.
A write-off of excess deferred taxes of approximately $145 million related to the regulatory liability for the monetization of guaranty settlement.
In addition, the SCPSC order approved the removal of SCE&G's investment in certain transmission assets that have not been abandoned from BLRA capital costs. As of December 31, 2018, such investment in these assets included approximately $367 million within utility plant, net and approximately $15 million within regulatory assets, which amount represents certain deferred operating costs. The SCPSC also approved deferral of certain operating costs related to the investment. Recovery of the transmission capital costs and associated deferred operating costs will be addressed in a future rate proceeding. The Company and Consolidated SCE&G believe these transmission capital and deferred operating costs are probable of recovery; however, if the SCPSCSouth Carolina Commission were to disallow recovery of or a reasonable return on all or a portion of them, an impairment charge equalup to the disallowed costs may be required.
Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued an order (1) granting the request of various parties and finding that DESC was imprudent in its actions by not disclosing material information to the ORS and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The deadline to appeal the SCANA Merger Approval Order and the order on rehearing expired in April 2019, and no party has sought appeal. Claims and Litigation
The following describes certain legal proceedings involving DESC relating to events occurring before closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against DESC. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. For certain of these matters, and unless otherwise noted therein, DESC is unable to estimate a reasonable range of possible loss and the related financial statement impacts, but for any such matter there could be a material impact to its results of operations, financial condition and/or cash flows. For the matters for which DESC is able to reasonably estimate a probable loss, the Consolidated Balance Sheets include reserves of $492 million and insurance receivables of $6 million included within other receivables at December 31, 2019. During the twelve months ended December 31, 2019, the Consolidated Statements of Comprehensive Loss includes charges of $590 million ($444 million after-tax), included within the Corporate and Other segment. Ratepayer Class Actions
In May 2018, a consolidated complaint against DESC, SCANA and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the Hampton County Court) against SCE&G, SCANA, and the State of South Carolina (the SCE&GDESC Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&GDESC was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NuclearNND Project, and that SCE&GDESC committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&GDESC may not charge its customers for any past or continuing costs of the NuclearNND Project, sought to have SCANA and SCE&G’sDESC’s assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NuclearNND Project.
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In December 2018, the judgeState Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&GDESC Ratepayer Case. The settlement agreement, providescontingent upon the closing of the SCANA Combination, provided that SCANA and SCE&GDESC would establish an escrow account (the Common Benefit Fund), and proceeds from the Common Benefit Fundescrow account would be distributed to the class members, after payment of certain taxes, attorneys' fees and other expenses and administrative costs. The Common Benefit Fundescrow account would include (1) the sum ofup to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the Common Benefit Fundescrow account in favor of class members over a period of time established by the SCPSCSouth Carolina Commission in its order related to matters before the Concurrent Dockets,South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain SCE&G-ownedDESC-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&GDESC Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA
and SCE&G haveDESC funded thisthe cash payment portion of the escrow account. The court has scheduledheld a fairness hearing on the settlement in May 2019. Any distribution fromIn June 2019, the Common Benefit Fundcourt entered an order granting final approval of the settlement, which order became effective July 2019. In July 2019, DESC transferred $117 million representing the cash payment, plus accrued interest, to the plaintiffs. In addition, property with a net recorded cost of $42 million is subject to court approval. As a result, the Company and Consolidated SCE&G expect to reflect an approximately $157 million ($118 million after-tax) charge in the first quarterprocess of 2019. In additionbeing transferred to court approval, thisthe plaintiffs in coordination with the court-appointed real estate trustee to satisfy the settlement was contingent on the consummation of the SCANA Combination, which became effective January 1, 2019. Therefore, as of December 31, 2018, no accrual for this potential loss has been included in the consolidated financial statements, but is expected to be recorded by the Company and Consolidated SCE&G in the first quarter of 2019.
agreement.In September 2017, a purported class action was filed by Santee Cooper ratepayers against Santee Cooper, SCE&G,DESC, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, CourtSouth Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&GDESC Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NuclearNND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina.Carolina which was denied. In December 2018, Santee Cooper filed its answer to the plaintiffs' fourth amended complaint and filed cross claims against SCE&G. TheseDESC. In October 2019, Santee Cooper voluntarily consented to stay its cross claims include breachagainst DESC pending the outcome of contract accompanied by a fraudulent act, gross negligence, breachthe trial of fiduciary duty, breachthe underlying case. In November 2019, DESC removed the case to the U.S. District Court for the District of contract accompanied by bad faith, wasteSouth Carolina. In December 2019, the plaintiffs and equitable indemnification. In January 2019, SCE&GSantee Cooper filed a motion to dismissremand the case to state court. In January 2020, the case was remanded to state court. In February 2020, the parties executed a preliminary settlement term sheet relating to this matter as well as the Luquire Case and the Glibowski Case described below. The proposed settlement is expected to be $520 million, of which DESC’s portion is $320 million. The parties are currently negotiating a settlement agreement based on the preliminary settlement term sheet that will be presented to the court for preliminary approval. This case is pending. In July 2019, a similar purported class action was filed by certain Santee Cooper's cross claims orCooper ratepayers against DESC, SCANA, Dominion Energy and former directors and officers of SCANA in the alternativeState Court of Common Pleas in Orangeburg, South Carolina (the Luquire Case). In August 2019, DESC, SCANA and Dominion Energy were voluntarily dismissed from the case. The claims are similar to compel arbitration andthe Santee Cooper Ratepayer Case. In February 2020, the parties executed a stay. A hearing has not been scheduled on this motion. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts ofpreliminary settlement term sheet as described above relating to this matter but there could be a material impact to their results of operations, financial condition and/or cash flows.
as well as the Santee Cooper Ratepayer Case and the Glibowski Case. This case is pending.RICO Class Action In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&GDESC and certain former executive officers in the U.S. District Court.Court for the District of South Carolina (the Glibowski Case). The plaintiffs allege,plaintiff alleges, among other things, that SCANA, SCE&GDESC and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&GDESC Ratepayer CaseClass Action settlement described previously contemplates dismissal of claims by SCE&GDESC ratepayers in this case against SCE&G,DESC, SCANA and their former officers. In JanuaryAugust 2019, the plaintiffsindividual defendants filed an amended complaint which continuesmotions to make allegations on behalf ofdismiss. In February 2020, the parties executed a preliminary settlement term sheet as described above relating to this matter as well as the Santee Cooper ratepayers against SCANA, SCE&GRatepayer Case and the individual former executive officers. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
State CourtLuquire Case. This case is pending.SCANA Shareholder Actions
LitigationIn September 2017,February 2018, a purported shareholder derivativeclass action was filed against Dominion Energy and certain former executive officers and directors of SCANA and DESC in the State Court of Common Pleas in Richland County, South Carolina (the Richland County Court). In September 2018, this action was consolidated with another action in the Business Court Pilot Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that certain of the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. These motions are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of WarrenMetzler Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County, South Carolina. Dominion Energy appealed the decision to remand to the Court of Appeals, where the appeal has been consolidated with a similar appeal and remains pending. Motions to stay and to consolidate this case are being held in abeyance. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
In February 2018, a purported class action was filed against certain former executive officers and directors of SCANA and SCE&G and Dominion Energy in the Richland County Court. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the CityDistrict of Warren Lawsuit. In February 2018, Dominion Energy removed the
case to the District CourtSouth Carolina and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County Court.County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has beenwas consolidated with another lawsuit regarding the CitySCANA Merger Agreement to which DESC is not a party. In June 2019, the U.S. Court of Warren Lawsuit.Appeals for the Fourth Circuit reversed the order remanding the case to state court. The Companycase is pending in the U.S. District Court for the District of South Carolina.Employment Class Actions and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
Federal Court Shareholder Actions
IndemnificationIn NovemberAugust 2017, a purported shareholder derivative actioncase was filed against SCANA and certain former executive officers and directors in the District Court. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by disseminating false and misleading information about the Nuclear Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants' motions to dismiss and in October 2018, the court denied SCANA's motion to stay all proceedings pending investigation by a Special Litigation Committee of its Board of Directors, with leave to refile after the SCPSC's decision on the merger between Dominion Energy and SCANA. On January 7, 2019, the defendants filed a motion for judgment on the pleadings, asserting the shareholders in this action lost standing to assert derivative claims as a result of the SCANA Combination. This motion is pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
In September 2017, a purported class action was filed against SCANA and certain former executive officers in the District Court. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the District Court consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of the Exchange Act. The defendants' motions to dismiss are pending. The Company and Consolidated SCE&G cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to their results of operations, financial condition and/or cash flows.
Employment Class Action and Indemnification
In July 2018, a case filed in the U.S. District Court was certified as a class actionfor the District of South Carolina on behalf of persons who were formerly workedemployed at the NuclearNND Project. In July 2018, the court certified this case as a class action. In February 2019, certain of these plaintiffs filed an additional case, which case has been dismissed and the plaintiffs have joined the case filed in August 2017. The plaintiffs allege, among other things, that SCANA, DESC, Fluor Corporation and Fluor Enterprises, Inc. violated the WARNWorker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NuclearNND Project. The plaintiffs allege that the 52
defendants failed to provide adequate advance written notice of their terminations of employment. While SCANAemployment and SCE&G intend to contest this case, it is reasonably possible that a lossare seeking damages, which are estimated to be as much as $75$100 million could be incurred, of which SCE&G's proportionate share as a co-ownerfor 100% of the Nuclear Project would be 55%. This potential loss could arise due to the Fluor Defendants seeking indemnification from SCE&G.
NND Project.In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina (the Fairfield County Court) by the Fluor DefendantsEnterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&GDESC and Santee Cooper. The Fluor Defendantsplaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants' alleged failure and refusal to defend and indemnify the Fluor Defendantsdefendants in the aforementioned case. The CompanyThese cases are pending. FILOT Litigation and Consolidated SCE&G cannot currently estimate the financial statement impacts of these cases, but there could be a material impact to their results of operations, financial condition and/or cash flows.
FILOT Litigation
Related MattersIn November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&GDESC in the State Court of Common Pleas in Fairfield County, Court. The complaint makesSouth Carolina, making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to SCE&G’sDESC’s termination of the FILOT agreement between SCE&GDESC and Fairfield County related to the NuclearNND Project. The plaintiff sought a temporary and permanent injunction to prevent DESC from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. This case is pending. The Company and Consolidated SCE&G are currently unable to make an estimate of the potential impacts to their respective consolidated financial statements related to this matter.
OtherGovernmental Proceedings and Investigations
In June 2018, SCE&GDESC received a notice of proposed assessment of approximately $410 million, excluding interest, from the DORSCDOR following its audit of SCE&G'sDESC’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NuclearNND Project, is based on the DOR’sSCDOR’s position that SCE&G’sDESC’s sales and use tax exemption for the NuclearNND Project does not apply because the facility will not become operational. SCE&GDESC has protested the proposed assessment, which remains pending,pending. In September and recorded an $11 million liabilityOctober 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In February 2020, the SEC filed a complaint against SCANA, two of its former executive officers and DESC in its Consolidated Balance Sheet asthe U.S. District Court for the District of December 31, 2018 for its shareSouth Carolina alleging that the defendants violated federal securities laws by making false and misleading statements about the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of any taxes ultimately due. Onthe NND Project by SCANA and DESC. These matters are pending. SCANA and DESC are cooperating fully with the investigations, including responding to additional subpoenas and document requests; however, Dominion Energy cannot currently predict whether or to what extent SCANA or DESC may incur a material liability.Other Litigation In December 29, 2018, arbitration proceedings commenced between SCE&GDESC and Cameco Corporation (Cameco) related to a supply agreement datedsigned in May 12, 2008. This agreement provides the terms and conditions under which SCE&GDESC agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that SCE&GDESC violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for the 2017 and 2018 delivery years. SCE&GDESC denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. The Company and Consolidated SCE&G cannot determineThis matter is pending. In September 2019, a South Carolina state court jury awarded a judgment to the outcome or timingestate of Jose Larios in a wrongful death suit filed in June 2017 against DESC, of which DESC was apportioned $19 million. DESC holds general liability insurance coverage which is expected to provide payment for substantially all DESC’s liability in this matter.
In 2017October 2019, DESC filed a motion requesting a reduction in the Companyjudgment or, in the alternative, a new trial. In November 2019, DESC’s motion for a new trial was served with subpoenas issuedgranted, setting aside the entire verdict amount. This matter is pending.Contractor Bankruptcy Proceedings Westinghouse’s Reorganization Plan became effective August 1, 2018. Initially, Westinghouse had projected that its Reorganization Plan would pay in full or nearly in full its pre-petition trade creditors, including several of the Westinghouse Subcontractors which have alleged non-payment by the United States Attorney’s OfficeConsortium for amounts owed for work performed on the DistrictNND Project and have filed liens on related property in Fairfield County, South Carolina. DESC is contesting approximately $285 million of South Carolinasuch filed liens. Most of these asserted liens are “pre-petition” claims that relate to work performed by Westinghouse Subcontractors before the Westinghouse bankruptcy, although some of them are “post-petition” claims arising from work performed after the Westinghouse bankruptcy. It is possible that the Reorganization Plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant. In addition, payments under the Toshiba Settlement are subject to reduction if Westinghouse pays Westinghouse Subcontractors holding pre-petition liens directly. Under these circumstances, DESC and Santee Cooper, each in its pro rata share, would be required to make Citibank, N.A., which purchased the staffscheduled payments under the Toshiba Settlement, whole for reductions related to valid subcontractor and vendor pre-petition liens up to $60 million ($33 million for DESC's 55% share). DESC and Santee Cooper were responsible for amounts owed to Westinghouse for valid work performed by Westinghouse Subcontractors on the NND Project after the Westinghouse bankruptcy filing (i.e., post-petition) until termination of the SEC's DivisionIAA (the IAA Period). In the Westinghouse bankruptcy proceeding, deadlines were established for creditors of Enforcement seeking documentsWestinghouse to assert the amounts owed to such creditors prior to the Westinghouse bankruptcy filing and during the IAA Period. Many of the Westinghouse Subcontractors have filed such claims. In December 2019, DESC and Santee Cooper entered into a confidential settlement agreement with W Wind Down Co LLC resolving claims relating to the Nuclear Project. Also, SLED is conducting a criminal investigation intoIAA. 53
Further, some Westinghouse Subcontractors who have made claims against Westinghouse in the handlingbankruptcy proceeding also filed against DESC and Santee Cooper in South Carolina state court for damages. The Westinghouse Subcontractor claims in South Carolina state court include common law claims for pre-petition work, IAA Period work, and work after the termination of the Nuclear Project by SCANA and SCE&G. These investigations are ongoing, and the Company and Consolidated SCE&G intend to fully cooperate with them.
While the Company and Consolidated SCE&G intend to vigorously contest the lawsuits, claims, and audit positions which have been filed or initiated against them, except as noted above, they cannot predict the timing or outcomeIAA. Many of these matters or othersclaimants have also asserted construction liens against the NND Project site. While DESC cannot be assured that may arise, and adverse outcomes from someit will not have any exposure on account of these matters would not be covered by insurance. Except as noted above, the variousunpaid Westinghouse Subcontractor claims, for damages do not specify an amount for those damages, and the number of plaintiffswhich claims DESC is presently disputing, DESC believes it is unlikely that are ultimately certified in any class action lawsuit is unknown. In addition, most of the cases referred to above are in their early stages. For these reasons, the Company and Consolidated SCE&G (i) have not determined that a loss is probable and (ii) except as noted above, cannot provide any estimate or range of potential loss for these matters at this time. Therefore, no accrual for these potential losses has been included in the consolidated financial statements. However, outcomes could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.
The Company and Consolidated SCE&G are subject to various other claims and litigation incidental to their business operations which management anticipatesit will be resolved without a material impactrequired to make payments on the Company's and Consolidated SCE&G's resultsaccount of operations, cash flows or financial condition.
such claims.Nuclear Insurance Under Price-Anderson, SCE&GDESC (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRCU.S. Nuclear Regulatory Commission that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Unit 1.Summer. Price-Anderson provides funds up to $14.0 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 ANIAmerican Nuclear Insurers 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 $137.7$138 million per reactor owned for each nuclear incident occurring at any reactor in the United States,U.S., provided that not more than $20.5$21 million of the liability per reactor would be assessed per year. SCE&G’sDESC’s maximum assessment, based on its two-thirds ownership of Unit 1,Summer, would be $91.8$92 million per incident, but not more than $13.7$14 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.
SCE&GDESC currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1Summer 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. The NEIL policies in 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’sDESC’s portion of the retrospective premium assessment would not exceed $23.4$24 million. SCE&GDESC currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1Summer 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'sDESC's portion of the retrospective premium assessment would not exceed $2.0$2 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 1Summer exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G'sDESC's rates would not recover the cost of any purchased replacement power, SCE&GDESC will retain the risk of loss as a self-insurer. SCE&GDESC 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'sDESC's results of operations, cash flows and financial position.
Environmental
The Company's operations are subject to extensive regulation by various federal and state authorities in the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes. Applicable statutes and rules include the CAA, CWA,Spent Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows. In addition, the Company and Consolidated SCE&G often cannot predict what conditions or requirements will be imposed by regulatory or legislative proposals. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, the Company and Consolidated SCE&G expect to recover such expenditures and costs through existing ratemaking provisions.
From a regulatory perspective, SCANA, SCE&G and GENCO continually monitor and evaluate their current and projected emission levels and strive to comply with all state and federal regulations regarding those emissions. SCE&G and GENCO participate in the SO2 and NOX emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at their coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.
In August 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO2 from newly constructed fossil fuel-fired units. The final rule required all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO2 per MWh and new natural gas units to meet 1,000 pounds CO2 per MWh. In December 2018, the EPA proposed to revise the standard for newly constructed large coal-fired units to 1,900 pounds of CO2 per MWh and for small units to 2,000 pounds CO2 per MWh. The Company and Consolidated SCE&G are monitoring the proposed rule, but do not plan to construct new coal-fired units in the foreseeable future.
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 CPP rule included state-specific goals for reducing national CO2 emissions by 32% from 2005 levels by 2030 and established a phased-in compliance approach beginning in 2022. The rule gave each state from one to three years to issue its SIP, which would ultimately define the specific compliance methodology that would 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 placed the rule under review and the Court of Appeals agreed to hold the case in abeyance. On October 10, 2017, the Administrator of the EPA signed a notice proposing to repeal the rule on the grounds that it exceeds the EPA's statutory authority. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.
On August 21, 2018, the EPA proposed the ACE rule which would replace the CPP. If implemented, the proposed ACE rule would define the “best system of emission reduction” for GHG emissions from existing power plants as on-site, heat-rate efficiency improvements; provide states with a list of “candidate technologies” that can be used to establish standards of performance and incorporated into their state plans; update the EPA’s NSR permitting program to incentivize efficiency improvements at existing power plants; and align CAA section 111(d) general implementing regulations to give states adequate time and flexibility to develop their state plans. The Company and Consolidated SCE&G are currently evaluating the ACE rule for potential impact at their coal fired units and 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 SO2 and NOX 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 SO2 emissions and annual and ozone season NOX emissions to assist in attaining the ozone and fine particle NAAQS. The rule establishes an emissions cap for SO2 and NOX 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 such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule became effective on January 4, 2016, after which state regulators could modify facility NPDES permits to match more restrictive standards, which would require facilities to retrofit with new wastewater treatment technologies. Compliance dates varied by type of wastewater, and some were based on a facility's five-year permit cycle and thus could range from 2018 to 2023. However, the ELG Rule is under reconsideration by the EPA and has been stayed administratively. The EPA has decided to conduct a new rulemaking that could result in revisions to certain flue gas desulfurization wastewater and bottom ash transport water requirements in the ELG Rule. Accordingly, in September 2017 the EPA finalized a rule that resets compliance dates under the ELG Rule to a range from November 1, 2020 to December 31, 2023. The EPA indicates that the new rulemaking process may take up to three years to complete, such that any revisions to the ELG Rule likely would not be final until the summer of 2020. While 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 certain of SCE&G's and GENCO's coal-fired generating facilities. An August 2018 decision by the United States Court of Appeals for the District of Columbia also imposed the rule requirements on CCR ponds at a former generation site owned by SCE&G. 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.
In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. To date, South Carolina has not begun drafting a CCR rule.
FuelThe Nuclear Waste Policy Act of 1982 required that the United States government accept and permanently dispose of high-level radioactive waste and spent nuclear fuel by January 31, 1998, and it imposed on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. SCE&GDESC entered into a Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with the DOE in 1983. As of December 31, 2018,2019, the federal government has not accepted any spent fuel from Unit 1,Summer, and it remains unclear when the repository may become available. SCE&GDESC has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&GSummer. DESC may evaluate other technology as it becomes available.
The provisions of CERCLA authorize the EPA to require the clean-up of hazardous waste sites. The states of South Carolina and North Carolina have similar laws. The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require clean-up. In addition, regulators from the EPA and other federal or state agencies periodically notify the Company that it may be required to perform or participate in the investigation and remediation of a hazardous waste site. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed necessary to investigate and remediate each site. These estimates are refined as additional information becomes available; therefore, actual expenditures may differ significantly from the original estimates. Amounts estimated and accrued to
date for site assessments and clean-up relate solely to regulated operations. Such amounts are recorded in regulatory assets and amortized, with recovery provided through 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 or under review by DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2020 and will cost an additional $9.5 million. In September 2018, SCE&G submitted an updated remediation work plan for one site (Congaree River) to DHEC which, if approved and subsequently permitted by the USACE, would increase remediation cost for that site by approximately $8 million. DHEC is considering a revised remedy under a MRA but has not issued its direction or approval. SCE&G cannot predict if or when DHEC and the USACE may approve or issue permits for this work to proceed. Major remediation activities are accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheets. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. Long-Term Purchase Agreements At December 31, 2018, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $23.3 million and are included in regulatory assets.
Other
The Company and Consolidated SCE&G have recorded an estimated liability for amounts collected in customer rates during 2018 that arose from the impact of the Tax Act. Such amounts have been recorded subject to refund, and are described in Note 2.
Long-Term Purchase Agreements
At December 31, 2018, the Company and Consolidated SCE&G2019, DESC had the following long-term commitments that are noncancelable or cancelable only under certain conditions, and that a third party that will provide the contracted goods or services has used to secure financing. (millions) | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | Thereafter | | | Total | | Purchased electric capacity(1) | | $ | 59 | | | $ | 58 | | | $ | 57 | | | $ | 57 | | | $ | 57 | | | $ | 661 | | | $ | 949 | |
(1) | Includes affiliated amounts with certain solar facilities of $234 million. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | Future Payments | Millions of dollars | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | The Company and Consolidated SCE&G | | $ | 40 |
| | $ | 39 |
| | $ | 39 |
| | $ | 38 |
| | $ | 38 |
| | $ | 396 |
|
Commitments represent estimated amounts payable for energy under power purchase contracts with qualifying facilities which expire at various dates through 2046. Energy payments are generally based on fixed dollar amounts per month and totaled approximately $23.7$37 million in 20182019 and $3.6$24 million in 2017.
Operating Lease Commitments
The Company2018.54
13. LEASES At December 31, 2019, DESC had the following lease assets and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, equipment, rail cars, and for the Company, airplanes. Leases expire at various dates through 2057. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rent Expense | | Future Minimum Rental Payments | Millions of dollars | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | The Company | | $ | 10.2 |
| | $ | 10 |
| | $ | 9.7 |
| | $ | 10 |
| | $ | 8 |
| | $ | 7 |
| | $ | 6 |
| | $ | 4 |
| | $ | 30 |
| Consolidated SCE&G | | 12.2 |
| | 11.4 |
| | 10.2 |
| | 3 |
| | 2 |
| | 1 |
| | 1 |
| | — |
| | 16 |
|
Guarantees, Surety Bonds and Letters of Credit
SCANA has issued guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees areliabilities recorded in the formConsolidated Balance Sheets:At December 31, | | 2019 | | (millions) | | | | | Lease assets: | | | | | Operating lease assets(1) | | $ | 23 | | Finance lease assets(2) | | | 26 | | Total lease assets | | $ | 49 | | Lease liabilities: | | | | | Operating lease - current(3) | | $ | 3 | | Operating lease - noncurrent(4) | | | 20 | | Finance lease - current(5) | | | 7 | | Finance lease - noncurrent | | | 20 | | Total lease liabilities | | $ | 50 | |
(1) | Included in other deferred debits and other assets in the Consolidated Balance Sheets. |
(2) | Included in utility plant, net, in the Consolidated Balance Sheets, net of $24 million of accumulated amortization at December 31, 2019. |
(3) | Included in other current liabilities in the Consolidated Balance Sheets. |
(4) | Included in other deferred credits and other liabilities in the Consolidated Balance Sheets. |
(5) | Included in current portion of long-term debt in the Consolidated Balance Sheets. |
For the year ended December 31, 2019, total lease cost consisted of performance guarantees, primarilythe following: Year Ended December 31, | | 2019 | | (millions) | | | | | Finance lease cost: | | | | | Amortization | | $ | 7 | | Interest | | | 1 | | Operating lease cost | | | 4 | | Short-term lease cost | | | 1 | | Total lease cost | | $ | 13 | |
For the year ended December 31, 2019, cash paid for the purchase and transportation of natural gas, and credit support for certain tax-exempt bond issues. SCANA is not required to recognize a liability for such guarantees unless it becomes probable that performance under the guarantees will be required. SCANA believes the likelihood that it would be required to perform or otherwise incur any losses associated with these guarantees is not probable; therefore, no liability for these guarantees has been recognized. To the extent that a liability subject to a guarantee has been incurred, the liability isamounts included in the consolidated financial statements. measurement of lease liabilities consisted of the following amounts, included in the Consolidated Statements of Cash Flows: Year Ended December 31, | | 2019 | | (millions) | | | | | Operating cash flows from finance leases | | $ | 1 | | Operating cash flows from operating leases | | | 3 | | Financing cash flows from finance leases | | | 7 | |
At December 31, 2018,2019, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $444.6 million.weighted average remaining lease term and weighted average discount rate for finance and operating leases were as follows: At December 31, | | 2019 | | Weighted average remaining lease term - finance leases | | 5 years | | Weighted average remaining lease term - operating leases | | 18 years | | Weighted average discount rate - finance leases | | | 2.94 | % | Weighted average discount rate - operating leases | | | 3.94 | % |
Lease liabilities have the following scheduled maturities: (millions) | | Operating | | | Finance | | 2020 | | $ | 4 | | | $ | 8 | | 2021 | | | 3 | | | | 7 | | 2022 | | | 2 | | | | 5 | | 2023 | | | 2 | | | | 4 | | 2024 | | | 1 | | | | 2 | | After 2024 | | | 23 | | | | 3 | | Total undiscounted lease payments | | | 35 | | | | 29 | | Present value adjustment | | | (12 | ) | | | (2 | ) | Present value of lease liabilities | | $ | 23 | | | $ | 27 | |
At55
14. OPERATING SEGMENTS In December 31, 2018, SCE&G had purchased a $100.4 million surety bond to facilitate commercial transactions with Dominion Energy Carolina Gas Transmission LLC,2019, DESC realigned its segments which became an affiliateresulted in connection with the SCANA Combination.
Under the terms of the surety bond, SCE&G is obligated to indemnify the surety bond company for any amounts paid. Further, the Company had authorized the issuance of letters of credit by financial institutions of approximately $80.4 million, including approximately $39.3 million by Consolidated SCE&G, primarily to facilitate commercial transactions and to provide credit support for certain tax-exempt bond issues. Certain of these letters of credit are supported by lines of credit and are discussed in Note 5.
Asset Retirement Obligations
A liability for the present value of an ARO is recognized when incurred if the liability can be reasonably estimated. Uncertainty about the timing or method of settlementformation of a conditional ARO is factored intosingle primary operating segment. The historical information presented herein has been recast to reflect the measurement of the liability when sufficient information exists, but such uncertainty is not a basis upon which to avoid liability recognition.
current segment presentation.The legal obligations associated with the retirement of long-lived tangible assets that result from their acquisition, construction, developmentCorporate and normal operation relateOther Segment primarily to the Company’s regulated utility operations. As of December 31, 2018, the Company and Consolidated SCE&G have recorded AROs of approximately $218 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $359 million, including $323 million for Consolidated SCE&G, for other conditional obligations primarily related to other generation, transmission and distribution properties, including gas pipelines. All of the amounts recorded are based upon estimates which are subject to varying degrees of precision, particularly since such payments will be made many years in the future. A reconciliation of the beginning and ending aggregate carrying amount of AROs is as follows:
| | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2018 | | 2017 | Beginning balance | | $ | 568 |
| | $ | 558 |
| | $ | 529 |
| | $ | 522 |
| Liabilities incurred | | — |
| | — |
| | — |
| | — |
| Liabilities settled | | (15 | ) | | (10 | ) | | (15 | ) | | (9 | ) | Accretion expense | | 25 |
| | 25 |
| | 23 |
| | 23 |
| Revisions in estimated cash flows | | (1 | ) | | (5 | ) | | 4 |
| | (7 | ) | Ending balance | | $ | 577 |
| | $ | 568 |
| | $ | 541 |
| | $ | 529 |
|
Revisions in estimated cash flows in 2018 and 2017 primarily related to ash pond retirement obligations settled and updates in the anticipated timing of cash flows as work is completed.
12. SEGMENT OF BUSINESS INFORMATION
Reportable segments, which are described below, follow the same accounting policies as those described in Note 1. Intersegment sales and transfers of electricity and gas are recorded based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations primarily generates, transmits and distributes electricity, and is regulated by the SCPSC and FERC. Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, purchases and sells natural gas, primarily at retail. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. Gas Marketing is comprised of the marketing operations of SCANA Energy, which markets natural gas to retail customers in Georgia and to industrial and large commercial customers and municipalities in the Southeast.
All Other includes the parent company and a services company.
Regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operations’ product differs from the other segments, as does its generation process and method of distribution. Gas Marketing operates in a deregulated environment.
Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segmentsspecific items attributable to SCE&G. As a result, no allocation is made to segments for interest charges, income tax expense (benefit) or assets other than utility plant. For nonregulated operations, management uses net income (loss) as the measure ofits operating segment profitability and evaluates total assets for financial position. Intersegment revenue for SCE&G was not significant. Interest income is not reported by segment and is not material. Deferred tax assets are netted with deferred tax liabilities for consolidated reporting purposes.
The consolidated financial statements report operating revenues which are comprised of the energy-related and regulated segments. Revenues from non-reportable and nonregulated segments are included in Other Income. Therefore, the adjustments to total operating revenues remove revenues from non-reportable segments. Adjustments to net income (loss) consist of the unallocated net income (loss) of regulated reportable segments.
Segment Assets include utility plant, net for SCE&G’s Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.
Adjustments to Interest Expense, Income Tax Expense (Benefit), Expenditures for Assets and Deferred Tax Assets include primarily the amounts that are not allocated to the segments. Interest Expense is also adjusted to eliminate charges between affiliates. Adjustments to Depreciation and Amortization consist of non-reportable segment expenses, which are not included in profit measures evaluated by executive management in assessing the depreciationsegment’s performance or in allocating resources.In 2019, DESC reported after-tax net expenses of $1.6 billion for specific items in the Corporate and amortization reported on a consolidated basis. ExpendituresOther segment, all of which were attributable to its operating segment. The net expense for Assets are adjusted for AFC and revisionsspecific items attributable to estimated cash flowsDESC’s operating segment in 2019 primarily related to AROs,the impact of the following items: | • | A $1.0 billion ($756 million after-tax) charge for refunds of amounts previously collected from retail electric customers for the NND Project; |
| • | $590 million ($444 million after-tax) of charges associated with litigation; |
| • | A $194 million tax charge for $258 million of income tax-related regulatory assets for which DESC committed to forgo recovery; |
| • | A $114 million ($86 million after-tax) charge for utility plant primarily for which DESC committed to forgo recovery; |
| • | $100 million ($76 million after-tax) of merger-related costs associated with the SCANA Combination, including a $79 million ($59 million after-tax) charge related to a voluntary retirement program; and |
| • | $66 million tax charges for changes in unrecognized tax benefits. |
In 2018, DESC reported after-tax net expenses of $917 million for specific items in the Corporate and totals not allocatedOther segment, all of which were attributable to other segments. Deferred Tax Assets are adjustedits operating segment. The net expense for specific items attributable to DESC’s operating segment in 2018 primarily related to a $1.4 billion ($870 million after-tax) impairment charge associated with the NND Project. In 2017, DESC reported after-tax net them against deferred tax liabilities onexpenses of $690 million for specific items in the Corporate and Other segment, all of which were attributable to its operating segment. The net expense for specific items attributable to DESC’s operating segment in 2017 related to a consolidated basis.
Disclosure of Reportable Segments
$1.1 billion ($690 million after-tax) impairment charge associated with the NND Project.56
The Company:following table presents segment information pertaining to DESC’s operations: Year Ended December 31, | | Dominion Energy South Carolina | | | Corporate and Other | | | Consolidated Total | | (millions) | | | | | | | | | | | | | 2019 | | | | | | | | | | | | | External revenue | | $ | 2,937 | | | $ | (1,008 | ) | | $ | 1,929 | | Depreciation and amortization | | | 452 | | | | (2 | ) | | | 450 | | Interest and related charges | | | 247 | | | | 13 | | | | 260 | | Income tax expense (benefit) | | | 163 | | | | (175 | ) | | | (12 | ) | Comprehensive income (loss) available (attributable) to common shareholder | | | 408 | | | | (1,647 | ) | | | (1,239 | ) | Capital expenditures | | | 497 | | | | — | | | | 497 | | Total assets (billions) | | | 14.3 | | | | — | | | | 14.3 | | | | | | | | | | | | | | | 2018 | | | | | | | | | | | | | External revenue | | $ | 2,763 | | | $ | (1 | ) | | $ | 2,762 | | Depreciation and amortization | | | 327 | | | | — | | | | 327 | | Interest and related charges | | | 306 | | | | (3 | ) | | | 303 | | Income tax expense (benefit) | | | 98 | | | | (514 | ) | | | (416 | ) | Comprehensive income (loss) available (attributable) to common shareholder | | | 304 | | | | (917 | ) | | | (613 | ) | Capital expenditures | | | 633 | | | | — | | | | 633 | | Total assets (billions) | | | 15.0 | | | | — | | | | 15.0 | | | | | | | | | | | | | | | 2017 | | | | | | | | | | | | | External revenue | | $ | 3,070 | | | $ | — | | | $ | 3,070 | | Depreciation and amortization | | | 312 | | | | — | | | | 312 | | Interest and related charges | | | 288 | | | | — | | | | 288 | | Income tax expense (benefit) | | | 257 | | | | (428 | ) | | | (171 | ) | Comprehensive income (loss) available (attributable) to common shareholder | | | 505 | | | | (690 | ) | | | (185 | ) | Capital expenditures | | | 928 | | | | — | | | | 928 | |
| | | | | | | | | | | | | | | | | | | | | | | | | Millions of dollars | Electric Operations | | Gas Distribution | | Gas Marketing | | All Other | | Adjustments/ Eliminations | | Consolidated Total | 2018 | | | | | | | | | | | | External Revenue | $ | 2,322 |
| | $ | 934 |
| | $ | 796 |
| | — |
| | — |
| | $ | 4,052 |
| Intersegment Revenue | 5 |
| | 1 |
| | 139 |
| | $ | 470 |
| | $ | (615 | ) | | — |
| Operating Income (Loss) | (894 | ) | | 173 |
| | n/a |
| | — |
| | (8 | ) | | (729 | ) | Interest Expense | 18 |
| | 37 |
| | 1 |
| | — |
| | 328 |
| | 384 |
| Depreciation and Amortization | 307 |
| | 94 |
| | 2 |
| | 15 |
| | (15 | ) | | 403 |
| Income Tax Expense (Benefit) | 9 |
| | 26 |
| | 15 |
| | (25 | ) | | (437 | ) | | (412 | ) | Net Income (Loss) | n/a |
| | n/a |
| | 43 |
| | (90 | ) | | (481 | ) | | (528 | ) | Segment Assets | 7,988 |
| | 3,517 |
| | 305 |
| | 1,212 |
| | 4,632 |
| | 17,654 |
| Expenditures for Assets | 973 |
| | 345 |
| | 2 |
| | 8 |
| | (438 | ) | | 890 |
| Deferred Tax Assets | 4 |
| | 17 |
| | 2 |
| | — |
| | (23 | ) | | — |
| | | | | | | | | | | | | 2017 | |
| | |
| | |
| | |
| | |
| | |
| External Revenue | $ | 2,659 |
| | $ | 874 |
| | $ | 874 |
| | — |
| | — |
| | $ | 4,407 |
| Intersegment Revenue | 5 |
| | 2 |
| | 127 |
| | $ | 389 |
| | $ | (523 | ) | | — |
| Operating Income (Loss) | (154 | ) | | 187 |
| | n/a |
| | — |
| | 52 |
| | 85 |
| Interest Expense | 19 |
| | 28 |
| | 1 |
| | — |
| | 315 |
| | 363 |
| Depreciation and Amortization | 295 |
| | 85 |
| | 2 |
| | 16 |
| | (16 | ) | | 382 |
| Income Tax Expense (Benefit) | 8 |
| | 41 |
| | 25 |
| | (7 | ) | | (179 | ) | | (112 | ) | Net Income (Loss) | n/a |
| | n/a |
| | 27 |
| | (46 | ) | | (100 | ) | | (119 | ) | Segment Assets | 11,979 |
| | 3,259 |
| | 230 |
| | 1,042 |
| | 2,229 |
| | 18,739 |
| Expenditures for Assets | 216 |
| | 417 |
| | 2 |
| | 7 |
| | 583 |
| | 1,225 |
| Deferred Tax Assets | 6 |
| | 25 |
| | 9 |
| | — |
| | (40 | ) | | — |
| | | | | | | | | | | | | 2016 | |
| | |
| | |
| | |
| | |
| | |
| External Revenue | $ | 2,614 |
| | $ | 788 |
| | $ | 825 |
| | — |
| | — |
| | $ | 4,227 |
| Intersegment Revenue | 5 |
| | 2 |
| | 111 |
| | $ | 414 |
| | $ | (532 | ) | | — |
| Operating Income | 969 |
| | 149 |
| | n/a |
| | — |
| | 49 |
| | 1,167 |
| Interest Expense | 17 |
| | 25 |
| | 1 |
| | — |
| | 299 |
| | 342 |
| Depreciation and Amortization | 287 |
| | 82 |
| | 2 |
| | 16 |
| | (16 | ) | | 371 |
| Income Tax Expense | 8 |
| | 32 |
| | 19 |
| | — |
| | 212 |
| | 271 |
| Net Income (Loss) | n/a |
| | n/a |
| | 30 |
| | (18 | ) | | 583 |
| | 595 |
| Segment Assets | 11,929 |
| | 2,892 |
| | 230 |
| | 1,124 |
| | 2,532 |
| | 18,707 |
| Expenditures for Assets | 1,275 |
| | 276 |
| | 2 |
| | 11 |
| | 15 |
| | 1,579 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Deferred Tax Assets | 9 |
| | 32 |
| | 11 |
| | — |
| | (52 | ) | | — |
|
Consolidated SCE&G:
| | | | | | | | | | | | | | | | | | Millions of dollars | | Electric Operations | | Gas Distribution | | Adjustments/ Eliminations | | Consolidated Total | 2018 | | | | | | | | | External Revenue | | $ | 2,327 |
| | $ | 435 |
| | ��� |
| | $ | 2,762 |
| Operating Income (Loss) | | (894 | ) | | 63 |
| | — |
| | (831 | ) | Interest Expense | | 18 |
| | — |
| | $ | 285 |
| | 303 |
| Depreciation and Amortization | | 307 |
| | 32 |
| | (12 | ) | | 327 |
| Segment Assets | | 7,988 |
| | 934 |
| | 6,041 |
| | 14,963 |
| Expenditures for Assets | | 973 |
| | 90 |
| | (430 | ) | | 633 |
| Deferred Tax Assets | | 4 |
| | n/a |
| | (4 | ) | | — |
| | | | | | | | | | 2017 | | |
| | |
| | |
| | |
| External Revenue | | $ | 2,664 |
| | $ | 406 |
| | — |
| | $ | 3,070 |
| Operating Income (Loss) | | (154 | ) | | 71 |
| | — |
| | (83 | ) | Interest Expense | | 19 |
| | — |
| | $ | 269 |
| | 288 |
| Depreciation and Amortization | | 295 |
| | 30 |
| | (13 | ) | | 312 |
| Segment Assets | | 11,979 |
| | 869 |
| | 3,098 |
| | 15,946 |
| Expenditures for Assets | | 216 |
| | 65 |
| | 647 |
| | 928 |
| Deferred Tax Assets | | 6 |
| | n/a |
| | (6 | ) | | — |
| | | | | | | | | | 2016 | | |
| | |
| | |
| | |
| External Revenue | | $ | 2,619 |
| | $ | 367 |
| | — |
| | $ | 2,986 |
| Operating Income | | 969 |
| | 56 |
| | — |
| | 1,025 |
| Interest Expense | | 17 |
| | — |
| | $ | 253 |
| | 270 |
| Depreciation and Amortization | | 287 |
| | 28 |
| | (13 | ) | | 302 |
| Segment Assets | | 11,929 |
| | 825 |
| | 3,337 |
| | 16,091 |
| Expenditures for Assets | | 1,275 |
| | 78 |
| | 46 |
| | 1,399 |
| Deferred Tax Assets | | 9 |
| | n/a |
| | (9 | ) | | — |
|
13.15. UTILITY PLANT AND NONUTILITY PROPERTY Major classes of utility plant and other property and their respective balances at December 31, 2019 and 2018 were as follows: At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | Gross utility plant: | | | | | | | | | Generation | | $ | 5,765 | | | $ | 5,751 | | Transmission | | | 1,905 | | | | 1,758 | | Distribution | | | 4,685 | | | | 4,456 | | Storage | | | 73 | | | | 74 | | General and other | | | 549 | | | | 535 | | Intangible | | | 231 | | | | 229 | | Construction work in progress | | | 339 | | | | 350 | | Nuclear fuel | | | 608 | | | | 611 | | Total gross utility plant | | $ | 14,155 | | | $ | 13,764 | | Gross nonutility property | | $ | 75 | | | $ | 73 | |
| | | | | | | | | | Millions of dollars | | The Company | | Consolidated SCE&G | Gross Utility Plant: | | | | | Generation | | $ | 5,751 |
| | $ | 5,751 |
| Transmission | | 2,417 |
| | 1,758 |
| Distribution | | 6,032 |
| | 4,456 |
| Storage | | 99 |
| | 74 |
| General and other | | 631 |
| | 535 |
| Intangible | | 241 |
| | 229 |
| Construction work in progress | | 527 |
| | 350 |
| Nuclear Fuel | | 611 |
| | 611 |
| Total Gross Utility Plant | | $ | 16,309 |
| | $ | 13,764 |
| | | | | | Gross Nonutility Property | | $ | 410 |
| | $ | 73 |
|
57
Jointly Owned Utility Plant SCE&GDESC jointly owns and is the operator of Unit 1.Summer. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’sDESC’s share of the direct expenses of Summer is included in the
corresponding operating expenses on its income statement. Unit 2 and Unit 3The units associated with the NND Project have been reclassified from construction work in progress to a regulatory asset as a result of the decision to stop their construction. See additional discussion at Note 2.3. In May 2019, DESC and Santee Cooper entered into an agreement in which DESC agreed to purchase 11.7% of Santee Cooper’s ownership interest in the NND Project nuclear fuel, which will be used at Summer, for $8 million to true up the ownership percentage from the 55% ownership percentage that was applicable for the NND Project to the 66.7% ownership percentage applicable for Summer.At December 31, | | 2019 | | 2018 | | | Summer Unit 1 | | Summer Unit 1 | Percent owned | | 66.7% | | 66.7% | Plant in service | | $ | 1.4 | | billion | | $ | 1.5 | | billion | Accumulated depreciation | | $ | 684 | | million | | $ | 644 | | million | Construction work in progress | | $ | 79 | | million | | $ | 128 | | million |
| | | | | | | | | | As of December 31, | | 2018 | | 2017 | | | Unit 1 | | Unit 1 | Percent owned | | 66.7% | | 66.7% | Plant in service | | $ | 1.5 | billion | | $ | 1.5 | billion | Accumulated depreciation | | $ | 643.9 | million | | $ | 637.6 | million | Construction work in progress | | $ | 127.5 | million | | $ | 110.1 | million |
Included within other receivables on the balance sheet were amounts due to SCE&GDESC from Santee Cooper for its share of direct expenses. These amounts totaled $46.3$50 million at December 31, 20182019 and $53.8$46 million at December 31, 2017.
14.2018.Sale of Warranty Service Contract Assets In May 2019, DESC entered into an agreement to sell certain warranty service contract assets for total consideration of $7 million. The transaction closed in August 2019, resulting in a $7 million ($5 million after-tax) gain recorded in other income (expense), net in DESC’s Consolidated Statements of Comprehensive Loss. Pursuant to the agreement, upon closing DESC entered into a service agreement with the buyer under which the buyer will compensate DESC in connection with the right to use DESC’s brand in marketing materials and other services over a ten-year term. 16. AFFILIATED AND RELATED PARTY TRANSACTIONS The Company:
The Company received cash distributions from equity-method investees of $2.3 million in 2018, $2.8 million in 2017 and $3.7 million in 2016. The Company made investments in equity-method investees of $4.2 million in 2018, $4.6 million in 2017 and $5.5 million in 2016.
The Company and Consolidated SCE&G:
SCE&GDESC owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&Gemissions at certain of DESC’s generating facilities. DESC accounts for this investment using the equity method. The netPurchases and sales of the total purchases and total salesrelated coal are recorded as other income (expense), net in Other expenses on the consolidated statementsConsolidated Statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G).
| | | | | | | | | | | | | | Millions of Dollars | | 2018 | | 2017 | | 2016 | Purchases from Canadys Refined Coal, LLC | | $ | 149.9 |
| | $ | 162.1 |
| | $ | 161.8 |
| Sales to Canadys Refined Coal, LLC | | 149.0 |
| | 161.1 |
| | 160.8 |
|
| | | | | | | | | | Millions of Dollars | | 2018 | | 2017 | Receivable from Canadys Refined Coal, LLC | | $ | 6.8 |
| | $ | 4.9 |
| Payable to Canadys Refined Coal, LLC | | 6.8 |
| | 4.9 |
|
Consolidated SCE&G:
SCE&GComprehensive Loss.DESC purchases natural gas and related pipeline capacity from SCANA Energy Marketing, Inc. to serveservice its retail gas customers and to satisfy certain electric generation requirements. SCANA Services,These purchases are included within gas purchased for resale or fuel used in electric generation, as applicable in the Consolidated Statements of Comprehensive Loss.DESS, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G,DESC, 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 ServicesDESS processes and pays invoices for Consolidated SCE&GDESC and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are primarily recorded in Other operationother operations and maintenance - nonconsolidated affiliate– affiliated suppliers and Other Income (Expense)other income (expense), net onin the consolidated statementsConsolidated Statements of comprehensive income.Comprehensive Loss. Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | Purchases of coal from affiliate | | $ | 121 | | | $ | 150 | | | $ | 162 | | Sales of coal to affiliate | | | 120 | | | | 149 | | | | 161 | | Purchases of fuel used in electric generation from affiliate | | | 43 | | | | 139 | | | | 127 | | Direct and allocated costs from services company affiliate(1) | | | 297 | | | | 283 | | | | 303 | | Operating Revenues – Electric from sales to affiliate | | | 4 | | | | 5 | | | | 5 | | Operating Revenues – Gas from sales to affiliate | | | 1 | | | | 1 | | | | 1 | | Operating Expenses – Other taxes from affiliate | | | 6 | | | | 6 | | | | 5 | |
(1) | Includes capitalized expenditures of $53 million, $41 million and $82 million for the years ended December 31, 2019, 2018 and 2017, respectively. |
At December 31, | | 2019 | | | 2018 | | (millions) | | | | | | | | | Receivable from Canadys Refined Coal, LLC | | $ | 2 | | | $ | 7 | | Payable to Canadys Refined Coal, LLC | | | 2 | | | | 7 | | Payable to SCANA Energy Marketing, Inc | | | — | | | | 14 | | Payable to DESS | | | 76 | | | | 38 | | Payable to Public Service Company of North Carolina, Incorporated | | | 8 | | | | 7 | |
| | | | | | | | | | | | | | Millions of Dollars | | 2018 | | 2017 | | 2016 | Purchases from SCANA Energy | | $ | 139.0 |
| | $ | 127.4 |
| | $ | 111.5 |
| Direct and Allocated Costs from SCANA Services | | 283.3 |
| | 302.8 |
| | 337.7 |
|
| | | | | | | | | | Millions of Dollars | | 2018 | | 2017 | Payable to SCANA Energy | | $ | 14.1 |
| | $ | 10.0 |
| Payable to SCANA Services | | 37.7 |
| | 42.0 |
|
In connection with the SCANA Combination, purchases from certain entities owned by Dominion Energy became affiliated transactions. During the year ended December 31, 2019, DESC purchased electricity generated by certain solar facilities, totaling $8 million, which is recorded as purchased power in the Consolidated SCE&G's money pool borrowingsStatements of Comprehensive Loss. At December 31, 2019, DESC 58
had accounts payable balances to these affiliates totaling less than $1 million. In addition, during the year ended December 31, 2019, DESC incurred demand and transportation charges from DECG totaling $63 million, of which $19 million is recorded as fuel used in electric generation and $44 million is recorded as gas purchased for resale in the Consolidated Statements of Comprehensive Loss. At December 31, 2019, DESC had an accounts payable balance due to this affiliate totaling $5 million and an accounts receivable to this affiliate totaling $1 million. Borrowings from an affiliate are described in Note 5.6. Certain disclosures regarding SCE&G'sDESC’s participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs are included in Note 9.
15.11.17. OTHER INCOME (EXPENSE), NET
Components of other income (expense), net are as follows: Year Ended December 31, | | 2019 | | | 2018 | | | 2017 | | (millions) | | | | | | | | | | | | | Revenues from contracts with customers | | $ | 4 | | | $ | 5 | | | $ | — | | Other income | | | 19 | | | | 141 | | | | 45 | | Other expense | | | (57 | ) | | | (28 | ) | | | (32 | ) | Allowance for equity funds used during construction | | | 1 | | | | 11 | | | | 15 | | Other income (expense), net | | $ | (33 | ) | | $ | 129 | | | $ | 28 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | Millions of dollars | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | Revenues from contracts with customers | | $ | 20 |
| | — |
| | — |
| | $ | 5 |
| | — |
| | — |
| Other income | | 180 |
| | $ | 79 |
| | $ | 64 |
| | 141 |
| | $ | 45 |
| | $ | 29 |
| Other expense | | (46 | ) | | (55 | ) | | (52 | ) | | (28 | ) | | (32 | ) | | (36 | ) | Allowance for equity funds used during construction | | 19 |
| | 23 |
| | 29 |
| | 11 |
| | 15 |
| | 26 |
| Other income (expense), net | | $ | 173 |
| | $ | 47 |
| | $ | 41 |
| | $ | 129 |
| | $ | 28 |
| | $ | 19 |
|
The recording of revenue from contracts with customers within other income (expense) arose upon the adoption of related accounting guidance described in Note 1 and Note 3,4, and as permitted, periods prior periodsto adoption have not been restated. For the Company and Consolidated SCE&G, otherOther income in 2018 includes gains from the settlement of interest rate derivatives of approximately $114$115 million (see Note 7)8). For the Company and Consolidated SCE&G, non-serviceNon-service cost components of pension and other postretirement benefits are included in other expense.
16.18. QUARTERLY FINANCIAL DATA (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | The Company Millions of dollars, except per share amounts | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Annual | 2018 | | |
| | |
| | |
| | |
| | |
| Total Operating Revenues | | $ | 1,180 |
|
| $ | 843 |
|
| $ | 926 |
|
| $ | 1,103 |
|
| $ | 4,052 |
| Operating Income (Loss) | | 189 |
|
| 103 |
|
| 183 |
|
| (1,204 | ) |
| (729 | ) | Net Income (Loss) | | 169 |
|
| 8 |
|
| 67 |
|
| (772 | ) |
| (528 | ) | Earnings (Loss) Per Share of Common Stock | | 1.18 |
|
| 0.06 |
|
| 0.47 |
|
| (5.41 | ) |
| (3.70 | ) | | | | | | | | | | | | 2017 | | |
| | |
| | |
| | |
| | |
| Total Operating Revenues | | $ | 1,173 |
| | $ | 1,001 |
| | $ | 1,076 |
| | $ | 1,157 |
| | $ | 4,407 |
| Operating Income (Loss) | | 320 |
| | 251 |
| | 122 |
| | (608 | ) | | 85 |
| Net Income (Loss) | | 171 |
| | 121 |
| | 34 |
| | (445 | ) | | (119 | ) | Earnings (Loss) Per Share of Common Stock | | 1.19 |
| | 0.85 |
| | 0.24 |
| | (3.11 | ) | | (0.83 | ) |
| | | | | | | | | | | | | | | | | | | | | | Consolidated SCE&G Millions of dollars | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Annual | 2018 | | |
| | |
| | |
| | |
| | |
| Total Operating Revenues | | $ | 702 |
| | $ | 632 |
| | $ | 739 |
| | $ | 689 |
| | $ | 2,762 |
| Operating Income (Loss) | | 121 |
| | 107 |
| | 212 |
| | (1,271 | ) | | (831 | ) | Total Comprehensive Income (Loss) | | 128 |
| | 31 |
| | 104 |
| | (852 | ) | | (589 | ) | Comprehensive Income Available (Loss Attributable) to Common Shareholder | | 124 |
| | 26 |
| | 98 |
| | (861 | ) | | (613 | ) | | | | | | | | | | | | 2017 | | |
| | |
| | |
| | |
| | |
| Total Operating Revenues | | $ | 719 |
| | $ | 756 |
| | $ | 856 |
| | $ | 739 |
| | $ | 3,070 |
| Operating Income (Loss) | | 226 |
| | 247 |
| | 124 |
| | (680 | ) | | (83 | ) | Total Comprehensive Income (Loss) | | 112 |
| | 126 |
| | 42 |
| | (452 | ) | | (172 | ) | Comprehensive Income Available (Loss Attributable) to Common Shareholder | | 109 |
| | 123 |
| | 39 |
| | (456 | ) | | (185 | ) |
See Note 11A summary of DESC’s quarterly results of operations for the years ended December 31, 2019 and 2018 follows. Amounts reflect all adjustments necessary in the opinion of management for a discussionfair statement of impairment losses bookedthe results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors. (millions) | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | 2019 | | | | | | | | | | | | | | | | | Operating revenue | | $ | (335 | ) | | $ | 698 | | | $ | 795 | | | $ | 771 | | Operating income (loss) | | | (1,143 | ) | | | 17 | | | | 261 | | | | (76 | ) | Total comprehensive income (loss) | | | (1,103 | ) | | | (70 | ) | | | 143 | | | | (191 | ) | Comprehensive income (loss) available (attributable) to common shareholder | | | (1,109 | ) | | | (78 | ) | | | 143 | | | | (195 | ) | | | | | | | | | | | | | | | | | | 2018 | | | | | | | | | | | | | | | | | Operating revenue | | $ | 702 | | | $ | 632 | | | $ | 739 | | | $ | 689 | | Operating income (loss) | | | 121 | | | | 107 | | | | 212 | | | | (1,271 | ) | Total comprehensive income (loss) | | | 128 | | | | 31 | | | | 104 | | | | (852 | ) | Comprehensive income (loss) available (attributable) to common shareholder | | | 124 | | | | 26 | | | | 98 | | | | (861 | ) |
DESC’s 2019 results include the thirdimpact of the following significant items: | • | Fourth quarter results include a $240 million after-tax charge related to litigation. |
| • | Second quarter results include a $75 million after-tax charge related to litigation and a $47 million after-tax charge related to a voluntary retirement program. |
| • | First quarter results include a $756 million after-tax charge for refunds of amounts previously collected from retail electric customers for the NND Project, a $198 million tax charge for $264 million of income tax-related regulatory assets for which DESC committed to forgo recovery, a $118 million after-tax charge for a settlement agreement of a DESC ratepayer class action lawsuit and an $86 million after-tax charge for property, plant and equipment for which DESC committed to forgo recovery. |
DESC’s 2018 results include the impact of the following significant item: | • | Fourth quarter results include a $870 million after-tax impairment charge related to the NND Project. |
59
Item 9. Changes in and fourth quarter of 2017Disagreements With Accountants on Accounting and the firstFinancial Disclosure None. Item 9A. Controls and fourth quarter of 2018.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable.
ITEM 9A. CONTROLS AND PROCEDURES
SCANA:
ProceduresEvaluation of Disclosure Controls and Procedures: As of December 31, 2018, SCANA conducted an evaluation under the supervision and with the participation of itsProceduresSenior management, including itsDESC’s CEO and CFO, ofevaluated the effectiveness of the design and operation of SCANA’sDESC’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)as of the Securities Exchange Actend of 1934).the period covered by this report. Based on this evaluation theprocess, DESC’s CEO and CFO have concluded that as of December 31, 2018, SCANA'sDESC’s disclosure controls and procedures are effective. There were effective.
Management’s Evaluation of Internal Control Over Financial Reporting:
As of December 31, 2018, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any changeno changes in SCANA'sDESC’s internal controlscontrol over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934)that occurred during the last fiscal quarter ended December 31, 2018. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2018 that hashave materially affected, or isare reasonably likely to materially affect, SCANA’sDESC’s internal control over financial reporting.
The Management Report on Internal Control over Financial Reporting follows.
MANAGEMENTMANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of DESC understands and accepts responsibility for DESC’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). DESC continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as DESC does throughout all aspects of its business. DESC maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits. The Board of Directors also serves as DESC’s Audit Committee and has periodic communications with the independent registered public accounting firm, the internal auditors and management concerning DESC’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities. SEC rules implementing Section 404 of SCANAthe Sarbanes-Oxley Act require DESC’s 2019 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, DESC tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2019, DESC makes the following assertions: Management is responsible for establishing and maintaining adequateeffective internal control over financial reporting. SCANA’sreporting of DESC. There are inherent limitations in the effectiveness of any internal control, system was designed by or underincluding the supervisionpossibility of SCANA’s management, including its CEO and CFO, to provide reasonable assurance to SCANA’s management and board of directors regarding the reliability of financial reportinghuman error and the preparationcircumvention or overriding of financial statements for external purposes in accordance with generally accepted accounting principles. Allcontrols. Accordingly, even effective internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effectivecontrols can provide only reasonable assurance with respect to financial statement preparation and presentation. Also,preparation. Further, because of changes in conditions, the effectiveness of the internal control may vary over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCANA’s management assessed the effectiveness of SCANA’stime.Management evaluated DESC’s internal control over financial reporting as of December 31, 2018. In making this2019. This assessment SCANA used thewas based on criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (2013). Based on this assessment, SCANA’s management believes that, as of December 31, 2018,for effective internal control over financial reporting is effective based on those criteria.SCANA’s independent registered public accounting firm has issued an attestation report on SCANA’s internal control over financial reporting. This report follows.
ATTESTATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
SCANA Corporation
Cayce, South Carolina
Opinion on described in Internal Control over Financial Reporting
We have audited the internal control over financial reporting of SCANA Corporation and subsidiaries (the “Company”) as of December 31, 2018, based on criteria established in Internal Control - IntegratedControl-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the CompanyCommission. Based on this assessment, management believes that DESC maintained in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards2019.This annual report does not include an attestation report of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2018, of the Company and our report dated February 28, 2019 expressed an unqualified opinion on those financial statements and financial statement schedule. Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are aDESC’s independent registered public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
| | | /s/DELOITTE & TOUCHE LLP | | Charlotte, North Carolina | | February 28, 2019 | |
SCE&G:
Evaluation of Disclosure Controls and Procedures:
As of December 31, 2018, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of the effectiveness of the design and operation of SCE&G’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934). Based on this evaluation, the CEO and CFO concluded that, as of December 31, 2018, SCE&G's disclosure controls and procedures were effective.
Management’s Evaluation of Internal Control Over Financial Reporting:
As of December 31, 2018, SCE&G conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCE&G's internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2018. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2018 that has materially affected or is reasonably likely to materially affect SCE&G’s internal control over financial reporting.
The Management Report on Internal Control over Financial Reporting follows.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of SCE&G is responsible for establishing and maintaining adequate internal control over financial reporting. SCE&G’s internal control system was designedManagement’s report is not subject to attestation by orDESC’s independent registered public accounting firm pursuant to a permanent exemption under the supervisionDodd-Frank Act.February 28, 2020 Item 9B. Other Information None. 60
Part III Item 10. Directors, Executive Officers and Corporate Governance Omitted pursuant to General Instructions I.(2)(c). Item 11. Executive Compensation Omitted pursuant to General Instructions I.(2)(c). Item 12. Security Ownership of SCE&G’s management, including its CEOCertain Beneficial Owners and CFO,Management and Related Stockholder Matters Omitted pursuant to provide reasonable assuranceGeneral Instructions I.(2)(c). Item 13. Certain Relationships and Related Transactions, and Director Independence Omitted pursuant to SCE&G’s managementGeneral Instructions I.(2)(c). Item 14. Principal Accountant Fees and board of directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, the effectiveness of the internal control over financial reporting may deteriorate in future periods due to either changes in conditions or declining levels of compliance with policies or procedures.
SCE&G’s management assessed the effectiveness of SCE&G’s internal control over financial reporting as of December 31, 2018. In making this assessment, SCE&G used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, SCE&G’s management believes that, as of December 31, 2018, internal control over financial reporting is effective based on those criteria.
ITEM 9B. OTHER INFORMATION
Not Applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Not applicable.
ITEM 11. EXECUTIVE COMPENSATION
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Not applicable.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
SCANA and SCE&G:
The Audit Committee Charter required the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the independent registered accounting firm. Pursuant to a policy adopted by the Audit Committee, its Chairman could pre-approve the rendering of services on behalf of the Audit Committee. Decisions by the Chairman to pre-approve the rendering of services would be presented to the Audit Committee at its next scheduled meeting.
Independent Registered Public Accounting Firm’s Fees
ServicesThe following table sets forth the aggregatepresents fees all of which were approved by the Audit Committee, chargedpaid to the Company and Consolidated SCE&GDeloitte & Touche LLP for services related to DESC for the fiscal years ended December 31, 20182019 and 2017 by2018. Type of Fees | | 2019 | | | 2018 | | (millions) | | | | | | | | | Audit fees | | $ | 1.92 | | | $ | 2.62 | | Audit-related fees | | | — | | | | 0.10 | | Total Fees | | $ | 1.92 | | | $ | 2.72 | |
Audit fees represent fees of Deloitte & Touche LLP for the member firmsaudit of Deloitte Touche Tohmatsu, and their respective affiliates. | | | | | | | | | | | | | | | | | | | | The Company | | Consolidated SCE&G | | | 2018 | | 2017 | | 2018 | | 2017 | Audit Fees (1) | | $ | 3,670,000 |
| | $ | 3,670,360 |
| | $ | 2,621,562 |
| | $ | 3,127,191 |
| Audit-Related Fees (2) | | 138,700 |
| | 168,229 |
| | 97,048 |
| | 139,172 |
| Tax Fees (3) | | 123,373 |
| | — |
| | — |
| | — |
| Total Fees | | $ | 3,932,073 |
| | $ | 3,838,589 |
| | $ | 2,718,610 |
| | $ | 3,266,363 |
|
(1) Fees for audit services billed in 2018 and 2017 consisted of audits ofDESC’s annual consolidated financial statements, the review of financial statements included in DESC’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, for securities underwriters, statutory and regulatory audits,attest services, consents, and other services related to SEC filings, and accounting research.
(2) Fees primarily for employee benefit plan audits and non-statutory audit services.
(3) Fees related to Internal Revenue Code Section 280G rules.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The followingassistance with review of documents are filed or furnished as a part of this Form 10-K:
(1) Financial Statements and Schedules:
The Report of Independent Registered Public Accounting Firm on the financial statements for each of SCANA and SCE&G is listed under Item 8 herein. The financial statements and supplementary financial data filed as part of this report for SCANA and SCE&G are listed under Item 8 herein. The financial statement schedules "Schedule II - Valuation and Qualifying Accounts" filed as part of this report for SCANA and SCE&G are included below.
(2) Exhibits
Exhibits required to be filed or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index immediately preceding the signature page. Certain of such exhibits which have heretofore been filed with the SECSEC.Audit-related fees consist of assurance and whichrelated services that are designated by referencereasonably related to their exhibit number in prior filings are incorporated herein by reference and made a part hereof. As permitted under Item 601(b)(4)(iii) of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10%performance of the totalaudit or review of DESC’s consolidated assets of SCANA, for itself and its subsidiaries and of SCE&G, for itself and its consolidated affiliates, have been omitted and SCANA and SCE&G agree to furnish a copy of such instrumentsfinancial statements or internal control over financial reporting. This category may include fees related to the SEC upon request.
Schedule II—Valuationperformance of audits and Qualifying Accounts
| | | | | | | | | | | | | | | | | | | | | | | | | Additions | | | | | Description (in millions) | | Beginning Balance | | Charged to Income | | Charged to Other Accounts | | Deductions from Reserves | | Ending Balance | SCANA: | | |
| | |
| | |
| | |
| | |
| Reserves deducted from related assets on the balance sheet: | | |
| | |
| | |
| | |
| | |
| Uncollectible accounts | | |
| | |
| | |
| | |
| | |
| 2018 | | $ | 6 |
| | $ | 15 |
| | — |
| | $ | 14 |
| | $ | 7 |
| 2017 | | 6 |
| | 13 |
| | — |
| | 13 |
| | 6 |
| 2016 | | 5 |
| | 12 |
| | — |
| | 11 |
| | 6 |
| Reserves other than those deducted from assets on the balance sheet: | | |
| | |
| | |
| | |
| | |
| Reserve for injuries and damages | | |
| | |
| | |
| | |
| | |
| 2018 | | $ | 9 |
| | $ | 5 |
| | — |
| | $ | 7 |
| | $ | 7 |
| 2017 | | 9 |
| | 8 |
| | — |
| | 8 |
| | 9 |
| 2016 | | 6 |
| | 5 |
| | — |
| | 2 |
| | 9 |
| | | | | | | | | | | | SCE&G: | | |
| | |
| | |
| | |
| | |
| Reserves deducted from related assets on the balance sheet: | | |
| | |
| | |
| | |
| | |
| Uncollectible accounts | | |
| | |
| | |
| | |
| | |
| 2018 | | $ | 4 |
| | $ | 7 |
| | — |
| | $ | 7 |
| | $ | 4 |
| 2017 | | 3 |
| | 8 |
| | — |
| | 7 |
| | 4 |
| 2016 | | 3 |
| | 6 |
| | — |
| | 6 |
| | 3 |
| Reserves other than those deducted from assets on the balance sheet: | | |
| | |
| | |
| | |
| | |
| Reserve for injuries and damages | | |
| | |
| | |
| | |
| | |
| 2018 | | $ | 8 |
| | $ | 5 |
| | — |
| | $ | 7 |
| | $ | 6 |
| 2017 | | 8 |
| | 8 |
| | — |
| | 8 |
| | 8 |
| 2016 | | 5 |
| | 5 |
| | — |
| | 2 |
| | 8 |
|
ITEM 16. FORM 10-K SUMMARY
Not Applicable.
EXHIBIT INDEX attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.DESC’s Board of Directors has adopted the Dominion Energy Audit Committee pre-approval policy for its independent auditor’s services and fees and has delegated the execution of this policy to the Dominion Energy Audit Committee. In accordance with this delegation, each year the Dominion Energy Audit Committee pre-approved a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2019 meeting, the Dominion Energy Audit Committee approved schedules of services and fees for 2020 inclusive of DESC. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the Dominion Energy Audit Committee or a delegated member of the Dominion Energy Audit Committee. 61
Part IV Item 15. Exhibits and Financial Statement Schedules | (a) | | | | | | | | Exhibit | | Applicable to
Certain documents are filed as part of this Form 10-K of | | | No. | | SCANA | | SCE&G | | Description | 2.01* |
| | X | | | | |
See Index on page 18. | 2. | All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes. |
| 3. | Exhibits (incorporated by reference unless otherwise noted) |
Exhibit | | | 3.01Number |
| Description | | X | | | | | 3.01 | | Amended and Restated Articles of Incorporation, of SCANA, as adopted on February 1,effective April 29, 2019 (Filed as Exhibit(Exhibit 3.1, to Form 8-K on February 8,filed April 29, 2019, (FileFile No. 001-08809)1-3375) and incorporated by reference herein). | 3.02 |
| | | | X | | | 3.03 3.02 |
| | X | | | | . | 3.04 |
| | | | X | | | 4.01 |
| | 4.01 | X | | X | | Articles of Exchange of SCE&GSouth Carolina Electric & Gas Company and SCANA Corporation (Filed as Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | 4.02 |
| | X | | | | Indenture dated as of November 1, 1989 between SCANA and The Bank of New York Mellon Trust Company, N. A. (successor to The Bank of New York), as Trustee (Filed as Exhibit 4-A to Registration No. 33-32107 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | 4.03 4.02 |
| | | | X | | Indenture dated as of April 1, 1993 from SCE&GSouth Carolina Electric & Gas Company to The Bank of New York Mellon Trust Company, N. A. (as successor to NationsBank of Georgia, National Association), as Trustee (Filed as Exhibit 4-F to Registration Statement No. 33-49421 and incorporated by reference herein)33-49421). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | 4.04 |
| | 4.03 | | | X | | First Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421 and incorporated by reference herein)33-49421). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | 4.05 |
| | 4.04 | | | X | | Second Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955 and incorporated by reference herein)33-57955). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T). | 4.06 |
| | 4.05 | | | X | | | 10.01 |
| | 4.06 | X | Description of Series A Nonvoting Preferred Shares (filed herewith). | | X | | | | | 10.01 | | Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and SCE&GSouth Carolina Electric & Gas Company for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 dated January 27, 2011 (portions of the exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended) (Filed as Exhibit(Exhibit 10.01, to Form 10-Q/A for the quarter ended June 30,March 31, 2011 (Filefiled August 3, 2011, File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)1-3375)) and incorporated by reference herein). | 10.02 |
| | | | X | | | 10.0310.02 |
| | X | | | | Second$6,000,000,000 Fourth Amended and Restated Five-YearRevolving Credit Agreement, dated as of December 17, 2015, byMarch 22, 2019, among Dominion Energy, Inc., Virginia Electric and among SCANA; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent;Power Company, Dominion Energy Gas Holdings, LLC, Questar Gas Company, South Carolina Electric & Gas Company, JP Morgan StanleyChase Bank, N.A., as Issuing Bank; Bank of America, N.A. and Morgan Stanley Senior Funding, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A.,Administrative Agent, Mizuho Bank LTD.Ltd., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.1 to Form 8-K on December 22, 2015 (File No. 001-08809) and incorporated by reference herein) |
| | | | | | | | | 10.04 |
| | X | | X | | Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Bank of America, N.A., as IssuingThe Bank of Nova Scotia and Co-Syndication Agent; Morgan Stanley Senior Funding, Inc., as Co-Syndication Agent; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan ChaseWells Fargo Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A.as Syndication Agents, and UBS Securities, LLC, as Documentation Agents (Filed as Exhibit 99.2 toother lenders named therein (Exhibit 10.1, Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA);filed March 26, 2019, File No. 001-03375 (SCE&G)1-3375)) and incorporated by reference herein) . | 10.05 |
| | 10.03 | X | | | | Second Amended and Restated Five-Year CreditService Agreement, dated as of December 17, 2015,January 1, 2004, by and among PSNC Energy; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lenderbetween South Carolina Electric & Gas Company and Agent; Bank of America, N.A. and Morgan Stanley Senior Funding,SCANA Services, Inc., as Co-Syndication Agents; and Branch Banking and Trust Company, Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents ( Filed as Exhibit 99.5 to (Exhibit 99.10, Form 8-K on December 22, 2015 (FileS-8 filed June 9, 2011, File No. 001-08809333-174796).) and incorporated by reference herein) | 10.06 |
| | 10.04 | X | DES Services Agreement, dated February 20, 2019, by and between South Carolina Electric & Gas Company and Dominion Energy Services, Inc. (filed herewith). | | X | | 10.05 | | Settlement Agreement dated as of July 27, 2017, by and among Toshiba, SCE&GSouth Carolina Electric & Gas Company and Santee Cooper (Filed as Exhibit(Exhibit 99.2, to Form 8-K datedfiled July 27,28, 2017, (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G)1-3375)) and incorporated by reference herein). | 10.07 |
| | 10.06 | X | | X | | Trade Confirmation dated September 25, 2017, between SCE&G,South Carolina Electric & Gas Company, Santee Cooper and Citibank, N.A., and associated Assignment and Purchase Agreement, dated September 27, 2017, by and among SCE&G,South Carolina Electric & Gas Company, Santee Cooper and Citibank, N. A. ( Filed as Exhibit(Exhibit 10.03, to Form 10-Q for the quarter ended September 30, 2017 (File No. 001-08809 (SCANA);filed November 3, 2017, File No. 001-03375 (SCE&G)1-3375)) and incorporated by reference herein) . | 10.08 |
| |
62
10.07 | X | | X | | Settlement Agreement and an Addendum dated as of November 24, 2018, by and among SCANA SCE&G,Corporation, South Carolina Electric & Gas Company, Richard Lightsey, LeBrian Cleckley, Phillip Cooper and the State of South Carolina.Carolina (Exhibit 10.08, Form 10-K for the fiscal year ended December 31, 2018 filed February 28, 2019, File No. 1-3375) (Filed herewith) . | 31.01 |
| | | X | | 31.a | | | | 31.02 |
| | 31.b | X | | | | | 31.03 |
| | | | X | | | 31.0432.a |
| | | | X | | | 32.01 |
| | X | | | | | 32.02 |
| | | | X | | | 101. INS**101 | | X | | X | | XBRL Instance DocumentThe following financial statements from Dominion Energy South Carolina, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2019, filed on February 28, 2020, formatted in iXBRL (Inline eXtensible Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Comprehensive Loss; (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Changes in Common Equity, and (v) the Notes to Consolidated Financial Statements. | 101. SCH** | | X | | X | | XBRL Taxonomy Extension Schema | 101. CAL**104 | | X | | X | | XBRL Taxonomy Extension Calculation Linkbase | 101. DEF** | | X | | X | | XBRL Taxonomy Extension Definition Linkbase | 101. LAB** | | X | | X | | XBRL Taxonomy Extension Label Linkbase | 101. PRE** | | X | | X | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | * Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. SCANA agrees to furnish supplementally to the SEC a copy of any omitted schedule upon request by the SEC. | ** Pursuant to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934,Cover Page Interactive Data File (formatted in iXBRL (Inline eXtensible Reporting Language) and otherwise is not subject to liability under these sections.contained in Exhibit 101). |
SIGNATURES
Item 16. Form 10-K Summary None. 63
Signatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. | | DOMINION ENERGY SOUTH CAROLINA, INC. | | BY: | | | | SCANA CORPORATION | | BY: | /s/ Thomas F. Farrell, II | | | (Thomas F. Farrell, II, Chairman of the Board of Directors) | | | | DATE: | February 28, 20192020 | | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated on the 28th28th day of February, 2019. 2020.Signature | | Title | | | Signature | Title | /s/ Thomas F. Farrell, II | | Chairman of the Board of Directors | Thomas F. Farrell, II | | | | | | | | /s/ P. Rodney BlevinsDiane Leopold | | Director President and Chief Executive Officer | P. Rodney BlevinsDiane Leopold | | | | | | | | /s/ James R. Chapman | | Director, Executive Vice President and Chief Financial Officer | James R. Chapman | | | | | | | /s/ Michele L. Cardiff | | Vice President, Controller and Chief Accounting Officer | Michele L. Cardiff | | | | | | | | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries or consolidated affiliates thereof.
| | | | | | SOUTH CAROLINA ELECTRIC & GAS COMPANY | | BY: | /s/ Thomas F. Farrell, II | | | (Thomas F. Farrell, II, Chairman of the Board of Directors)
| | | | DATE: | February 28, 2019 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries or consolidated affiliates thereof.
| | | Signature | Title | /s/ Thomas F. Farrell, II | Chairman of the Board of Directors | Thomas F. Farrell, II | | | | | | /s/ P. Rodney Blevins | Director, President and Chief Executive Officer | P. Rodney Blevins | | | | | | /s/ James R. Chapman | Director, Executive Vice President and Chief Financial Officer | James R. Chapman | | | | | /s/ Michele L. Cardiff | Vice President, Controller and Chief Accounting Officer | Michele L. Cardiff | | | | | | | | | |
DATE: February 28, 2019
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