UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
    
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2017
SCANALOGOA42.JPG
Commission
File Number
Registrant, State of Incorporation,
Address and Telephone Number
I.R.S. Employer
Identification No.
1-8809
1-3375
SCANA Corporation (a South Carolina corporation)
South Carolina Electric & Gas Company (a South Carolina corporation)
100 SCANA Parkway, Cayce, South Carolina 29033
(803) 217-9000
57-0784499
57-0248695
Securities registered pursuant to Section 12(b) of the Act: SCANA Corporation: Common stock, without par value, registered on The New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
South Carolina Electric & Gas Company: Series A Nonvoting Preferred Shares

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
SCANA Corporation  x         South Carolina Electric & Gas Company  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
SCANA Corporation  o         South Carolina Electric & Gas Company  o

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.         SCANA Corporation Yes  x No  o     South Carolina Electric & Gas Company Yes  x No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).         SCANA Corporation Yes  x No o     South Carolina Electric & Gas Company Yes x No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
         SCANA Corporation x         South Carolina Electric & Gas Company  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
SCANA Corporation
Large accelerated filer  x
Accelerated filer  o
Non-accelerated filer  o
Smaller reporting company  o
Emerging growth company  o
South Carolina Electric & Gas Company
Large accelerated filer  o
Accelerated filer  o
Non-accelerated filer  x
Smaller reporting company  o
Emerging growth company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. SCANA Corporation o South Carolina Electric & Gas Company   o  

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).
SCANA Corporation Yes  o No  x     South Carolina Electric & Gas Company Yes  o No  x
     
The aggregate market value of voting stock held by non-affiliates of SCANA Corporation was $9.5 billion at June 30, 2017, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price of $67.01 per share. South Carolina Electric & Gas Company is a wholly‑owned subsidiary of SCANA Corporation and has no voting stock other than its common stock, all of which is held beneficially and of record by SCANA Corporation. A description of registrants’ common stock follows:
Registrant
 
Description of
Common Stock
 
Shares Outstanding
at February 20, 2018
SCANA Corporation
 
Without Par Value
 
142,638,371
South Carolina Electric & Gas Company
 
Without Par Value
 
40,296,147

Documents incorporated by reference: Information required by Items 10-13 of Part III of this Form 10-K will be incorporated by reference to SCANA Corporation's definitive proxy statement with respect to its 2018 Annual Meeting of Shareholders, if such definitive proxy statement is filed with the Securities and Exchange Commission on or before April 30, 2018. Due to the pending merger with Dominion Energy, Inc., we may not be required to file a definitive proxy statement with regard to such meeting or may file it after April 30, 2018, in which case we will file an amendment to this Form 10-K on or before April 30, 2018 to include the information that would otherwise be incorporated by reference.

This combined Form 10-K is separately filed by SCANA Corporation and South Carolina Electric & Gas Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. South Carolina Electric & Gas Company makes no representation as to information relating to SCANA Corporation or its subsidiaries (other than South Carolina Electric & Gas Company and its consolidated affiliates).
South Carolina Electric & Gas Company meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and therefore is filing this Form with the reduced disclosure format allowed under General Instruction I(2).



TABLE OF CONTENTS
 
 
Page
Cautionary Statement Regarding Forward-Looking Information
Definitions
 
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
 
SCANA Corporation and Subsidiaries
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
Consolidated Balance Sheets
 
 
 
Consolidated Statements of Operations
 
 
 
Consolidated Statements of Comprehensive Income (Loss)
 
 
 
Consolidated Statements of Cash Flows
 
 
 
Consolidated Statements of Changes in Common Equity
 
 
South Carolina Electric & Gas Company and Affiliates
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
Consolidated Balance Sheets
 
 
 
Consolidated Statements of Comprehensive Income (Loss)
 
 
 
Consolidated Statements of Cash Flows
 
 
 
Consolidated Statements of Changes in Common Equity
 
 
Notes to Consolidated Financial Statements
 
 
 
 
Item 9.
Item 9A.
Item 9B.
Other Information
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
Item 15.
 
 
Signatures


2


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 
Statements included in this Annual Report on Form 10-K which are not statements of historical fact are intended to be, and are hereby identified as, “forward-looking statements” for purposes of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements include, but are not limited to, statements concerning the proposed merger with Dominion Energy, recovery of Nuclear Project abandonment costs, key earnings drivers, customer growth, environmental regulations and expenditures, leverage ratio, projections for pension fund contributions, financing activities, access to sources of capital, impacts of the adoption of new accounting rules and estimated capital and other expenditures.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “forecasts,” “plans,” “targets,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential” or “continue” or the negative of these terms or other similar terminology.  Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements due to the information being of a preliminary nature and subject to further and/or continuing review and adjustment. Other important factors that could cause such material differences include, but are not limited to, the following:
  
(1) the occurrence of any event, change or other circumstances that could give rise to the failure by SCANA and its subsidiaries (the Company) to consummate the proposed merger with Dominion Energy; (2) the ability of the Company to recover through rates the costs expended on Unit 2 and Unit 3, and a reasonable return on those costs, under the abandonment provisions of the BLRA or through other means; (3) uncertainties relating to the bankruptcy filing by WEC and WECTEC; (4) further changes in tax laws and realization of tax benefits and credits, and the ability or inability to realize credits and deductions, particularly in light of the abandonment of Unit 2 and Unit 3; (5) legislative and regulatory actions, particularly changes related to electric and gas services, rate regulation, regulations governing electric grid reliability and pipeline integrity, environmental regulations including any imposition of fees or taxes on carbon emitting generating facilities, the BLRA, and any actions affecting the abandonment of Unit 2 and Unit 3; (6) current and future litigation, including particularly litigation or government investigations or actions involving or arising from the construction or abandonment of Unit 2 and Unit 3 or arising from the proposed merger with Dominion Energy; (7) the results of short- and long-term financing efforts, including prospects for obtaining access to capital markets and other sources of liquidity, and the effect of rating agency actions on the Company’s cost of and access to capital and sources of liquidity; (8) the ability of suppliers, both domestic and international, to timely provide the labor, secure processes, components, parts, tools, equipment and other supplies needed which may be highly specialized or in short supply, at agreed upon quality and prices, for our construction program, operations and maintenance; (9) the results of efforts to ensure the physical and cyber security of key assets and processes; (10) changes in the economy, especially in areas served by subsidiaries of SCANA; (11) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial markets; (12) the impact of conservation and demand side management efforts and/or technological advances on customer usage; (13) the loss of electricity sales to distributed generation, such as solar photovoltaic systems or energy storage systems; (14) growth opportunities for SCANA’s regulated and other subsidiaries; (15) the effects of weather, especially in areas where the generation and transmission facilities of SCANA and its subsidiaries are located and in areas served by SCANA’s subsidiaries; (16) changes in SCANA’s or its subsidiaries’ accounting rules and accounting policies; (17) payment and performance by counterparties and customers as contracted and when due; (18) the results of efforts to license, site, construct and finance facilities, and to receive related rate recovery, for generation and transmission; (19) the results of efforts to operate the Company's electric and gas systems and assets in accordance with acceptable performance standards, including the impact of additional distributed generation; (20) the availability of fuels such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; the level and volatility of future market prices for such fuels and purchased power; and the ability to recover the costs for such fuels and purchased power; (21) the availability of skilled, licensed and experienced human resources to properly manage, operate, and grow the Company’s businesses, particularly in light of uncertainties with respect to legislative and regulatory actions surrounding recovery of Nuclear Project costs and the announced potential merger; (22) labor disputes; (23) performance of SCANA’s pension plan assets and the effect(s) of associated discount rates; (24) inflation or deflation; (25) changes in interest rates; (26) compliance with regulations; (27) natural disasters, man-made mishaps and acts of terrorism that directly affect our operations or the regulations governing them; and (28) the other risks and uncertainties described from time to time in the reports filed by SCANA or SCE&G with the SEC.

SCANA and SCE&G disclaim any obligation to update any forward-looking statements.

3


DEFINITIONS
Abbreviations used in this Form 10-K have the meanings set forth below unless the context requires otherwise:
TERM
 
MEANING
AFC
 
Allowance for Funds Used During Construction
ANI
 
American Nuclear Insurers
AOCI
 
Accumulated Other Comprehensive Income (Loss)
ARO
 
Asset Retirement Obligation
ARP
 
Alternative Revenue Program
BACT
 
Best Available Control Technology
Bankruptcy Court
 
U.S. Bankruptcy Court for the Southern District of New York
BLRA
 
Base Load Review Act
CAA
 
Clean Air Act, as amended
CAIR
 
Clean Air Interstate Rule
CCR
 
Coal Combustion Residuals
CEO
 
Chief Executive Officer
CERCLA
 
Comprehensive Environmental Response, Compensation and Liability Act
CFO
 
Chief Financial Officer
CFTC
 
Commodity Futures Trading Commission
CGT
 
Carolina Gas Transmission Corporation
CIAC
 
Contributions In Aid of Construction
Citibank
 
Citibank, N.A.
CO 2
 
Carbon Dioxide
Company
 
SCANA, together with its consolidated subsidiaries
Consolidated SCE&G
 
SCE&G and its consolidated affiliates
Consortium
 
A consortium consisting of WEC and WECTEC
Court of Appeals
 
United States Court of Appeals for the District of Columbia
CSAPR
 
Cross-State Air Pollution Rule
CUT
 
Customer Usage Tracker (decoupling mechanism)
CWA
 
Clean Water Act
DECG
 
Dominion Energy Carolina Gas Transmission LLC
DER
 
Distributed Energy Resource
DHEC
 
South Carolina Department of Health and Environmental Control
District Court
 
United States District Court for the District of South Carolina
Dodd-Frank
 
Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE
 
United States Department of Energy
DOJ
 
United States Department of Justice
Dominion Energy
 
Dominion Energy, Inc.
DOR
 
South Carolina Department of Revenue
DOT
 
United States Department of Transportation
DSM Programs
 
Electric Demand Side Management Programs
ELG Rule
 
Federal effluent limitation guidelines for steam electric generating units
EMANI
 
European Mutual Association for Nuclear Insurance
EPA
 
United States Environmental Protection Agency
EPC Contract
 
Engineering, Procurement and Construction Agreement dated May 23, 2008, as amended by the October 2015 Amendment
Exchange Act
 
Securities Exchange Act of 1934, as amended
FASB
 
Financial Accounting Standards Board
FERC
 
United States Federal Energy Regulatory Commission
FILOT
 
Fee in Lieu of Taxes
Fluor
 
Fluor Corporation
Fuel Company
 
South Carolina Fuel Company, Inc.
GAAP
 
Accounting principles generally accepted in the United States of America
GENCO
 
South Carolina Generating Company, Inc.
GHG
 
Greenhouse Gas
GPSC
 
Georgia Public Service Commission
GWh
 
Gigawatt hour
Interim Assessment Agreement
 
Interim Assessment Agreement dated March 28, 2017, as amended, among SCE&G, Santee Cooper, WEC and WECTEC
IRC
 
Internal Revenue Code of 1986, as amended
IRS
 
Internal Revenue Service
Joint Petition
 
Joint application and petition of SCE&G and Dominion Energy for review and approval of a proposed business combination as set forth in the Merger Agreement and for a prudency determination regarding the abandonment of the Nuclear Project and associated merger benefits and cost recovery plans, filed with the SCPSC on January 12, 2018
kWh
 
Kilowatt-hour
Level 1
 
A fair value measurement using unadjusted quoted prices in active markets for identical assets or liabilities
Level 2
 
A fair value measurement using observable inputs other than those for Level 1, including quoted prices for similar (not identical) assets or liabilities or inputs that are derived from observable market data by correlation or other means
Level 3
 
A fair value measurement using unobservable inputs, including situations where there is little, if any, market activity for the asset or liability
LNG
 
Liquefied Natural Gas
LOC
 
Lines of Credit
LTECP
 
SCANA Long-Term Equity Compensation Plan
MATS
 
Mercury and Air Toxics Standards
MCF
 
Thousand Cubic Feet
MGP
 
Manufactured Gas Plant
Merger Agreement
 
Agreement and Plan of Merger, dated as of January 2, 2018, by and among Dominion Energy, Sedona Corp. (a wholly-owned subsidiary of Dominion Energy) and SCANA
MMBTU
 
Million British Thermal Units
MW or MWh
 
Megawatt or Megawatt-hour
NASDAQ
 
The NASDAQ Stock Market, Inc.
NAV
 
Net Asset Value
NCUC
 
North Carolina Utilities Commission
NEIL
 
Nuclear Electric Insurance Limited
NERC
 
North American Electric Reliability Corporation
NOL
 
Net Operating Loss
NO X
 
Nitrogen Oxide
NPDES
 
National Pollutant Discharge Elimination System
NRC
 
United States Nuclear Regulatory Commission
NSPS
 
New Source Performance Standards
Nuclear Project
 
Project to construct Unit 2 and Unit 3 under the EPC Contract
Nuclear Waste Act
 
Nuclear Waste Policy Act of 1982
NYMEX
 
New York Mercantile Exchange
NYSE
 
The New York Stock Exchange
OCI
 
Other Comprehensive Income
October 2015 Amendment
 
Amendment, dated October 27, 2015, to the EPC Contract
ORS
 
South Carolina Office of Regulatory Staff
PGA
 
Purchased Gas Adjustment
PHMSA
 
United States Pipeline Hazardous Materials Safety Administration
Price-Anderson
 
Price-Anderson Indemnification Act
PSNC Energy
 
Public Service Company of North Carolina, Incorporated
Registrants
 
SCANA and SCE&G
Request
 
Request for Rate Relief filed by the ORS on September 26, 2017, as amended October 17, 2017
ROE
 
Return on Equity
RSA
 
Natural Gas Rate Stabilization Act
RTO/ISO
 
Regional Transmission Organization/Independent System Operator
Santee Cooper
 
South Carolina Public Service Authority
SCANA
 
SCANA Corporation, the parent company
SCANA Energy
 
SCANA Energy Marketing, Inc.
SCANA Services
 
SCANA Services, Inc.
SCE&G
 
South Carolina Electric & Gas Company
SCEUC
 
South Carolina Energy Users Committee
SCI
 
SCANA Communications, Inc.
SCPSC
 
Public Service Commission of South Carolina
SEC
 
United States Securities and Exchange Commission
SERC
 
SERC Reliability Corporation
SIP
 
State Implementation Plan
SLED
 
South Carolina Law Enforcement Division
SO 2
 
Sulfur Dioxide
Southern Natural
 
Southern Natural Gas Company
Spirit Communications
 
SCTG, LLC and its wholly-owned subsidiary SCTG Communications, Inc.
Summer Station
 
V.C. Summer Nuclear Station
Supreme Court
 
United States Supreme Court
Tax Act
 
An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017

Toshiba
 
Toshiba Corporation, parent company of WEC
Toshiba Settlement
 
Settlement Agreement dated as of July 27, 2017, by and among Toshiba, SCE&G and Santee Cooper
Transco
 
Transcontinental Gas Pipeline Corporation
TSR
 
Total Shareholder Return
Unit 1
 
Nuclear Unit 1 at Summer Station
Unit 2
 
Nuclear Unit 2 at Summer Station (abandoned prior to construction completion)
Unit 3
 
Nuclear Unit 3 at Summer Station (abandoned prior to construction completion)
VACAR
 
Virginia-Carolinas Reliability Group
VIE
 
Variable Interest Entity
WEC
 
Westinghouse Electric Company LLC
WECTEC
 
WECTEC Global Project Services, Inc. (formerly known as Stone & Webster, Inc.), a wholly-owned subsidiary of WEC
Williams Station
 
A.M. Williams Generating Station, owned by GENCO
WNA
 
Weather Normalization Adjustment


4


PART I
 
ITEM 1. BUSINESS
INVESTOR INFORMATION
SCANA’s and SCE&G’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available free of charge through SCANA’s internet website at www.scana.com (which is not intended as an active hyperlink; the information on SCANA’s website is not a part of this report or any other report or document that SCANA or SCE&G files with or furnishes to the SEC) as soon as reasonably practicable after these reports are filed or furnished.

SCANA and SCE&G post information from time to time regarding developments relating to SCE&G’s Nuclear Project and other matters of interest to investors on SCANA’s website. On SCANA’s homepage, there is a yellow box containing links to the Nuclear and Other Investor Information sections of the website. The Nuclear section contains a yellow box with a link to project news and updates. The Other Investor Information section of the website contains a link to recent investor-related information that cannot be found at other areas of the website. Some of the information that will be posted from time to time, including the quarterly reports that SCE&G submits to the SCPSC and the ORS in connection with the Nuclear Project, may be deemed to be material information that has not otherwise become public. Investors, media and other interested persons are encouraged to review this information and can sign up, under the Investor Relations Section of the website, for an email alert when there is a new posting in the Nuclear and Other Investor Information yellow box.

CORPORATE STRUCTURE AND SEGMENTS OF BUSINESS
SCANA is a South Carolina corporation created in 1984 as a holding company. SCANA and its subsidiaries had full-time, permanent employees as of February 20, 2018 and 2017 of 5,228 and 5,910, respectively. SCANA does not directly own or operate any significant physical properties, but it holds directly all of the capital stock of its subsidiaries, including the subsidiaries described below.

On January 2, 2018, SCANA entered into the Merger Agreement whereby it would become a wholly-owned subsidiary of Dominion Energy. The merger is subject to a variety of closing conditions including the receipt of approvals from several regulators and from SCANA's shareholders. Refer to Exhibit 2.01 in the Exhibit Index for information on where a copy of the Merger Agreement may be obtained. See also Note 10 to the consolidated financial statements for more discussion.

Regulated Utilities
 
SCE&G is engaged in the generation, transmission, distribution and sale of electricity to approximately 719,000 customers and the purchase, sale and transportation of natural gas to approximately 368,000 customers (each as of December 31, 2017). SCE&G’s business experiences seasonal fluctuations, with generally higher sales of electricity during the summer and winter months because of air conditioning and heating requirements, and generally higher sales of natural gas during the winter months due to heating requirements. SCE&G’s electric service territory extends into 24 counties covering nearly 16,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 35 counties in South Carolina and covers approximately 23,000 square miles. More than 3.4 million persons live in the counties where SCE&G conducts its business. Resale customers include municipalities, electric cooperatives, other investor-owned utilities, registered marketers and federal and state electric agencies. Predominant industries served by SCE&G include chemicals, educational services, paper products, food products, lumber and wood products, health services, textile manufacturing, rubber and miscellaneous plastic products, automotive and tire and fabricated metal products.
 
GENCO owns Williams Station and sells electricity, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a unit power sales agreement and related operating agreement. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, certain fossil fuels and emission allowances.

PSNC Energy purchases, sells and transports natural gas to approximately 563,000 residential, commercial and industrial customers (as of December 31, 2017). PSNC Energy serves 28 franchised counties covering approximately 12,000 square miles in North Carolina. The predominant industries served by PSNC Energy include educational services, food and beverage products, health services, automotive, chemicals, motorsports, non-woven textiles and electrical generation and construction.
 

5


Nonregulated Businesses
 
SCANA Energy markets natural gas in the southeast and provides energy-related services. A division of SCANA Energy sells natural gas to approximately 425,000 customers (as of December 31, 2017) in Georgia’s deregulated natural gas market.
 
SCANA Services provides shared administrative and management services to SCANA's other subsidiaries.

For information with respect to major segments of business, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 12 of the consolidated financial statements. All such information is incorporated herein by reference.

ELECTRIC OPERATIONS
 
Electric Sales
 
SCE&G’s sales of electricity by customer classification as percentages of electric revenues were as follows:
 
 
Sales
Customer Classification
 
2017
 
2016
Residential
 
45
%
 
46
%
Commercial
 
33
%
 
33
%
Industrial
 
18
%
 
17
%
Sales for resale
 
2
%
 
2
%
Other
 
2
%
 
2
%
Total
 
100
%
 
100
%
 
Sales for resale include sales to three municipalities in 2017 and 2016. Other includes short-term system sales which during 2017 included sales to two investor-owned utilities or registered marketers. Short-term system sales during 2016 included sales to four investor-owned utilities or registered marketers.
 
During 2017 SCE&G experienced a net increase of approximately 10,000 electric customers (growth rate of 1.4%), increasing its total electric customers to approximately 719,000 at year end.
 
The following projections assume normal weather where applicable.  For the period 2017 to 2018, SCE&G projects a retail kWh sales increase of approximately 0.4% and customer growth of 1.5%. For the period 2018-2020, SCE&G projects total territorial kWh sales of electricity to increase 0.3% annually, total retail sales to decrease 0.2% annually, total electric customer base to increase 1.5% annually and territorial peak load (summer, in MW) to increase 1.0% annually. SCE&G’s goal is to maintain a planning reserve margin of between 14% and 20%; however, weather and other factors affect territorial peak load and can cause actual generating capacity on any given day to fall below the reserve margin goal.

Electric Interconnections
 
SCE&G purchases all of the electric generation of GENCO’s Williams Station under a unit power sales agreement which has been approved by FERC. Williams Station has a net generating capacity (summer rating) of 605 MW.
 
SCE&G’s transmission system extends over a large part of the central, southern and southwestern portions of South Carolina. The system interconnects with Duke Energy Carolinas, LLC, Duke Energy Progress, LLC, Santee Cooper, Georgia Power Company and the Southeastern Power Administration’s Clarks Hill (Thurmond) Project. SCE&G is a member of VACAR, one of several geographic divisions within the SERC. SERC is one of eight regional entities with delegated authority from NERC for the purpose of proposing and enforcing reliability standards approved by FERC. The regional entities and all members of NERC work to safeguard the reliability of the bulk power systems throughout North America.
 

6


Fuel Costs and Fuel Supply
 
The average cost of various fuels and the weighted average cost of all fuels (including oil) were as follows:
 
Cost of Fuel Used
 
2017
 
2016
 
2015
Per MMBTU:
 

 
 

 
 

Nuclear
$
0.95

 
$
0.98

 
$
0.95

Coal
3.31

 
3.41

 
3.81

Natural Gas
3.52

 
3.02

 
3.26

All Fuels (weighted average)
2.63

 
2.41

 
3.01

Per Ton: Coal
82.45

 
84.62

 
95.69

Per MCF: Gas
3.57

 
3.11

 
3.35


The sources and percentages of total MWh by each category of fuel for the preceding three years and estimates for the next three years follow:
 
% of Total MWh Generated
 
Actual
 
Estimated
 
2015
2016
2017
 
2018
2019
2020
Coal
39
%
37
%
39
%
 
38
%
29
%
30
%
Nuclear
20
%
25
%
20
%
 
20
%
23
%
20
%
Hydro
3
%
3
%
2
%
 
3
%
3
%
3
%
Natural Gas & Oil
36
%
33
%
37
%
 
35
%
42
%
41
%
Biomass/Solar
2
%
2
%
2
%
 
4
%
3
%
6
%
Total
100
%
100
%
100
%
 
100
%
100
%
100
%

For a listing of the Company's generating facilities, see the Electric Properties section within Item 2. Properties.

In 2017, coal was primarily obtained through long-term contracts with suppliers located in eastern Kentucky, Tennessee, Virginia, and West Virginia. These contracts provide for approximately 2.1 million tons annually. Sulfur restrictions on the contract coal range from 1.0% to 1.6%. These contracts expire at various times through 2019. Spot market purchases may occur when needed or when prices are believed to be favorable. The Company relies on unit trains and, in some cases, trucks for coal deliveries.
 
SCANA and SCE&G believe that electric operations comply with all applicable regulations relating to the discharge of SO 2 and NO X . See additional discussion at Environmental Matters in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

SCE&G, for itself and as agent for Santee Cooper, and WEC are parties to a fuel alliance agreement and contracts for fuel fabrication and related services. Under these contracts, SCE&G supplies enriched products to WEC and WEC supplies nuclear fuel assemblies for Unit 1. WEC is SCE&G’s exclusive provider of such fuel assemblies on a cost-plus basis. The fuel assemblies to be delivered under the contracts are expected to supply the nuclear fuel requirements of Unit 1 through 2033.

In addition, SCE&G has contracts covering its nuclear fuel needs for uranium, conversion services and enrichment services. These contracts have varying expiration dates through 2024. SCE&G believes that it will be able to renew contracts as they expire or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services and that sufficient capacity for nuclear fuel supplies and processing exists to allow for normal operations of its nuclear generating unit.
 
SCE&G stores spent nuclear fuel in its on-site spent-fuel pool, and has constructed a dry cask storage facility to accommodate the spent fuel output for the life of Unit 1. In addition, Unit 1 has sufficient on-site capacity to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary. For information about the contract with the DOE regarding disposal of spent fuel, see the Environmental section of Note 10 to the consolidated financial statements.


7


SCE&G also uses long-term power purchase agreements to ensure that adequate power supply resources are in place to meet load obligations and reserve requirements. As of January 1, 2018, SCE&G had such agreements in place for 325 MW of capacity (expiring at various times through 2020). In addition, SCE&G had the ability to purchase an additional 204 MW of capacity under these agreements. On December 20, 2017, SCE&G entered into an agreement to purchase the Columbia Energy Center, which is the existing 540 MW combined cycle gas generating station to which these capacity contracts relate. Upon the closing of such purchase, these contracts will be moot, and all output of that station will be available for SCE&G's load obligations and reserve requirements. Also, as of December 31, 2017, SCE&G is taking delivery of utility scale solar generated power pursuant to 17 executed power purchase agreements totaling 218 MW-alternating current.
GAS OPERATIONS
 
Gas Sales-Regulated
 
Regulated sales of natural gas by customer classification as a percent of total regulated gas revenues sold or transported were as follows: 
 
 
SCANA
 
SCE&G
Customer Classification
 
2017
 
2016
 
2017
 
2016
Residential
 
57.1
%
 
57.9
%
 
47.0
%
 
48.3
%
Commercial
 
26.5
%
 
26.4
%
 
27.8
%
 
28.6
%
Industrial
 
11.4
%
 
10.4
%
 
21.6
%
 
19.5
%
Transportation Gas
 
5.0
%
 
5.3
%
 
3.6
%
 
3.6
%
Total
 
100.0
%
 
100.0
%
 
100.0
%
 
100.0
%
 
For the period 2018-2020, SCANA projects total consolidated sales of regulated natural gas in MMBTUs to increase 31.7% annually (excluding transportation and assuming normal weather). Annual projected increases over such period in MMBTU sales include residential of 2.5%, commercial of 0.9%, and industrial of 84.8%. Projections of total and industrial sales include amounts for new gas-fired electric generating plants that will be served by PSNC Energy.

For the period 2018-2020, SCE&G projects total consolidated sales of regulated natural gas in MMBTUs to increase 2.2% annually (excluding transportation and assuming normal weather). Annual projected increases over such period in MMBTU sales include residential of 2.4%, commercial of 1.0% and industrial of 2.9%.

For the period 2018-2020, each of SCANA’s and SCE&G’s total regulated natural gas customer base is projected to increase 2.6% annually. During 2017, SCANA recorded a net increase of approximately 24,000 regulated gas customers (growth rate of 2.6%), increasing the number of its regulated gas customers to approximately 931,000. Of this increase, SCE&G recorded a net increase of approximately 10,000 gas customers (growth rate of 2.9%), increasing the number of its total gas customers to approximately 368,000 (as of December 31, 2017).
 
Demand for gas changes primarily due to weather and the price relationship between gas and alternate fuels.

Gas Cost and Supply
 
 SCE&G purchases natural gas under contracts with producers and marketers on both a short-term and long-term basis at market based prices. The gas is delivered to South Carolina through firm transportation agreements with Southern Natural (expiring in 2019), Transco (expiring at various times through 2084) and DECG (expiring at various times through 2036). The maximum daily volume of gas that SCE&G is entitled to transport under these contracts is 212,194 MMBTU from Southern Natural, 110,458 MMBTU from Transco and 456,427 MMBTU from DECG. Additional natural gas volumes may be delivered to SCE&G’s system as capacity is available through interruptible transportation.
 
The daily volume of gas that SCANA Energy is entitled to transport under its service agreements (expiring at various times through 2023) on a firm basis is 761,860 MMBTU. Additional natural gas volumes may be delivered as capacity is available through interruptible transportation.
 
SCE&G purchased natural gas, including fixed transportation, at an average cost of $3.96 per MMBTU during 2017 and $3.46 per MMBTU during 2016.
 

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To meet the requirements of its high priority natural gas customers during periods of maximum demand, SCE&G has 5,502,600 MMBTU of natural gas storage capacity on the systems of Southern Natural and Transco. Approximately 3,433,200 MMBTU of gas were in storage on December 31, 2017. SCE&G supplements its supplies of natural gas with two LNG storage facilities, one of which has liquefaction capability. Approximately 1,624,300 MMBTU (liquefied equivalent) of gas were in storage on December 31, 2017. For a discussion of SCE&G's natural gas storage capacity, see Item 2. Properties.
 
PSNC Energy purchases natural gas under contracts with producers and marketers on a short-term basis at market based prices and on a long-term basis for reliability assurance at first of the month index prices plus a reservation charge in certain cases. Transco transports natural gas to North Carolina through transportation agreements with varying expiration dates through 2031. On a peak day, PSNC Energy is capable of receiving daily transportation volumes of natural gas under these contracts, utilizing firm contracts of 710,062 MMBTU from Transco.
 
PSNC Energy purchased natural gas, including fixed transportation, at an average cost of $4.39 per MMBTU during 2017 compared to $3.73 per MMBTU during 2016.
 
To meet the requirements of its high priority natural gas customers during periods of maximum demand, PSNC Energy supplements its supplies of natural gas with underground natural gas storage services and LNG peaking services. Underground natural gas storage service agreements with Dominion Energy Transmission, Inc., Columbia Gas Transmission, Transco and Enbridge Inc. provide for storage capacity of approximately 13,000,000 MMBTU. Approximately 9,000,000 MMBTU of gas were in storage under these agreements at December 31, 2017. PSNC Energy also maintains LNG storage service agreements with Transco, Cove Point LNG and Pine Needle LNG which provides 1,300,000 MMBTU (liquefied equivalent) of storage space. Approximately 1,200,000 MMBTU (liquefied equivalent) were in storage under these agreements at December 31, 2017. Approximately 800,000 MMBTU (liquefied equivalent) of gas were in storage at PSNC Energy's LNG storage facility at December 31, 2017. For a discussion of PSNC Energy's LNG storage capacity, see Item 2. Properties.
 
SCANA and SCE&G believe that supplies under long-term contracts and supplies available for spot market purchase are adequate to meet existing customer demands and to accommodate growth.
 
Gas Marketing-Nonregulated
 
SCANA Energy markets natural gas and provides energy-related services in the Southeast. In addition, a division of SCANA Energy markets natural gas to greater than 425,000 customers (as of December 31, 2017) in Georgia’s natural gas market. Georgia’s natural gas market includes approximately 1.6 million customers.

Risk Management
 
For a discussion of risk management policies and procedures, see Note 6 to the consolidated financial statements.
 
REGULATION
 
Regulatory jurisdictions to which SCANA and its subsidiaries are subject are described in the Regulatory Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
SCE&G has obtained FERC authority 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 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, bankers, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority 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 2018. 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.
 
SCE&G holds licenses under the Federal Power Act for each of its hydroelectric projects. The licenses expire as follows:

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Project
 
License
Expiration
Saluda (Lake Murray)
 
*
Fairfield Pumped Storage/Parr Shoals
 
2020
Stevens Creek
 
2025
Neal Shoals
 
2036
 
* SCE&G operates the Saluda hydroelectric project under an annual license while its long-term re-licensing application is being reviewed by FERC.
    
At the termination of a license under the Federal Power Act, FERC may extend or issue a new license to the previous licensee, may issue a license to another applicant, or the federal government may take over the related project. If the federal government takes over a project or if FERC issues a license to another applicant, the federal government or the new licensee, as the case may be, must pay the previous licensee an amount equal to its net investment in the project, not to exceed fair value, plus severance damages.
 
RATE MATTERS
 
For a discussion of the impact of various rate matters, see the Regulatory Matters section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 2 to the consolidated financial statements.

Fuel Cost Recovery Procedures
 
The SCPSC’s fuel cost recovery procedure determines the fuel component in SCE&G’s retail electric base rates annually based on projected fuel costs for the ensuing 12-month period, adjusted for any over-collection or under-collection from the preceding 12-month period. The statutory definition of fuel costs includes certain variable environmental costs, such as ammonia, lime, limestone and catalysts consumed in reducing or treating emissions, and the cost of emission allowances used for SO 2 , NO X , mercury and particulates. In addition, the statutory definition of fuel cost allows electric utilities to recover avoided costs under the Public Utility Regulatory Policy Act of 1978, as well as costs incurred as a result of offering DER and net metering programs to its customers. SCE&G may request a formal proceeding concerning its fuel costs at any time.
 
Purchased gas cost recovery procedures related to the Company's natural gas operations along with related rate proceedings by the SCPSC and NCUC are described in Note 2 to the consolidated financial statements.
   
ENVIRONMENTAL MATTERS
 
Federal and state authorities have imposed environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of any new or pending regulations or standards upon existing operations cannot be predicted. For a discussion of how these regulations and standards may impact SCANA and SCE&G (including capital expenditures necessitated thereby), see the Environmental Matters section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 10 to the consolidated financial statements.
 
OTHER MATTERS
 
Insurance coverage for Unit 1 is described in Note 10 to the consolidated financial statements.

 For a discussion of the impact of competition, see the Overview section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For a discussion of cash requirements for construction and nuclear fuel expenditures, contractual cash obligations, financing limits, financing transactions and other related information, see the Liquidity and Capital Resources section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


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ITEM 1A. RISK FACTORS
 
The risk factors that follow relate in each case to the Company, and where indicated the risk factors also relate to Consolidated SCE&G.

The completion of the merger is subject to the receipt of consents, approvals and/or findings from governmental entities, which may impose conditions that could have an adverse effect on Dominion Energy or SCANA or could cause either Dominion Energy or SCANA to terminate the merger. The completion of the merger is also subject to there having not been certain substantive changes in certain South Carolina laws that have or would reasonably be expected to have an adverse effect on SCANA or its subsidiaries or changes in law that impose any condition that would reasonably be expected to result in specified changes to the Joint Petition. Additionally, any such changes in certain South Carolina law could affect the considerations which were relied upon by SCANA and/or Dominion Energy prior to the signing of the Merger Agreement.

Dominion Energy and SCANA are not required to complete the merger until after the requisite authorizations, approvals, consents and/or permits are received from the FERC, NRC, SCPSC, NCUC and GPSC. Any of the relevant governmental entities may oppose the merger, fail to approve the merger, fail to make required findings in favor of the merger, or impose certain requirements or obligations as conditions for their consent, approval or findings or in connection with their review. Regulatory approvals of the merger or findings with respect to the merger may not be obtained on a timely basis or at all, and such approvals or findings may include conditions that could have an adverse effect on the Company or Consolidated SCE&G, and/or result in the termination of the merger. The terms of any conditions imposed in order to obtain the requisite regulatory approvals or findings may not be known by the date of the special meeting of SCANA shareholders to vote on the merger proposal. No assurance can be given that the necessary approvals or findings will be obtained or that any required conditions will not have an adverse effect on Dominion Energy following the merger. If SCANA shareholders vote in favor of the merger proposal at the special meeting, Dominion Energy or SCANA may make decisions after the special meeting to waive a condition or approve certain actions required to obtain regulatory approvals or findings without seeking further approval of the SCANA shareholders.

Subject to the terms and conditions set forth in the Merger Agreement, the Merger Agreement requires Dominion Energy to accept conditions from regulators that could adversely impact Dominion Energy after the merger without either of Dominion Energy or SCANA having the right to refuse to close the merger on the basis of those regulatory conditions, except that Dominion Energy is generally not required, and SCANA is generally not permitted without Dominion Energy’s prior approval, to take any action or accept any condition that results in a burdensome condition.

In addition, the Merger Agreement provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if, since the date of the Merger Agreement, any governmental entity shall have enacted any order, or there shall have been any change in law (including the BLRA and the other laws governing South Carolina public utilities), which imposes any material change to the terms, conditions or undertakings set forth in the Joint Petition, or any significant changes to the economic value of the Joint Petition, in each case as determined by Dominion Energy in good faith.

The Merger Agreement further provides that Dominion Energy (but not SCANA) will have the right to refuse to complete the merger if there shall have occurred any substantive change in the BLRA or other laws governing South Carolina public utilities which has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries. There is currently pending before the South Carolina Senate a bill that would make substantive changes to the BLRA. This bill (H.4375) has passed the South Carolina House of Representatives. If this bill becomes law, Dominion Energy would not be obligated to complete the merger if it is determined that the bill has or would reasonably be expected to have an adverse effect on SCANA or any of its subsidiaries.

Certain lawsuits and regulatory actions have been filed against SCANA and SCE&G in connection with the abandonment of the Nuclear Project. If the relief requested in these matters (including a request for declaratory judgment that the BLRA is unconstitutional) is granted, Dominion Energy might not be obligated to complete the merger.

No assurance can be given that these risks will not materialize and either adversely impact Dominion Energy after the completion of the merger or, if such conditions rise to the thresholds discussed above, some of which, as described above, are in the subjective determination of Dominion Energy acting in good faith, or if the required authorizations, approvals, consents and/or permits are not obtained or received, result in the termination of the merger and adversely impact the results of operations, cash flows and financial conditions of the Company and Consolidated SCE&G.


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Failure to complete the merger could negatively impact the stock price and the future business and financial results of SCANA.

If the merger is not completed, the ongoing business of the Company and Consolidated SCE&G may be adversely affected and the Company and Consolidated SCE&G could be subject to several risks, including the following:

the price of SCANA common stock may decline to the extent that the current market price reflects an expectation by the market that the merger will be completed;
obligations to pay certain costs relating to the merger, such as legal, accounting, financial advisory, filing, printing and mailing fees;  
the disruption of the Company’s and Consolidated SCE&G’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies due to management’s focus on the merger, any of which could adversely affect the ability of the Company and Consolidated SCE&G to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect the business and financial results of the Company or Consolidated SCE&G, without realizing any of the benefits of having the merger completed;
the potential negative impact on the Company and Consolidated SCE&G ultimately resolving the rate and regulatory issues, including pending investigations and legal challenges, relating to the abandonment of the Nuclear Project in a manner satisfactory to SCANA on account of SCANA working with Dominion Energy to pursue the resolution of these issues as contemplated by the Merger Agreement rather than pursuing its regulatory and legal options for resolving these issues independently of considerations and obligations related to the merger; and
the loss of other opportunities that could be beneficial to the Company and Consolidated SCE&G that could have been pursued during the pendency of the merger, without realizing any of the benefits of having the merger completed.

In addition to the above risks, SCANA may be required, under certain circumstances, to pay to Dominion Energy a termination fee of $240 million.

If the merger is not completed, no assurance can be given that these risks will not materialize and will not materially affect SCANA's business, financial results and stock price.

The Merger Agreement contains provisions that limit SCANA’s ability to pursue alternatives to the merger, which could discourage a potential competing acquirer of SCANA or could result in any competing proposal being at a lower price than it might otherwise be.

The Merger Agreement contains provisions that, subject to certain exceptions, restrict SCANA’s ability to initiate, solicit, knowingly encourage, facilitate or discuss competing third-party proposals to acquire all or a significant part of SCANA, or provide information to a third party that could reasonably be expected to lead to such a proposal. In addition, Dominion Energy generally has an opportunity to offer to modify the terms of the merger in response to any superior acquisition proposal that may be made before the SCANA board of directors is permitted to withdraw or qualify its recommendation. In some circumstances on termination of the Merger Agreement, SCANA may be required to pay to Dominion Energy a termination fee of $240 million.

These provisions, which the SCANA board regards as customary for transactions of this type, could discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of SCANA from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the merger consideration, or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable by SCANA in certain circumstances.

The pendency of the merger could adversely affect the business and operations of SCANA.

In connection with the pending merger, some current or prospective customers or vendors of SCANA’s utilities may delay or defer decisions regarding their existing or proposed relationships with those utilities, which could negatively impact the operation, revenues, earnings, cash flows and expenses of the Company and Consolidated SCE&G, regardless of whether the merger is completed. Similarly, current and prospective employees of SCANA and its utilities may experience uncertainty about their future roles following the merger, which may adversely affect the ability of SCANA and its utilities to attract and retain key personnel during the pendency of the merger. In addition, due to operating covenants in the Merger Agreement, during the pendency of the merger, SCANA and its utilities may be unable to pursue strategic transactions, undertake

12


significant capital projects, undertake certain significant financing or other specified transactions or pursue actions that are not in the ordinary course of business, even if such actions would prove beneficial.

Following the merger, Dominion Energy may be unable to successfully integrate the Company’s and Consolidated SCE&G’s businesses.

Dominion Energy and SCANA currently operate as independent public companies. After the merger, Dominion Energy will be required to devote significant management attention and resources to integrating the Company’s and Consolidated SCE&G’s business. Potential difficulties Dominion Energy may encounter in the integration process include the following:

the complexities associated with integrating SCANA and its utility businesses, while at the same time continuing to provide consistent, high quality services;
the complexities of integrating a company with different core services, markets and customers;
the inability to attract and retain key employees;
potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the merger;
difficulties in managing political and regulatory conditions related to SCANA’s utility business after the merger;
the cost recovery plan includes a moratorium on filing requests for adjustments in SCANA’s base electric rates until 2021 if the merger is approved by the SCPSC, which would limit Dominion Energy’s ability to recover increases in non-fuel related costs of electric operations for SCE&G’s customers; and
performance shortfalls as a result of the diversion of Dominion Energy management’s attention caused by completing the merger and integrating SCANA’s utility businesses.

For these reasons, you should be aware that it is possible that the integration process following the merger could result in the distraction of Dominion Energy’s management, the disruption of Dominion Energy’s ongoing business or inconsistencies in its services, standards, controls, procedures and policies, any of which could adversely affect the ability of Dominion Energy to maintain or establish relationships with current and prospective customers, vendors and employees or could otherwise adversely affect the business and financial results of Dominion Energy.

Dominion Energy, the Company and Consolidated SCE&G may be adversely affected by negative publicity related to the merger and in connection with other related matters, including the abandonment of the Nuclear Project.

From time to time, political and public sentiment in connection with the merger and in connection with other matters, including the abandonment of the Nuclear Project, may result in a significant amount of adverse press coverage and other adverse public statements affecting Dominion Energy and the Company and Consolidated SCE&G. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceedings, as well as responding to and addressing adverse press coverage and other adverse public statements, can divert the time and effort of senior management from the management of Dominion Energy’s, the Company’s and Consolidated SCE&G’s respective businesses.

Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of Dominion Energy, the Company and Consolidated SCE&G, on the morale and performance of their employees and on their relationships with their respective regulators, customers and commercial counterparties. It may also have a negative impact on their ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have an adverse effect on Dominion Energy’s, the Company’s and Consolidated SCE&G’s respective business, financial condition, results of operations and prospects.

Pending litigation against SCANA and Dominion Energy could result in an injunction preventing the completion of the merger or may adversely affect the combined company’s business, financial condition or results of operations following the merger.

Following the announcement of the merger, three lawsuits were filed asserting claims relating to the merger. First, an existing derivative lawsuit was amended to assert direct claims of a putative class of SCANA shareholders in the Court of Common Pleas of the County of Richland, South Carolina against the members of the SCANA board of directors, Dominion Energy and Sedona Corp., alleging breaches of various fiduciary duties by the members of the SCANA board of directors in connection with the merger and alleging that Dominion Energy and Sedona Corp. aided and abetted such alleged breaches.

13


Second, two putative class actions on behalf of SCANA shareholders have been filed in the Court of Common Pleas of the Counties of Lexington and Richland, South Carolina, respectively, against SCANA, the members of the SCANA board of directors, Dominion Energy and Sedona Corp., alleging breaches of various fiduciary duties by the members of the SCANA board of directors in connection with the merger and alleging that SCANA, Dominion Energy and Sedona Corp. aided and abetted such alleged breaches. Among other remedies, the plaintiffs in each case seek to enjoin the merger and rescind the Merger Agreement. In addition, the second and third lawsuits seek in the alternative, should the merger be completed, an award of unspecified monetary damages.

While the defendants believe that dismissal is warranted, the outcome of any such litigation is inherently uncertain. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect the combined company’s business, financial condition or results of operation.

There is uncertainty as to whether the Company and Consolidated SCE&G will be able to recover costs expended for the Nuclear Project, and a reasonable return on those costs, under the abandonment provisions of the BLRA or through other means. As of December 31, 2017, the Company and Consolidated SCE&G have recognized a significant estimated impairment loss with respect to such investment and related costs. In the event the Company and Consolidated SCE&G were to determine that all or an additional portion of their remaining unrecovered Nuclear Project costs are to be disallowed and that significant additional impairment losses must be recognized, further material adverse impacts on their results of operations, cash flows and financial condition would occur.

During the term of the Interim Assessment Agreement, SCE&G and Santee Cooper evaluated the various elements of the Nuclear Project, including forecasted costs and completion dates, while construction continued, and SCE&G and Santee Cooper continued to make payments for such work. Based on this evaluation, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement, and notified WEC of its determination to stop construction of Unit 2 and Unit 3.

On August 1, 2017, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the Nuclear Project and this decision, and SCE&G also filed a petition with the SCPSC which included its plan of abandonment and certain proposed actions which would mitigate related customer rate increases, including a proposal to return to customers the net value of the proceeds received by SCE&G under or arising from the Toshiba Settlement.

The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs may be recoverable through rates, if the SCPSC determines that the decision to abandon the Nuclear Project was prudent. Through its August 1, 2017 petition, SCE&G had sought recovery of such costs expended on the construction of the project, including certain costs incurred subsequent to SCE&G's last revised rates update, and a reasonable return on those costs, and certain other costs under the abandonment provisions of the BLRA. Subsequently, SCE&G’s management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow for adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew its August 1, 2017 petition from the SCPSC on August 15, 2017.

In August 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, began conducting public hearings regarding the decision to abandon the Nuclear Project. Members of SCE&G's senior management, along with representatives from Santee Cooper, the ORS and other interested parties, testified before these committees. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and are being considered by the General Assembly in 2018. In January 2018, these committees reconvened for the purpose of considering the effects of the proposed merger. On January 31, 2018, the House of Representatives passed a bill (H. 4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law, the

14


precise impact of any change in the law, or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA.

In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. No assurance can be given as to the timing or outcome of these matters.

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections currently total approximately $445 million annually, and the amounts accumulated as of December 31, 2017 total approximately $1.9 billion.

On September 27, 2017, the scheduled payments under the Toshiba Settlement, exclusive of the payment due in October 2017, were purchased by Citibank for a one-time upfront payment of $1.847 billion (approximately $1.016 billion for SCE&G's 55% share), including amounts related to certain liens that SCE&G was contesting but for which SCE&G may ultimately have been liable. The initial payment was then received from Toshiba on October 2, 2017, as scheduled, in the amount of $150 million ($82.5 million for SCE&G's 55% share). A regulatory liability has been recorded on the consolidated balance sheets to reflect the amount related to the Toshiba Settlement that will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. While this determination is pending, SCE&G has utilized portions of the proceeds to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction. On October 17, 2017, the ORS filed a motion with the SCPSC to amend its earlier Request, in which the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. It is possible that the outcome of regulatory or legal proceedings could result in requiring SCE&G's share of these proceeds to be placed in escrow pending their final disposition, or could require these proceeds to be refunded to customers in the near-term or otherwise make these funds unavailable to SCE&G. If any of these circumstances were to arise, it is anticipated that SCE&G would reissue commercial paper or draw on its credit facilities to fund such requirement. However, such sources may not be available. Any such requirement would significantly harm the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition. In addition, 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.

On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. Parties who filed to intervene in the matter or who filed a letter in support of the request by the ORS include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, the SCEUC, certain large industrial customers, and several environmental groups. After conducting a hearing to consider SCE&G's motion, the SCPSC denied the motion on December 20, 2017 and ordered that a hearing be scheduled to consider the Request. The hearing has not yet been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. Any adverse action by the SCPSC, such as that sought by the ORS in the Request, could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

In the third quarter of 2017, SCE&G recorded a pre-tax impairment loss of $210 million related to unrecovered nuclear project costs. In the fourth quarter of 2017, SCE&G recorded an additional pre-tax impairment loss of $908 million related to such unrecovered costs and other related costs. See Note 10 to the consolidated financial statements. These

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impairment losses have had the effect of increasing the Company's and Consolidated SCE&G's debt to total capitalization. If the SCPSC were to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered Nuclear Project costs would be adversely impacted. Also, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could further increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities and also could constitute a default under these credit facilities. Borrowing costs for long-term debt issuances and access to capital markets could also be negatively impacted.

The ability of SCE&G to recover its costs related to the construction and subsequent abandonment of the Nuclear Project, and a reasonable return on them, through rates will be subject to review and approval by the SCPSC. An application under the abandonment provisions of the BLRA, and the regulatory process contemplated thereby, have never been pursued or legally challenged. As a result, and in light of the contentious nature of the ongoing reviews by and related activities of the South Carolina House Utility Ratepayer Protection Committee, the South Carolina Senate's V.C. Summer Nuclear Project Review Committee and others, and given pending legislation, it is uncertain whether SCE&G will be able to successfully recover the costs of the abandoned units, and a reasonable return on them. Under the BLRA, the SCPSC must consider and rule on a petition within six months. Even so, and although expedited action has been requested by SCE&G, it is unclear when the SCPSC will consider the Joint Petition. In any case, anticipated appeals of any ruling by the SCPSC could be protracted. Further, should the regulatory construct in South Carolina change in such a manner that recovery is sought through other legal proceedings or through regulatory proceedings outside the provisions of the BLRA, such as in a general rate case, other uncertainties may arise, such as those highlighted with respect to the Merger Agreement.

Further downgrades in the credit ratings of SCANA or any of SCANA’s subsidiaries, including SCE&G, could negatively affect our ability to access capital and to operate our businesses, thereby adversely affecting results of operations, cash flows and financial condition.

Various rating agencies currently rate SCE&G’s senior secured debt and the senior unsecured debt of PSNC Energy as investment grade. One rating agency currently rates SCANA’s senior unsecured debt as investment grade, and two rating agencies rate SCANA's senior unsecured debt as below investment grade. In addition, rating agencies maintain ratings on the short-term debt of SCANA, SCE&G, Fuel Company (which ratings are based upon the guarantee of SCE&G) and PSNC Energy. Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including regulatory environment, capital structure and the ability to meet liquidity requirements.

In the first quarter of 2017, the rating agencies placed SCANA and SCE&G’s credit ratings on negative outlook or watch status due to adverse developments relating to the WEC bankruptcy. In the third quarter of 2017, two agencies lowered their ratings for SCANA and its rated subsidiaries, citing a decline in the regulatory environment as a principal reason for the downgrades, and both agencies maintained their negative outlook or watch status. On January 3, 2018, after SCANA announced a proposed merger with Dominion Energy, each of the three agencies affirmed or reported no change to their respective credit ratings, and one agency revised its rating outlook for SCANA and its rated operating companies from negative to evolving. However, on January 31, 2018, the South Carolina House of Representatives overwhelmingly approved a bill (H. 4375) that, if enacted, would temporarily repeal rates SCE&G collects under the BLRA. As a result, on February 5, 2018, one agency downgraded its ratings for SCANA and SCE&G, and attributed the downgrade to the action taken by the House of Representatives and the politically charged environment that is expected to weigh heavily on any decisions by the SCPSC related to SCE&G's electric rates. All of the ratings for SCANA, SCE&G and PSNC Energy are either under review for possible downgrade or have a negative or evolving outlook.

Any actions taken by or anticipated to be taken by regulators or legislators that are viewed as adverse, including a change to the BLRA or a requirement that SCE&G make credits to future bills or refunds to customers above such amounts as are included in the Merger Agreement or any requirement that SCE&G make such credits or refunds in the absence of the merger being consummated, or deterioration of our rated companies’ commonly monitored financial credit metrics and additional adverse developments with respect to the Nuclear Project, could further negatively affect their debt ratings. If these rating agencies were to further lower any of these ratings, borrowing costs on new issuances of long-term debt and commercial paper would increase, which could adversely impact financial results or limit or eliminate refinancing opportunities, and the potential pool of investors and funding sources could decrease. Any further lowering of these ratings could also trigger higher interest costs as well as more stringent collateral requirements on interest rate and commodity hedges and under gas supply agreements and a reduction in the availability of suppliers.


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The Company and Consolidated SCE&G are defendants in numerous legal proceedings and the subject of ongoing governmental investigations, examinations and other inquiries stemming from the decision to abandon the Nuclear Project. The outcome of each of these matters is uncertain, and any resolution adverse to the Company and Consolidated SCE&G could adversely affect results of operations, cash flows and financial condition.
 
Following the Company’s decision to abandon construction of Unit 2 and Unit 3, putative derivative and class action lawsuits seeking have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory, consequential and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, namely all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement for the Nuclear Project.

In addition, purported class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and two suits allege violations of the Racketeer Influenced and Corrupt Organizations Act. In one suit, the plaintiff alleges that director defendants violated Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

The Company has also been served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. In addition, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee have requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. The Company and Consolidated SCE&G intend to fully cooperate with any such investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have challenged or may attempt to challenge, reverse or revoke one or more previously-approved tax or economic development incentives, benefits or exemptions, including use tax exemptions, and are attempting to apply such action retroactively.

The Company and Consolidated SCE&G cannot predict the outcome of these matters or other claims, allegations or assessments which may arise, and it is possible that adverse outcomes from some of these matters would not be covered by insurance. A resolution adverse to the Company and Consolidated SCE&G could adversely affect results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G are engaged in activities for which they have claimed, and expect to claim in the future, research and experimentation tax deductions and credits and tax abandonment losses, all of which are the subject of uncertainty and which may be considered controversial by the taxing authorities.  The outcome of those uncertainties could adversely impact cash flows, results of operations and financial condition.

The Company and Consolidated SCE&G have claimed significant research and experimentation tax deductions and credits related to the design and construction activities of Unit 2 and Unit 3. A significant portion of 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. (See also Note 5 to the consolidated financial statements.) The Company and Consolidated SCE&G also expect to claim a significant tax deduction related to the decision to stop construction and to abandon the Nuclear Project in 2017.

These tax claims primarily involve the timing of recognition of tax deductions rather than permanent tax attributes, and their permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to them, had been deferred within regulatory assets. As such, until December 31, 2017 when it was determined to treat these deferrals as

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impaired (see Note 10 to the consolidated financial statements), these claims had not had, and were not expected to have in the future, significant direct effects on the Company’s and Consolidated SCE&G’s results of operations.  Nonetheless, the claims have contributed significantly to the Company’s and Consolidated SCE&G’s cash flows by providing a significant source of capital and lessening the level of debt and equity financing that the Company and Consolidated SCE&G have needed to raise in the financial markets. 

The claims made to date are under examination and are considered controversial by the IRS. Tax deductions which are expected to be claimed in connection with the determination to abandon the construction of Unit 2 and Unit 3 may also be considered controversial; therefore, it is also expected that the IRS will examine future tax returns. To the extent that any of these claims are not sustained as ordinary losses on examination or through any subsequent appeal, the Company and Consolidated SCE&G will be required to repay any cash received for tax benefit claims which are ultimately disallowed, along with interest on those amounts. Such amounts could be significant and could adversely affect the Company's and Consolidated SCE&G's liquidity, cash flows, results of operations and financial condition. In certain circumstances, which management considers to be remote, penalties for underpayment of income taxes could also be assessed. Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access capital markets for other purposes.

The Company and Consolidated SCE&G are subject to numerous environmental laws and regulations that require significant capital expenditures, can increase our costs of operations and may impact our business plans or expose us to environmental liabilities.

The Company and Consolidated SCE&G are subject to extensive federal, state and local environmental laws and regulations, including those relating to water quality and air emissions (such as reducing NO X , SO 2 , mercury and particulate matter). Some form of regulation is expected at the federal and state levels to impose regulatory requirements specifically directed at reducing GHG emissions from fossil fuel-fired electric generating units. On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO 2 from newly constructed fossil fuel-fired units. No new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final rule, but do not plan to construct new coal-fired units in the foreseeable future. In addition, 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. 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 EPA is further considering the scope of any potential replacement rule and plans to formally solicit information on systems of emission reduction that are in accord with the EPA's interpretation of its statutory authority. However, a number of bills have been introduced in Congress that seek to require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none has yet been enacted. In April 2012, the EPA issued the finalized MATS for power plants that requires reduced emissions from new and existing coal and oil-fired electric utility steam generating facilities. The EPA's rule for cooling water intake structures to meet the best technology available became effective in October 2014, and the EPA also issued a final rule in December 2014 regarding the handling of coal ash and other combustion by-products produced by power plant operations. Furthermore, the EPA finalized new standards under the CWA governing effluent limitation guidelines for electric generating units in September 2015. The rule setting forth these new standards has been stayed administratively, and the EPA has begun a new rulemaking process that could take until 2020 before revisions to the effluent limitation guidelines for electric generating units is complete.

Compliance with these environmental laws and regulations requires us to commit significant resources toward environmental monitoring, installation of pollution control equipment, emissions fees and permitting at our facilities. These expenditures have been significant in the past and are expected to continue or even increase in the future. Changes in compliance requirements, additional regulations and related costs, or more restrictive interpretations by governmental authorities of existing requirements may impose additional costs on us (such as more stringent clean-up of contaminated sites or reduced emission allowances) or require us to incur additional expenditures or curtail some of our cost savings activities (such as the recycling of fly ash and other coal combustion products for beneficial use). Compliance with any GHG emission reduction requirements, including any mandated renewable portfolio standards, also may impose significant costs on us, and the resulting price increases to our customers may lower customer consumption. Such costs of compliance with environmental regulations could negatively impact our businesses and our results of operations and financial position, especially if emissions or discharge limits are reduced or more onerous permitting requirements or additional regulatory requirements are imposed. Additionally, there can be no assurance that a federal tax or fee for carbon emitting generating facilities will not be imposed.

Renewable and/or alternative electric generation portfolio standards may be enacted at the federal or state level. Such renewable energy may not be readily available in our service territories and could be costly to build, finance, acquire, integrate, and/or operate. Resulting increases in the price of electricity to recover the cost of these types of generation, and the costs of

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their integration to the electric system, could result in lower usage of electricity by our customers. In addition, DER generation at customers’ facilities could result in the loss of sales to those customers. Compliance with potential future portfolio standards could significantly impact our capital expenditures and our results of operations and financial condition. Utility scale solar development companies are currently working in South Carolina to develop projects in SCE&G's service territory. The integration of those resources at high penetration levels may be challenging.

The compliance costs of these environmental laws and regulations are important considerations in the Company's and Consolidated SCE&G's strategic planning and, as a result, significantly affect the decisions to construct, operate, and retire facilities, including generating facilities. In turn, they affect the costs and rates of the Company and Consolidated SCE&G. In effecting compliance with MATS, SCE&G has retired three of its oldest and smallest coal-fired units and converted three others such that they are gas-fired.

Commodity price changes, delays in delivery of commodities, commodity availability and other factors may affect the operating cost, capital expenditures and competitive positions of the Company’s and Consolidated SCE&G’s energy businesses, thereby adversely impacting results of operations, cash flows and financial condition.

Our energy businesses are sensitive to changes in coal, natural gas, uranium and other commodity prices (as well as their transportation costs), availability and deliverability. Any such changes could affect the prices these businesses charge, their operating costs, and the competitive position of their products and services. In addition, the abandonment of the Nuclear Project may heighten the Company's and Consolidated SCE&G's future exposure to volatility in prices of non-nuclear commodities such as natural gas. Consolidated SCE&G is permitted to recover the prudently incurred cost of purchased power and fuel (including transportation) used in electric generation through retail customers’ bills, but purchased power and fuel cost increases affect electric prices and therefore the competitive position of electricity against other energy sources. In addition, when natural gas prices are low enough relative to coal to result in the dispatch of gas-fired electric generation ahead of coal-fired electric generation, higher inventories of coal, with related increased carrying costs, may result. This may adversely affect our results of operations, cash flows and financial condition.

In the case of regulated natural gas operations, costs prudently incurred for purchased gas and pipeline capacity may be recovered through retail customers’ bills. However, in both our regulated and deregulated natural gas markets, increases in gas costs affect total retail prices and therefore the competitive position of gas relative to electricity and other forms of energy. Accordingly, customers able to do so may switch to alternate forms of energy and reduce their usage of gas from the Company and Consolidated SCE&G. Customers on a volumetric rate structure unable to switch to alternate fuels or suppliers may reduce their usage of gas from the Company and Consolidated SCE&G. A regulatory mechanism applies to residential and commercial customers at PSNC Energy to mitigate the earnings impact of an increase or decrease in gas usage.

Certain construction-related commodities, such as copper and aluminum used in our transmission and distribution lines and in our electrical equipment, and steel, concrete and rare earth elements, have experienced significant price fluctuations due to changes in worldwide demand. To operate our air emissions control equipment, we use significant quantities of ammonia, limestone and lime. With EPA-mandated industry-wide compliance requirements for air emissions controls, increased demand for these reagents, combined with the increased demand for low sulfur coal, may result in higher costs for coal and reagents used for compliance purposes.

Changing and complex laws and regulations to which the Company and Consolidated SCE&G are subject could adversely affect revenues, increase costs, or curtail activities, thereby adversely impacting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G operate under the regulatory authority of the United States government and its various regulatory agencies, including the FERC, NRC, SEC, IRS, EPA, the Department of Homeland Security, CFTC and PHMSA. In addition, the Company and Consolidated SCE&G are subject to regulation by the state governments of South Carolina, North Carolina and Georgia via regulatory agencies, state environmental agencies, and state employment commissions. Accordingly, the Company and Consolidated SCE&G must comply with extensive federal, state and local laws and regulations. Such governmental oversight and regulation broadly and materially affect the operation of our businesses. In addition to many other aspects of our businesses, these requirements impact the services mandated or offered to our customers, and the licensing, siting, construction and operation of facilities. They affect our management of safety, the reliability of our electric and natural gas systems, the physical and cyber security of key assets, customer conservation through DSM Programs, information security, the issuance of securities and borrowing of money, financial reporting, interactions among affiliates, the pricing of utility services, the payment of dividends and employment programs and practices. Changes to governmental regulations are continual and potentially costly to effect compliance. Non-compliance with these requirements by third parties, such as our contractors, vendors and agents, may subject the Company and Consolidated SCE&G to operational risks and to

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liability. We cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on the Company’s or Consolidated SCE&G’s businesses. Non-compliance with these laws and regulations could result in fines, litigation, loss of licenses or permits, mandated capital expenditures and other adverse business outcomes, as well as reputational damage, which could adversely affect the cash flows, results of operations, and financial condition of the Company and Consolidated SCE&G.

Furthermore, changes in or uncertainty in monetary, fiscal, tax, economic, trade, or regulatory policies of the Federal government may adversely affect the debt and equity markets and the economic climate for the nation, region or particular industries, such as ours or those of our customers. The Company and Consolidated SCE&G also could be adversely impacted by changes in tax policy, or taxes related to the usage of certain fuel types in our businesses or our ownership and/or operation of certain types of generating facilities. Future, unknown regulation of hydraulic fracturing activities also could impact the operations and finances of the Company and Consolidated SCE&G.

The Company and Consolidated SCE&G are subject to extensive rate regulation which could adversely affect operations. Large capital projects (including the abandonment of Unit 2 and Unit 3 as previously described), results of DSM Programs, results of DER programs, and/or increases in operating costs may lead to requests for regulatory relief and any related administrative or legislative action, decision, regulation or law affecting rates, such as rate increases, which may be denied, in whole or part, by rate regulators. Rate increases may also result in reductions in customer usage of electricity or gas, legislative action and lawsuits. Additionally, in 2017, several legislative proposals were introduced that are being or are expected to be considered by the South Carolina General Assembly in 2018. In the event certain provisions of these legislative proposals were to become law as proposed, such provisions could adversely impact SCE&G’s rate recovery with respect to the Nuclear Project. Furthermore, there can be no assurance that other legislation which might modify or repeal the BLRA in a manner which would adversely impact SCE&G’s rate recovery, including its reasonable return on costs, with respect to its abandonment of Unit 2 and Unit 3 will not be proposed and passed. Any such action could also result in a failure to consummate the merger.

SCE&G’s electric operations in South Carolina and the Company’s gas distribution operations in South Carolina and North Carolina are regulated by state utilities commissions. In addition, the ability of SCE&G to recover the cost of the Nuclear Project, including abandonment costs, and a reasonable return on those costs, is subject to rate regulation by the SCPSC. Consolidated SCE&G’s generating facilities are subject to extensive regulation and oversight from the NRC and SCPSC. SCE&G's electric transmission system is subject to extensive regulations and oversight from the SCPSC, NERC and FERC. Implementing and maintaining compliance with the NERC's mandatory reliability standards, enforced by FERC, for bulk electric systems could result in higher operating costs and capital expenditures. Non-compliance with these standards could subject SCE&G to substantial monetary penalties. Our gas marketing operations in Georgia are subject to state regulatory oversight and, for a portion of its operations, to rate regulation. There can be no assurance that Georgia’s gas delivery regulatory framework will remain unchanged as market conditions evolve.

Furthermore, Dodd-Frank affects the use and reporting of derivative instruments. The regulations under this legislation provide for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and require numerous rule-makings by the CFTC and the SEC to implement, many of which are still pending final action by those federal agencies. The Company and Consolidated SCE&G have determined that they meet the end-user exception to mandatory clearing of swaps under Dodd-Frank. In addition, the Company and Consolidated SCE&G have taken steps to ensure that they are not the party required to report these transactions in real-time (the "reporting party") by transacting solely with swap dealers and major swap participants, when possible, as well as entering into reporting party agreements with counterparties who also are not swap dealers or major swap participants, which establishes that those counterparties are obligated to report the transactions in accordance with applicable Dodd-Frank regulations. While these actions minimize the reporting obligations of the Company, they do not eliminate required recordkeeping for any Dodd-Frank regulated transactions. Despite qualifying for the end-user exception to mandatory clearing and ensuring that neither the Company nor Consolidated SCE&G is the reporting party to a transaction required to be reported in real-time, we cannot predict when the final regulations will be issued or what requirements they will impose.

Our ability to charge customer rates that will allow us to maintain reasonable rates of return is dependent upon regulatory determinations, and there can be no assurance that we will be able to implement rate adjustments when sought.

The Company and Consolidated SCE&G are subject to the reputational risks that may result from a failure to adhere to high standards related to compliance with laws and regulations, ethical conduct, operational effectiveness, customer service and the safety of employees, customers and the public. These risks could adversely affect the valuation of our common stock and the Company’s and Consolidated SCE&G’s access to capital.


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The Company and Consolidated SCE&G are committed to comply with all laws and regulations, to assure reliability of provided services, to focus on the safety of employees, customers and the public, to ensure environmental compliance, to maintain the physical and cyber security of their operations and assets, to maintain the privacy of information related to our customers and employees, and to maintain effective communications with the public and key stakeholder groups, particularly during emergencies and times of crisis. Traditional news media and social media can very rapidly convey information, whether factual or not, to large numbers of people, including customers, investors, regulators, legislators and other stakeholders, and the failure to effectively manage timely, accurate communication through these channels could adversely impact our reputation. The Company and Consolidated SCE&G also are committed to operational excellence, to quality customer service, and, through our Code of Conduct and Ethics, to maintain high standards of ethical conduct in our business operations. A failure to meet these commitments, or a perceived failure to meet these commitments, may subject the Company and Consolidated SCE&G not only to fraud, regulatory action, litigation or financial loss, but also to reputational risk that could adversely affect the valuation of SCANA’s stock, adversely affect the Company’s and Consolidated SCE&G’s access to capital, and result in further regulatory oversight. Insurance may not be available or adequate to respond to these events.

A failure of the Company and Consolidated SCE&G to maintain the physical and cyber security of its operations may result in the failure of operations, damage to equipment, or loss of information, and could result in a significant adverse impact to the Company's and Consolidated SCE&G's financial condition, results of operations and cash flows.

The Company and Consolidated SCE&G depend on maintaining the physical and cyber security of their operations and assets.  As much of our business is part of the nation's critical infrastructure, the loss or impairment of the assets associated with that portion of our businesses could have serious adverse impacts on the customers and communities that we serve.  Virtually all of the Company's and Consolidated SCE&G's operations are dependent in some manner upon our cyber systems, which encompass electric and gas operations, nuclear and fossil fuel generating plants, human resource and customer systems and databases, information system networks, and systems containing confidential corporate information. Cyber systems, such as those of the Company and Consolidated SCE&G, are often targets of malicious cyber attacks. A successful physical or cyber attack could lead to outages, failure of operations of all or portions of our businesses, damage to key components and equipment, and exposure of confidential customer, vendor, shareholder, employee, or corporate information. The Company and Consolidated SCE&G may not be readily able to recover from such events. In addition, the failure to secure our operations from such physical and cyber events may cause us reputational damage. Litigation, penalties and claims from a number of parties, including customers, regulators and shareholders, may ensue. Insurance may not be adequate to mitigate the adverse impacts of these events. As a result, the Company's and Consolidated SCE&G's financial condition, results of operations, and cash flows may be adversely affected.

The Company and Consolidated SCE&G are vulnerable to interest rate increases, which would increase our borrowing costs, and we may not have access to capital at favorable rates, if at all. Additionally, potential disruptions in the capital and credit markets may further adversely affect the availability and cost of short-term funds for liquidity requirements and our ability to meet long-term commitments; each could in turn adversely affect our results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G rely on the capital markets, particularly for publicly offered debt and equity, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs if internal funds are not available from operations. Changes in interest rates affect the cost of borrowing. The Company’s and Consolidated SCE&G’s business plans, which include significant investments in energy generation and other internal infrastructure projects, reflect the expectation that we will have access to the capital markets on satisfactory terms to fund commitments. Moreover, the ability to maintain short-term liquidity by utilizing commercial paper programs is dependent upon maintaining satisfactory short-term debt ratings and the existence of a market for our commercial paper generally.

The Company’s and Consolidated SCE&G’s ability to draw on our respective bank revolving credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments and on our ability to timely renew such facilities. Those banks may not be able to meet their funding commitments to the Company or Consolidated SCE&G if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time. Longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to liquidity needed for our businesses. Any disruption could require the Company and Consolidated SCE&G to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures or other discretionary uses of cash. Disruptions in capital and credit markets also could result in higher interest rates on debt securities, limited or no access to the commercial paper market, increased costs associated with commercial paper borrowing or limitations on the

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maturities of commercial paper that can be sold (if at all), increased costs under bank credit facilities and reduced availability thereof, and increased costs for certain variable interest rate debt securities of the Company and Consolidated SCE&G.

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy also adversely affect the value of the investments held within SCANA’s pension trust. A significant long-term decline in the value of these investments may require us to make or increase contributions to the trust to meet future funding requirements. In addition, a significant decline in the market value of the investments may adversely impact the Company’s and Consolidated SCE&G’s results of operations, cash flows and financial condition, including its shareholders’ equity.

Operating results may be adversely affected by natural disasters, man-made mishaps and abnormal weather.

The Company has delivered less gas and, in deregulated markets, received lower prices for natural gas when weather conditions have been milder than normal, and as a consequence earned less income from those operations. Mild weather in the future could adversely impact the revenues and results of operations and harm the financial condition of the Company and Consolidated SCE&G. Hot or cold weather could result in higher bills for customers and result in higher write-offs of receivables and in a greater number of disconnections for non-payment. In addition, for the Company and Consolidated SCE&G, severe weather can be destructive, causing outages and property damage, adversely affecting operating expenses and revenues.

Natural disasters (such as hurricanes or other significant weather events, electromagnetic events, the 2011 earthquake and tsunami in Japan or fires) or man-made mishaps (such as natural gas transmission pipeline failure, electric utility companies' ash pond failures, and cyber-security failures experienced by many businesses) could have direct significant impacts on the Company and Consolidated SCE&G and on our key contractors and suppliers or could impact us through changes to federal, state or local policies, laws and regulations, and have a significant impact on our financial condition, operating expenses, and cash flows.

The costs of large capital projects, such as the Company’s and Consolidated SCE&G’s construction and environmental compliance, are significant, and these projects are subject to a number of risks and uncertainties that may adversely affect the cost, timing and completion of these projects.

The Company’s and Consolidated SCE&G’s businesses are capital intensive and require significant investments in electric generation and in other internal infrastructure projects, including projects for environmental compliance. Achieving the intended benefits of any large construction project is subject to many uncertainties. For instance, the ability to adhere to established budgets and construction schedules may be affected by many variables, such as the regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected timeframes, the availability of labor and materials at estimated costs, the availability and cost of financing, and weather. There also may be contractor or supplier performance issues or adverse changes in their creditworthiness and/or financial stability, unforeseen difficulties meeting critical regulatory requirements, contract disputes and litigation, and changes in key contractors or subcontractors. There may be unforeseen engineering problems or unanticipated changes in project design or scope. Our ability to complete construction projects as well as our ability to maintain current operations at reasonable cost could be affected by the availability of key components or commodities, increases in the price of or the unavailability of labor, commodities or other materials, increases in lead times for components, adverse changes in applicable laws and regulations, new or enhanced environmental or regulatory requirements, supply chain failures (whether resulting from the foregoing or other factors), and disruptions in the transportation of components, commodities and fuels. To the extent that, in connection with the construction of a project, delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete the project, our results of operations, cash flows and financial condition, as well as our qualifications for applicable governmental programs, benefits and tax credits may be adversely affected.

A significant portion of Consolidated SCE&G’s generating capacity is derived from nuclear power, the use of which exposes us to regulatory, environmental and business risks. These risks could increase our costs or otherwise constrain our business, thereby adversely impacting our results of operations, cash flows and financial condition.

SCE&G jointly owns and is the operator of Unit 1. Various risks of nuclear generation to which SCE&G is subject include the following:

The potential harmful effects on the environment and human health resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; 

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Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
The possibility that new laws and regulations could be enacted that could adversely affect the liability structure that currently exists in the United States;
Uncertainties with respect to procurement of nuclear fuel and suppliers thereof, fabrication of nuclear fuel and related vendors, and the storage of spent nuclear fuel;
Uncertainties with respect to contingencies if insurance coverage is inadequate;
Uncertainties with respect to possible future increased regulation of nuclear facilities and nuclear generation, and related costs thereof; and
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their operating lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate capital expenditures at nuclear plants such as ours. In today’s environment, there is a heightened risk of terrorist attack on the nation’s nuclear facilities, which has resulted in increased security costs at our nuclear plant. Although we have no reason to anticipate a serious nuclear incident, a major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit, resulting in costly changes to units in operation and adversely impacting our results of operations, cash flows and financial condition. Furthermore, a major incident at a domestic nuclear facility could result in retrospective premium assessments under our nuclear insurance coverages.

Potential competitive changes may adversely affect our gas and electricity businesses due to the loss of customers, reductions in revenues, or write-down of stranded assets.

The utility industry has been undergoing structural change for a number of years, resulting in increasing competitive pressures on electric and natural gas utility companies. Competition in wholesale power sales via an RTO/ISO is in effect across much of the country, but the Southeastern utilities have retained the traditional bundled, vertically integrated structure. Should an RTO/ISO-market be implemented in the Southeast, potential risks emerge from reliance on volatile wholesale market prices as well as increased costs associated with new transmission and distribution infrastructure.

Some states have also mandated or encouraged unbundled retail competition. Should this occur in South Carolina or North Carolina, increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and natural gas sales. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their customers. In addition, the Company’s and Consolidated SCE&G’s generation assets would be exposed to considerable financial risk in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write-down in the value of the related assets could be required.

The Company and Consolidated SCE&G are subject to the risk of loss of sales due to the growth of distributed generation especially in the form of renewable power such as solar photovoltaic systems, which systems have undergone a rapid decline in their costs. As a result of federal and state subsidies, potential regulations allowing third-party retail sales, and advances in distributed generation technology, the growth of such distributed generation could be significant in the future. Such growth will lessen Company and Consolidated SCE&G sales and will slow growth, potentially causing higher rates to customers.

The Company and Consolidated SCE&G are subject to risks associated with changes in business and economic climate which could adversely affect revenues, results of operations, cash flows and financial condition and could limit access to capital.

Sales, sales growth and customer usage patterns are dependent upon the economic climate in the service territories of the Company and Consolidated SCE&G, which may be affected by regional, national or even international economic factors. Adverse events, economic or otherwise, may also affect the operations of suppliers and key customers. Such events may result in the loss of suppliers or customers, in higher costs charged by suppliers, in changes to customer usage patterns and in the failure of customers to make timely payments to us. With respect to the Company, such events also could adversely impact the results of operations through the recording of a goodwill or other asset impairment. Also, in connection with the pending merger, some customers or vendors of the Company and Consolidated SCE&G may delay or defer decisions, which could

23


negatively impact the revenues, earnings, cash flows and expenses of the Company and Consolidated SCE&G regardless of whether the merger is completed. The success of local and state governments in attracting new industry to our service territories is important to our sales and growth in sales, as are stable levels of taxation (including property, income or other taxes) which may be affected by local, state, or federal budget deficits, adverse economic climates generally, legislative actions (including tax reform), or regulatory actions. Industrial and commercial customer growth also potentially is affected by the availability of "clean" energy options in our service territory. Budget cutbacks also adversely affect funding levels of federal and state support agencies and non-profit organizations that assist low income customers with bill payments.

In addition, conservation and demand side management efforts and/or technological advances may cause or enable customers to significantly reduce their usage of the Company’s and SCE&G’s products and adversely affect sales, sales growth, and customer usage patterns. For instance, improvements in energy storage technology, if realized, could have dramatic impacts on the viability of and growth in distributed generation.

Factors that generally could affect our ability to access capital include economic conditions and our capital structure. Much of our business is capital intensive, and achievement of our capital plan and long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms that are attractive. If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be adversely impacted.

Problems with operations could cause us to curtail or limit our ability to serve customers or cause us to incur substantial costs, thereby adversely impacting revenues, results of operations, cash flows and financial condition.

Critical processes or systems in the Company’s or Consolidated SCE&G’s operations could become impaired or fail from a variety of causes, such as equipment breakdown, transmission equipment failure, information systems failure or security breach, operator error, natural disasters, and the effects of a pandemic, terrorist attack or cyber attack on our workforce or facilities or on vendors and suppliers necessary to maintain services key to our operations.

In particular, as the operator of power generation facilities, many of which entered service prior to 1985 and may be difficult to maintain, Consolidated SCE&G could incur problems, such as the breakdown or failure of power generation or emission control equipment, transmission equipment, or other equipment or processes which would result in performance below assumed levels of output or efficiency. The integration of a significant amount of distributed generation into our systems may entail additional cycling of our coal-fired generation facilities and may thereby increase the number of unplanned outages at those facilities. In addition, any such breakdown or failure may result in Consolidated SCE&G purchasing emission allowances or replacement power at market rates, if such allowances and replacement power are available at all. These purchases are subject to state regulatory prudency reviews for recovery through rates. If replacement power is not available, such problems could result in interruptions of service (blackout or brownout conditions) in all or part of SCE&G’s territory or elsewhere in the region. Similarly, a natural gas line failure of the Company or Consolidated SCE&G could affect the safety of the public, destroy property, and interrupt our ability to serve customers.

Events such as these could entail substantial repair costs, litigation, fines and penalties, and damage to reputation, each of which could have an adverse effect on the Company’s and Consolidated SCE&G's revenues, results of operations, cash flows, and financial condition. Insurance may not be available or adequate to mitigate the adverse impacts of these events.

SCANA’s ability to pay dividends and to make payments on SCANA’s debt securities may be limited by covenants in certain financial instruments and by the financial results and condition of its subsidiaries, thereby adversely impacting the valuation of our common stock and our access to capital.

We are a holding company that conducts substantially all of our operations through our subsidiaries. Our assets consist primarily of investments in subsidiaries. Therefore, our ability to meet our obligations for payment of interest and principal on outstanding debt and to pay dividends to shareholders and corporate expenses depends on the earnings, cash flows, financial condition and capital requirements of our subsidiaries, and the ability of our subsidiaries, principally Consolidated SCE&G, PSNC Energy and SCANA Energy, to pay dividends or to repay funds to us. Our ability to pay dividends on our common stock may also be limited by existing or future covenants limiting the right of our subsidiaries to pay dividends on their common stock. Further, SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending. Any significant reduction in our payment of dividends in the future may result in a decline in the value of our common stock. Such a decline in value could limit our ability to raise debt and equity capital.


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The use of derivative instruments could result in financial losses and liquidity constraints. The Company and Consolidated SCE&G do not fully hedge against financial market risks or price changes in commodities. This could result in increased costs, thereby resulting in lower margins and adversely affecting results of operations, cash flows and financial condition.

The Company and Consolidated SCE&G use derivative instruments, including futures, forwards, options and swaps, to manage our financial market risks. The Company also uses such derivative instruments to manage certain commodity (i.e., natural gas) market risk. We could be required to provide cash collateral or recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities and financial contracts or if a counterparty fails to perform under a contract. We could also be required to provide additional cash collateral if credit rating agency downgrades of our debt trigger more stringent requirements.

The Company strives to manage commodity price exposure by establishing risk limits and utilizing various financial instruments (exchange traded and over-the-counter instruments) to hedge physical obligations and reduce price volatility. We do not hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility or our hedges are not effective, results of operations, cash flows and financial condition may be adversely impacted.

Failure to retain and attract key personnel could adversely affect the Company’s and Consolidated SCE&G’s operations and financial performance, particularly in light of uncertainties related to and resulting from abandonment of the Nuclear Project and the pending merger.

A significant portion of our workforce will be eligible for retirement during the next few years. Uncertainties related to regulatory, legislative and legal proceedings, as well as the proposed merger, also weigh significantly on the employment considerations made by current and prospective employees. We must attract, retain and develop executive officers and other professional, technical and craft employees with the skills and experience necessary to successfully manage, operate and grow our businesses. Competition for these employees is high, and in some cases we must compete for these employees on a regional or national basis. We may be unable to attract and retain these personnel. Further, the Company’s or Consolidated SCE&G’s ability to construct or maintain generation or other assets requires the availability of suitable skilled contractor personnel. We may be unable to obtain appropriate contractor personnel at the times and places needed. Labor disputes with employees or contractors covered by collective bargaining agreements also could adversely affect implementation of our strategic plan and our operational and financial performance. Furthermore, increased medical benefit costs of employees and retirees could adversely affect the results of operations of the Company and Consolidated SCE&G. Medical costs in this country have risen significantly over the past number of years and are expected to continue to increase at unpredictable rates. Such increases, unless satisfactorily managed by the Company and Consolidated SCE&G, could adversely affect results of operations.

The Company and Consolidated SCE&G are subject to the risk that strategic decisions made by us either do not result in a return of or on invested capital or might negatively impact our competitive position, which can adversely impact our results of operations, cash flows, financial condition, and access to capital .

From time to time, the Company and Consolidated SCE&G make strategic decisions that may impact our direction with regard to business opportunities, the services and technologies offered to customers or that are used to serve customers, and the generating plants and other infrastructure that form the basis of much of our business. These strategic decisions may not result in a return of or on our invested capital, and the effects of these strategic decisions may have long-term implications that are not likely to be known to us in the short-term. Changing political climates and public attitudes, including customers' concerns regarding rate increases, such as the current environment relating to proposed recovery of costs, and a reasonable return on those costs, under the abandonment provisions of the BLRA or through other means, may adversely affect the ongoing acceptability of strategic decisions that have been made (and, in some cases, previously supported by legislation or approved by regulators), to the detriment of the Company or Consolidated SCE&G (e.g., revision or repeal of the BLRA). In addition, operating covenants in the Merger Agreement require the consent of Dominion Energy prior to SCANA taking certain actions, which consent cannot be unreasonably withheld, during the pendency of the merger. As a result, the Company and Consolidated SCE&G may be unable to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing or other specified transactions or pursue actions that are not in the ordinary course of business even if such actions would prove beneficial. Further, the Company's and Consolidated SCE&G's management may be focused on completion of the merger, which could lead to the disruption of ongoing business or inconsistencies in service, standards, controls, procedures and policies, any of which could adversely affect the ability of the Company and Consolidated SCE&G to maintain relationships with customers, regulators, vendors and employees, or could otherwise adversely affect their business and financial results, without realizing any of the benefits of having the merger completed. Over time, these strategic decisions or changing attitudes toward such decisions, which could be adverse to the Company’s or Consolidated SCE&G’s interests,

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may have a negative effect on our results of operations, cash flows and financial condition, as well as limit our ability to access capital.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS
 
Not Applicable

ITEM 2. PROPERTIES
 
SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds directly all of the capital stock of each of its subsidiaries.
SCE&G's bond indenture, which secures its First Mortgage Bonds, constitutes a direct mortgage lien on substantially all of its electric utility property. GENCO's Williams Station is also subject to a first mortgage lien which secures certain outstanding debt of GENCO.
Electric Properties

The following table shows the electric generating facilities and their net generating capacity as of December 31, 2017.
 
 
Net Generating Capacity
 
In-Service
Summer
 
Date
(MW)
Coal-Fired Steam:
 
 
  Wateree - Eastover, SC
1970
684

  Williams - Goose Creek, SC
1973
605

  Cope - Cope, SC
1996
415

  Kapstone - Charleston, SC
1999
85

 
 
 
Gas-Fired Steam:
 
 
  McMeekin - Irmo, SC
1958
250

  Urquhart Unit 3 - Beech Island, SC
1953
95

 
 
 
Nuclear:
 
 
  Summer Station Unit 1 - Parr, SC (reflects SCE&G's 66.7% ownership share)
1984
647

 
 
 
Internal Combustion Turbines:
 
 
  Jasper Combined Cycle - Jasper, SC
2004
852

  Urquhart Combined Cycle - Beech Island, SC
2002
458

  Peaking units - various locations in SC
1968-2010
348

 
 
 
Hydro:
 
 
  Fairfield Pumped Storage - Parr, SC
1978
576

  Saluda - Irmo, SC
1930
200

  Other - various locations in or bordering SC
1905-1914
18


SCE&G owns 436 substations having an aggregate transformer capacity of 32.1 million Kilovolt ampere. The transmission system consists of 3,469 miles of lines, and the distribution system consists of 18,559 pole miles of overhead lines and 7,622 trench miles of underground lines.
 
Natural Gas Distribution and Transmission Properties
 
SCE&G's natural gas system includes 447 miles of transmission pipeline of up to 20 inches in diameter that connect its distribution system with Southern Natural, Transco and DECG. SCE&G’s distribution system consists of 17,671 miles of distribution mains and related service facilities. SCE&G also owns two LNG plants, one located near Charleston, South Carolina, and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6,180 MMBTU per day and store the liquefied equivalent of 1,009,400 MMBTU of natural gas. The Salley facility can store the liquefied equivalent of 927,000 MMBTU of natural gas and has no liquefying capabilities. The LNG facilities have the capacity to regasify approximately 61,800 MMBTU per day at Charleston and 92,700 MMBTU per day at Salley.
 
PSNC Energy’s natural gas system consists of 607 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy’s distribution system consists of 22,141 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000,000 MMBTU, the capacity to liquefy up to 4,000 MMBTU per day and the capacity to regasify approximately 100,000 MMBTU per day.

ITEM 3.  LEGAL PROCEEDINGS
 
SCANA and SCE&G:

The following describes certain legal proceedings through December 31, 2017. The Company and Consolidated SCE&G intend to vigorously contest the lawsuits which have been filed against them. For developments related to these or other proceedings subsequent to December 31, 2017, see Note 2 and Note 10 to the consolidated financial statements. 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 or that such proceeding, items or matter is required to be referred to or disclosed in this Form 10-K.

Ratepayer Class Actions

On August 11, 2017, a purported class action was filed against SCE&G by plaintiff LeBrian Cleckley (the “Cleckley Lawsuit”), on behalf of himself and all others similarly situated, in the State Court of Common Pleas in Richland County, South Carolina (the “Richland County Court”). The plaintiff alleges, among other things, that SCE&G was negligent and unjustly enriched and breached alleged fiduciary and contractual duties by failing to properly manage the Nuclear project. The plaintiff seeks to recover, on behalf of the purported class, unspecified damages and attorneys’ fees, specific performance of the alleged implied contract to construct the now abandoned project, and any other relief the court deems proper. At December 31, 2017, SCE&G’s amended motion to dismiss was scheduled to be heard on January 8, 2018. Also at December 31, 2017, the following additional motions were pending: SCE&G’s Motion for Protective Order, filed October 2, 2017; Plaintiff’s Motion to Compel Discovery, filed October 20, 2017; and Plaintiff’s Motion to Appoint a Receiver, filed November 1, 2017. By order dated October 31, 2017, the South Carolina Supreme Court consolidated all pending state court ratepayer class actions and assigned the consolidated cases to a single Circuit Court judge.
On August 14, 2017, a purported class action was filed against SCE&G by plaintiff Richard Lightsey (the "Lightsey Lawsuit"), on behalf of himself and all others similarly situated, in the State Court of Common Pleas in Hampton County (the "Hampton County Court"). The plaintiff makes substantially similar allegations as those alleged in the Cleckley Lawsuit and, in addition, alleges that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiff seeks a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the Nuclear Project. The plaintiff also seeks compensatory, punitive and statutory treble damages, attorneys’ fees, and any other relief the court deems proper. On August 25, 2017, SCE&G filed a motion to transfer venue to Lexington County, South Carolina. At December 31, 2017, the following motions were pending: Plaintiff’s Motion for Class Certification, filed August 23, 2017; SCE&G’s Motion to Dismiss, etc., filed September 14, 2017; SCE&G’s Motion for Protective Order, filed September 26, 2017; Plaintiff’s Motion to Compel, filed October 12, 2017; and SCE&G’s Motion to Dismiss, etc., Second Amended Complaint, filed October 24, 2017.

On August 28, 2017, a purported class action was filed against SCANA and SCE&G by plaintiff Edwinda Goodman, on behalf of herself and all others similarly situated, in the State Court of Common Pleas in Fairfield County (the “Fairfield County Court”). The plaintiff makes substantially similar allegations as those alleged in the Cleckley Lawsuit and, in addition, alleges that SCE&G committed fraud and misrepresentation in failing to properly manage the Nuclear Project. The plaintiff seeks to have the defendants’ assets frozen and all monies recovered from Toshiba and other sources be placed in a constructive trust for the benefit of ratepayers. The plaintiff also seeks compensatory, punitive and treble damages, attorneys’ fees, and any other relief the court deems proper. At December 31, 2017, the following motions were pending: SCE&G’s Motion to Dismiss and Strike, filed October 2, 2017; SCE&G’s Motion for Protective Order, filed October 2, 2017; and Plaintiff’s Motion to Appoint Receiver and Expedite Hearing, served November 2, 2017.


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On September 7, 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. by plaintiff Jessica Cook, on behalf of herself and all others similarly situated, in the Hampton County Court. The plaintiff makes substantially similar allegations as the Cleckley Lawsuit and the Lightsey Lawsuit. The plaintiff seeks a declaratory judgment that defendants may not charge the purported class for reimbursement for past or future costs of the Nuclear Project, as well as other compensatory and statutory treble damages, attorneys’ fees, and any other relief the court deems proper. At December 31, 2017, the following motions were pending: SCE&G’s Motion to Dismiss and to Strike, filed October 11, 2017; SCE&G’s Motion for Protective Order, filed October 11, 2017; Santee Cooper’s Motion to Dismiss Third Amended Complaint, filed October 24, 2017; Plaintiff’s Motion for Default Judgment against Central Electric Power Cooperative, filed November 1, 2017; and Central Electric Power Cooperative, Inc.’s Motion to Dismiss Third Amended Complaint, filed November 16, 2017.

Also on September 7, 2017, a purported class action was filed against Santee Cooper and SCANA by plaintiffs Hope Brown and Thomas Lott, on behalf of themselves and all others similarly situated, in the Richland County Court. The plaintiffs allege, among other things, that SCE&G conspired with Santee Cooper to unlawfully deprive plaintiffs of their property rights guaranteed under the United States and South Carolina Constitutions and were unjustly enriched by the Nuclear Project. The plaintiffs seek disgorgement of all monies spent by defendants on the project, as well as other compensatory and punitive damages, attorneys’ fees, and any other relief the court deems proper. Plaintiffs’ counsel voluntarily dismissed this action without prejudice on November 12, 2017.

On September 25, 2017, a purported class action was filed against SCANA by plaintiff Christine Delmater, on behalf of herself and all others similarly situated, in the District Court. The plaintiff alleges, among other things, that SCE&G violated provisions of the Racketeer Influenced and Corrupt Organizations Act 18 U.S.C. §1961, was negligent, breached alleged contractual duties, and was unjustly enriched by failing to properly manage the Nuclear Project. The plaintiff seeks compensatory and consequential damages, and any other relief the court deems proper. Plaintiff filed its Second Amended Complaint on November 7, 2017, and filed a Motion for Injunctive Relief on November 8, 2017. Following extensions, responsive pleadings to the Second Amended Complaint and the Motion for Injunctive Relief were filed December 21, 2017.

On October 9, 2017, plaintiffs Chris Kolbe and Ruth Ann Keffer filed an amended complaint in a purported class action, on behalf of themselves and all others similarly situated, against Santee Cooper and certain of its directors and officers, in the Berkeley County Court of Common Pleas, naming SCE&G and SCANA as additional defendants. The plaintiffs allege, among other things, that SCE&G and SCANA were grossly negligent, reckless, breached contracts, were unjustly enriched, and violated principles of equity in connection with their management of the Nuclear Project. The plaintiffs seek compensatory damages and attorneys’ fees, and a declaratory judgment as to Santee Cooper’s rates. SCANA and SCE&G filed a Motion to Dismiss and to Strike on November 17, 2017.

Shareholder Derivative and 10b-5 Class Actions

On September 26, 2017, a purported shareholder derivative action was filed against defendants Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynne Miller, James Roquemore, Maceo Sloan, Alfredo Trujillo, Jimmy Addison, Stephen Byrne, and nominal defendant SCANA by plaintiff John Crangle, purportedly on behalf of SCANA, in the Richland County Court (the "Crangle Lawsuit"). The plaintiff alleges, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, and that the defendants Marsh, Addison, and Byrne were unjustly enriched by bonuses they were paid in connection with the project. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper. Defendants filed motions to dismiss the complaint in December 2017.

On September 27, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, Jimmy E. Addison, and Stephen A. Byrne by plaintiff Robert L. Norman, on behalf of himself and all others similarly situated, in the District Court. The plaintiff alleges, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individual named defendants are liable under §20(a) of the Exchange Act. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper.

On October 5, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, and Jimmy E. Addison by plaintiff Kenneth Evans on behalf of himself and all others similarly situated in the District Court. The plaintiff alleges, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individual named defendants violated §20(a) of the Exchange Act. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper.


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On October 30, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynn Miller, James Roquemore, Maceo Sloan, Aldredo Trujillo, Jimmy Addison, Stephen Byrne, and SCANA by plaintiff R. Wayne Todd, purportedly on behalf of SCANA in Richland County Court (the “Todd Lawsuit”). The plaintiff makes substantially similar allegations as those alleged in the Crangle Lawsuit, and alleges that the defendants Marsh, Addison, and Byrne were unjustly enriched by bonuses they were paid in connection with the Nuclear Project. The plaintiff seeks compensatory and consequential damages, punitive damages, attorneys’ fees, and any other relief the court deems proper. Defendants filed motions to dismiss the complaint in December 2017.

On November 10, 2017, a purported class action was filed against SCANA, Kevin Marsh, Jimmy Addison, and Steve Byrne by plaintiff Marsha Fox on behalf of herself and all others similarly situated in the District Court. The plaintiff alleges, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individual named defendants violated §20(a) of the Exchange Act. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper.

On November 17, 2017, a purported class action was filed against SCANA, Kevin B. Marsh, Jimmy E. Addison, and Steve B. Byrne by plaintiff West Palm Beach Firefighters’ Pension Fund on behalf of itself and all others similarly situated in the District Court. The plaintiff alleges, among other things, that the defendants violated §10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and that the individual named defendants violated §20(a) of the Exchange Act. The plaintiff seeks compensatory and consequential damages, attorneys’ fees, and any other relief the court deems proper.

On November 21, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynn Miller, James Roquemore, Maceo Sloan, Aldredo Trujillo, Jimmy Addison, Stephen Byrne, and SCANA by plaintiff Colleen Witmer, purportedly on behalf of SCANA in the District Court. The plaintiff alleges, 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 the company, and that the individual defendants were unjustly enriched in their compensation. The plaintiff seeks compensatory and consequential damages, disgorgement of compensation, punitive damages, attorneys’ fees, and any other relief the court deems proper.

On November 22, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Gregory Aliff, James Bennett, John Cecil, Sharon Decker, Maybank Hagood, Lynn Miller, James Roquemore, Maceo Sloan, Aldredo Trujillo, and SCANA by plaintiff Richard Wickstrom, purportedly on behalf of SCANA in the District Court. The plaintiff alleges, among other things, that the defendants violated their fiduciary duties to shareholders by affirmatively making and allowing material misstatements to be made to shareholders regarding the Nuclear Project. The plaintiff seeks compensatory and consequential damages, disgorgement of Marsh’s compensation, attorneys’ fees, and any other relief the court deems proper.

On December 5, 2017, a purported shareholder derivative action was filed against Kevin B. Marsh, Stephen A. Byrne, Jimmy Addison, Gregory E. Aliff, James A. Bennett, John F.A.V. Cecil, Sharon A. Decker, D. Maybank Hagood, Lynne M. Miller, James W. Roquemore, Maceo K. Sloan, Aldredo Trujillo, James M. Micali, Harold C. Stowe, and nominal defendant SCANA by plaintiff City of Hollywood Employees Retirement Fund in the District Court. The plaintiff alleges, among other things, that the defendants violated their fiduciary duties to shareholders by their gross mismanagement of the Nuclear Project, committed corporate waste, were unjustly enriched, and that the director defendants violated Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued in 2016 and 2017. Plaintiff seeks equitable and injunctive relief related to corporate governance functions, as well as compensatory and consequential damages, disgorgement of compensation, attorneys’ fees, and any other relief the court deems proper.

On December 13, 2017, a purported shareholder derivative action was filed against Kevin Marsh, Jimmy Addison, Stephen Byrne, Maybank Hagood, Lynne Miller, James Bennett, Maceo Sloan, Sharon Decker, James Roquemore, Alfredo Trujillo, John F.A.V. Cecil, Gregory Aliff, James Micali, Harold Stowe, and nominal defendant SCANA by plaintiff Firemen's Retirement System of St. Louis, purportedly on behalf of SCANA, in the Richland County Court. The plaintiff makes substantially similar allegations as those alleged in the Crangle and Todd Lawsuits. The plaintiff seeks compensatory and consequential damages, injunctive relief, restitution, attorneys’ fees, and any other relief the court deems proper.

Contractor Lien Litigation

On April 27, 2017, SCE&G filed a declaratory judgment lawsuit in the Fairfield County Court against Structural Preservation Systems, Inc., a subcontractor to WECTEC and several dozen other companies that were WECTEC subcontractors, or who otherwise provided such labor and materials for other companies for the use and benefit of WECTEC (collectively, the “WECTEC Subcontractors”), who claimed that WECTEC had not paid them for work on the Nuclear Project.

28



The lawsuit was filed for the purpose of asserting SCE&G’s common defenses to such claims by the WECTEC Subcontractors that WECTEC owed them payment for labor or materials they supplied on the project. Since that time, more than 40 individual cases have been filed by WECTEC Subcontractors against SCE&G and Santee Cooper asserting statutory and common law claims against both entities for alleged non-payment by WECTEC. On September 29, 2017, SCE&G obtained a court order consolidating all current and future lawsuits among SCE&G, Santee Cooper, and the WECTEC Subcontractors arising out of allegations of non-payment of the WECTEC Subcontractors by WEC. SCE&G also obtained a court order that designated all such lawsuits as complex and assigning them to one judge. Finally, SCE&G obtained a third court order that stayed any party's otherwise required response to any lawsuit, claim, cross-claim, counterclaim, or third party claim in these lawsuits until the parties could work on case management issues and present a plan for case management to the judge assigned the cases. The lawsuits are in the pleadings stage. The WECTEC Subcontractors have made claims including but not limited to foreclosure of mechanics liens, common law theories including but not limited to negligence and breach of contract, equitable theories including the imposition of a constructive trust on the Toshiba settlement proceeds, damages, and injunctive relief.

FILOT Litigation

On November 29, 2017, Fairfield County filed a Complaint and a Motion for Temporary Injunction against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees. Plaintiff sought a hearing within ten days on their motion for temporary injunction. The Court heard arguments on December 15, 2017 on the motion for temporary injunction, and asked the parties to submit supplemental briefing and proposed orders by December 20, 2017. Plaintiff voluntarily withdrew the Motion for Temporary Injunction on December 20, 2017. The Court set a hearing for February 8, 2018 on SCE&G’s Motion to Transfer Venue.

Regulatory Proceedings and Investigations

On June 22, 2017, the Friends of the Earth and the Sierra Club filed a complaint against SCE&G with the SCPSC, requesting that the SCPSC initiate a formal proceeding to direct SCE&G to immediately cease and desist from expending any further capital costs related to the construction of Unit 2 and Unit 3; to determine the prudence of acts and omissions by SCE&G in connection with the construction of Unit 2 and Unit 3; to review and determine the prudence of abandonment of the Nuclear Project and of the available least cost efficiency and renewable energy alternatives; and to remedy, abate and make due reparations for the rates charged to ratepayers related to the construction of Unit 2 and Unit 3. SCE&G filed its answer to the complaint on July 19, 2017. SCE&G has filed a motion to dismiss the plaintiff's complaint, which motion was argued at a hearing held on December 13, 2017. On December 20, 2017, the SCPSC, among other things, denied SCE&G's motion to dismiss and ordered that the matter be consolidated with proceedings related to the Request, described below.

On September 26, 2017, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon an opinion of the South Carolina Office of Attorney General issued on the same date, to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections.

On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed with the SCPSC a motion to amend its request, in which the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. A hearing on the parties' motions was held on December 12, 2017, and included the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, a large industrial customer, and several environmental groups. In addition, on November 20, 2017, the ORS filed a letter with the SCPSC providing ORS's preliminary list for stabilization and protection of the site containing Unit 2 and Unit 3 and suggesting that the SCPSC have SCE&G respond to ORS's November 20, 2017 letter and "explain why there is no violation of S.C. Code Ann. § 58-27-1300." The SCPSC granted ORS's request, and SCE&G filed its response with the SCPSC on December 27, 2017.

29




By order dated December 20, 2017, the SCPSC denied SCE&G’s Motion to Dismiss the Request and ordered that a hearing be set on the Request. In addition, the SCPSC ordered ORS to perform a thorough inspection and audit, within 30 days, to determine the reasonableness of SCE&G’s retail electric rates and to determine the reasonableness of SCE&G’s statements regarding the potential effect that the removal of approximately $445 million in annual revenues, as requested by the ORS, could have on SCE&G. The SCPSC also granted ORS’s motion to amend the Request and consider the monetization of the Toshiba payout along with any other related factors that may be appropriate in determining a fair and reasonable rate. Lastly, the order consolidated the Friends of the Earth and Sierra Club petition with the Request.

The Company has also been served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. In addition, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee have requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. The Company and Consolidated SCE&G intend to fully cooperate with any such investigations.

On November 30, 2017, the SCPSC served upon SCE&G a document styled as “South Carolinians Against Monetary Abuse (SCAMA) and Leslie Minerd v. South Carolina Electric & Gas Company” requesting that SCE&G include a line item on customers’ monthly bill identifying the charges incurred as a result of the BLRA. On December 29, 2017, SCE&G filed its Answer and Motion to Dismiss and requested that the testimony deadlines and hearing date be held in abeyance pending a determination on SCE&G’s Motion to Dismiss.

Bankruptcy Court Litigation

On March 29, 2017, WEC and WECTEC and certain of their affiliates filed petitions for protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court. 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. The Proofs of Claim are based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC any and all claims that are based thereon or that may be related thereto. On September 27, 2017, SCE&G sold substantially all of its interest in the Toshiba Settlement and assigned all of its claims under the WEC bankruptcy process to Citibank. SCE&G has agreed to use commercially reasonable efforts to cooperate with Citibank and provide reasonable support necessary for its enforcement of those claims. 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.

Employment Class Action

On August 8, 2017, a purported class action was filed against SCANA, SCE&G, and its co-defendants Fluor and Fluor Enterprises, Inc., by plaintiffs Harry Pennington III and Timothy Lorenz, on behalf of themselves and all others similarly situated, in the District Court. The plaintiffs allege, among other things, that the defendants violated the Worker Adjustment and Retraining Notification Act (“WARN Act”) in connection with the decision to stop construction on the Nuclear Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment.

ITEM 4.  MINE SAFETY DISCLOSURES
 
Not Applicable


30


EXECUTIVE OFFICERS OF SCANA CORPORATION

Executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless (1) a resignation is submitted, (2) the Board of Directors shall otherwise determine or (3) as provided in the By-laws of SCANA. Positions held are for SCANA and all wholly-owned subsidiaries unless otherwise indicated.
Name 
Age
Positions Held During Past Five Years
Dates
Jimmy E. Addison
57
Chief Executive Officer and President-SCANA
President and Chief Operating Officer-SCANA Energy
Executive Vice President-SCANA and Chief Financial Officer
2018-present
2014-2018 *-2017
Jeffrey B. Archie
60
Senior Vice President and Chief Nuclear Officer-SCE&G
Senior Vice President-SCANA
*-present
*-present
Sarena D. Burch
60
Senior Vice President-Risk Management and Corporate Compliance Senior Vice President-Fuel Procurement and Asset Management-SCANA, SCE&G and PSNC Energy
2016-present

*-2015
Iris N. Griffin
41
Senior Vice President, Chief Financial Officer and Treasurer
Vice President - Finance and Treasurer
Associate Treasurer
Director - Audit Services, Privacy and Corporate Compliance Officer
Manager - Investor Relations
2018-present
2016-2017
2015-2016
2013-2015
*-2013
D. Russell Harris
53
President-Gas Operations-SCE&G
President and Chief Operating Officer-PSNC Energy
President and Chief Operating Officer-SCANA Energy
Senior Vice President-SCANA
2013-present
*-present
2018-present 2013-present
Kenneth R. Jackson
61
Senior Vice President-Economic Development, Governmental and Regulatory Affairs
Vice President-Rates and Regulatory Services
2014-present
*-2014
W. Keller Kissam
51
President-Generation, Transmission and Distribution and Chief Operating Officer-SCE&G
President-Retail Operations-SCE&G
Senior Vice President-SCANA
2018-present
*-2017
*-present
Randal M. Senn
61
Senior Vice President-Administration-SCANA
Vice President and Chief Information Officer
Chief Information Officer
2016-present
2016
*-2016
Jim Odell Stuckey
49
Senior Vice President, General Counsel and Assistant Secretary
Director - Legal Department and Deputy General Counsel
Director - Legal Department and Associate General Counsel
2017-present 2014-2017 *-2014

*Indicates positions held at least since February 23, 2013.


31


PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
 
SCANA :
 
Price Range (NYSE Composite Listing): 
 
2017
 
2016
 
4th Qtr.
 
3rd Qtr.
 
2nd Qtr.
 
1st Qtr.
 
4th Qtr.
 
3rd Qtr.
 
2nd Qtr.
 
1st Qtr.
High
$
50.22

 
$
68.35

 
$
71.28

 
$
72.75

 
$
74.94

 
$
76.41

 
$
75.67

 
$
70.35

Low
$
37.10

 
$
48.32

 
$
63.90

 
$
63.63

 
$
67.31

 
$
69.04

 
$
66.02

 
$
59.46

 
SCANA common stock trades on the NYSE using the ticker symbol SCG. At February 20, 2018 there were approximately 143 million shares of SCANA common stock outstanding which were held by approximately 23,100 shareholders of record. See Item 12 for a summary of equity securities issuable under SCANA’s compensation plans at December 31, 2017.
 
SCANA declared quarterly dividends on its common stock of $0.6125 per share in 2017 and $0.575 per share in 2016. On February 22, 2018, SCANA declared a quarterly cash dividend on SCANA common stock of $0.6125 per share, which quarterly dividend is payable April 1, 2018 to shareholders of record on March 12, 2018. For a discussion of provisions that could limit the payment of cash dividends, see Financing Limits and Related Matters in the Liquidity and Capital Resources section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 3 to the consolidated financial statements.
 
The following table provides information about purchases by or on behalf of SCANA or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended (Exchange Act)) of shares or other units of any class of SCANA's equity securities that are registered pursuant to Section 12 of the Exchange Act:
Issuer Purchases of Equity Securities
 
 
(a)
 
(b)
 
(c)
 
(d)
Period
 
Total number of shares (or units) purchased
 
Average price paid
per share (or unit)
 
Total number of shares (or units) purchased as
part of publicly announced
plans or programs
 
Maximum number (or approximate dollar value) of shares (or units) that may yet be
purchased under the
plans or programs
October 1-31, 2017
 
7,964

 
$
49.01

 
7,964

 
 
November 1-30, 2017
 

 

 

 
 
December 1-31, 2017
 

 

 

 
 
Total
 
7,964

 
 
 
7,964

 
*

*The above table represents shares acquired for non-employee directors under the Director Compensation and Deferral Plan. On December 16, 2014, SCANA announced a program to convert from original issue to open market purchase of SCANA common stock for all applicable compensation and dividend reinvestment plans. This program took effect in the first quarter of 2015 and has no stated maximum number of shares that may be purchased and no stated expiration date.

SCE&G:
 
All of SCE&G’s common stock is owned by SCANA, and no established public trading market exists for SCE&G common stock. During 2017 and 2016, SCE&G declared quarterly dividends on its common stock in the following amounts:
 
Declaration Date
 
Amount
 
Declaration Date
 
Amount
February 16, 2017
 
$
76.9
 million
 
February 18, 2016
 
$
72.2
 million
April 27, 2017
 
78.1
 million
 
April 28, 2016
 
73.3
 million
August 3, 2017
 
78.5
 million
 
July 28, 2016
 
74.0
 million
October 26, 2017
 
80.6
 million
 
October 27, 2016
 
77.5
 million
 

32



On February 22, 2018, SCE&G declared a quarterly dividend on its common stock of $71.9 million.
 
For a discussion of provisions that could limit the payment of cash dividends, see Financing Limits and Related Matters in the Liquidity and Capital Resources section of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 3 to the consolidated financial statements.


ITEM 6.  SELECTED FINANCIAL DATA
As of or for the Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(Millions of dollars, except statistics and per share amounts)
SCANA:
 
 
 
 
 
 
 
 

 
 

Statement of Operations Data
 
 
 
 
 
 
 
 

 
 

Operating Revenues
 
$
4,407

 
$
4,227

 
$
4,380

 
$
4,951

 
$
4,495

Operating Income
 
$
87

 
$
1,153

 
$
1,308

 
$
1,007

 
$
910

Net Income (Loss)
 
$
(119
)
 
$
595

 
$
746

 
$
538

 
$
471

Common Stock Data
 
 
 
 
 
 
 
 
 
 
Weighted Avg Common Shares Outstanding (Millions)
 
142.6

 
142.6

 
142.6

 
142.6

 
138.4

Basic Earnings (Loss) Per Share
 
$
(0.83
)
 
$
4.16

 
$
5.22

 
$
3.79

 
$
3.40

Diluted Earnings (Loss) Per Share
 
$
(0.83
)
 
$
4.16

 
$
5.22

 
$
3.79

 
$
3.39

Dividends Declared Per Share of Common Stock
 
$
2.45

 
$
2.30

 
$
2.18

 
$
2.10

 
$
2.03

Balance Sheet Data
 
 
 
 
 
 
 
 
 
 
Utility Plant, Net
 
$
10,648

 
$
14,324

 
$
13,145

 
$
12,232

 
$
11,643

Total Assets
 
$
18,739

 
$
18,707

 
$
17,146

 
$
16,818

 
$
15,127

Total Equity
 
$
5,255

 
$
5,725

 
$
5,443

 
$
4,987

 
$
4,664

Short-term and Long-term Debt
 
$
6,983

 
$
7,431

 
$
6,529

 
$
6,581

 
$
5,788

Other Statistics
 
 
 
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
 
 
Customers (Year-End)
 
718,822

 
709,418

 
698,372

 
687,800

 
678,273

Total sales (Million kWh)
 
22,866

 
23,458

 
23,102

 
23,319

 
22,313

Generating capability-Net MW (Year-End)
 
5,233

 
5,233

 
5,234

 
5,237

 
5,237

Territorial peak demand-Net MW
 
4,701

 
4,807

 
4,970

 
4,853

 
4,574

Regulated Gas:
 
 
 
 
 
 
 
 
 
 
Customers, excluding transportation (Year-End)
 
930,790

 
906,883

 
881,295

 
859,186

 
837,232

Sales, excluding transportation (Thousand Therms)
 
857,886

 
890,113

 
875,218

 
973,907

 
921,533

Transportation customers (Year-End)
 
616

 
632

 
627

 
656

 
667

Transportation volumes (Thousand Therms)
 
700,254

 
674,999

 
791,402

 
1,786,897

 
1,729,399


The comparability of Selected Financial Data is affected by the following:

In 2017, as a result of the decision to stop construction on Unit 2 and Unit 3, approximately $4.7 billion (prior to an estimated impairment loss) was reclassified from construction work in progress within Utility Plant, Net into regulatory assets. In addition, a pre-tax impairment loss of $1.1 billion was recorded. See Note 10 to the consolidated financial statements. Finally, deferred income tax assets and liabilities were remeasured in connection with the enactment of the Tax Act, resulting in an increase in Net Loss of approximately $30 million.

In 2015, a regulated gas operating subsidiary and a non-operating subsidiary were sold, resulting in pre-tax gains totaling approximately $342 million. See Note 1 to the consolidated financial statements.




33



ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pursuant to General Instruction I of Form 10-K, SCE&G is permitted to omit certain information related to itself and its consolidated affiliates called for by Item 7 of Form 10-K, and instead provide a management’s narrative explanation of its consolidated results of operation and other information described therein. Such information is presented hereunder specifically for Consolidated SCE&G, but may be presented alongside information presented for the Company generally. Consolidated SCE&G makes no representation as to information relating solely to SCANA Corporation and its subsidiaries (other than Consolidated SCE&G).

OVERVIEW
 
SCANA, through its wholly-owned regulated subsidiaries, is primarily engaged in the generation, transmission, distribution and sale of electricity in South Carolina and in the purchase, transmission and sale of natural gas in North Carolina and South Carolina. Through a wholly-owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers in the southeast. A service company subsidiary of SCANA provides primarily administrative and management services to SCANA and its subsidiaries.

Key Earnings Drivers and Outlook
 
The outcome of contentious regulatory, legislative and court proceedings stemming from the Company's July 31, 2017 decision to stop construction of Unit 2 and Unit 3 and to seek recovery of its investment in the abandoned Nuclear Project will significantly affect the Company's future earnings. These proceedings could result in the SCPSC ordering SCE&G to cease collecting BLRA-related rates and to immediately refund such amounts previously collected. Such an outcome would likely result in degraded credit ratings with a corresponding higher cost of capital, if such capital were available at all. In 2017, the Company's principal subsidiary, SCE&G, recorded an aggregate pre-tax impairment loss of $1.118 billion related to the abandoned Nuclear Project. These matters are discussed further in Electric Operations below, in Liquidity and Capital Resources herein and in Note 10 to the consolidated financial statements.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy. Under the terms of that agreement, Dominion Energy would provide the financial support for SCE&G to make a $1.3 billion up-front, one time rate credit to SCE&G's electric customers to be paid within 90 days of the closing of the merger, a $575 million refund along with the benefits of the Tax Act resulting in at least a 5% reduction to SCE&G electric service customers' bills over an eight-year period, and the exclusion from rate recovery of approximately $1.7 billion of costs related to the Nuclear Project. These terms, together with other terms and commitments in the Merger Agreement and the Joint Petition, could resolve many of the outstanding issues related to the Nuclear Project. The Company targets the closing of the merger by the end of 2018. Significant hurdles must be overcome before closing may occur, however, including the receipt of the requisite authorizations, approvals, consents and/or permits from various federal and state regulatory entities and the approval of two-thirds of the shares represented by SCANA's shareholders. Regulatory approvals of the merger may not be obtained on a timely basis or at all, and such approvals may include conditions that could have an adverse effect on the Company and Consolidated SCE&G or result in the abandonment of the merger. No assurance can be provided that the necessary approvals will be obtained or that any required conditions will not have an adverse effect on Consolidated SCE&G following the merger. See additional discussion in Item 1A. Risk Factors and in Note 2 and Note 10 to the consolidated financial statements.

Electric Operations
 
SCE&G's electric operations primarily generate electricity and provide for its transmission, distribution and sale to approximately 719,000 customers (as of December 31, 2017) in portions of South Carolina in an area covering nearly 17,000 square miles. GENCO owns a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns, provides financing for and sells at cost to SCE&G nuclear fuel, certain fossil fuels and emission and other environmental allowances.
 
Operating results are primarily driven by customer demand for electricity, rates allowed to be charged to customers and the ability to control costs. Demand for electricity is primarily affected by weather, customer growth and the economy.  SCE&G is able to recover the cost of fuel used in electric generation through retail customers’ bills, but increases in fuel costs affect electricity prices and, therefore, the competitive position of electricity compared to other energy sources.


34


Embedded in the rates charged to customers is an allowed regulatory ROE. SCE&G’s allowed ROE in 2017 was 10.25% for non-BLRA rate base. For BLRA-related rate base existing prior to 2016, SCE&G's ROE was 11.0%, and for such rate base arising in 2016, the ROE was 10.5%. As described in Note 2 to the consolidated financial statements, the SCPSC revised SCE&G's ROE for Nuclear Project costs to 10.25%, which was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. No revised rates filing was pursued in 2017. Uncertainties that are expected to adversely impact ROE on BLRA-related rate base are discussed in Abandoned Nuclear Project herein and in Note 10 to the consolidated financial statements.

In 2017, the enactment of federal environmental laws and regulations related to the generation of electricity slowed significantly; however, public sentiment surrounding air quality and water quality remains strong and is expected to continue. Over several years, SCE&G has incurred significant costs and made substantial investments to comply with federal environmental initiatives, including the retirement of certain coal-fired plants and the conversion of others to burn natural gas. In addition, SCE&G has added the renewable energy from several new solar generating facilities at locations throughout its electric service territory. In addition, SCE&G and GENCO have installed pollution control equipment at their remaining coal-fired plants, which have resulted in reduced air emissions. The status of significant environmental laws and regulations and certain initiatives undertaken to ensure compliance with them are described in Environmental Matters herein and in Note 10 to the consolidated financial statements.

Abandoned Nuclear Project

Significant events leading up to the Company's decision to abandon the Nuclear Project include the following:

On July 1, 2016, SCE&G, on behalf of itself and as agent for Santee Cooper, elected the fixed price option as provided for in the October 2015 Amendment to the EPC Contract, subject to SCPSC approval. The fixed price option was designed to shift the risk of significant cost overruns from SCE&G and Santee Cooper by fixing the total amount to be paid to the Consortium for its entire scope of work on the project, with limited exceptions.

On November 9, 2016, the SCPSC approved SCE&G's election of the fixed price option.

On March 29, 2017, WEC and WECTEC 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 them to seek protection under the bankruptcy laws. As part of their filing, WEC and WECTEC publicly announced their inability to complete Unit 2 and Unit 3 under the fixed price terms of the EPC Contract.

In connection with the bankruptcy filing, SCE&G, Santee Cooper, WEC and WECTEC entered into an Interim Assessment Agreement under which engineering and construction continued on the project and under which SCE&G and Santee Cooper were provided the right to discuss project status with Fluor and other subcontractors and vendors and to obtain from them relevant project information and documents that had been previously contractually unavailable in order for SCE&G and Santee Cooper to perform comprehensive analyses regarding whether or how to proceed with the project.

On July 31, 2017, based on the results of its analysis and in light of Santee Cooper's decision to suspend construction on the units, the Company determined to stop the construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with their construction under the abandonment provisions of the BLRA or through other regulatory means.

The Company's decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with their construction have been the subject of contentious proceedings before the SCPSC and special committees of the South Carolina legislature. The Governor has likewise asserted, among other things, that the BLRA should be replaced and any further collection of money from customers for the Nuclear Project should be prevented. The SCPSC is actively considering a request that could result in the suspension of rates currently being collected by SCE&G under the BLRA (approximately $445 million annually, which includes collections related to transmission assets expected to be placed into service), that could require the return of such amounts previously collected (approximately $1.9 billion as of December 31, 2017), and that will affect when and in what manner proceeds arising from the Toshiba guaranty (approximately $1.1 billion) will be used for the benefit of SCE&G customers.


35


Proposals to Resolve Outstanding Issues

On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for liquidation of project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In the Joint Petition, among other things, the parties commit to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, at least a 5% reduction in customer bills, shortening the amortization period for recovery of costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and the addition of an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. The petition also puts forth other less-favored alternatives for rate recovery in the event the joint proposal were not to be accepted by the SCPSC and the merger were not to be consummated.

The outcome of these matters is uncertain, and any resolution adverse to the Company and Consolidated SCE&G could adversely affect results of operations, cash flows and financial condition. These matters and others are further discussed in Liquidity and Capital Resources and in Note 2 and Note 10 to the consolidated financial statements.

Gas Distribution
 
The local distribution operations of SCE&G and PSNC Energy purchase, transport and sell natural gas to approximately 931,000 retail customers (as of December 31, 2017) in portions of South Carolina and North Carolina in areas covering approximately 35,000 square miles. Operating results for gas distribution are primarily influenced by customer demand for natural gas, rates allowed to be charged to customers and the ability to control costs. Embedded in the rates charged to customers is an allowed regulatory ROE for SCE&G of 10.25% and for PSNC Energy of 9.7%.
 
Demand for natural gas is primarily affected by weather, customer growth, the economy and the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and will impact the Company’s ability to retain large commercial and industrial customers.

The production of shale gas in the United States continues to keep prices for this commodity at historic lows, and such prices are expected to continue at generally low levels for several years. The supply of natural gas from the Marcellus shale basin has prompted Dominion Energy and other companies unaffiliated with SCANA to propose construction of an approximately 600-mile pipeline that would bring natural gas from West Virginia to Virginia and North Carolina. This pipeline is expected to be completed in late 2019 and, if successful, it may drive economic development along its path, including areas within PSNC Energy's service territory, and may serve to assist in keeping natural gas competitively priced in the region.

Gas Marketing
 
SCANA Energy markets natural gas in the southeast and provides energy-related services to customers, including retail customers in Georgia. Operating results for energy marketing are influenced by customer demand for natural gas and the ability to control costs. The price of alternate fuels and customer growth significantly affect demand for natural gas. In addition, the availability of certain pipeline capacity to serve industrial and other customers is dependent upon the market share held by SCANA Energy in the Georgia retail market. SCANA Energy sells natural gas to over 425,000 customers (as of December 31, 2017) throughout Georgia. This market is mature, resulting in low margins and significant competition from affiliates of large energy companies and electric membership cooperatives, among others. SCANA Energy’s ability to maintain its market share primarily depends on the prices it charges customers relative to the prices charged by its competitors and its ability to provide

36


high levels of customer service. In addition, SCANA Energy's operating results are sensitive to the impacts of weather on customer demand.


RESULTS OF OPERATIONS

Earnings (Loss) and dividends were as follows:
 
2017
 
2016
 
2015
The Company
 
 
 
 
 
Earnings (loss) per share
$
(0.83
)
 
$
4.16

 
$
5.22

Cash dividends declared per share
$
2.45

 
$
2.30

 
$
2.18

 
 
 
 
 
 
Consolidated SCE&G
 
 
 
 
 
Net income (loss) (millions of dollars)
$
(171.9
)
 
$
525.8

 
$
479.5


On February 22, 2018, SCANA declared a quarterly cash dividend on its common stock of $0.6125 per share.

2017 vs 2016
The Company's earnings (loss) per share and Consolidated SCE&G's net income (loss) primarily reflects an operating loss from Electric Operations, which includes an impairment loss associated with the abandonment of the Nuclear Project, partially offset by improved operating income from Gas Distribution. In addition, the Company's earnings (loss) per share reflects a loss resulting from enactment of the Tax Act. These and other results are discussed below.

2016 vs 2015
The Company's earnings per share and Consolidated SCE&G's net income reflects higher operating income from Electric Operations and Gas Distribution. The Company's earnings per share also reflects higher net income from Gas Marketing. These and other results are discussed below.

Matters Impacting Future Results

The Company's decision on July 31, 2017 to stop construction of Unit 2 and Unit 3 and to pursue recovery of the cost of the abandoned Nuclear Project has had and could continue to have significant impacts on the Company's and Consolidated SCE&G's future earnings, cash flows and financial position, including those related to the ultimate recovery of regulatory assets and the sustainability of tax positions. The Company continues to believe the decision to abandon the Nuclear Project was prudent and that costs incurred with respect to the project were prudent, have contested specific challenges to this decision, and believe that the issues related to the recovery of the cost of the abandoned Nuclear Project and related to the rates currently being collected under the BLRA for financing costs should be resolved in future proceedings before the SCPSC. However, based on various events following the abandonment, there is significant uncertainty as to SCE&G's ultimate ability to fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. These events include the contentious nature of ongoing reviews by legislative committees and others, legislative proposals being considered by the General Assembly and promoted by the Governor, and the Request being considered by the SCPSC that could result in the suspension of rates currently being collected under the BLRA, as well as the return of such amounts previously collected.

The Company and Consolidated SCE&G have determined that a disallowance of recovery of part of the cost of the abandoned plant is both probable and reasonably estimable under applicable accounting guidance, and have recorded a pre-tax impairment loss with respect to disallowance of unrecovered nuclear project costs and other related deferred costs totaling approximately $1.118 billion. This amount includes $210 million recorded in the third quarter of 2017 and the remaining $908 million recorded in the fourth quarter of 2017. For additional discussion, see Impairment Considerations in Critical Accounting Policies and Estimates and Note 10 to the consolidated financial statements.

It is reasonably possible that further changes in these estimates will occur in the near term and could be material; however, all such changes cannot be reasonably estimated. The above impairment loss reflects impacts similar to those that would have resulted had the proposed solution announced November 16, 2017 been implemented. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion would be expected to be recorded. If instead the Joint Petition is not approved and the Request by the ORS is approved, if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, the Company and Consolidated SCE&G may be

37


required to record an additional impairment loss and other charges totaling as much as approximately $4.8 billion. This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.976 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $1.9 billion, net of approximately $1.062 billion, which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $1.9 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter.

                In December 2017, the Tax Act was enacted, resulting in the remeasurement of all federal deferred income tax assets and liabilities to reflect a 21% federal statutory corporate 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. As described in Note 2 to the consolidated financial statements, SCE&G and PSNC Energy have responded to orders from state regulators seeking information on the effects the Tax Act would have on their respective operations. The Company and Consolidated SCE&G cannot determine the amount or timing of any refunds to customers that may result. Going forward, the Company and Consolidated SCE&G expect that the lower tax expense resulting from the reduced federal statutory tax rate will result in similar reductions to amounts collected from customers through electric and gas rates, and no significant impact on financial results are expected. See also Note 5 to the consolidated financial statements for additional discussion related to deferred tax assets and deferred tax liabilities.

These matters impacting future results are further discussed under Impact of Abandonment of Nuclear Project within LIQUIDITY AND CAPITAL RESOURCES, in Note 2 and Note 10 to the consolidated financial statements and in Part I, Item 1A. Risk Factors.

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 income (including transactions with affiliates) was as follows: 
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Operating revenues
 
$
2,664.4

 
$
2,619.4

 
$
2,557.1

 
$
2,664.4

 
$
2,619.4

 
$
2,557.1

Fuel used in electric generation
 
593.6

 
576.1

 
660.6

 
593.6

 
576.1

 
660.6

Purchased power
 
80.1

 
63.7

 
52.1

 
80.1

 
63.7

 
52.1

Other operation and maintenance
 
519.0

 
526.1

 
497.1

 
533.4

 
540.2

 
509.6

Impairment loss
 
1,118.1

 

 

 
1,118.1

 

 

Depreciation and amortization
 
294.7

 
286.5

 
277.3

 
282.8

 
274.9

 
266.9

Other taxes
 
220.3

 
210.4

 
194.5

 
217.8

 
207.9

 
192.4

Operating Income (Loss)
 
$
(161.4
)
 
$
956.6

 
$
875.5

 
$
(161.4
)
 
$
956.6

 
$
875.5


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 develop an estimate of electric revenue and fuel costs attributable to the effects of abnormal weather. Results in 2017 reflect milder than normal weather in the first and fourth quarters and warmer than normal weather in the second and third quarters. Results in 2016 reflect significantly warmer than normal weather in the second and third quarters and milder than normal weather in the first and fourth quarters. Results in 2015 reflect colder than normal weather in the first quarter, warmer than normal weather in the second and third quarters and milder than normal weather in the fourth quarter.

2017 vs 2016
Ÿ
Operating revenue increased due to revised rates increases under the BLRA of $57.6 million, residential and commercial growth of $29.4 million, industrial growth and higher usage of $5.5 million, increased revenue recognized under the DER program of $7.3 million and higher fuel cost recovery of $48.1 million. These revenue increases were partially offset by the effects of milder weather of $77.7 million, lower residential and commercial average use of $18.9 million and lower collections under the rate rider for pension costs of $4.0 million. The lower pension rider collections had no impact on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of lower pension costs.

Ÿ
Fuel used in electric generation and purchased power expenses increased due to higher fuel prices of $48.1 million, amortization of DER program costs of $3.9 million and increased sales volumes associated with residential     and

38


commercial customer growth of $5.8 million. These increases were partially offset due to lower sales volumes associated with the effects of milder weather of $15.9 million, lower residential and commercial average use of $4.1 million, lower industrial usage of $1.6 million and lower fuel handling expenses of $2.4 million.

Ÿ
Other operation and maintenance expenses decreased due to lower labor costs of $24.0 million, primarily due to lower incentive compensation costs and lower pension costs associated with the lower pension rider collections, partially offset by nuclear abandonment-related severance costs of $12.3 million. This decrease was offset by higher non-labor electric generation costs of $2.2 million and due to wind down and other costs associated with the abandonment of the Nuclear Project of $10.9 million.

Ÿ
Impairment loss represents the estimate of the probable disallowance of recovery associated with the abandonment of the Unit 2 and Unit 3 of $670 million, a write down to estimated fair value of the carrying value of nuclear fuel acquired for use in Unit 2 and Unit 3 of $87 million and an aggregate amount of $361 million to write off costs which had been previously deferred primarily within regulatory assets in connection with the 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.

2016 vs 2015
Ÿ Operating revenue increased due to revised rates increases under the BLRA of $60.7 million, residential and commercial growth of $29.0 million, industrial growth and higher usage of $9.7 million, increased revenue recognized under the DER program of $5.8 million, the effects of weather of $28.2 million and higher collections under the rate rider for pension costs of $13.5 million. The higher pension rider collections had no impact on net income as they were fully offset by the recognition, within other operation and maintenance expenses, of higher pension costs. Revenue also increased due to downward adjustments in 2015, pursuant to orders from the SCPSC, to apply $14.5 million as an offset to fuel cost recovery upon the adoption of new (lower) electric depreciation rates and by $5.2 million related to DSM Programs. These adjustments had no effect on net income in 2015 as they were fully offset by the recognition of $14.5 million of lower depreciation expense and by the recognition, within other income, of $5.2 million of gains realized upon the settlement of certain interest rate contracts. These revenue increases were partially offset by lower fuel cost recovery of $84.1 million and lower residential and commercial average use of $19.5 million.

Ÿ
Fuel used in electric generation and purchased power expenses decreased due to lower fuel prices of $84.1 million, lower sales volumes associated with residential and commercial average use of $4.2 million and lower fuel handling expenses of $2.3 million. These decreases were partially offset due higher to amortization of DER program costs of $4.6 million, higher industrial usage of $1.9 million, increased sales volumes associated with residential and commercial customer growth of $6.4 million and higher sales volumes associated with the effects of weather of $4.9 million.

Ÿ
Other operation and maintenance expenses increased due to higher labor costs of $25.4 million, primarily due to increased pension costs associated with the higher pension rider collections and higher incentive compensation costs. Other operation and maintenance expenses also increased due to higher amortization of DSM program costs of $2.0 million.

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.
    

39


Sales volumes (in GWh) related to the electric operations above, by class, were as follows: 
Classification
 
2017
 
2016
 
2015
Residential
 
7,782

 
8,140

 
7,978

Commercial
 
7,372

 
7,506

 
7,386

Industrial
 
6,212

 
6,265

 
6,201

Other
 
584

 
600

 
595

Total retail sales
 
21,950

 
22,511

 
22,160

Wholesale
 
916

 
947

 
942

Total Sales
 
22,866

 
23,458

 
23,102


2017 vs 2016
Retail and wholesale sales volumes decreased primarily due to the effects of weather, partially offset by increases associated with customer growth.
    
2016 vs 2015
Retail sales volumes increased primarily due to the effects of weather and customer growth.

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Operating revenues
 
$
876.0

 
$
789.8

 
$
811.7

 
$
405.8

 
$
366.8

 
$
372.7

Gas purchased for resale
 
393.0

 
345.9

 
383.7

 
205.9

 
182.9

 
192.5

Other operation and maintenance
 
168.9

 
172.7

 
161.4

 
70.6

 
73.6

 
69.8

Depreciation and amortization
 
84.9

 
82.0

 
77.5

 
29.0

 
27.3

 
26.8

Other taxes
 
42.5

 
41.5

 
37.5

 
28.5

 
26.8

 
24.9

Operating Income
 
$
186.7

 
$
147.7

 
$
151.6

 
$
71.8

 
$
56.2

 
$
58.7


The effect of abnormal weather conditions on gas distribution margin is mitigated by the WNA at SCE&G and the CUT at PSNC Energy as further described in Revenue Recognition in Note 1 of the consolidated financial statements. The WNA and CUT do not affect sales volumes.

2017 vs 2016
Ÿ
Operating revenue increased at SCE&G primarily due to increased base rates under the RSA of $6.7 million, customer growth of $11.7 million and higher gas cost recovery of $14.9 million. These increases were partially offset by lower average use of $1.6 million. In addition to these factors, operating revenue increased at the Company due to PSNC Energy's higher gas cost collections of $28.9 million, a rate increase of $14.9 million, customer growth of $8.1 million and higher CUT of $17.2 million. These increases at PSNC Energy were partially offset by milder weather and declining consumption of $18.8 million.

Ÿ
Gas purchased for resale at SCE&G increased due to higher gas prices of $15.7 million and increased sales volumes associated with firm customer growth of $7.1 million. In addition to these factors, gas purchased for resale at the Company increased primarily due to PSNC Energy's higher gas costs of $28.9 million and customer growth of $2.2 million that were partially offset by milder weather and declining consumption of $7.3 million.

Ÿ
Other operation and maintenance expenses decreased primarily due to lower labor costs of $4.9 million at SCE&G and $10.9 million at PSNC Energy, due primarily to lower incentive compensation costs. These decreases were partially offset by higher non-labor costs of $1.7 million at SCE&G and $8.6 million at PSNC Energy.

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.


40


2016 vs 2015
Ÿ
Operating revenue decreased at SCE&G primarily due to lower gas cost recovery of $17.6 million and lower firm average use of $6.1 million. These decreases were partially offset by increased base rates under the RSA of $2.6 million and firm customer growth of $13.1 million. In addition to these factors, operating revenue decreased at the Company due to PSNC Energy's lower gas cost collections of $45.4 million. These decreases at PSNC Energy were partially offset by a rate increase of $6.5 million, increased customer growth of $10.3 million and higher CUT of $13.8 million.
 
Ÿ
Gas purchased for resale at SCE&G decreased due to lower gas prices of $17.6 million. These decreases at SCE&G were partially offset by increased sales volumes associated with firm customer growth of $6.5 million. In addition to these factors, gas purchased for resale at the Company decreased due to PSNC Energy's decreased gas cost of $45.4 million and an excess state deferred income tax refund of $1.9 million. This decrease at PSNC Energy was partially offset by customer growth of $3.8 million, as well as higher CUT of $15.5 million.

Ÿ
Other operation and maintenance expenses increased due to higher labor costs of $2.1 million at SCE&G and $6.7 million at the Company, due primarily to higher incentive compensation costs.

Ÿ
Depreciation and amortization increased due to net plant additions, partially offset by the implementation of SCPSC-approved revised (lower) depreciation rates at SCE&G of $1.1 million.

Ÿ
Other taxes increased primarily due to 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)
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Residential
 
37,251

 
40,142

 
39,090

 
11,285

 
12,420

 
12,086

Commercial
 
28,429

 
29,078

 
28,064

 
12,565

 
12,879

 
12,580

Industrial
 
20,108

 
19,364

 
20,101

 
18,091

 
17,228

 
17,901

Transportation gas
 
51,587

 
49,769

 
49,297

 
6,229

 
5,250

 
4,781

Total
 
137,375

 
138,353

 
136,552

 
48,170

 
47,777

 
47,348


2017 vs 2016
Residential and commercial sales volumes decreased due to the effects of weather and lower average use. These decreases were partially offset by customer growth. Industrial sales volumes at SCE&G increased due to fewer curtailments and customer growth. Transportation volumes at SCE&G increased primarily due to firm customers transporting rather than purchasing system supply. Transportation volumes at PSNC Energy increased primarily due to firm service expansion partly offset by a decline in natural gas fired electric generation transportation and milder weather.

2016 vs 2015
Residential and commercial firm sales volumes increased primarily due to customer growth. Commercial and industrial interruptible volumes decreased, and firm volumes increased, due to customers switching from interruptible to firm service at SCE&G. Industrial volumes decreased and transportation volumes increased due to customers switching to transportation only service.
 
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
 
2017
 
2016
 
2015
Operating revenues
 
$
1,001.4

 
$
936.7

 
$
1,146.7

Net Income
 
26.9

 
29.8

 
27.6



41


2017 vs 2016
Operating revenues increased primarily due to higher natural gas prices. Net income decreased primarily due to the impact of the remeasurement of deferred income taxes upon enactment of the Tax Act.

2016 vs 2015
Operating revenues decreased due to the lower market price of natural gas and lower industrial sales volume. Net income increased primarily due to a weather-related increase in demand.

Other Operating Expenses
 
Other operating expenses were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Other operation and maintenance
 
$
736.7

 
$
755.6

 
$
715.3

 
$
604.0

 
$
613.8

 
$
579.4

Impairment loss
 
1,118.1

 

 

 
1,118.1

 

 

Depreciation and amortization
 
381.6

 
370.9

 
357.5

 
311.8

 
302.2

 
293.7

Other taxes
 
264.2

 
253.9

 
234.2

 
246.4

 
234.7

 
217.3


Changes in other operating expenses are largely attributable to the electric operations and gas distribution segments and are addressed in their respective discussions of operating income (loss). In addition, overall increases in other operating expenses in 2016 were partially offset by the Company's sale of CGT in early 2015, which resulted in decreases in other operation and maintenance expenses of $2.2 million, depreciation and amortization of $0.7 million and other taxes of $0.5 million.

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
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Income Statement Impact:
 
 
 
 
 
 
 
 
 
 
 
 
Employee benefit costs
 
$
15.3

 
$
19.2

 
$
5.3

 
$
12.3

 
$
16.4

 
$
2.8

Other expense
 
0.5

 
0.9

 
1.1

 
0.3

 
0.2

 
0.2

Balance Sheet Impact:
 
 
 
 
 
 
 
 
 
 
 
 
Increase in capital expenditures
 
5.2

 
5.3

 
3.9

 
4.7

 
4.7

 
3.4

Component of amount receivable from Summer Station co-owner
 
2.1

 
2.1

 
1.5

 
2.1

 
2.1

 
1.5

Increase (decrease) in regulatory assets
 
(0.8
)
 
(4.6
)
 
6.2

 
(0.8
)
 
(4.6
)
 
6.2

Net periodic benefit cost
 
$
22.3

 
$
22.9

 
$
18.0

 
$
18.6

 
$
18.8

 
$
14.1


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 8 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), net
 
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 the parent company 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: 

42


 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Other income
 
$
78.4

 
$
64.4

 
$
74.5

 
$
44.9

 
$
29.3

 
$
31.1

Other expense
 
(46.2
)
 
(38.5
)
 
(60.1
)
 
(24.9
)
 
(24.1
)
 
(31.1
)
Gain on sale of SCI, net of transaction costs
 

 

 
106.6

 

 

 

AFC - equity funds
 
23.2

 
29.4

 
27.0

 
14.8

 
26.1

 
24.8


2017 vs 2016
Other income at the Company and Consolidated SCE&G increased by $10.9 million due to the accrual of carrying costs on unrecovered nuclear project costs and by $6.3 million due to SCPSC-approved carrying cost accrual on certain deferred items. Other expenses at the Company increased primarily due to higher legal costs at the parent company. AFC decreased due to the abandonment of the Nuclear Project and a lower AFC rate as a result of removing Nuclear Project related capital costs from the average construction work in progress balance used to determine the annual AFC rate following the abandonment decision.

2016 vs 2015
Other income at the Company and Consolidated SCE&G decreased by $3.5 million due to lower gains on the sale of land and due to the recognition in 2015 of $5.2 million of gains realized upon the settlement of certain interest rate contracts previously recorded as regulatory liabilities pursuant to SCPSC orders previously discussed. Such gain recognition was fully offset by downward adjustments to electric operating revenues and had no effect on net income (see electric margin discussion). At the Company, other income also decreased by $3.9 million and other expenses decreased by $2.3 million due to the sale of SCI, and other income and other expenses decreased by $10.5 million for billings to DECG for transition services provided at cost pursuant to the terms of the sale of CGT. Other expenses at the Company and Consolidated SCE&G decreased by $5.2 million due to lower contribution expenses. In 2015, the Company's other income included the gain on the sale of SCI (see Dispositions in Note 1 to the consolidated financial statements). AFC increased due to construction activity.
    
Interest Expense
 
Components of interest expense, net of the debt component of AFC, were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Interest on long-term debt, net
 
$
346.7

 
$
330.3

 
$
311.3

 
$
266.1

 
$
253.8

 
$
236.0

Other interest expense
 
16.7

 
12.0

 
6.5

 
21.5

 
16.2

 
12.1

Total
 
$
363.4

 
$
342.3

 
$
317.8

 
$
287.6

 
$
270.0

 
$
248.1


Interest expense increased in each year primarily due to increased borrowings, and in 2017 due to lower AFC on borrowed funds.

Income Taxes
    
At the Company, the income tax benefit for 2017 was primarily due to the impairment loss. Additionally, the impact of remeasuring deferred taxes upon enactment of the Tax Act increased deferred tax expense and resulted in additional net loss of approximately $30 million. Exclusive of these items, income tax expense increased from 2016 to 2017 primarily due to higher income before taxes. Income tax expense decreased from 2015 to 2016 primarily due to lower income before taxes. In 2015 income tax expense and income before taxes were affected by the sales of CGT and SCI. At Consolidated SCE&G, income tax expense decreased from 2016 to 2017 primarily due to impacts related to the impairment loss. Without these impacts, income tax expense increased from 2016 to 2017 primarily due to higher income before taxes. Income tax expense increased from 2015 to 2016 primarily due to higher income before taxes. 

LIQUIDITY AND CAPITAL RESOURCES
 
Liquidity Considerations

              The Company and Consolidated SCE&G have experienced significant adverse events leading up to their decision to stop construction of Unit 2 and Unit 3, as well as significant adverse events since that decision was made. These events include the bankruptcy filing of the Consortium, the anticipated rejection by the Consortium of the EPC Contract with its fixed-price

43


provisions, and the ongoing contentious proceedings before regulatory and legislative bodies, among others things described in Note 10. In addition, downgrades by credit ratings agencies have occurred since the beginning of 2017, including recent rating actions.  The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $350 million for the Company (including $252 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $259 million for Consolidated SCE&G), and future minimum payments for operating leases of $34 million for the Company (including $26 million for Consolidated SCE&G).  Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs.

              Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed lines of credit that expire in December 2018 totaling $200 million for the Company, all of which pertains to Consolidated SCE&G, and committed long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect in customer rates amounts previously approved under the BLRA, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. However, as further described below, SCANA's credit rating has fallen below investment grade, which has constricted its ability and that of Consolidated SCE&G to issue commercial paper.

As described in Note 10, on January 31, 2018, the South Carolina House of Representatives passed a bill (H.4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Such regulatory, legislative or judicial proceedings outside of the Company’s and Consolidated SCE&G’s control may result in the temporary or permanent suspension of the approximately $445 million annually of rates being collected currently under the BLRA, the return of such amounts previously collected of $1.9 billion, or the requirement that SCE&G's share of payments received from the Toshiba Settlement ($1.095 billion) be placed in escrow or be refunded to customers. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA.

Were the SCPSC to grant the relief sought by ORS in the Request or grant similar relief resulting from legislative action, and as further discussed in Note 10 in the consolidated financial statements, an additional impairment loss or other charges totaling as much as approximately $4.8 billion may be required. Such an impairment loss or other charges would further stress the Company’s and Consolidated SCE&G’s equity to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of equity to total capitalization falling below minimum levels prescribed in the Company’s credit agreements. In such an event, the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and credit facilities and their ability to pay future dividends would likely be limited or may trigger events of default under such agreements.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, possible future actions related to rates or refunds could have a material adverse effect on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

Impact of Abandonment of Nuclear Project

Toshiba provided a parental guaranty for WEC’s payment obligations under the EPC Contract. Following the bankruptcy of WEC, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments in the total amount of approximately $2.2 billion ($1.2 billion for SCE&G's 55% share), including certain amounts with respect to contractor liens. In 2017, the first payment under the Toshiba Settlement was received and the remaining amounts due were monetized, resulting in total cash inflows of approximately $2 billion (approximately $1.1 billion for SCE&G's 55% share), including amounts related to the contractor liens. See also Note 10 to the consolidated financial statements. Portions of these

44


proceeds have been utilized to repay maturing commercial paper balances. Such short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction.

Regulatory proceedings being considered by the SCPSC include the Request filed by the ORS which, if granted, would require SCE&G to (1) immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA, and (2) make credits to future bills or refunds to customers for prior revised rates collections in the event that the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes it. SCE&G estimates that revised rates collections, including collections related to transmission assets expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of December 31, 2017 total approximately $1.9 billion.

In an amendment to the Request, the ORS has asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. Parties who filed to intervene in these proceedings or who filed a letter in support of the Request, as amended, include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, the SCEUC, certain large industrial customers, and several environmental groups. On December 20, 2017, the SCPSC denied SCE&G's motion to dismiss the Request and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable and also ordered that a hearing be scheduled to consider the Request. The hearing has not yet been scheduled. See Note 2 for additional developments. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. Any adverse action by the SCPSC, such as that sought by the ORS in the Request, could have a material adverse impact on the Company's and Consolidated SCE&G's results of operations, cash flows and financial condition.

Should the SCPSC or a court direct that proceeds arising from the Toshiba Settlement be refunded to customers in the near-term, or direct that such funds be escrowed or otherwise made unavailable to SCE&G, it is anticipated that SCE&G would reissue commercial paper, draw on its credit facilities or issue long-term debt to fund such requirement if such sources are available. However, were the SCPSC to rule in favor of the ORS in response to the Request that SCE&G suspend collections from customers of amounts previously authorized under the BLRA, or were other actions of the SCPSC or others taken in order to significantly restrict SCE&G’s access to revenues or impose additional adverse refund obligations on SCE&G, the Company’s and Consolidated SCE&G's assessments regarding the recoverability of all or a portion of the remaining balance of unrecovered nuclear project costs (see Note 2 to the consolidated financial statements) would be adversely impacted and additional impairment losses would likely be recorded. Further, the recognition of significant additional impairment losses with respect to unrecovered Nuclear Project costs could increase the Company’s and Consolidated SCE&G’s debt to total capitalization to a level which may limit their ability to borrow under their commercial paper programs or under their credit facilities and also could constitute a default under these credit facilities. Borrowing costs for long-term debt issuances and access to capital markets could also be negatively impacted.

For additional background on the Nuclear Project and further details on the matters described above, see Note 10 to the consolidated financial statements under Abandoned Nuclear Project - Toshiba Settlement and Subsequent Monetization
and Determination to Stop Construction and Related Regulatory, Political and Legal Developments.

In the first quarter of 2017, credit ratings agencies placed SCANA and SCE&G’s credit ratings on negative outlook or watch status due to adverse developments relating to the WEC Bankruptcy. In the third quarter of 2017, two agencies lowered their ratings for SCANA and its rated subsidiaries, citing a decline in the regulatory environment as a principal reason for the downgrades, and both agencies maintained their negative outlook or watch status. On January 3, 2018, after SCANA announced a proposed merger with Dominion Energy, each of the three agencies affirmed or reported no change to their respective credit ratings, and one agency revised its rating outlook for SCANA and its rated operating companies from negative to evolving. However, on January 31, 2018, the South Carolina House of Representatives overwhelmingly approved a bill (H.4375) that, if enacted, would temporarily repeal rates SCE&G collects under the BLRA. As a result, on February 5, 2018, one agency downgraded its ratings for SCANA and SCE&G, and attributed the downgrade to the action taken by the House of Representatives and the politically charged environment that is expected to weigh heavily on any decisions by the SCPSC related to SCE&G's electric rates. With this recent downgrade, the issuer ratings and the senior unsecured debt ratings for SCANA are considered below investment grade by two credit agencies; the issuer ratings for SCE&G are considered to be at the threshold for investment grade by two credit agencies while its senior secured debt ratings remain above investment grade; and the issuer ratings for PSNC Energy are considered to be at the threshold for investment grade by one credit agency while its senior secured debt ratings remain above investment grade. All of the ratings for SCANA, SCE&G and PSNC Energy are either under review for possible downgrade or have a negative or evolving outlook.


45


Any actions taken by or anticipated to be taken by regulators or legislators that are viewed as adverse, including a change to the BLRA or a requirement that SCE&G make credits to future bills or refunds to customers above such amounts as are included in the Merger Agreement or any requirement that SCE&G make such credits or refunds in the absence of the merger being consummated, or deterioration of the rated companies’ commonly monitored financial credit metrics or any additional adverse developments with respect to the Nuclear Project, could further negatively affect their debt ratings. If these rating agencies were to further lower any of these ratings, borrowing costs on new issuances of long-term debt and commercial paper would increase, which could adversely impact financial results or limit or eliminate refinancing opportunities, and the potential pool of investors and funding sources could decrease. In addition, further ratings downgrades may result in lower collateral thresholds being applied to the Company's and Consolidated SCE&G's commodity derivatives, or the removal of such thresholds altogether. This action would have the effect of requiring the Company to post additional collateral for commodity derivative instruments with unfavorable fair values. Ratings downgrades have also resulted in prepayments and demands from vendors for letters of credit, cash deposits, or other forms of credit support under certain gas supply and other agreements, and further ratings downgrades could result in requirements for additional deposits or the provision of additional credit support in order to conduct business under these agreements. See further discussion under the heading Credit Risk Considerations in Note 6 to the consolidated financial statements.

Significant Tax Deductions and Credits
 
The Company and Consolidated SCE&G have claimed significant research and experimentation tax deductions and credits related to the design and construction activities of Unit 2 and Unit 3. A significant portion of 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.  (See also Note 5 to the consolidated financial statements.) The Company and Consolidated SCE&G also expect to claim a significant tax deduction related to the decision to stop construction and to abandon the Nuclear Project in 2017.

These tax claims primarily involve the timing of recognition of tax deductions rather than permanent tax attributes, and their permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to them, had been deferred within regulatory assets. As such, until December 31, 2017 when it was determined to treat these deferrals as impaired (see Note 10 to the consolidated financial statements), these claims had not had, and were not expected to have in the future, significant direct effects on the Company’s and Consolidated SCE&G’s results of operations.  Nonetheless, the claims have contributed significantly to the Company’s and Consolidated SCE&G’s cash flows by providing a significant source of capital and lessening the level of debt and equity financing that the Company and Consolidated SCE&G have needed to raise in the financial markets. 

The claims made to date are under examination, and are considered controversial, by the IRS. Tax deductions which are expected to be claimed in connection with the determination to abandon the construction of Unit 2 and Unit 3 may also be considered controversial; therefore, it is also expected that the IRS will examine future tax returns.  To the extent that any of these claims are not sustained as ordinary losses on examination or through any subsequent appeal, the Company and Consolidated SCE&G will be required to repay any cash received for tax benefit claims which are ultimately disallowed, along with interest on those amounts. Such amounts could be significant and could adversely affect the Company's and Consolidated SCE&G's liquidity, cash flows, results of operations and financial condition. In certain circumstances, which management considers to be remote, penalties for underpayment of income taxes could also be assessed. Additionally, in such circumstances, the Company and Consolidated SCE&G may need to access the capital markets to fund those tax and interest payments, which could in turn adversely impact their ability to access financial markets for other purposes.

Other Liquidity Requirements and Restrictions

The terms of the Merger Agreement place limits on the Company and its subsidiaries as to certain investing and financing transactions. While the Merger Agreement permits the Company and its subsidiaries to refinance and issue certain long-term debt, make capital expenditures at certain levels, consummate certain planned investments, and make regular quarterly dividend payments to its shareholders at certain levels, transactions above these levels would require consent from Dominion Energy, which consent cannot be unreasonably withheld. Permitted transactions include, but are not limited to, the planned refinancing of $710 million of long-term debt maturing in 2018 at Consolidated SCE&G and the planned new issuance of $100 million of long-term debt at PSNC Energy, the purchase of an existing 540-MW gas fired power plant, and the payment by SCANA of regular quarterly dividends to its shareholders subject to certain limits. See Capital Expenditures herein for additional restrictions. In addition, SCANA’s Supplementary Key Executive Severance Benefits Plan provides certain payments to qualified senior executive officers in connection with a change in control. In January 2018, approximately $110.7 million was placed irrevocably in a rabbi trust to fund payments pursuant to this and certain other deferred compensation, incentive and

46


retirement plans, which might arise in connection with a change in control and/or a termination of employment or service if and when such payments become due.

The Company expects to meet contractual cash obligations in 2018 through internally generated funds and additional short- and long-term borrowings. Subject to the outcome of the regulatory, legislative and legal proceedings discussed above, the Company expects that, barring a future impairment of the capital markets or its access to such markets, it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future, including the cash requirements for refinancing maturing long-term debt. As noted above, adverse developments in regulatory, legislative or legal proceedings could alter these conclusions.

The terms of the Merger Agreement limit the dividends that SCANA can pay on its shares of common stock to an amount not greater than $0.6125 per share for any quarter. In order to preserve liquidity, the Company may revise its dividend policy to reduce or eliminate dividend payments. Such a decision could result in a significant decrease in the price of SCANA's common stock and an increase in the cost of raising equity capital.
 
Cash requirements for SCANA’s regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, to expand to meet future demand for electricity and gas and to install equipment necessary to comply with environmental regulations, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief.
 
Rating agencies consider qualitative and quantitative factors when assessing SCANA and its rated operating companies’ credit ratings, including the legislative and regulatory environment, capital structure and the ability to meet liquidity requirements. As previously noted, adverse developments with respect to recovery of Nuclear Project costs have negatively affected the Company’s and Consolidated SCE&G's debt ratings. Further adverse developments, changes in the legislative and regulatory environment or deterioration of SCANA's or its rated operating companies' commonly monitored financial credit metrics could cause the Company and Consolidated SCE&G to pay higher interest rates on its long- and short-term indebtedness, could limit the Company's and Consolidated SCE&G's access to capital markets and liquidity, and could trigger more stringent collateral requirements on interest rate and commodity hedges and under gas supply agreements and other contracts.
    
Cash provided from operating activities in 2016 and 2017 reflect significant tax benefits (reductions in income tax payments) arising from the deductions previously described under Significant Tax Deductions and Credits. The Company's decision in 2017 to stop construction of Unit 2 and Unit 3 and to abandon the Nuclear Project is expected to result in a significant tax deduction and an associated NOL for tax purposes. The Company expects to obtain a refund of taxes paid in certain prior years as a result of the carryback of the NOL, and expects to benefit from the carryforward of the NOL in future years. These cash flows are expected to supplant portions of financing which would otherwise be obtained in the capital markets.

Enactment of the Tax Act resulted in the remeasurement of deferred income tax assets and liabilities and the recognition as regulatory liabilities of certain excess deferred income taxes (see Note 2 and Note 5 to the consolidated financial statements). These regulatory liabilities will be amortized to the benefit of customers in accordance with the normalization provisions of the IRC and Code of Federal Regulations, which will serve to mitigate significant negative cash impact. Similarly, since the majority of the Company’s and Consolidated SCE&G's businesses are rate regulated, lower income taxes payable in future years due to the Tax Act should ultimately result in lower collections from customers in rates.

Capital Expenditures
 
Cash outlays for property additions and construction expenditures, including nuclear fuel, were $1.2 billion in 2017. Estimates of capital expenditures for construction and nuclear fuel for the next three years, which are subject to continuing review and adjustment, are as follows:

47


Estimated Capital Expenditures
Millions of dollars
 
2018
 
2019
SCE&G
 
 

 
 

Generation
 
$
124

 
$
145

Transmission & Distribution
 
229

 
203

Other
 
12

 
23

Gas
 
98

 
105

Common
 
3

 
11

Total SCE&G
 
466

 
487

PSNC Energy
 
288

 
275

Other
 
37

 
24

Total Normal
 
791

 
786

Nuclear Fuel - SCE&G
 
54

 
51

Total Estimated Capital Expenditures
 
$
845

 
$
837


Under the terms of the Merger Agreement, the Company may increase the amounts of the above estimated capital expenditures in 2018 and 2019 by not more than 10% without obtaining the consent of Dominion Energy.

Contractual cash obligations as of December 31, 2017 are summarized as follows:
Contractual Cash Obligations
 
Payments due by periods
Millions of dollars
 
Total
 
Less than
1 year
 
1 - 3 years
 
4 - 5 years
 
More than
5 years
Long- and short-term debt, including interest
 
$
13,352

 
$
1,406

 
$
1,721

 
$
768

 
$
9,457

Capital leases
 
28

 
5

 
14

 
3

 
6

Operating leases
 
112

 
34

 
42

 
9

 
27

Purchase obligations
 
3,159

 
2,345

 
812

 
2

 

Other commercial commitments
 
2,929

 
1,057

 
846

 
258

 
768

Total
 
$
19,580

 
$
4,847

 
$
3,435

 
$
1,040

 
$
10,258

 
As of December 31, 2017, the SCPSC has taken no final action with regard to the Request by the ORS or in connection with the effect of the Tax Act on customer rates, including any action with respect to excess deferred income taxes. Therefore, no amounts have been included in the table above for these matters. See Note 2 to the consolidated financial statements.

Purchase obligations include customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such arrangements without penalty. Purchase obligations also includes amounts related to the EPC Contract, which the Company anticipates that WEC and WECTEC will reject. The Company does not expect that such amounts will be expended. See Note 10 to the consolidated financial statements.

Other commercial commitments includes estimated obligations under forward contracts for natural gas purchases. Such forward contracts include customary “make-whole” or default provisions, but are not considered to be “take-or-pay” contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates.  Other commercial commitments also includes a “take-and-pay” contract for natural gas which expires in 2019 and estimated obligations for coal and nuclear fuel purchases. The Company has included certain amounts related to nuclear fuel commitments based on its interpretation of its obligations under existing contract terms that are currently disputed by the supplier.

Unrecognized tax benefits of approximately $19 million have been excluded from the table above due to uncertainty as to the timing of any future payments. In addition, the table excludes amounts that may be required to be paid to federal or state taxing authorities related to tax deductions and credits on tax returns for which examinations have not been completed or closed. For additional information, see Note 5 to the consolidated financial statements.

In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded under current regulations, and no significant contributions are anticipated for the foreseeable future. Cash payments under the

48


postretirement health care and life insurance benefit plan were $12.5 million in 2017, and such annual payments are expected to be the same or increase to as much as $16.5 million in the future.
 
The Company is party to certain NYMEX natural gas futures contracts for which any unfavorable market movements are funded in cash. These derivatives are accounted for as cash flow hedges and their effects are reflected within other comprehensive income until the anticipated sales transactions occur. The Company, including Consolidated SCE&G, is also party to certain interest rate derivative contracts for which unfavorable market movements above certain thresholds are funded in cash collateral. Certain of these interest rate derivative contracts are accounted for as cash flow hedges, and others are not designated for accounting purposes as cash flow hedges but are accounted for pursuant to regulatory orders. See further discussion at Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 6 to the consolidated financial statements. As of December 31, 2017, the Company had posted approximately $29 million in cash collateral related to interest rate derivative contracts.
 
The Company has a legal obligation associated with the decommissioning and dismantling of Unit 1 and other conditional AROs that are not listed in contractual cash obligations above. See Notes 1 and 10 to the consolidated financial statements. SCE&G's method for funding decommissioning costs is described in Note 1 to the consolidated financial statements.
 
Financing Limits and Related Matters

Issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by regulatory bodies including state public service commissions and FERC.

SCE&G has obtained FERC authority 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 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million. GENCO has obtained FERC authority 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 2018. 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.

At December 31, 2017 SCANA, SCE&G (including Fuel Company) and PSNC Energy were parties to five-year credit agreements in the amounts of $400 million, $1.2 billion, of which $500 million relates to Fuel Company, and $200 million, respectively, which expire in December 2020. In addition, at December 31, 2017 SCE&G was party to a three-year credit agreement in the amount of $200 million which expires in December 2018. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances. For a list of banks providing credit support and other information, see Note 4 to the consolidated financial statements.

As of December 31, 2017, the Company had no outstanding borrowings under its credit facilities, had approximately $350 million in commercial paper borrowings outstanding, was obligated under $3.3 million in LOC-supported letters of credit, and held approximately $409 million in cash and temporary investments. The Company regularly monitors the commercial paper and short-term credit markets to optimize the timing for repayment of the outstanding balance on its draws, while maintaining appropriate levels of liquidity. The Company's average short-term borrowings outstanding during 2017 were approximately $870 million. Short-term cash needs were met primarily through the issuance of commercial paper.

At December 31, 2017, the Company’s long-term debt portfolio has a weighted average maturity of approximately 19 years and bears an average cost of 5.75%. Substantially all long-term debt bears fixed interest rates or is swapped to fixed.

The Company’s articles of incorporation do not limit the dividends that may be paid on its common stock. However, the terms of the Merger Agreement limit the dividends that SCANA can pay on its shares of common stock to an amount not greater than $0.6125 per share for any quarter.

SCE&G’s bond indenture (relating to the hereinafter defined Bonds) contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (which as defined equates to its retained earnings) 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

49


Power Act requires the appropriation of a portion of certain earnings from hydroelectric projects.  At December 31, 2017, approximately $94.0 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment 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, 2017, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million.
 
SCANA Corporation
 
SCANA has an indenture which permits the issuance of unsecured debt securities from time to time including its medium-term notes. This indenture contains no specific limit on the amount of unsecured debt securities which may be issued.
 
South Carolina Electric & Gas Company
 
SCE&G 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. At December 31, 2017, SCE&G's Unfunded Net Property Additions (which are based on property certified November 30, 2017) totaled approximately $754 million, and the aggregate principal of retired Bonds totaled approximately $491 million. 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, 2017, the Bond Ratio was 5.24. Adjusted Net Earnings, as therein defined, excludes the impairment loss.

Financing Activities

During 2017, net cash outflows related to financing activities totaled approximately $802 million, primarily associated with short-term borrowings and the payment of dividends. During 2016, net cash inflows related to financing activities totaled approximately $560 million, primarily associated with the proceeds from the issuance of long-term debt and short-term borrowings, partially offset by the payment of dividends.

On November 1, 2016, Consolidated SCE&G paid at maturity $100 million related to a nuclear fuel financing which had an imputed interest rate of 0.78%.
    
In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. Also in June 2016, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of the $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 22, 2047. In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

Investing Activities

To settle interest rate derivative contracts, the Company paid approximately $39 million in 2017, $113 million in 2016, and $253 million, net, in 2015.

For additional information, see Note 4 to the consolidated financial statements.
      

50


Ratios of earnings to fixed charges for each of the five years ended December 31, 2017, were as follows:
December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
The Company
 
0.43
 
3.38
 
4.40
 
3.39
 
3.22
Consolidated SCE&G
 
(0.10)
 
3.66
 
3.69
 
3.77
 
3.48

The earnings deficiency below fixed charges for 2017 is approximately $226 million for the Company and approximately $338 million for Consolidated SCE&G. Ratios for 2017 reflect impairment losses related to the Nuclear Project. See Note 10 to the consolidated financial statements. The Company's ratio for 2015 reflects the impact of gains recorded upon the sale of certain subsidiaries. See Note 1 to the consolidated financial statements.

ENVIRONMENTAL MATTERS
 
The operations of the Company 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, Nuclear Waste Act and CERCLA, among others. In many cases, regulations proposed by such authorities could have a significant impact on financial condition, results of operations and cash flows. In addition, the conditions or requirements that will be imposed by regulatory or legislative proposals often cannot be predicted. To the extent that compliance with environmental regulations or legislation results in capital expenditures or operating costs, recovery of such expenditures and costs are expected through existing ratemaking provisions.

For the three years ended December 31, 2017, capital expenditures for environmental control equipment at fossil fuel generating stations totaled $60.7 million. During this same period, expenditures were made for the construction and retirement of landfills and ash ponds, net of disposal proceeds, of approximately $23.6 million. In addition, expenditures were made to operate and maintain environmental control equipment at fossil plants of $8.2 million in 2017, $9.5 million in 2016 and $8.7 million in 2015, which are included in other operation and maintenance expense, and expenditures were made to handle waste ash, net of disposal proceeds, of $1.2 million in 2017, $2.4 million in 2016 and $1.3 million in 2015, which are included in fuel used in electric generation. In addition, included within other operation and maintenance expense is an annual amortization of $1.4 million in each of 2017, 2016 and 2015 related to SCE&G's recovery of MGP remediation costs as approved by the SCPSC. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $28 million for 2018 and $329 million for the four-year period 2019-2022.  These expenditures are included in the Estimated Capital Expenditures table, discussed in Liquidity and Capital Resources, and include known costs related to the matters discussed below.
 
The EPA is conducting an enforcement initiative against the utilities industry related to the New Source Review provisions and the NSPS of the CAA. In addition, the DOJ, on behalf of the EPA, has taken civil enforcement action against several utilities. The primary basis for these actions is the assertion by the EPA that maintenance activities undertaken by the utilities at their coal-fired power plants constituted “major modifications” which required the installation of costly BACT. Some of the utilities subject to the actions have reached settlement. Though the Company cannot predict what action, if any, the EPA will initiate against it, any costs incurred are expected to be recoverable through rates.

With the pervasive emergence of concern over the issue of global climate change as a significant influence upon the economy, SCANA, SCE&G and GENCO are subject to climate-related financial risks, including those involving regulatory requirements responsive to GHG emissions, as well as those involving other potential physical impacts. Other business and financial risks arising from such climate change could also materialize. The Company cannot predict all of the climate-related regulatory and physical risks nor the related consequences which might impact the Company, and the following discussion should not be considered all-inclusive.
 
Physical effects associated with climate changes could include changes in weather patterns, such as storm frequency and intensity, and any resultant damage to the Company's electric and gas systems, as well as impacts on employees and customers, the supply chain and many others. Much of the service territory of SCE&G is subject to the damaging effects of Atlantic and Gulf coast hurricanes and also to the damaging impact of winter ice storms. To help mitigate the financial risks arising from these potential occurrences, SCE&G maintains insurance on certain properties. As part of its ongoing operations, SCE&G maintains emergency response and storm preparation plans and teams who receive ongoing training and related simulations, all in order to allow for the protection of assets and the return of systems to normal reliable operation in a timely fashion following any such event.

Environmental commitments and contingencies are further described in Note 10 to the consolidated financial statements.

51



REGULATORY MATTERS
 
SCANA and its subsidiaries are subject to the regulatory jurisdiction of the following entities for the matters noted below. In addition, see Environmental Matters above for a discussion of related regulations to which the Company's operations are subject.
Company
Regulatory Jurisdiction/Matters
SCANA
The SEC as to the issuance of certain securities and other matters and the FERC as to certain acquisitions and other matters.
 
 
SCANA and all subsidiaries
The CFTC, under Dodd-Frank, concerning record keeping, reporting, and other related regulations associated with swaps, options, forward contracts, and trade options, to the extent SCANA and any of its subsidiaries engage in any such activities.
 
 
SCE&G
The SEC as to the issuance of certain securities and other matters; the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters; the FERC as to issuance of short-term borrowings, guarantees of short-term indebtedness, certain acquisitions, wholesale electric power and transmission rates and services, the transmission of electric energy in interstate commerce, the wholesale sale of electric energy, the licensing of hydroelectric projects and other matters, including accounting; the DOE under the Federal Power Act as to use of emergency authority and coordination of all applicable federal authorizations and related environmental reviews to site an electric transmission facility; and the NRC with respect to the ownership, construction, operation and decommissioning of its nuclear facilities. NRC jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety and environmental impact. In addition, the Federal Emergency Management Agency reviews, in conjunction with the NRC, certain aspects of emergency planning relating to the operation of nuclear plants.
 
 
GENCO
The SCPSC as to the issuance of securities (other than short-term borrowings); the FERC as to issuance of short-term borrowings, the wholesale sale of electric energy, accounting, certain acquisitions and other matters; and the DOE under the Federal Power Act as to use of emergency authority.
 
 
Fuel Company
The SEC as to the issuance of certain securities.
 
 
PSNC Energy
The NCUC as to gas rates, service, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters, and the SEC as to the issuance of certain securities.
 
 
SCE&G and PSNC Energy
The PHMSA and the DOT as to federal pipeline safety requirements for gas distribution pipeline systems and natural gas transmission systems, respectively. The ORS and the NCUC as to enforcement of federal and state pipeline safety requirements in South Carolina (SCE&G) and North Carolina (PSNC Energy), respectively. The FERC as to participation in wholesale natural gas markets.
 
 
SCANA Energy
The GPSC through its certification as a natural gas marketer in Georgia and specifically as to retail prices for customers served under its regulated provider contract. The FERC as to participation in wholesale natural gas markets.

Material retail rate proceedings, and significant uncertainties with respect to certain of these proceedings, are described in Note 2 and Note 10 to the consolidated financial statements. In addition, the RSA allows natural gas distribution companies in South Carolina to request annual adjustments to rates to reflect changes in revenues and expenses and changes in investment. Such annual adjustments are subject to certain qualifying criteria and review by the SCPSC.

SCE&G’s electric transmission system and certain facilities related to generation and distribution are subject to NERC, which develops and enforces reliability standards for the bulk power systems throughout North America. NERC is subject to oversight by FERC.

Dodd-Frank provides for substantial additional regulation of over-the-counter and security-based derivative instruments, among other things, and the CFTC and the SEC continue to modify the implementation of Dodd-Frank through rule makings. The Company has determined that it meets the end-user exception in Dodd-Frank, with the lowest level of required regulatory reporting burden imposed by this law. The Company is currently complying with these enacted regulations and intends to comply with regulations enacted in the future.

52



CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
Following are descriptions of the accounting policies and estimates which are most critical in terms of reporting financial condition or results of operations.
 
Impairment Considerations

Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. SCE&G continues to contest the specific challenges set forth in regulatory, legislative and legal proceedings (see also Note 10 to the consolidated financial statements). However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G have determined that a disallowance of recovery of part of the cost of the abandoned plant is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, as of December 31, 2017, the Company and Consolidated SCE&G have recognized a pre-tax impairment loss totaling $1.118 billion ($690 million net of tax). With the exception of the $210 million loss recorded in the third quarter of 2017 as explained below, this impairment loss was recorded in the fourth quarter of 2017. A discussion of this impairment loss follows:

A pre-tax impairment loss was recorded with respect to disallowance of unrecovered nuclear project costs of approximately $670 million. This amount includes $210 million recorded in the third quarter of 2017, which represented costs of approximately $1.2 billion that had been expended on the project, exclusive of transmission costs, but which had not yet been determined to be prudent by the SCPSC in connection with revised rates proceedings under the BLRA, offset by the amount of approximately $1 billion, which amount represents the recovery of the Toshiba Settlement proceeds that are in excess of amounts from that settlement that the Company and Consolidated SCE&G estimated may be necessary to satisfy certain project liens. This impairment loss also includes $180 million, which amount arises from SCE&G’s entry into an agreement in the fourth quarter of 2017 to purchase in 2018 an existing 540-MW combined cycle gas generating station along with SCE&G's commitment to regulators and the public that the recovery of the initial capital investment in the facility would not be sought from customers. The remaining $280 million of this impairment loss was recorded after consideration of the regulatory and political developments in the fourth quarter of 2017 and early 2018 described in Note 10 to the consolidated financial statements.
A pre-tax impairment loss was recorded in the aggregate amount of $361 million to write off costs which had been previously deferred, primarily as regulatory assets, in connection with the Nuclear Project. Such regulatory assets included deferred losses on interest rate swaps for which debt will not be issued due to the abandonment of the Nuclear Project, carrying costs on deferred tax assets arising from the capitalization of interest costs for tax purposes, net deferred costs and tax benefits related to foregone domestic production activities deductions (net of uncertain tax positions and credits) taken with respect to the project, and taxes associated with equity AFC.
Finally, an $87 million pre-tax impairment loss was recorded in order to reduce to estimated fair value the carrying value of nuclear fuel acquired for use in Unit 2 and Unit 3.

With the exception of the $87 million related to nuclear fuel, the above impairment loss reflects impacts similar to those that may have resulted had the proposed solution announced November 16, 2017 been implemented. That proposal is presented by SCE&G as a less-favored alternative to the merger benefits and cost recovery plan in the January 12, 2018 Joint Petition. It is reasonably possible that a change in the estimated impairment loss could occur in the near term. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $856 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion, net of approximately $1.062 billion, which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle

53


contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, and if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.8 billion. This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.976 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $1.9 billion, net of approximately $1.062 billion, which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens.

Accounting for Rate Regulated Operations
 
Regulated utilities record certain assets and liabilities that defer the recognition of expenses and revenues to future periods in accordance with accounting guidance for rate-regulated utilities. In the future, in the event of deregulation or other changes in the regulatory environment, the criteria of accounting for rate-regulated utilities may no longer be met, and the write off of regulatory assets and liabilities could be required. Such an event could have a material effect on the results of operations, liquidity or financial position of the Electric Operations and Gas Distribution segments in the period the write-off would be recorded. See Note 2 to the consolidated financial statements for a description of the regulatory assets and liabilities.
 
Generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, a write down in those assets could be required. It is not possible to predict whether any write-downs would be necessary and, if they were, the extent to which they would affect results of operations in the period in which they would be recorded. As of December 31, 2017, net investments in fossil/hydro and nuclear generation assets (excluding assets associated with the Nuclear Project, which are discussed under Impairment Considerations above) were approximately $2.2 billion and $825 million, respectively.
    
Revenue Recognition and Unbilled Revenues
 
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of the utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, estimates are recorded for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers for which they have not yet been billed. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules and, where applicable, the impact of weather normalization or other regulatory provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. The Company's accounts receivable included unbilled revenues of $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016, compared to total revenues of $4.4 billion in 2017 and $4.2 billion in 2016. See Note 1 to the consolidated financial statements for a discussion of the impact expected from the adoption of new revenue recognition guidance in 2018.
 
Nuclear Decommissioning
 
Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years into the future. Among the factors that could change SCE&G’s accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, and changes in financial assumptions such as discount rates and the estimated timing of cash flows. Changes in any of these estimates could significantly impact financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
 
Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including both the cost of decommissioning plant components that are and are not subject to radioactive contamination, totals $786.4 million, stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. The cost estimate assumes that upon closure the site would be maintained for 60 years in such a manner as to allow for subsequent decontamination that would permit release for unrestricted use.
 
Under SCE&G’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates, 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 the 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 1 on an after-tax basis.

54



Asset Retirement Obligations
 
AROs are accrued for legal obligations associated with the retirement of long-lived tangible assets that result from acquisition, construction, development and normal operation in accordance with applicable accounting guidance. These obligations are recognized at present value in the period in which they are incurred, and associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived assets. Because such obligations relate primarily to regulated utility operations, their recognition has no significant impact on results of operations. As of December 31, 2017, the Company has recorded AROs of $208 million for nuclear plant decommissioning (as discussed above) and AROs of $360 million for other conditional obligations primarily related to other generation, transmission and distribution properties, including gas pipelines. All of the amounts are based upon estimates which are subject to varying degrees of precision, particularly since payments in settlement of such obligations may be made many years in the future. Changes in these estimates will be recorded over time; however, these changes in estimates are not expected to materially impact results of operations so long as the regulatory framework for the utilities remains in place.
 
Accounting for Pensions and Other Postretirement Benefits
 
The Company recognizes the funded status of its defined benefit pension plan as a liability and changes in funded status as a component of net periodic benefit cost or other comprehensive income, net of tax, or as a regulatory asset as required by accounting guidance. Accounting guidance requires the use of several assumptions that impact pension cost, of which the discount rate and the expected return on assets are the most sensitive. Net pension cost of $22.3 million recorded in 2017 reflects the use of a 4.22% discount rate derived using a cash flow matching technique, and an assumed 7.25% long-term rate of return on plan assets. The Company believes that these assumptions and the resulting pension cost amount were reasonable. For purposes of comparison, a 25 basis point reduction in the discount rate in 2017 would have increased the Company’s pension cost by $1.7 million and increased the pension obligation by $25.2 million. Further, had the assumed long-term rate of return on assets been 7.00%, the Company’s pension cost for 2017 would have increased by $1.9 million.
 
The following information with respect to pension assets (and returns thereon) should also be noted.
 
In developing the expected long-term rate of return assumptions, the Company evaluates historical performance, targeted allocation amounts and expected payment terms. As of the beginning of 2017, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 5.1%, 5.4%, 6.9% and 8.2%, respectively. The 2017 expected long-term rate of return of 7.25% was based on a target asset allocation of 58% with equity managers, 33% with fixed income managers and 9% with hedge fund managers. Management regularly reviews such allocations and periodically rebalances the portfolio when considered appropriate. As of the beginning of 2018, the plan’s historical 10, 15, 20 and 25 year cumulative performance showed actual returns of 6.1%, 7.8%, 6.6% and 8.5%, respectively. For 2018, it is anticipated that the long-term expected rate of return will be 7.00%.
 
Pursuant to regulatory orders, certain previously deferred pension costs are being amortized as described in Note 2 to the consolidated financial statements. Current pension expense for electric operations is being recovered through a pension cost rider, and current pension expense related to SCE&G's and PSNC Energy's gas operations is being recovered through cost of service rates.

Pension benefits are not offered to employees hired or rehired after 2013, and pension benefits for existing participants will no longer accrue for services performed or compensation earned after 2023. As a result, the significance of pension costs and the criticality of the related estimates will continue to diminish. Further, the pension trust is adequately funded under current regulations, and management does not anticipate the need to make significant pension contributions for the foreseeable future based on current market conditions and assumptions.

The Company accounts for the cost of its postretirement medical and life insurance benefit plan in a similar manner to that used for its defined benefit pension plan. This plan is unfunded, so no assumptions related to rate of return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. The Company used a discount rate of 4.30%, derived using a cash flow matching technique, and recorded a net cost for 2017 of $17.0 million. Had the selected discount rate been 4.05% (25 basis points lower than the discount rate referenced above), the expense for 2017 would have been $0.6 million higher and the obligation would have increased by $8.6 million. Because the plan provisions include “caps” on company per capita costs, and because employees hired after 2010 are responsible for the full cost of retiree medical benefits elected by them, health care cost inflation rate assumptions do not materially impact the net expense recorded. 


55


Uncertain Income Tax Positions

During 2013 and 2014, SCANA amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). SCANA also made similar claims in filing its original 2013 and 2014 returns in 2014 and 2015, respectively. In 2016 and 2017, SCANA claimed significant research and experimentation deductions and credits (offset by reductions in its domestic production activities deductions), related to the design and construction activities of the Nuclear Project, in its 2015 and 2016 income tax returns. SCANA expects to claim similar deductions and credits on its 2017 tax return when it is 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.  See also Note 5 to the consolidated financial statements.

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, SCANA anticipates that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no such estimated unrecognized tax benefits were recorded as of December 31, 2017. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits.
  
As of December 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ($19 million net of the impact of state deductions on federal returns, net of NOLs and credit carryforwards, and net of receivables related to the uncertain tax positions). If recognized, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2017.

The estimates of unrecognized tax benefits were computed with consideration as to whether the claims are (or are not) more likely than not to be sustained and with consideration of analyses of cumulative probabilities regarding potential outcomes.  Such estimates involve significant management judgment and varying levels of precision.  Changes in such estimates are required to be recorded as circumstances change and additional information regarding the claims and potential outcomes becomes available, and these changes could be significant.

                Historically, because the unrecognized tax benefit through December 31, 2017 primarily involved the timing of recognition of tax deductions rather than permanent tax attributes, the estimates regarding their recognition did not have a significant impact on the Company's effective tax rate. Further, until December 31, 2017, when such deferrals were considered to be less than probable of recovery (see Note 10), these permanent attributes (net), as well as most of the interest accruals required to be recorded with respect to the unrecognized tax benefits, had been deferred within regulatory assets.  As such, the impacts of these significant accounting estimates, and changes therein, had primarily been reflected on the balance sheet rather than in results of operations. In the future, the impact of changes in estimates with respect to these permanent attributes (net) are not expected to be deferred within regulatory assets (see Note 10) and the impact of such changes to the unrecognized tax benefit related to these permanent attributes (net) could be significant.

                Upon resolution of the uncertainties, the Company will be required to re-pay any tax benefits claimed which are ultimately disallowed, along with interest on those amounts.  In certain circumstances, which the Company considers to be remote, penalties for underpayment of income taxes could also be assessed. Such re-payment amounts could be significant and adversely affect cash flow and financial condition.

OTHER MATTERS
 
Off-Balance Sheet Arrangements
 
SCANA holds insignificant investments in securities and business ventures. The Company does not engage in significant off-balance sheet financing or similar transactions, although it is party to various operating leases in the normal course of business for land, office space, furniture, equipment, rail cars, a purchase power agreement, and airplanes.


56


Claims and Litigation
 
For a description of claims and litigation, see Note 10 to the consolidated financial statements.

Other

As Georgia’s regulated provider, SCANA Energy provides service to customers considered to be low-income or that are otherwise unable to obtain natural gas service from other marketers. SCANA Energy provides this service at rates approved by the GPSC and receives funding from Georgia's Universal Service Fund to offset some of the resulting bad debt. SCANA Energy files financial and other information periodically with the GPSC, and such information is available at www.psc.state.ga.us (which is not intended as an active hyperlink; the information on the GPSC website is not part of this or any other report filed by the Company with the SEC).
 
SCANA’s natural gas distribution and gas marketing segments maintain gas inventory and utilize forward contracts and other financial instruments, including commodity swaps and futures contracts, to manage exposure to fluctuating natural gas commodity prices. See Note 6 to the consolidated financial statements. As a part of this risk management process, at any given time, a portion of SCANA’s projected natural gas needs has been purchased or placed under contract.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
All financial instruments described in this section 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 sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts, weighted average 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, 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

 

December 31, 2016
Expected Maturity Date
Millions of dollars
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
 
Fair Value
Long-Term Debt:
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

   Fixed Rate ($)
12.5

 
721.7

 
11.1

 
360.2

 
489.0

 
4,789.7

 
6,384.3

 
7,040.6

   Average Fixed Interest Rate (%)
4.21

 
6.01

 
4.40

 
6.33

 
4.64

 
5.73

 
5.70

 

   Variable Rate ($)
4.4

 
4.4

 
4.4

 
4.4

 
4.4

 
125.0

 
147.0

 
142.7

   Average Variable Interest Rate (%)
1.63

 
1.63

 
1.63

 
1.63

 
1.63

 
1.16

 
1.23

 

Interest Rate Swaps:
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
   Pay Fixed/Receive Variable ($)
554.4

 
704.4

 
4.4

 
4.4

 
4.4

 
128.6

 
1,400.6

 
12.3

   Average Pay Interest Rate (%)
2.91

 
2.22

 
6.17

 
6.17

 
6.17

 
4.57

 
2.74

 

   Average Receive Interest Rate (%)
1.00

 
1.00

 
1.63

 
1.63

 
1.63

 
1.08

 
1.02

 


57


Consolidated SCE&G
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

 

December 31, 2016
 
Expected Maturity Date
Millions of dollars
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
 
Fair Value
Long-Term Debt:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

   Fixed Rate ($)
 
12.0

 
721.7

 
11.1

 
10.2

 
39.0

 
4,339.7

 
5,133.7

 
5,687.3

   Average Fixed Interest Rate (%)
 
4.27

 
6.01

 
4.40

 
4.54

 
3.60

 
5.75

 
5.76

 

   Variable Rate ($)
 

 

 

 

 

 
67.8

 
67.8

 
64.9

   Average Variable Interest Rate (%)
 

 

 

 

 

 
0.76

 
0.76

 

Interest Rate Swaps:
 
 

 
 

 
 

 
 

 
 
 
 
 
 
 
 
   Pay Fixed/Receive Variable ($)
 
550.0

 
700.0

 

 

 

 
71.4

 
1,321.4

 
31.7

   Average Pay Interest Rate (%)
 
2.88

 
2.19

 

 

 

 
3.29

 
2.54

 

   Average Receive Interest Rate (%)
 
1.00

 
1.00

 

 

 

 
0.64

 
0.98

 


 While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
 
For further discussion of long-term debt and interest rate derivatives, see the Liquidity and Capital Resources section in Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 4 and Note 6 to the consolidated financial statements.

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
 
2018
 
2019
 
2020
 
Futures - Long
 
 
 
 
 
 
 
Settlement Price (a)
 
2.87

 
2.94

 

 
Contract Amount (b)
 
53.1

 
13.3

 

 
Fair Value (b)
 
49.8

 
13.0

 

 
 
 
 
 
 
 
 
 
Futures - Short
 
 
 
 
 
 
 
Settlement Price (a)
 
2.85

 

 

 
Contract Amount (b)
 
5.6

 

 

 
Fair Value (b)
 
5.1

 

 

 
 
 
 
 
 
 
 
 
Options - Purchased Call (Long)
 
 
 
 
 
 
 
Strike Price (a)
 
3.35

 

 

 
Contract Amount (b)
 
20.7

 

 

 
Fair Value (b)
 
0.7

 

 

 
 
 
 
 
 
 
 
 
Swaps - Commodity
 
 

 
 

 
 

 
Pay fixed/receive variable (b)
 
15.9

 
6.7

 
3.0

 
Average pay rate (a)
 
3.2293

 
2.9298

 
2.8730

 
Average received rate (a)
 
2.8587

 
2.8613

 
2.8211

 
Fair Value (b)
 
14.1

 
6.5

 
2.9

 

58


Pay variable/receive fixed (b)
 
29.6

 
11.5

 
2.7

 
Average pay rate (a)
 
2.8505

 
2.8710

 
2.8211

 
Average received rate (a)
 
3.0993

 
2.9410

 
2.8764

 
Fair Value (b)
 
32.2

 
11.8

 
2.8

 
 
 
 
 
 
 
 
 
Swaps - Basis
 
 

 
 

 
 

 
Pay variable/receive variable (b)
 
7.0

 
0.3

 

 
Average pay rate (a)
 
2.8191

 
3.0876

 

 
Average received rate (a)
 
2.7935

 
3.0306

 

 
Fair Value (b)
 
7.0

 
0.3

 

 

(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 6 to the consolidated financial statements.
 
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.

59


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
SCANA Corporation
Cayce, South Carolina

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of SCANA Corporation and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), changes in common equity, and cash flows, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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 22, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company'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.

Emphasis of Matter

As discussed in Note 10 to the financial statements, the abandoned Nuclear Project has led to legal, legislative, and regulatory matters that may result in material impacts to results and the liquidity of the Company.




/s/DELOITTE & TOUCHE LLP
 
Charlotte, North Carolina
 
February 22, 2018
 

We have served as the Company's auditor since 1945.


60



SCANA Corporation and Subsidiaries
Consolidated Balance Sheets
 
December 31, (Millions of dollars)
 
2017
 
2016
Assets
 
 

 
 

Utility Plant In Service
 
$
14,370

 
$
13,444

Accumulated Depreciation and Amortization
 
(4,611
)
 
(4,446
)
Construction Work in Progress
 
471

 
4,845

Nuclear Fuel, Net of Accumulated Amortization
 
208

 
271

Goodwill
 
210

 
210

Utility Plant, Net
 
10,648

 
14,324

Nonutility Property and Investments:
 
 

 
 

Nonutility property, net of accumulated depreciation of $133 and $138
 
270

 
276

Assets held in trust, net-nuclear decommissioning
 
136

 
123

Other investments
 
68

 
76

Nonutility Property and Investments, Net
 
474

 
475

Current Assets:
 
 

 
 

Cash and cash equivalents
 
409

 
208

Receivables:
 
 
 
 
    Customer, net of allowance for uncollectible accounts of $6 and $6
 
665

 
616

    Income taxes
 
198

 
142

    Other
 
105

 
127

Inventories:
 
 

 
 

Fuel
 
143

 
136

Materials and supplies
 
161

 
155

Prepayments
 
99

 
105

Other current assets
 
17

 
17

Derivative financial instruments
 
54

 

Total Current Assets
 
1,851

 
1,506

Deferred Debits and Other Assets:
 
 

 
 

Regulatory assets
 
5,580

 
2,130

Other
 
186

 
272

Total Deferred Debits and Other Assets
 
5,766

 
2,402

Total
 
$
18,739

 
$
18,707

 
See Notes to Consolidated Financial Statements.


 

61


December 31, (Millions of dollars)
 
2017
 
2016
Capitalization and Liabilities
 
 

 
 

Common Stock - no par value, 143 million shares outstanding for all periods presented
 
$
2,390

 
$
2,390

Retained Earnings
 
2,915

 
3,384

Accumulated Other Comprehensive Loss
 
(50
)
 
(49
)
  Total Common Equity
 
5,255

 
5,725

Long-Term Debt, Net
 
5,906

 
6,473

Total Capitalization
 
11,161

 
12,198

Current Liabilities:
 
 

 
 

Short-term borrowings
 
350

 
941

Current portion of long-term debt
 
727

 
17

Accounts payable
 
438

 
404

Customer deposits and customer prepayments
 
112

 
168

Taxes accrued
 
214

 
201

Interest accrued
 
87

 
84

Dividends declared
 
86

 
80

Derivative financial instruments
 
6

 
35

Other
 
93

 
135

Total Current Liabilities
 
2,113

 
2,065

Deferred Credits and Other Liabilities:
 
 

 
 

Deferred income taxes, net
 
1,261

 
2,159

Asset retirement obligations
 
568

 
558

Pension and postretirement benefits
 
360

 
373

Unrecognized tax benefits
 
19

 
219

Regulatory liabilities
 
3,059

 
930

Other
 
198

 
205

Total Deferred Credits and Other Liabilities
 
5,465

 
4,444

Commitments and Contingencies (Note 10)
 

 

Total
 
$
18,739

 
$
18,707

 
See Notes to Consolidated Financial Statements.


62


SCANA Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended December 31, (Millions of dollars, except per share amounts)
 
2017
 
2016
 
2015
Operating Revenues:
 
 

 
 

 
 

Electric
 
$
2,659

 
$
2,614

 
$
2,551

Gas-regulated
 
874

 
788

 
811

Gas-nonregulated
 
874

 
825

 
1,018

Total Operating Revenues
 
4,407

 
4,227

 
4,380

 
 
 
 
 
 
 
Operating Expenses:
 
 

 
 

 
 

Fuel used in electric generation
 
594

 
576

 
660

Purchased power
 
80

 
64

 
52

Gas purchased for resale
 
1,156

 
1,054

 
1,287

Other operation and maintenance
 
737

 
755

 
715

Impairment loss
 
1,118

 

 

Depreciation and amortization
 
382

 
371

 
358

Other taxes
 
264

 
254

 
234

Total Operating Expenses
 
4,331

 
3,074

 
3,306

Gain on sale of CGT, net of transaction costs
 

 

 
234

Operating Income
 
76

 
1,153

 
1,308

 
 
 
 
 
 
 
Other Income (Expense), net
 
56

 
55

 
42

Gain on sale of SCI, net of transaction costs
 

 

 
107

Interest charges, net of allowance for borrowed funds used during construction of $18, $19 and $15
 
(363
)
 
(342
)
 
(318
)
 
 
 
 
 
 
 
Income (Loss) Before Income Tax Expense
 
(231
)
 
866

 
1,139

Income Tax Expense (Benefit)
 
(112
)
 
271

 
393

Net Income (Loss)
 
$
(119
)
 
$
595

 
$
746

 
 
 
 
 
 
 
Earnings (Loss) Per Share of Common Stock
 
$
(0.83
)
 
$
4.16

 
$
5.22

Weighted Average Common Shares Outstanding (millions)
 
143

 
143

 
143

Dividends Declared Per Share of Common Stock
 
$
2.45

 
$
2.30

 
$
2.18

 
See Notes to Consolidated Financial Statements.


63


SCANA Corporation and Subsidiaries
  Consolidated Statements of Comprehensive Income (Loss)
 
Years Ended December 31, (Millions of dollars)
 
2017
 
2016
 
2015
Net Income (Loss)
 
$
(119
)
 
$
595

 
$
746

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
Unrealized Losses on Cash Flow Hedging Activities:
 
 
 
 
 
 
Unrealized gains (losses) on cash flow hedging activities arising during period, net of tax of $(4), $2 and $(7)
 
(7
)
 
4

 
(12
)
Cash flow hedging activities reclassified to interest expense, net of tax of $4, $4 and $4
 
7

 
7

 
7

Cash flow hedging activities reclassified to gas purchased for resale, net of tax of $-, $4 and $9
 
(1
)
 
6

 
15

Net unrealized gains (losses) on cash flow hedging activities
 
(1
)
 
17

 
10

Deferred Costs of Employee Benefit Plans:
 
 
 
 
 
 
Amortization of deferred employee benefit plan costs reclassified to net income (see Note 8), net of tax of $-, $- and $-
 

 
(1
)
 

Net deferred costs of employee benefit plans
 

 
(1
)
 

     Other Comprehensive Income (Loss)
 
(1
)
 
16

 
10

Total Comprehensive Income (Loss)
 
$
(120
)
 
$
611

 
$
756

 
See Notes to Consolidated Financial Statements.


64


SCANA Corporation and Subsidiaries
Consolidated Statements of Cash Flows
 
For the Years Ended December 31, (Millions of dollars)
 
2017
 
2016
 
2015
Cash Flows From Operating Activities:
 
 

 
 

 
 

Net Income (Loss)
 
$
(119
)
 
$
595

 
$
746

Adjustments to reconcile net income to net cash provided from operating activities:
 
 
 
 
 
 

Gain on sale of subsidiaries
 

 

 
(355
)
Impairment loss
 
1,118

 

 

  Deferred income taxes, net
 
(911
)
 
242

 
(31
)
Depreciation and amortization
 
406

 
389

 
368

Amortization of nuclear fuel
 
44

 
57

 
46

Allowance for equity funds used during construction
 
(23
)
 
(29
)
 
(27
)
Carrying cost recovery
 
(34
)
 
(17
)
 
(12
)
Changes in certain assets and liabilities:
 
 
 
 
 
 

Receivables
 
(56
)
 
(112
)
 
188

Income tax receivable
 
(56
)
 
(142
)
 

Inventories
 
(93
)
 
(43
)
 
(16
)
Prepayments
 
(5
)
 
11

 
211

Regulatory assets
 
181

 
(114
)
 
(31
)
Regulatory liabilities
 
1,051

 
(2
)
 
(1
)
Accounts payable
 
24

 
44

 
(78
)
Unrecognized tax benefits
 
(224
)
 
175

 
31

Taxes accrued
 
13

 
(41
)
 
61

Pension and other postretirement benefits
 
(20
)
 
51

 
(6
)
Derivative financial instruments
 
(3
)
 
(9
)
 
(9
)
     Other assets
 
(47
)
 
(44
)
 
(3
)
     Other liabilities
 
(77
)
 
81

 
(23
)
Net Cash Provided From Operating Activities
 
1,169

 
1,092

 
1,059

Cash Flows From Investing Activities:
 
 

 
 

 
 

Property additions and construction expenditures
 
(1,225
)
 
(1,579
)
 
(1,153
)
Proceeds from sale of subsidiaries
 

 

 
647

Proceeds from guaranty settlement
 
1,096

 

 

Proceeds from investments (including derivative collateral returned)
 
145

 
860

 
1,117

Purchase of investments (including derivative collateral posted)
 
(143
)
 
(788
)
 
(1,018
)
Payments upon interest rate derivative contract settlement
 
(39
)
 
(113
)
 
(263
)
  Proceeds from interest rate derivative contract settlement
 

 

 
10

Net Cash Used For Investing Activities
 
(166
)
 
(1,620
)
 
(660
)
Cash Flows From Financing Activities:
 
 

 
 

 
 

Proceeds from issuance of common stock
 

 

 
14

Proceeds from issuance of long-term debt
 
150

 
592

 
491

Repayments of long-term debt
 
(17
)
 
(117
)
 
(166
)
Dividends
 
(344
)
 
(325
)
 
(309
)
Short-term borrowings, net
 
(591
)
 
410

 
(387
)
Deferred financing costs
 

 

 
(3
)
Net Cash Provided From (Used For) Financing Activities
 
(802
)
 
560

 
(360
)
Net Increase in Cash and Cash Equivalents
 
201

 
32

 
39

Cash and Cash Equivalents, January 1
 
208

 
176

 
137

Cash and Cash Equivalents, December 31
 
$
409

 
$
208

 
$
176

Supplemental Cash Flow Information:
 
 

 
 

 
 

Cash for—Interest paid (net of capitalized interest of $18, $19 and $15)
 
$
346

 
$
328

 
$
306

              —Income taxes paid
 
2

 
229

 
184

              —Income taxes received
 
184

 
166

 

Noncash Investing and Financing Activities:
 
 
 
 
 
 

Accrued construction expenditures (including nuclear fuel)
 
139

 
109

 
244

Capital leases
 
8

 
15

 
6

 See Notes to Consolidated Financial Statements.

65


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, 2015
 
143

 
$
2,388

 
$
(10
)
 
$
2,684

 
$
(63
)
 
$
(12
)
 
$
(75
)
 
$
4,987

Net Income
 
 
 
 
 
 
 
746

 
 
 
 
 
 
 
746

Other Comprehensive Income (Loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Losses arising during the period
 
 
 
 
 
 
 
 
 
(12
)
 

 
(12
)
 
(12
)
 Losses/amortization reclassified from AOCI
 
 
 
 
 
 
 
 
 
22

 

 
22

 
22

  Total Comprehensive Income (Loss)
 
 
 
 
 
 
 
746

 
10

 

 
10

 
756

Issuance of Common Stock
 

 
14

 
(2
)
 
 
 
 
 
 
 
 
 
12

Dividends Declared
 
 
 
 
 
 
 
(312
)
 
 
 
 
 
 
 
(312
)
Balance as of December 31, 2015
 
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
 
 
 
 
 
 
 
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


Dividends declared per share of common stock were $2.45 , $2.30 and $2.18 for 2017, 2016 and 2015, respectively.

See Notes to Consolidated Financial Statements.


66



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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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'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 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. The Company 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’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 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.

Emphasis of Matter

As discussed in Note 10 to the financial statements, the abandoned Nuclear Project has led to legal, legislative, and regulatory matters that may result in material impacts to results and the liquidity of the Company.



 
/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 22, 2018

We have served as the Company's auditor since 1945.


70



South Carolina Electric & Gas Company and Affiliates
Consolidated Balance Sheets
 
December 31, (Millions of dollars)
 
2017
 
2016
Assets
 
 

 
 

Utility Plant In Service
 
$
12,161

 
$
11,510

Accumulated Depreciation and Amortization
 
(4,124
)
 
(3,991
)
Construction Work in Progress
 
375

 
4,813

Nuclear Fuel, Net of Accumulated Amortization
 
208

 
271

Utility Plant, Net ($711 and $756 related to VIEs)
 
8,620

 
12,603

Nonutility Property and Investments:
 
 

 
 

Nonutility property, net of accumulated depreciation
 
71

 
69

Assets held in trust, net-nuclear decommissioning
 
136

 
123

Other investments
 
2

 
3

Nonutility Property and Investments, Net
 
209

 
195

Current Assets:
 
 

 
 

Cash and cash equivalents
 
395

 
164

Receivables:
 
 
 
 
    Customer, net of allowance for uncollectible accounts of $4 and $3
 
390

 
378

    Affiliated companies
 
32

 
16

    Income taxes
 
198

 
53

    Other
 
85

 
94

Inventories:
 
 

 
 

Fuel
 
90

 
83

Materials and supplies
 
149

 
143

Prepayments
 
82

 
88

Derivative financial instrument
 
54

 

Other current assets
 
2

 
1

Total Current Assets ($191 and $85 related to VIEs)
 
1,477

 
1,020

Deferred Debits and Other Assets:
 
 

 
 

Regulatory assets
 
5,476

 
2,030

Other
 
164

 
243

Total Deferred Debits and Other Assets ($50 and $52 related to VIEs)
 
5,640

 
2,273

Total
 
$
15,946

 
$
16,091

 
See Notes to Consolidated Financial Statements.

71


December 31, (Millions of dollars)
 
2017
 
2016
Capitalization and Liabilities
 
 

 
 

Common Stock - no par value, 40.3 million shares outstanding for all periods presented
 
$
2,860

 
$
2,860

Retained Earnings
 
1,982

 
2,481

Accumulated Other Comprehensive Loss
 
(4
)
 
(3
)
Total Common Equity
 
4,838

 
5,338

Noncontrolling interest
 
142

 
134

Total Equity
 
4,980

 
5,472

Long-Term Debt, net
 
4,441

 
5,154

Total Capitalization
 
9,421

 
10,626

Current Liabilities:
 
 

 
 

Short-term borrowings
 
252

 
804

Current portion of long-term debt
 
723

 
12

Accounts payable
 
251

 
247

Affiliated payables
 
102

 
122

Customer deposits and customer prepayments
 
70

 
126

Taxes accrued
 
208

 
195

Interest accrued
 
67

 
68

Dividends declared
 
82

 
79

Derivative financial instruments
 
2

 
28

Other
 
47

 
55

Total Current Liabilities
 
1,804

 
1,736

Deferred Credits and Other Liabilities:
 
 

 
 

Deferred income taxes, net
 
1,173

 
1,939

Asset retirement obligations
 
529

 
522

Pension and postretirement benefits
 
217

 
232

Unrecognized tax benefits
 
19

 
236

Regulatory liabilities
 
2,667

 
695

Other
 
97

 
89

Other - affiliate
 
19

 
16

Total Deferred Credits and Other Liabilities
 
4,721

 
3,729

Commitments and Contingencies (Note 10)
 

 

Total
 
$
15,946

 
$
16,091

 
See Notes to Consolidated Financial Statements.

72


South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Comprehensive Income (Loss)
 
For the Years Ended December 31, (Millions of dollars)
 
2017
 
2016
 
2015
Operating Revenues:
 
 

 
 

 
 

Electric
 
$
2,659

 
$
2,614

 
$
2,551

Electric - nonconsolidated affiliate
 
5

 
5

 
6

Gas
 
405

 
366

 
372

Gas - nonconsolidated affiliate
 
1

 
1

 
1

Total Operating Revenues
 
3,070

 
2,986

 
2,930

Operating Expenses:
 
 

 
 

 
 

Fuel used in electric generation
 
465

 
472

 
559

Fuel used in electric generation - nonconsolidated affiliate
 
129

 
104

 
102

Purchased power
 
80

 
64

 
52

Gas purchased for resale
 
206

 
174

 
162

Gas purchased for resale - nonconsolidated affiliate
 

 
9

 
31

Other operation and maintenance
 
417

 
403

 
380

Other operation and maintenance - nonconsolidated affiliate
 
187

 
211

 
199

Impairment loss
 
1,118

 

 

Depreciation and amortization
 
312

 
302

 
294

Other taxes
 
241

 
227

 
211

Other taxes - nonconsolidated affiliate
 
5

 
7

 
6

Total Operating Expenses
 
3,160

 
1,973

 
1,996

Operating Income (Loss)
 
(90
)
 
1,013

 
934

Other Income (Expense), net
 
35

 
31

 
25

Interest charges, net of allowance for borrowed funds used during construction of $15, $18 and $14
 
(288
)
 
(270
)
 
(248
)
Income (Loss) Before Income Tax Expense
 
(343
)
 
774

 
711

Income Tax Expense (Benefit)
 
(171
)
 
248

 
231

Net Income (Loss) and Total Comprehensive Income (Loss)
 
(172
)
 
526

 
480

Less Net Income and Total Comprehensive Income Attributable to Noncontrolling Interest
 
13

 
13

 
14

Earnings (Loss) and Comprehensive Income Available (Loss Attributable) to Common Shareholder
 
$
(185
)
 
$
513

 
$
466

 
 
 
 
 
 
 
Dividends Declared on Common Stock
 
$
323

 
$
305

 
$
285

 
See Notes to Consolidated Financial Statements.



73


South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Cash Flow
For the Years Ended December 31, (Millions of dollars)
 
2017
 
2016
 
2015
Cash Flows From Operating Activities:
 
 

 
 

 
 

Net income (Loss)
 
$
(172
)
 
$
526

 
$
480

Adjustments to reconcile net income to net cash provided from operating activities:
 
 
 
 
 
 
Impairment loss
 
1,118

 

 

Deferred income taxes, net
 
(780
)
 
207

 
8

Depreciation and amortization
 
323

 
310

 
294

Amortization of nuclear fuel
 
44

 
57

 
46

Allowance for equity funds used during construction
 
(15
)
 
(26
)
 
(25
)
Carrying cost recovery
 
(34
)
 
(17
)
 
(12
)
Changes in certain assets and liabilities:
 
 
 
 
 
 
Receivables
 
(32
)
 
(47
)
 
85

Receivables - affiliate
 
12

 
(3
)
 
16

Income tax receivable
 
(145
)
 
(53
)
 

Inventories
 
(60
)
 
(35
)
 
(24
)
Prepayments
 
6

 
(4
)
 
70

Regulatory assets
 
185

 
(94
)
 
(29
)
Other regulatory liabilities
 
899

 
(5
)
 
(3
)
Accounts payable
 
20

 
8

 
11

Accounts payable - affiliate
 
(28
)
 
13

 
(17
)
Unrecognized tax benefits
 
(241
)
 
192

 
31

Taxes accrued
 
13

 
(104
)
 
129

Pension and other postretirement benefits
 
(21
)
 
39

 
(5
)
    Other assets
 
(46
)
 
(99
)
 
57

    Other liabilities
 
(43
)
 
58

 
(28
)
    Other liabilities - affiliate
 
3

 
(1
)
 
(6
)
Net Cash Provided From Operating Activities
 
1,006

 
922

 
1,078

Cash Flows From Investing Activities:
 
 

 
 

 
 

Property additions and construction expenditures
 
(928
)
 
(1,399
)
 
(1,008
)
Proceeds from guaranty settlement
 
1,096

 

 

Proceeds from investments and sales of assets (including derivative collateral returned)
 
118

 
794

 
975

Purchase of investments (including derivative collateral posted)
 
(122
)
 
(740
)
 
(887
)
Payments upon interest rate derivative contract settlement
 
(39
)
 
(113
)
 
(263
)
  Proceeds from interest rate derivative contract settlement
 

 

 
10

  Proceeds from investment in affiliate
 

 
9

 
71

Investment in affiliate
 
(28
)
 

 

Net Cash Used For Investing Activities
 
97

 
(1,449
)
 
(1,102
)
Cash Flows From Financing Activities:
 
 

 
 

 
 

Proceeds from issuance of long-term debt
 

 
494

 
491

Repayment of long-term debt
 
(12
)
 
(112
)
 
(11
)
Dividends
 
(319
)
 
(301
)
 
(285
)
Short-term borrowings, net
 
(552
)
 
384

 
(289
)
Short-term borrowings-nonconsolidated affiliate, net
 
8

 
(4
)
 
(50
)
Contribution from parent
 
3

 
100

 
204

Return of capital to parent
 

 

 
(4
)
Deferred financing costs
 

 

 
(2
)
Net Cash Provided From Financing Activities
 
(872
)
 
561

 
54

Net Increase in Cash and Cash Equivalents
 
231

 
34

 
30

Cash and Cash Equivalents, January 1
 
164

 
130

 
100

Cash and Cash Equivalents, December 31
 
$
395

 
$
164

 
$
130

Supplemental Cash Flow Information:
 
 

 
 

 
 

Cash for—Interest paid (net of capitalized interest of $15, $18 and $14)
 
$
269

 
$
251

 
$
228

              —Income taxes paid
 
47

 
289

 
89

              —Income taxes received
 
145

 
189

 
84

Noncash Investing and Financing Activities:
 
 
 
 
 
 
Accrued construction expenditures (including nuclear fuel)
 
99

 
95

 
230

Capital leases
 
8

 
14

 
6

  See Notes to Consolidated Financial Statements.

74


South Carolina Electric & Gas Company and Affiliates
Consolidated Statements of Changes in Equity
 
 
 
Common Stock
 
 
 
 
 
 
 
 
Millions
 
Shares
 
Amount
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 
Total
Equity
Balance at January 1, 2015
 
40

 
$
2,560

 
$
2,077

 
$
(3
)
 
$
123

 
$
4,757

Earnings available for common shareholder
 
 

 
 

 
466

 
 

 
14

 
480

Deferred cost of employee benefit plans, net of tax $-
 
 

 
 

 
 

 

 
 

 

Total Comprehensive Income
 
 
 
 
 
466

 

 
14

 
480

Capital contributions from parent
 
 

 
200

 
 

 
 

 

 
200

Cash dividends declared
 
 

 
 

 
(278
)
 
 

 
(8
)
 
(286
)
Balance at December 31, 2015
 
40

 
2,760

 
2,265

 
(3
)
 
129

 
5,151

Earnings Available for 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

 
(1
)
Total Comprehensive Income (Loss)
 
 
 
 
 
(185
)
 
(1
)
 
13

 
(173
)
Capital contributions from parent
 
 

 

 
 

 
 

 
3

 
3

Cash dividends declared
 
 

 
 

 
(314
)
 
 

 
(8
)
 
(322
)
Balance at December 31, 2017
 
40

 
$
2,860

 
$
1,982

 
$
(4
)
 
$
142

 
$
4,980

 
See Notes to Consolidated Financial Statements.


75


SCANA Corporation and Subsidiaries
South Carolina Electric & Gas Company and Affiliates
Notes to Consolidated Financial Statements

The following notes to the consolidated financial statements are 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 to SCANA Corporation or its subsidiaries (other than Consolidated SCE&G).

1.             SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Organization and Principles of Consolidation
 
The Company

SCANA, a South Carolina corporation, is a holding company. The Company engages predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina, the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia and conducts other energy-related business.
 
The accompanying consolidated financial statements reflect the accounts of SCANA, the following wholly-owned subsidiaries, and subsidiaries that formerly were wholly-owned during the periods presented.
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, a South Carolina corporation. Consolidated SCE&G engages predominantly 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&G has determined that it has a controlling financial interest in GENCO and Fuel Company (which are considered to be VIEs) and accordingly, Consolidated SCE&G's consolidated financial statements include the accounts of SCE&G, GENCO and Fuel Company. The equity interests in GENCO and Fuel Company are held solely by SCANA, SCE&G’s parent. As a result, GENCO’s and Fuel Company’s equity and results of operations are reflected as noncontrolling interest in Consolidated SCE&G’s consolidated financial statements.
 
GENCO owns a coal-fired electric generating station with a 605 MW net generating capacity (summer rating). GENCO’s electricity is sold, pursuant to a FERC-approved tariff, solely to SCE&G under the terms of a power purchase agreement and related operating agreement. The effects of these transactions are eliminated in consolidation. Substantially all of GENCO’s property (carrying value of approximately $503 million ) serves as collateral for its long-term borrowings. Fuel Company acquires, owns and provides financing for SCE&G’s nuclear fuel, certain fossil fuels and emission and other environmental allowances. See also Note 4.

Dispositions

In the first quarter of 2015, SCANA sold CGT and SCI. CGT was an interstate natural gas pipeline regulated by FERC that transported natural gas in South Carolina and southeastern Georgia, and it was sold to Dominion Resources, Inc. SCI provided fiber optic communications and other services and built, managed and leased communications towers in several

76


southeastern states, and it was sold to Spirit Communications. These sales resulted in recognition of pre-tax gains totaling approximately $342 million . The pre-tax gain from the sale of CGT is included within Operating Income and the pre-tax gain from the sale of SCI is included within Other Income (Expense) on the Company's consolidated statement of operations.

CGT and SCI operated principally in wholesale markets, whereas the Company's primary focus is the delivery of energy-related products and services to retail markets. In addition, neither CGT nor SCI met accounting criteria for disclosure as a reportable segment. The sales of CGT and SCI did not represent a strategic shift that had a major effect on the Company's operations; therefore, these sales did not meet the criteria for classification as discontinued operations.     
 
Use of Estimates
 
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of 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.

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, 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.
 
AFC 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. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company’s regulated subsidiaries calculated AFC using average composite rates of 5.6% for 2017, 5.3% for 2016, and 6.1% for 2015. Consolidated SCE&G calculated AFC using average composite rates of 3.9% for 2017, 4.7% for 2016, and 5.6% for 2015. These rates do not exceed the maximum rates allowed in the various regulatory jurisdictions. SCE&G capitalizes interest on nuclear fuel in process at the actual interest cost incurred.
 
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. In 2015, SCE&G adopted lower depreciation rates for electric and common plant, as approved by the SCPSC and further described in Note 2. In addition, CGT was sold in the first quarter of 2015 (see Dispositions herein) and excluded from the 2015 calculation of composite weighted average depreciation rates. The composite weighted average depreciation rates for utility plant assets were as follows:
 
2017
 
2016
 
2015
SCE&G
2.55
%
 
2.56
%
 
2.55
%
GENCO
2.66
%
 
2.66
%
 
2.66
%
PSNC Energy
3.03
%
 
2.90
%
 
2.94
%
Weighted average of above
2.63
%
 
2.61
%
 
2.61
%
Consolidated SCE&G
2.55
%
 
2.56
%
 
2.56
%

SCE&G records nuclear fuel amortization using the units-of-production method. Nuclear fuel amortization is included in Fuel used in electric generation and recovered through the fuel cost component of retail electric rates.

Jointly Owned Utility Plant
 
SCE&G jointly owns and is the operator of Unit 1. Each joint owner provides its own financing and shares the direct expenses and generation output in proportion to its ownership. SCE&G’s share of the direct expenses is included in the corresponding operating expenses on its income statement. Unit 2 and Unit 3 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.

77


As of December 31,
 
2017
 
2016
 
 
Unit 1
 
Unit 1
 
Unit 2 and Unit 3
Percent owned
 
66.7%
 
66.7%
 
55.0%
Plant in service
 
$
1.5
 billion
 
$
1.3
 billion
 
Accumulated depreciation
 
$
637.6
 million
 
$
634.4
 million
 
Construction work in progress
 
$
110.1
 million
 
$
167.7
 million
 
$
4.2
 billion
 
Included within other receivables on the balance sheet were amounts due to SCE&G from Santee Cooper for its share of direct expenses and construction costs for the units. These amounts totaled $53.8 million at December 31, 2017 and $76.2 million at December 31, 2016.

Major Maintenance

 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 SCPSC 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&G is authorized to collect $18.4 million annually through electric rates to offset certain turbine maintenance expenditures. For the years ended December 31, 2017, and 2016, SCE&G incurred $26.1 million and $23.8 million , respectively, for turbine maintenance.

Nuclear refueling outages are scheduled 18 months apart. As approved by the SCPSC, SCE&G accrues $17.2 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&G was responsible totaled $1.8 million in 2016 in preparation for the Spring 2017 outage and $23.2 million in 2017.
 
Goodwill
 
The Company considers certain amounts categorized by FERC as acquisition adjustments to be goodwill. The Company tests goodwill for impairment annually as of January 1, unless indicators, events or circumstances require interim testing to be performed. Accounting guidance adopted by the Company gives it the option to perform a qualitative assessment of impairment ("step zero"). Based on this qualitative assessment, if the Company determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, the Company is not required to proceed with a two-step quantitative assessment. If the quantitative assessment becomes necessary, step one requires estimation of the fair value of the reporting unit and the comparison of that amount to its carrying value. If this step indicates an impairment (a carrying value in excess of fair value), then step two, measurement of the amount of the goodwill impairment (if any), is required. Should a write-down be required, such a charge would be treated 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 utilized the step zero qualitative assessment in its evaluations as of January 1, 2018 and as of January 1, 2017 and was not required to use the two-step quantitative assessment.

Nuclear Decommissioning

Based on a decommissioning cost study, SCE&G’s two-thirds share of estimated site-specific nuclear decommissioning costs for Unit 1, including the cost of decommissioning plant components both subject to and not subject to radioactive contamination, totals $786.4 million , stated in 2016 dollars. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in Unit 1. 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’s method of funding decommissioning costs, SCE&G transfers to an external trust fund the amounts collected through rates ( $3.2 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

78


intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures for Unit 1 on an after-tax basis.
 
Cash and Cash Equivalents
 
Temporary cash investments having original maturities of three months or less at time of purchase are considered to be cash equivalents. These cash equivalents are generally in the form of commercial paper, certificates of deposit, repurchase agreements, treasury bills and money market funds.
 
Receivables
 
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 below. Customer receivables are generally due within one month of receipt of invoices which are presented on a monthly cycle basis. Unbilled revenues totaled $220.9 million at December 31, 2017 and $178.9 million at December 31, 2016 for the Company. Unbilled revenues totaled $140.3 million at December 31, 2017 and $117.6 million at December 31, 2016 for Consolidated SCE&G.
Other receivables consist primarily of amounts due from Santee Cooper related to the jointly owned nuclear generating facilities at Summer Station.

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, 39% and 40% of PSNC Energy’s natural gas inventory at December 31, 2017 and December 31, 2016, respectively, with a carrying value of $11.5 million and $9.8 million , respectively. Under the terms of this agreement, PSNC Energy receives storage asset management fees of which 75% are credited to customers. This agreement expires on March 31, 2019.
 
Income Taxes
 
SCANA files consolidated federal income tax returns. Under a joint consolidated income tax allocation agreement, each subsidiary’s current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such tax rates through charges or credits to regulatory assets or liabilities if such impacts are expected to be recovered from, or passed through to, customers of the Company’s regulated subsidiaries; otherwise, such adjustments are charged or credited to deferred income tax expense. Also, see Note 5 for a discussion of the impact of adjustments recorded upon enactment of the Tax Act.

Consolidated SCE&G is included in the consolidated federal income tax returns of SCANA. Also under provisions of the income tax allocation agreement, certain tax benefits of the parent holding company are distributed in cash 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 that have been or are expected to be allowed in the ratemaking process in periods different from the periods in which the costs would be charged to expense, or record revenues in periods different from the periods 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 (see Note 2) and are amortized consistent with the treatment of the related costs or revenues in the ratemaking process. Certain deferred amounts expected to be recovered or repaid within 12 months are classified in the balance sheet as Receivables - Customer or Customer deposits and customer prepayments, respectively.
 

79


Debt Issuance Premiums, Discounts and Other Costs
 
Premiums, discounts and debt issuance costs are presented within long-term debt and are amortized as components of interest charges over the terms of the respective debt issues. For regulated subsidiaries, gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and are amortized over the term of the replacement debt, also as interest charges.
 
Environmental
 
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). Consistent with this presentation, the Company presents the 2015 gain on the sale of CGT within Operating Income and the 2015 gain on the sale of SCI within Other Income (Expense).

Revenue Recognition
 
Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered 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&G customers subject to a PGA are billed based on a cost of gas factor calculated in accordance with a gas cost recovery procedure approved by the SCPSC and subject to adjustment monthly. 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.
 
SCE&G’s gas rate schedules for residential, small commercial and small industrial customers include a WNA which minimizes fluctuations in gas revenues due to abnormal weather conditions.
 
PSNC Energy is authorized by the NCUC to utilize a CUT which allows it to adjust base rates semi-annually for residential and commercial customers based on average per customer consumption, whether impacted by weather or other factors.
 
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 income. 

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 outstanding for the period. When applicable, the Company computes diluted earnings (loss) per share using

80


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 2017, the Company and Consolidated SCE&G adopted the following accounting guidance issued by the FASB. The adoption of this guidance had no impact on their respective financial statements except as indicated.

Guidance issued in August 2014 requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern. See related disclosure at Note 10.
Guidance issued in July 2015 requires most inventory to be measured at the lower of cost and net realizable value.
Guidance issued in October 2016 requires entities to recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs.

In January 2017, the FASB issued accounting guidance to simplify the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test. The guidance is effective for years beginning in 2020, though early adoption after January 1, 2017 is allowed. The Company adopted this guidance on January 1, 2018, and its adoption had no impact on its financial statements.

Pending Adoption

In the first quarter of 2018, the Company and Consolidated SCE&G will adopt the following accounting guidance issued by the FASB.

Guidance issued in May 2014 for revenue arising from contracts with customers supersedes most prior revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides for a five-step analysis in determining when and how revenue is recognized, and requires revenue recognition to depict the transfer of promised goods or services to customers, based on the transfer of control, in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In addition, this guidance requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The analysis of contracts with customers to which the guidance might be applicable has been completed and activities of the FASB's Transition Resource Group for Revenue Recognition, particularly as they relate to the treatment of CIAC, ARP and the collectability of revenue of utilities subject to rate regulation have been considered. Specifically, the Company and Consolidated SCE&G have concluded that their use of CIAC is outside the scope of the new revenue recognition guidance. The Company and Consolidated SCE&G have determined that aspects of SCE&G’s WNA and, for the Company, PSNC Energy's CUT allow for revenue adjustments to be recognized prior to amounts being reflected in customer bills. These revenue adjustments, which give rise to regulatory assets or liabilities, represent ARPs that are outside the scope of the new guidance and will be reported as Other operating revenue separately from revenue from contracts with customers on the statement of operations. An evaluation of the enhanced disclosure requirements is being completed, including determining the appropriate disaggregation of revenue.

The Company and Consolidated SCE&G will adopt this guidance using the modified retrospective method, and comparative periods will not be restated. In connection with this adoption, the Company has determined that its gas marketing subsidiary serves as an agent for gas distribution services in its retail market. Accordingly, certain pass through charges that the Company currently records within Gas-nonregulated revenues, and which are entirely offset within Gas purchased for resale, in the future will be recorded net on the statements of operations. The Company and Consolidated SCE&G do not anticipate that the adoption of this guidance will have any material impacts on their respective financial statements, but its adoption will result in additional disclosures. The adoption of this guidance will not result in a cumulative effect adjustment to beginning retained earnings.

Guidance issued in January 2016 changes how entities measure certain equity investments and financial liabilities, among other things. Entities will be required to make a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective, with certain exceptions. The Company and Consolidated SCE&G expect to adopt this guidance when required in the first quarter of 2018 and do not anticipate that its adoption will have a significant impact on their respective financial statements.

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Guidance issued in August 2016 is intended to reduce diversity in cash flow statement classification related to certain transactions, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G.

Guidance issued in November 2016 clarifies how restricted cash should be presented on the statement of cash flows, and entities must apply the guidance retrospectively to all periods presented. The adoption of this guidance will have no impact on the financial statements of the Company and Consolidated SCE&G.

Guidance issued in March 2017 changes the required presentation of net periodic pension and postretirement benefit costs. Under this guidance, such costs will be separated into service cost components and other components. The service cost components will be presented in the same line item (or items) as other compensation costs arising from services rendered by employees during the period. The other components will be reported in the income statement separately from the service cost component and outside operating income. Only the service cost component will be eligible for capitalization in assets. Entities must apply this guidance on a retrospective basis for the presentation of the service cost component and the other components, and on a prospective basis for the capitalization of only the service cost component. As permitted, service cost and other costs disclosed in related footnotes to previously issued financial statements will be used when estimating retrospective changes for such costs in the income statements for prior periods. Due to regulatory overlay, non-service cost components related to regulated operations that are capitalized in assets under current accounting guidance will be deferred within regulatory assets in the future. As a result, the adoption of this guidance will not have a material impact on the financial statements of the Company and Consolidated SCE&G.

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 accounting guidance related to the recognition, measurement and presentation of leases. The guidance applies a right-of-use model and, for lessees, requires all leases with a duration over 12 months to be recorded on the balance sheet, with the rights of use treated as assets and the payment obligations treated as liabilities. Further,
and without consideration of any regulatory accounting requirements which may apply, depending primarily on the nature of the assets and the relative consumption of them, lease costs will be recognized either through the separate amortization of the right-of-use asset and the recognition of the interest cost related to the payment obligation, or through the recording of a combined straight-line rental expense. For lessors, the guidance calls for the recognition of income either through the derecognition of assets and subsequent recording of interest income on lease amounts receivable, or through the recognition of rental income on a straight-line basis, also depending on the nature of the assets and relative consumption. In January 2018, FASB amended this accounting guidance to provide an optional transition practical expedient that would allow adopters to not evaluate under the new guidance existing or expired land easements that were not previously accounted for as leases under existing guidance. The new guidance is effective for years beginning in 2019, and the Company and Consolidated SCE&G do not anticipate that its adoption will impact their respective financial statements other than increasing amounts reported for assets and liabilities on the balance sheet and changing the place on their respective statements of operations on which certain expenses are recorded. No impact on net income (loss) is expected. The identification and analysis of leasing and related contracts to which the guidance might be applicable has begun. In addition, the Company and Consolidated SCE&G have begun implementation of a third party software tool that will assist with initial adoption and ongoing compliance. Specifically, preliminary system configuration has been completed and data from certain leases are being entered.

In June 2016, the FASB issued accounting guidance requiring the use of a current expected credit loss impairment model for certain financial instruments. The new model is applicable to trade receivables and most debt instruments, among other financial instruments, and 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. 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 2017, the FASB issued accounting guidance 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

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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 expect to adopt this guidance when required in the first quarter of 2019, though early adoption is permitted, and have not determined what impact such adoption will have 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 either 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 must adopt this guidance beginning in 2019, 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. No impact is expected on statements of operations or cash flows.

2.             RATE AND OTHER REGULATORY MATTERS
 
Rate Matters
 
Electric - Cost of Fuel

SCE&G's retail electric rates include a cost of fuel component approved by the SCPSC which may be adjusted periodically to reflect changes in the price of fuel purchased by SCE&G.
    
By order dated April 30, 2015, the SCPSC approved a settlement agreement among SCE&G and certain other parties in which SCE&G agreed to decrease the total fuel cost component of retail electric rates. Under this order, SCE&G is to recover an amount equal to its under-collected balance of base fuel and variable environmental costs as of April 30, 2015, over the subsequent 12-month period beginning with the first billing cycle of May 2015.

By order dated July 15, 2015, the SCPSC approved SCE&G's participation in a DER program and recovery of related costs as a separate component of SCE&G's overall fuel factor. Under this order, SCE&G is to implement programs to encourage the development of renewable energy facilities with a total nameplate capacity of at least approximately 84.5 MW by the end of 2020, of which half is to be customer-scale solar capacity and half is to be utility-scale solar capacity. This nameplate capacity goal was achieved in 2017.

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 will be allowed for base fuel component under-collected balances as they occur.

In October 2017, the SCPSC initiated its 2018 annual review of base rates for fuel costs. A public hearing for this annual review is scheduled for April 10, 2018.

Electric - Base Rates

Pursuant to an SCPSC order, SCE&G has 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 and $14.0 million during 2017 and 2016, respectively. As part of the impairment loss described in Note 10, accumulated carrying costs related to the Nuclear Project totaling $51.0 million were written off.


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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
2017
 
First billing cycle of May
 
$37.0 million
2016
 
First billing cycle of May
 
$37.6 million
2015
 
First billing cycle of May
 
$32.0 million

By order dated April 29, 2016, the SCPSC approved SCE&G’s request to increase its pension costs rider. The increased pension rider was designed to allow SCE&G to recover projected pension costs, including under-collections, over a 12-month period, beginning with the first billing cycle in May 2016.

By order dated March 1, 2017, the SCPSC approved SCE&G’s request to decrease its pension costs rider. The change in the pension rider decreased annual revenue by approximately $11.9 million . The pension rider is designed to allow SCE&G to recover projected pension costs, net of the previously over-collected balance, over a 12-month period, beginning with the first billing cycle in May 2017.

In December 2017, the ORS filed a petition with the SCPSC requesting all investor-owned utilities under the SCPSC’s jurisdiction to report the impact of the Tax Act on their individual company’s operations. The Tax Act contains provisions that lower the federal corporate tax rate from 35% to 21% effective January 1, 2018. The petition requested that utilities file an estimate of the Tax Act’s effects on their most recent test year information available, including an explanation of those effects, and requested that utilities propose procedures for changing rates to reflect the impacts. Lastly, the petition requested that the SCPSC state in its order that rates in effect as of January 1, 2018, be subject to refund so that ratepayers receive the benefit of the tax law changes as of January 1, 2018. By order dated January 10, 2018, the SCPSC granted the ORS petition but did not state that rates in effect as of January 1, 2018 would be subject to refund. SCE&G provided its comments on January 24, 2018, concerning the timing and the format of the report.

In January 2018, SCE&G submitted its annual DSM Programs filing to the SCPSC. If approved the filing would allow recovery of $37.0 million of costs and net lost revenues associated with DSM programs, along with an incentive to invest in such programs.

Electric - BLRA and Joint Petition

Under the BLRA, SCE&G filed revised rates with the SCPSC in 2015 and 2016 to incorporate the financing cost of incremental construction work in progress incurred for the Nuclear Project. Rate adjustments were based on SCE&G's updated cost of debt and capital structure and on an allowed ROE. No revised rates filing was pursued in 2017. The SCPSC approved recovery of the following amounts.
 
Increase
 
Effective for bills rendered on and after
 
Amount
 
Allowed ROE
 
 
2.7%
 
November 27, 2016
 
$64.4 million
 
10.50%
*
 
2.6%
 
October 30, 2015
 
$64.5 million
 
11.00%
 
*Applied prospectively for purposes of calculating revised rates under the BLRA on and after January 1, 2016.

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 (see Note 10). 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. 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.

The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G’s total project capital cost as then

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approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. In addition, SCE&G could not file future requests to amend capital cost schedules prior to January 28, 2019, unless its annual revised rate request was denied because SCE&G was out of compliance with its approved capital cost schedule or BLRA construction milestone schedule, subject to certain extensions. See also Abandoned Nuclear Project in Note 10.

Following WEC and WECTEC's bankruptcy filing on March 29, 2017, on June 22, 2017, the Friends of the Earth and the Sierra Club filed a complaint against SCE&G with the SCPSC, requesting that the SCPSC initiate a formal proceeding to direct SCE&G to immediately cease and desist from expending any further capital costs related to the construction of Unit 2 and Unit 3; to determine the prudence of acts and omissions by SCE&G in connection with this construction; to review and determine the prudence of abandonment of Unit 2 and Unit 3 and of the available least cost efficiency and renewable energy alternatives; and to remedy, abate and make due reparations for the rates charged to ratepayers related to the construction of Unit 2 and Unit 3. SCE&G filed its answer to the complaint and a motion to dismiss the complaint on July 19, 2017. On October 4, 2017, the SCPSC ordered proceedings under this complaint to be coordinated with proceedings for the Request filed by the ORS on September 26, 2017, described below, and allowed discovery to proceed. SCE&G's subsequent petition for rehearing and reconsideration was denied by the SCPSC on November 1, 2017. Proceedings related to this complaint have been consolidated with proceedings for the Request and the Joint Petition as described below.

On August 1, 2017, SCE&G filed the Abandonment Petition with the SCPSC which sought recovery of costs expended on the construction of Unit 2 and Unit 3, including certain costs incurred subsequent to SCE&G's last revised rates update, other costs under the abandonment provisions of the BLRA, and affirmation of SCE&G's decision to abandon construction of Unit 2 and Unit 3, among other things. Subsequently, SCE&G management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew the Abandonment Petition on August 15, 2017. See additional discussion at Note 10.

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which had been previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections.

On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed with the SCPSC a motion to amend its request, in which the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. A hearing on the parties' motions was held on December 12, 2017, and included the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, a large industrial customer, and several environmental groups.

By order dated December 20, 2017, the SCPSC denied SCE&G’s Motion to Dismiss the Request and ordered that a hearing be set on the Request. In addition, the SCPSC ordered the ORS to perform a thorough inspection and audit, within 30 days, to determine the reasonableness of SCE&G’s retail electric rates and to determine the reasonableness of SCE&G’s statements regarding the potential effect that the removal of approximately $445 million in annual revenues, as requested by the ORS, could have on SCE&G. The SCPSC also granted the ORS’s motion to amend the Request and consider the monetization of the Toshiba payout along with any other related factors that may be appropriate in determining a fair and reasonable rate. SCE&G intends to vigorously contest the Request, but cannot give any assurance as to the timing or outcome of this matter. Proceedings for the Request, the complaint filed by Friends of the Earth and the Sierra Club on June 22, 2017, and the Joint Petition discussed below have been consolidated.

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On November 20, 2017, the ORS filed a letter with the SCPSC providing the ORS's preliminary list for stabilization and protection of the site where Unit 2 and Unit 3 are located and suggesting that the SCPSC have SCE&G respond to the ORS's November 20, 2017 letter and "explain why there is no violation of S.C. Code Ann. § 58-27-1300." The SCPSC granted the ORS's request, and SCE&G filed its response with the SCPSC on December 27, 2017.

On January 12, 2018, SCE&G and Dominion Energy filed with the SCPSC the Joint Petition for review and approval of a proposed business combination whereby SCANA would become a wholly-owned subsidiary of Dominion Energy. In the Joint Petition, approval of a customer benefits plan and a cost recovery plan for the Nuclear Project is also sought. Key provisions of this Joint Petition are summarized at Note 10. A hearing on this matter has not yet been scheduled.

On January 19, 2018, the ORS filed a report with the SCPSC in response to the SCPSC's order for a thorough inspection and audit of SCE&G's statements regarding potential adverse effects that could result from the removal of annual BLRA revenues. The ORS report relied on the analysis of bankruptcy counsel to conclude that the suspension of revised rates collections is unlikely to force SCE&G into bankruptcy. Notwithstanding this conclusion, the ORS predicted that there is 35% likelihood of an SCE&G bankruptcy if revised rates are terminated. The report also indicated that a full audit, as ordered by the SCPSC, would require upwards of 90 days to complete. SCE&G filed responses to the ORS report alleging numerous deficiencies in it, including that the report was not verified by an accountant and that it contained incorrect and misleading accounting conclusions, particularly with regard to the timing and magnitude of any impairment loss that would be required by GAAP. On January 31, 2018, the SCPSC ordered the ORS to complete this previously ordered thorough audit, inspection and examination of SCE&G's accounting records by March 30, 2018, encouraged them to employ the assistance of a utility financial professional if needed, and indicated that a request by the ORS for an extension of time would not be considered unreasonable.

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
2017
 
2.2
%
 
Increase
 
$8.6 million
2016
 
1.2
%
 
Increase
 
$4.1 million
2015
 
No change
 

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. The annual reviews conducted for each of the 12-month periods ended July 31, 2017, 2016 and 2015 resulted in the SCPSC issuing an order finding that SCE&G's gas purchasing policies and practices during each of the review periods were reasonable and prudent. See Electric - Base Rates for a discussion of the ORS petition related to the Tax Act, which also applies to Gas - SCE&G.

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 its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy’s gas purchasing practices annually. In addition, PSNC Energy utilizes a CUT which allows it to adjust its base rates semi-annually for residential and commercial customers based on average per customer consumption.
    
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

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complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. PSNC Energy has filed biannual applications to adjust its rates for this purpose, and the NCUC has approved those applications for the incremental annual revenue requirements, as follows:
Rates Effective
 
Incremental Increase
March 1, 2017
 
$1.9 million
September 1, 2017
 
$0.7 million

In December 2017, in connection with PSNC Energy's 2017 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12 months ended March 31, 2017.

On January 3, 2018, the NCUC sought reports from its jurisdictional utilities as to how they planned to respond to the Tax Act. In its response on February 1, 2018, PSNC Energy proposed certain adjustments to its rates that, if enacted, would serve to reduce amounts that are currently being collected from customers based on pre-Tax Act rates. PSNC Energy cannot determine when the NCUC may take action on this matter.
 
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
 
2017
 
2016
 
2017
 
2016
Regulatory Assets:
 
 
 
 

 
 
 
 
Unrecovered Nuclear Project costs
 
$
3,976

 

 
$
3,976

 

Accumulated deferred income taxes
 

 
$
316

 

 
$
307

AROs and related funding
 
434

 
425

 
410

 
403

Deferred employee benefit plan costs
 
305

 
342

 
273

 
309

Deferred losses on interest rate derivatives
 
456

 
620

 
456

 
620

Other unrecovered plant
 
105

 
117

 
105

 
117

DSM Programs
 
59

 
59

 
59

 
59

Carrying costs on deferred tax assets related to the Nuclear Project
 

 
32

 

 
32

Pipeline integrity management costs
 
51

 
33

 
8

 
6

Environmental remediation costs
 
30

 
32

 
25

 
26

Deferred storm damage costs
 
24

 
20

 
24

 
20

Deferred costs related to uncertain tax position
 

 
15

 

 
15

Other
 
140

 
119

 
140

 
116

Total Regulatory Assets
 
$
5,580

 
$
2,130

 
$
5,476

 
$
2,030

 
Regulatory Liabilities:
 
 
 
 

 
 
 
 
Monetization of guaranty settlement
 
$
1,095

 

 
$
1,095

 

Accumulated deferred income taxes
 
1,076

 
23

 
914

 
14

Asset removal costs
 
757

 
755

 
527

 
529

Deferred gains on interest rate derivatives
 
131

 
151

 
131

 
151

Other
 

 
1

 

 
1

Total Regulatory Liabilities
 
$
3,059

 
$
930

 
$
2,667

 
$
695


Regulatory assets for unrecovered Nuclear Project costs have been recorded based on such amounts 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

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orders certain of the items shown as regulatory assets. Other regulatory assets include, but are not limited to, certain costs which have not been specifically approved for recovery by one of these regulatory agencies, including unrecovered nuclear project costs that are the subject of regulatory proceedings as further discussed in Note 10. In recording such costs as regulatory assets, management believes the costs would be allowable under existing rate-making concepts that are embodied in rate orders or current 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, 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 as a result of the decision to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs under the abandonment provisions of the BLRA or through other regulatory means, net of an estimated impairment loss and the transfer of certain assets described at Note 10.

Accumulated deferred income taxes contained within regulatory assets represent deferred tax liabilities that arise from utility operations that have not been included in customer rates.  A portion of these regulatory assets related to depreciation and are netted within regulatory liabilities in the current period.

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 107 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. The amounts recorded with respect to (i) are expected to be amortized to interest expense over the lives of the underlying debt through 2043. The amounts recorded with respect to (ii) are expected to be similarly amortized to interest expense through 2065 except when such amounts are applied otherwise at the direction of the SCPSC. See also Note 10 for a discussion of certain amounts that were treated as impaired as of December 31, 2017.

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 currently being recovered over approximately five years through an approved rate rider.

Carrying costs on deferred tax assets related to the Nuclear Project were calculated on accumulated deferred income tax assets associated with Unit 2 and Unit 3 which were not part of electric rate base using the weighted average long-term debt cost of capital. These carrying costs were written off as a part of the impairment loss in 2017. See also Note 10.

Pipeline integrity management costs represent operating and maintenance costs incurred 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, 2017 costs of $26.6 million have been deferred pending future approval of rate recovery. SCE&G amortizes $1.9 million of such costs annually.


88


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 17 years, and PSNC Energy's remediation costs total $6.9 million are being recovered over a five year period that will end in 2021 .

Deferred storm damage costs represent costs incurred in excess of amounts previously collected through SCE&G's SCPSC-approved storm damage reserve, and for which SCE&G expects to receive future recovery through customer rates.

Deferred costs related to uncertain tax position primarily represented the estimated amounts of domestic production activities deductions foregone as a result of the deduction of certain research and experimentation expenditures for income tax purposes, net of related tax credits, as well as accrued interest expense and other costs arising from this uncertain tax position. SCE&G's current customer rates reflect the availability of domestic production activities deductions. These net deferred costs were written off as a part of the impairment loss in 2017. See Note 5 and Note 10.

Various other regulatory assets are expected to be recovered through rates over periods through 2047 .

Monetization of guaranty settlement represents proceeds received under or arising from the monetization of the Toshiba Settlement, net of certain expenses.    

Accumulated deferred income taxes contained within regulatory liabilities represent (i) excess deferred income taxes arising from the remeasurement of deferred income taxes upon the enactment of the Tax Act (certain of which are protected under normalization regulations and will be amortized over the remaining lives of related property, and certain of which will be amortized to the benefit of customers over a prescribed period 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 5.

Asset removal costs represent estimated net collections through depreciation rates of amounts to be incurred for the removal of assets in the future.

3.                                       COMMON EQUITY
  
Authorized shares of SCANA common stock were 200 million as of December 31, 2017 and 2016. Authorized shares of SCE&G common stock were 50 million as of December 31, 2017 and 2016. Authorized shares of SCE&G preferred stock were 20 million , of which 1,000 shares, no par value, were held by SCANA as of December 31, 2017 and 2016.

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. SCANA has agreed to obtain the consent of Dominion Energy, which consent cannot be unreasonably withheld, prior to making dividend payments to shareholders greater than $0.6125 per share for any quarter while the Merger Agreement is pending.

SCE&G’s bond indenture under which it issues First Mortgage Bonds contains provisions that could limit the payment of cash dividends on its common stock. SCE&G's bond indenture permits the payment of dividends on SCE&G's common stock only either (1) out of its Surplus (which as defined in the bond indenture equates to its retained earnings) 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 December 31, 2017 and 2016, retained earnings of approximately $93.9 million and $79.0 million , respectively, were restricted by this requirement as to payment of cash dividends on SCE&G’s common stock.

PSNC Energy’s note purchase and debenture purchase agreements contain provisions that could limit the payment 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, 2017, this limitation would permit PSNC Energy to pay cash distributions in excess of $100 million .


89


4.    LONG-TERM AND SHORT-TERM DEBT
 
Long-term debt by type with related weighted average effective interest rates and maturities at December 31 is as follows:
The Company
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
 
 
 
2017
 
2016
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)
 
2018
-
2034
 
75

 
2.18
%
 
79

 
1.63
%
SCE&G First Mortgage Bonds (secured)
 
2018
-
2065
 
4,840

 
5.80
%
 
4,840

 
5.79
%
GENCO Notes (secured)
 
2018
-
2024
 
207

 
5.94
%
 
213

 
5.93
%
Industrial and Pollution Control Bonds (b)
 
2028
-
2038
 
122

 
3.52
%
 
122

 
3.51
%
PSNC Energy Senior Debentures and Notes
 
2020
-
2046
 
600

 
5.19
%
 
450

 
5.53
%
Other
 
2018
-
2027
 
28

 
2.83
%
 
27

 
2.76
%
Total debt
 
 
 
 
 
6,672

 
 
 
6,531

 
 
Current maturities of long-term debt
 
 
 
 
 
(727
)
 
 
 
(17
)
 
 
Unamortized discount, net
 
 
 
 
 
(1
)
 
 
 
(1
)
 
 
Unamortized debt issuance costs
 
 
 
 
 
(38
)
 
 
 
(40
)
 
 
Total long-term debt, net
 
 
 
 
 
$
5,906

 
 
 
$
6,473

 
 

Consolidated SCE&G
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
 
 
 
2017
 
2016
Dollars in millions
 
Maturity
 
Balance
 
Rate
 
Balance
 
Rate
First Mortgage Bonds (secured)
 
2018
-
2065
 
$
4,840

 
5.80
%
 
$
4,840

 
5.79
%
GENCO Notes (secured)
 
2018
-
2024
 
207

 
5.94
%
 
213

 
5.93
%
Industrial and Pollution Control Bonds (b)
 
2028
-
2038
 
122

 
3.52
%
 
122

 
3.51
%
Other
 
2018
-
2027
 
28

 
2.83
%
 
26

 
2.76
%
Total debt
 
 
 
 
 
5,197

 
 
 
5,201

 
 

Current maturities of long-term debt
 
 
 
 
 
(723
)
 
 
 
(12
)
 
 

Unamortized premium, net
 
 
 
 
 
1

 
 
 
1

 
 

Unamortized debt issuance costs
 
 
 
 
 
(34
)
 
 
 
(36
)
 
 
Total long-term debt, net
 
 
 
 
 
$
4,441

 
 
 
$
5,154

 
 


(a)  Variable rate notes hedged by a fixed interest rate swap (fixed rate of 6.17% ).
(b) Includes variable rate debt of $67.8 million at December 31, 2017 (rate of 1.85% ) and 2016 (rate of 0.76% ) which are hedged by fixed swaps.
    
In June 2016, SCE&G issued $425 million of 4.1% first mortgage bonds due June 15, 2046. Also in June 2016, SCE&G issued $75 million of 4.5% first mortgage bonds due June 1, 2064, which constituted a reopening of $300 million of 4.5% first mortgage bonds issued in May 2014. Proceeds from these sales were used to repay short-term debt primarily incurred as a result of SCE&G’s construction program, to finance capital expenditures, and for general corporate purposes.

In June 2017, PSNC Energy issued $150 million of 4.18% senior notes due June 30, 2047. In June 2016, PSNC Energy issued $100 million of 4.13% senior notes due June 22, 2046. Proceeds from these sales were used to repay short-term debt, to finance capital expenditures, and for general corporate purposes.

The Company's long-term debt maturities will be $727 million in 2018, $16 million in 2019, $366 million in 2020, $494 million in 2021 and $264 million in 2022. These amounts include, for Consolidated SCE&G, $723 million in 2018, $12 million in 2019, $11 million in 2020, $40 million in 2021 and $9 million in 2022.

Substantially all electric utility plant is pledged as collateral in connection with long-term debt.

SCE&G 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

90


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, 2017, the Bond Ratio was 5.24 . Adjusted Net Earnings, as therein defined, excludes the impairment loss.

Lines of Credit and Short-Term Borrowings
 
At December 31, 2017 and 2016, SCANA, SCE&G (including Fuel Company) and PSNC Energy had available the following committed LOC and had outstanding the following LOC-related obligations and commercial paper borrowings:
Millions of dollars
 
Total
 
SCANA
 
SCE&G
 
PSNC  Energy
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

December 31, 2016
 
 
 
 
 
 
 
 
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)
 
$
940.5

 
$
64.4

 
$
804.3

 
$
71.8

Weighted average interest rate
 
 
 
1.43
%
 
1.04
%
 
1.07
%
Letters of credit supported by LOC
 
$
3.3

 
$
3.0

 
$
0.3

 

Available
 
$
1,056.2

 
$
332.6

 
$
595.4

 
$
128.2


 SCANA, SCE&G (including Fuel Company) and PSNC Energy are parties to credit agreements in the amounts and for the terms described above. These credit agreements are used for general corporate purposes, including liquidity support for each company's commercial paper program and working capital needs and, in the case of Fuel Company, to finance or refinance the purchase of nuclear fuel, certain fossil fuels, and emission and other environmental allowances.  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% 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.
SCE&G has obtained FERC authority 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 billion outstanding with maturity dates of one year or less, and may enter into guaranty agreements in favor of lenders, banks, and dealers in commercial paper in amounts not to exceed $600 million . GENCO has obtained FERC authority 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 2018. 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.

91


Each of the Company and Consolidated SCE&G is obligated with respect to an aggregate of $67.8 million of industrial revenue bonds which are secured by letters of credit issued by TD Bank N.A.  The letters of credit expire, subject to renewal, in the fourth quarter of 2019.

Consolidated SCE&G participates in a utility money pool with SCANA and certain other subsidiaries of SCANA. Money pool borrowings and investments bear interest at short-term market rates. Consolidated SCE&G’s interest income and expense from money pool transactions were not significant for any period presented. 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 . At December 31, 2016, Consolidated SCE&G had outstanding money pool borrowings due to an affiliate of $29 million . On SCE&G's consolidated balance sheets, amounts due from an affiliate are included within Receivables-affiliated companies, and amounts due to an affiliate are included within Affiliated payables.

5.                                       INCOME TAXES
 
Components of income tax expense (benefit) are as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current taxes (benefit):
 
 
 
 
 
 
 
 
 
 
 
 
Federal
 
$
(414
)
 
$
36

 
$
382

 
$
(410
)
 
$
50

 
$
208

State
 
18

 
13

 
57

 
(18
)
 
13

 
32

Total current taxes (benefit)
 
(396
)
 
49

 
439

 
(428
)
 
63

 
240

Deferred tax (benefit) expense, net:
 
 
 
 
 
 

 
 
 
 
 
 
Federal
 
323

 
203

 
(36
)
 
261

 
167

 
(3
)
State
 
(37
)
 
21

 
(7
)
 
(2
)
 
20

 
(3
)
Total deferred taxes (benefit)
 
286

 
224

 
(43
)
 
259

 
187

 
(6
)
Investment tax credits:
 
 
 
 
 
 

 
 
 
 
 
 
Amortization of amounts deferred-state
 

 

 
(1
)
 

 

 
(1
)
Amortization of amounts deferred-federal
 
(2
)
 
(2
)
 
(2
)
 
(2
)
 
(2
)
 
(2
)
Total investment tax credits
 
(2
)
 
(2
)
 
(3
)
 
(2
)
 
(2
)
 
(3
)
Total income tax expense (benefit)
 
$
(112
)
 
$
271

 
$
393

 
$
(171
)
 
$
248

 
$
231


The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income is reconciled as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Net income (loss)
 
$
(119
)
 
$
595

 
$
746

 
$
(185
)
 
$
513

 
$
466

Income tax expense (benefit)
 
(112
)
 
271

 
393

 
(171
)
 
248

 
231

Noncontrolling interest
 

 

 

 
13

 
13

 
14

Total pre-tax income (loss)
 
$
(231
)
 
$
866

 
$
1,139

 
$
(343
)
 
$
774

 
$
711

 
 
 
 
 
 
 
 
 
 
 
 
 
Income taxes (benefit) on above at statutory federal income tax rate
 
$
(81
)
 
$
303

 
$
399

 
$
(120
)
 
$
271

 
$
249

Increases (decreases) attributed to:
 
 
 
 
 
 

 
 
 
 
 
 
State income taxes (less federal income tax effect)
 
(7
)
 
27

 
38

 
(8
)
 
26

 
24

State investment tax credits (less federal income tax effect)
 
(5
)
 
(5
)
 
(6
)
 
(5
)
 
(5
)
 
(6
)
Allowance for equity funds used during construction
 
(8
)
 
(10
)
 
(9
)
 
(5
)
 
(9
)
 
(9
)
Deductible dividends—401(k) Retirement Savings Plan
 
(9
)
 
(10
)
 
(10
)
 

 

 

Amortization of federal investment tax credits
 
(2
)
 
(2
)
 
(2
)
 
(2
)
 
(2
)
 
(2
)
Section 45 tax credits
 
(8
)
 
(8
)
 
(9
)
 
(8
)
 
(8
)
 
(9
)
Domestic production activities deduction
 
(18
)
 
(23
)
 
(18
)
 
(18
)
 
(23
)
 
(18
)
Remeasurement of deferred taxes upon enactment of Tax Act
 
30

 

 

 
(1
)
 

 

Realization of basis differences upon sale of subsidiaries
 

 

 
7

 

 

 

Other differences, net
 
(4
)
 
(1
)
 
3

 
(4
)
 
(2
)
 
2

Total income tax expense (benefit)
 
$
(112
)
 
$
271

 
$
393

 
$
(171
)
 
$
248

 
$
231


92


 
The tax effects of significant temporary differences comprising net deferred tax liabilities are as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2017
 
2016
Deferred tax assets:
 
 
 
 
 
 
 
 
Net operating loss and tax credit carryforward
 
$
600

 

 
$
541

 

Toshiba settlement
 
273

 

 
273

 

Nondeductible accruals
 
88

 
$
148

 
42

 
$
53

Asset retirement obligation, including nuclear decommissioning
 
141

 
213

 
132

 
200

Regulatory liability, non-property accumulated deferred income tax
 
54

 

 
54

 

Financial instruments
 
15

 
22

 

 

Unamortized investment tax credits
 
8

 
15

 
8

 
15

Deferred fuel costs
 

 
17

 

 
17

Other
 
6

 
10

 
5

 
8

Total deferred tax assets
 
1,185

 
425

 
1,055

 
293

Deferred tax liabilities:
 
 
 
 
 
 
 
 
Property, plant and equipment
 
1,220

 
2,159

 
1,035

 
1,856

Regulatory asset, unrecovered nuclear plant costs
 
962

 

 
962

 

Deferred employee benefit plan costs
 
60

 
105

 
53

 
93

Regulatory asset, asset retirement obligation
 
91

 
143

 
85

 
135

Regulatory asset, other unrecovered plant
 
27

 
45

 
27

 
45

Demand side management costs
 
16

 
23

 
16

 
23

Prepayments
 
21

 
32

 
19

 
30

Other
 
49

 
77

 
31

 
50

Total deferred tax liabilities
 
2,446

 
2,584

 
2,228

 
2,232

Net deferred tax liabilities
 
$
1,261

 
$
2,159

 
$
1,173

 
$
1,939


The federal and state tax credits and NOL carryforwards are presented below:
 
 
December 31, 2017
Millions of dollars
 
The Company
 
Consolidated SCE&G
 
Expiration Year
Federal NOL Carryforwards
 
$
2,052

 
$
1,905

 
2037
Federal Tax Credits
 
35

 
35

 
2035
-
2037
Federal Charitable Carryforwards
 
7

 
5

 
2021
-
2022
State NOL Carryforwards
 
2,382

 
2,301

 
2037
State Charitable Carryforwards
 
3

 
2

 
2022
Total Tax Credits and NOL Carryforwards
 
$
4,479

 
$
4,248

 
 
 
 

A valuation allowance is needed when it is more likely than not that all or a portion of a deferred tax asset will not be realized. In determining whether 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 a deferred tax asset. Based on this evaluation, management has concluded that a valuation allowance is not needed.

In December 2017, the Tax 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 deferred income tax balances within regulatory liabilities (see Note 2). In connection with this remeasurement, however, the Company recorded additional deferred income tax expense of approximately $30 million , and Consolidated SCE&G recorded a deferred income tax benefit of approximately $1 million in their respective statements of operations for the year ended December 31, 2017. Upon the eventual filing of the Company’s 2017 consolidated income tax return, adjustments to deferred income taxes and deferred income taxes may be recorded; however, these adjustments are not expected to have a material impact on the Company’s financial position, results of operations or cash flows.


93


The State of North Carolina lowered its corporate income tax rate from 6.0% to 5.0% in 2015, 4.0% in 2016, 3% in 2017 and 2.5% effective January 1, 2019. In connection with these changes in tax rates, related state deferred tax amounts were remeasured, with 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, results of operations or cash flows.
    
The Company files consolidated federal income tax returns which includes Consolidated SCE&G, and the Company and its subsidiaries file various applicable state and local income tax returns.

The IRS has completed examinations of the Company’s federal returns through 2004, and the Company’s federal returns through 2009 are closed for additional assessment. The IRS is currently examining SCANA's open federal returns through 2015 as a result of claims discussed below. With few exceptions, the Company, including Consolidated SCE&G, is no longer subject to state and local income tax examinations by tax authorities for years before 2010.
 
Changes in Unrecognized Tax Benefits
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Unrecognized tax benefits, January 1
 
$
350

 
$
49

 
$
16

 
$
350

 
$
49

 
$
16

Gross increases—uncertain tax positions in prior period
 

 
94

 
33

 

 
94

 
33

Gross decreases—uncertain tax positions in prior period
 
(273
)
 

 
(2
)
 
(273
)
 

 
(2
)
Gross increases—current period uncertain tax positions
 
21

 
207

 
2

 
21

 
207

 
2

Unrecognized tax benefits, December 31
 
$
98

 
$
350

 
$
49

 
$
98

 
$
350

 
$
49

    
During 2013 and 2014, the Company amended certain of its income tax returns to claim additional tax-defined research and experimentation deductions (under IRC Section 174) and credits (under IRC Section 41) and to reflect related impacts on other items such as domestic production activities deductions (under IRC Section 199). 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 expects to claim similar deductions and credits in its 2017 tax return when it is 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 2015 income tax returns, and it is expected that the IRS will also examine later 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 anticipate that an abandonment loss deduction under IRC Section 165 will be claimed on the 2017 tax return. As such, certain of the IRC Section 174 deductions, to the extent they are denied, would instead be deductible in 2017 under IRC Section 165. The abandonment loss deduction is also considered an uncertain tax position; however, under relevant accounting guidance, no estimated unrecognized tax benefits were recorded as of December 31, 2017. The remaining unrecognized tax benefits include the impact of the IRC Section 174 deductions on domestic production activities deductions, credits, and certain unrecognized state tax benefits.

As of December 31, 2017, the Company and Consolidated SCE&G have recorded an unrecognized tax benefit of $98 million ( $19 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, $98 million of the tax benefit would affect the Company’s and Consolidated SCE&G's effective tax rates. These unrecognized tax benefits are not expected to increase significantly within the next 12 months. It is also reasonably possible that these unrecognized tax benefits may decrease by $11 million within the next 12 months. No other material changes in the status of the Company’s or Consolidated SCE&G's tax positions have occurred through December 31, 2017.


94


In connection with the research and experimentation deduction and credit claims reflected on the 2015 and 2016 income tax returns and similar claims made in determining taxable income for 2017, and under the terms of an SCPSC order, the Company and Consolidated SCE&G recorded regulatory assets for estimated foregone domestic production activities deductions, offset by estimated tax credits, with the expectation that these deferred costs and related interest thereon would be recoverable through customer rates in future years (see Note 2). However, as further described in Note 10, as of December 31, 2017, an impairment loss with respect to such deferred regulatory asset was recorded. SCE&G's current customer rates reflect the availability of domestic production activities deductions.

Also under the terms of an SCPSC order, estimated interest expense accrued with respect to the unrecognized tax benefits related to the research and experimentation deductions in the 2015 and 2016 income tax returns was deferred as a regulatory asset and was expected to be recoverable through customer rates in future years. An impairment loss with respect to these deferred amounts was also recorded as of December 31, 2017 (see Note 10). Otherwise, the Company and Consolidated SCE&G recognize interest accrued related to unrecognized tax benefits within interest expense or interest income and recognize tax penalties within other expenses. Amounts recorded for such interest income, interest expense or tax penalties have not been material for any period presented.

6.                                       DERIVATIVE FINANCIAL INSTRUMENTS
 
Derivative instruments are recognized either as assets or liabilities in the statement of financial position and are measured at fair value. Changes in the fair value of derivative instruments are recognized either in earnings, as a component of other comprehensive income (loss) or, for regulated operations, within regulatory assets or regulatory liabilities, depending upon the intended use of the derivative and the resulting designation. 

Policies and procedures, and in some cases risk limits, are established to control the level of market, credit, liquidity and operational and administrative risks. SCANA’s Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure for SCANA and each of its subsidiaries. The Risk Management Committee, which is comprised of certain officers, including the Risk Management Officer and other senior officers, apprises the Audit Committee of the Board of Directors with regard to the management of risk and brings to their attention significant areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions.

Commodity Derivatives
 
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types.  Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. Instruments designated as fair value hedges are used to mitigate exposure to fluctuating market prices created by fixed prices of stored natural gas.  The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as options and swaps, which are typically offered by energy companies and financial institutions.  Cash settlements of commodity derivatives are classified as operating activities in the consolidated statements of cash flows.

PSNC Energy hedges natural gas purchasing activities using over-the-counter options and NYMEX futures and options.  PSNC Energy’s tariffs include a provision for the recovery of actual gas costs incurred, including any costs of hedging.  PSNC Energy records premiums, transaction fees, margin requirements and any realized gains or losses from its hedging program in deferred accounts as a regulatory asset or liability for the under- or over-recovery of gas costs.  These derivative financial instruments are not designated as hedges for accounting purposes.

Unrealized gains and losses on qualifying cash flow hedges of nonregulated operations are deferred in AOCI.  When the hedged transactions affect earnings, previously recorded gains and losses are reclassified from AOCI to cost of gas.  The effects of gains or losses resulting from these hedging activities are either offset by the recording of the related hedged transactions or are included in gas sales pricing decisions made by the business unit.
 
As an accommodation to certain customers, SCANA Energy, as part of its energy management services, offers fixed price supply contracts which are accounted for as derivatives.  These sales contracts are offset by the purchase of supply futures and swaps which are also accounted for as derivatives. Neither the sales contracts nor the related supply futures and swaps are designated as hedges for accounting purposes.


95


Interest Rate Swaps

Interest rate swaps may be used to manage interest rate risk and exposure to changes in fair value attributable to changes in interest rates on certain debt issuances.  In cases in which swaps designated as cash flow hedges are used to synthetically convert variable rate debt to fixed rate debt, periodic payments to or receipts from swap counterparties related to these derivatives are recorded within interest expense.

Forward starting swap agreements that are designated as cash flow hedges may be used in anticipation of the issuance of debt.  Except as described in the following paragraph, the effective portions of changes in fair value and payments made or received upon termination of such agreements for regulated subsidiaries are recorded in regulatory assets or regulatory liabilities. For SCANA and its nonregulated subsidiaries, such amounts are recorded in AOCI. Such amounts are amortized to interest expense over the term of the underlying debt. Ineffective portions of fair value changes are recognized in income.

Pursuant to regulatory orders, interest rate derivatives entered into by SCE&G after October 2013 are not designated 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 have generally been amortized over the lives of subsequent debt issuances and gains have been amortized to interest expense or may be applied as otherwise directed by the SCPSC. However, see Note 10 for a discussion of the impairment of previously deferred regulatory asset amounts related to settlement losses on swaps that had been entered into for debt that was anticipated to be issued in connection with the Nuclear Project.

Cash payments made or received upon termination of these financial instruments are classified as investing activities for cash flow statement purposes.
 
Quantitative Disclosures Related to Derivatives
 
The Company was party to natural gas derivative contracts outstanding in the following quantities:
 
 
Commodity and Other Energy Management Contracts (in MMBTU)
Hedge designation
 
Gas Distribution
 
Gas Marketing
 
Total
As of December 31, 2017
 
 

 
 

 
 

Commodity
 
6,430,000

 
13,433,000

 
19,863,000

Energy Management (a)
 

 
41,856,890

 
41,856,890

Total (a)
 
6,430,000

 
55,289,890

 
61,719,890

 
 
 
 
 
 
 
As of December 31, 2016
 
 

 
 

 
 

Commodity
 
4,510,000

 
11,947,000

 
16,457,000

Energy Management (a)
 

 
67,447,223

 
67,447,223

Total (a)
 
4,510,000

 
79,394,223

 
83,904,223


(a) Includes amounts related to basis swap contracts totaling 2,582,000 MMBTU in 2017 and 730,721 MMBTU in 2016.

The aggregate notional amounts of the interest rate swaps were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
December 31, 2017
 
December 31, 2016
 
December 31, 2017
 
December 31, 2016
Designated as hedging instruments
 
$
111.2

 
$
115.6

 
$
36.4

 
$
36.4

Not designated as hedging instruments
 
735.0

 
1,285.0

 
735.0

 
1,285.0


The following table shows the fair value and balance sheet location of derivative instruments. Although derivatives subject to master netting arrangements are netted on the consolidated balance sheet, the fair values presented below are shown gross and cash collateral on the derivatives has not been netted against the fair values shown.


96


Fair Values of Derivative Instruments
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
Balance Sheet Location
 
Asset
 
Liability
 
Asset
 
Liability
As of December 31, 2017
 
 

 
 

 
 
 
 
Designated as hedging instruments
 
 

 
 

 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
 
 
$
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 deferred debits and other assets
 


 
 
 

 
 
 
 
Derivative financial instruments
 
$
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

 
 
 
 
 
 
 
 
Derivative financial instruments
 
 
 
2

 
 
 
 
Total
 
 
 
$
59

 
$
8

 
$
54

 
$
5

 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2016
 
 
 
 
 
 
 
 
Designated as hedging instruments
 
 
 
 
 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
 
 
$
4

 
 
 
$
1

 
 
Other deferred credits and other liabilities
 
 
 
24

 
 
 
8

Commodity contracts
 
 
 
 
 
 
 
 
 
 
Prepayments
 
$
5

 


 
 
 
 
 
 
Other current assets
 
1

 

 
 
 
 
Total
 
$
6

 
$
28

 

 
$
9

 
 
 
 
 
 
 
 
 
 
 
Not designated as hedging instruments
 
 
 
 
 
 
 
 
Interest rate contracts
 
 
 
 
 
 
 
 
 
 
Other deferred debits and other assets
 
$
71

 
 
 
$
71

 
 
 
 
Derivative financial instruments
 
 
 
$
27

 
 
 
$
27

 
 
Other deferred credits and other liabilities
 
 
 
3

 
 
 
3

Commodity contracts
 
 
 
 
 
 
 
 
 
 
Other current assets
 
3

 
 
 
 
 
 
Energy management contracts
 
 
 
 
 
 
 
 
 
 
Prepayments
 
6

 
2

 
 
 
 
 
 
Other current assets
 
2

 
1

 
 
 
 
 
 
Other deferred debits and other assets
 
2

 
 
 
 
 
 
 
 
Derivative financial instruments
 
 
 
4

 
 
 
 
 
 
Other deferred credits and other liabilities
 
 
 
2

 
 
 
 
Total
 
 
 
$
84

 
$
39

 
$
71

 
$
30



97


Derivatives Designated as Fair Value Hedges

The Company had no interest rate or commodity derivatives designated as fair value hedges for any period presented.

Derivatives in Cash Flow Hedging Relationships

The effect of derivative instruments on the consolidated statements of income is as follows: 
The Company and Consolidated SCE&G:
 
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, 2017
 
 

 
 
 
 

Interest rate contracts
 
$
(2
)
 
Interest expense
 
$
(2
)
Year Ended December 31, 2016
 
 

 
 
 
 

Interest rate contracts
 

 
Interest expense
 
$
(2
)
Year Ended December 31, 2015
 
 

 
 
 
 
Interest rate contracts
 
$
(3
)
 
Interest expense
 
$
(3
)
The Company:
 
Gain or (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, 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
)
Year Ended December 31, 2015
 
 

 
 
 
 

Interest rate contracts
 
$
(2
)
 
Interest expense
 
$
(7
)
Commodity contracts
 
(10
)
 
Gas purchased for resale
 
(15
)
Total
 
$
(12
)
 
 
 
$
(22
)
 
As of December 31, 2017, the Company expects that during the next 12 months reclassifications from AOCI to earnings arising from cash flow hedges will include approximately $3.3 million as an increase to gas cost, assuming natural gas markets remain at their current levels, and approximately $7.2 million as an increase to interest expense, assuming financial markets remain at their current levels. As of December 31, 2017, all of the Company’s commodity cash flow hedges settle by their terms before the end of the fourth quarter of 2020.

As of December 31, 2017, each of the Company and Consolidated SCE&G expects that during the next 12 months reclassifications from regulatory accounts to earnings arising from cash flow hedges designated as hedging instruments will include approximately $1.5 million as an increase to interest expense assuming financial markets remain at their current levels.
 
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.


98


Derivatives Not Designated as Hedging Instruments
The Company and Consolidated SCE&G:
 
Loss Deferred in 
 
Gain (Loss) Reclassified from
Deferred Accounts into Income
Millions of dollars
 
Regulatory Accounts
 
Location
 
Amount
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
)
Year Ended December 31, 2015
 
 
 
 
 
 
Interest rate contracts
 
$
(69
)
 
Other income
 
$
5


Gains reclassified to other income offset revenue reductions as previously described herein and in Note 2. For more discussion of amounts reclassified to Impairment Loss, see Note 10.

As of December 31, 2017, the Company and Consolidated SCE&G expect that during the next 12 months reclassifications from regulatory accounts to earnings arising from interest rate swaps not designated as cash flow hedges will include approximately $2.7 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, 2017
 
December 31, 2016
 
December 31, 2017
 
December 31, 2016
in Net Liability Position
 
 

 
 

 
 
 
 
Aggregate fair value of derivatives in net liability position
 
$
33.7

 
$
50.3

 
$
14.7

 
$
30.3

Fair value of collateral already posted
 
28.9

 
29.2

 
10.1

 
9.2

Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
 
4.8

 
21.1

 
4.6

 
21.1

 
 
 
 
 
 
 
 
 
in Net Asset Position
 
 
 
 
 
 
 
 
Aggregate fair value of derivatives in net asset position
 
$
53.5

 
$
62.9

 
$
53.5

 
$
62.0

Fair value of collateral already posted
 

 

 

 

Additional cash collateral or letters of credit in the event credit-risk-related contingent features were triggered
 
53.5

 
62.9

 
53.5

 
62.0


In addition, for fixed price supply contracts offered to certain of SCANA Energy's customers, the Company could have called on letters of credit in the amount of $1.2 million related to $4.0 million in commodity derivatives that are in a net asset position at December 31, 2017, compared to letters of credit of $1.5 million related to derivatives of $9.0 million at December 31, 2016, if all the contingent features underlying these instruments had been fully triggered.


99


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, 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

 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
Gross Amounts of Recognized Assets
 
$
71

 
$
9

 
$
10

 
$
90

 
$
71

Gross Amounts Offset in Statement of Financial Position
 
 
 
 
 
(4
)
 
(4
)
 
 
Net Amounts Presented in Statement of Financial Position
 
71

 
9

 
6

 
86

 
71

Gross Amounts Not Offset - Financial Instruments
 
(9
)
 
 
 
 
 
(9
)
 
(9
)
Gross Amounts Not Offset - Cash Collateral Received
 
 
 
 
 
 
 


 
 
Net Amount
 
$
62

 
$
9

 
$
6

 
$
77

 
$
62

Balance sheet location
 
 
 
 
 
 
 
 
 
 
     Prepayments
 
 
 
 
 
 
 
$
9

 
 
     Other current assets
 
 
 
 
 
 
 
5

 


     Other deferred debits and other assets
 
 
 
 
 
 
 
72

 
$
71

Total
 
 
 
 
 
 
 
$
86

 
$
71


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, 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
)
 
27

 

Net Amount
 
$
60

 
$
3

 
$
1

 
$
64

 
$
15

Balance sheet location
 
 
 
 
 
 
 
 
 
 
     Other current assets
 
 
 
 
 
 
 
$
2

 
 
     Derivative financial instruments
 
 
 
 
 
 
 
7

 
$
2

     Other deferred credits and other liabilities
 
 
 
 
 
 
 
28

 
13

Total
 
 
 
 
 
 
 
$
37

 
$
15

 
 
 
 
 
 
 
 
 
 
 

100


As of December 31, 2016
 
 
 
 
 
 
 
 
 
 
Gross Amounts of Recognized Liabilities
 
$
58

 

 
$
9

 
$
67

 
$
39

Gross Amounts Offset in Statement of Financial Position
 
 
 
 
 
(3
)
 
(3
)
 
 
Net Amounts Presented in Statement of Financial Position
 
58

 

 
6

 
64

 
39

Gross Amounts Not Offset - Financial Instruments
 
(9
)
 
 
 
 
 
(9
)
 
(9
)
Gross Amounts Not Offset - Cash Collateral Posted
 
(29
)
 


 


 
(29
)
 
(9
)
Net Amount
 
$
20

 

 
$
6

 
$
26

 
$
21

Balance sheet location
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
     Derivative financial instruments
 
 
 
 
 
 
 
$
35

 
$
28

     Other deferred credits and other liabilities
 
 
 
 
 
 
 
29

 
11

Total
 
 
 
 
 
 
 
$
64

 
$
39


7.             FAIR VALUE MEASUREMENTS, INCLUDING DERIVATIVES
 
Available for sale securities are valued using quoted prices from a national stock exchange, such as the NASDAQ, where the securities are actively traded or are open-ended mutual funds registered with the SEC which maintain a stable NAV and are invested in government money market agreements or fully collateralized repurchase agreements. For commodity derivative and energy management assets and liabilities, the Company uses unadjusted NYMEX prices to determine fair value, and considers such measures of fair value to be Level 1 for exchange traded instruments and Level 2 for over-the-counter instruments. Interest rate swap agreements are valued using discounted cash flow models with independently sourced data. Fair value measurements, and the level within the fair value hierarchy   in which the measurements fall, were as follows:
 
 
As of December 31, 2017
 
As of December 31, 2016
 
 
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 2
Assets:
 

 
 
 
 

 
 
 
 
 
 
Available for sale securities
 
$
119

 

 
$
100


 
$
14

 

 

Held to maturity securities
 

 
$
6

 


 

 
$
7

 

Interest rate contracts
 

 
54

 

$
54

 

 
71

 
$
71

Commodity contracts
 
1

 

 


 
8

 
1

 

Energy management contracts
 

 
4

 


 
6

 
4

 

Liabilities:
 

 

 
 

 


 
 
 
 
Interest rate contracts
 

 
32

 

15

 

 
58

 
39

Commodity contracts
 
2

 
1

 


 

 

 

Energy management contracts
 
1

 
4

 


 
2

 
10

 

 
There were no Level 3 fair value measurements for either period presented, and there were no transfers of fair value amounts into or out of Levels 1, 2 or 3 during the periods presented.
 
Financial instruments for which the carrying amount may not equal estimated fair value at December 31, 2017 and December 31, 2016 were as follows:
 
 
As of December 31, 2017
 
As of December 31, 2016
Millions of dollars
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
The Company
 
$
6,632.9

 
$
7,399.7

 
$
6,489.8

 
$
7,183.3

Consolidated SCE&G
 
5,163.3

 
5,790.3

 
5,166.0

 
5,752.3


 Fair values of long-term debt instruments are based on net present value calculations using independently sourced market data that incorporate a developed discount rate using similarly rated long-term debt, along with benchmark interest rates. As such, the aggregate fair values presented above are considered to be Level 2. Early settlement of long-term debt may not be possible or may not be considered prudent.

Carrying values of short-term borrowings approximate their fair values, which are based on quoted prices from dealers in the commercial paper market. These fair values are considered to be Level 2.

101



In connection with the impairment loss described in Note 10, the Company and Consolidated SCE&G determined that the fair value of certain of their nuclear fuel was lower than its carrying amount. At December 31, 2017, this nuclear fuel had an estimated fair value of $43.8 million. This estimate is based on quoted prices received from vendors of nuclear fuel, which are considered to be Level 3 fair value measurements. The Company and Consolidated SCE&G assess the fair value of nuclear fuel in connection with the analysis of impairment described in Note 10 on a quarterly basis.

8.             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&G 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 and the final average pay formula will continue to accrue through December 31, 2023, after which date no benefits will be accrued except that participants under the cash balance formula will continue to earn interest credits.
 
In addition to pension benefits, SCANA provides certain unfunded postretirement health care and life insurance benefits to certain active and retired employees. SCE&G 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.

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.
 
 
The Company
 
Consolidated SCE&G
 
 
Pension Benefits

Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017

2016

2017

2016
 
2017
 
2016
 
2017
 
2016
Benefit obligation, January 1
 
$
904.3

 
$
855.4

 
$
274.7

 
$
253.6

 
$
768.4

 
$
724.0

 
$
207.2

 
$
191.7

Service cost
 
21.7

 
20.7

 
4.5

 
4.4

 
18.1

 
16.9

 
3.7

 
3.6

Interest cost
 
37.4

 
39.4

 
11.5

 
12.1

 
31.9

 
33.4

 
9.5

 
9.9

Plan participants’ contributions
 

 

 
1.3

 
1.7

 

 

 
1.1

 
1.3

Actuarial (gain) loss
 
42.2

 
45.0

 
9.7

 
14.0

 
36.6

 
41.8

 
6.8

 
11.5

Benefits paid
 
(72.4
)
 
(56.2
)
 
(12.5
)
 
(11.1
)
 
(62.0
)
 
(47.7
)
 
(10.3
)
 
(9.1
)
Amounts Funded to parent
 
n/a

 
n/a

 
n/a

 
n/a

 

 

 
(1.4
)
 
(1.7
)
Benefit obligation, December 31
 
$
933.2

 
$
904.3

 
$
289.2

 
$
274.7

 
$
793.0

 
$
768.4

 
$
216.6

 
$
207.2

 
The accumulated benefit obligation for pension benefits for the Company was $ 905.8 million at the end of 2017 and $ 874.3  million at the end of 2016. The accumulated benefit obligation for pension benefits for Consolidated SCE&G was $769.7  million at the end of 2017 and $742.9 million at the end of 2016.The accumulated pension benefit obligation differs from the projected pension benefit obligation above in that it reflects no assumptions about future compensation levels.
 

102


Significant assumptions used to determine the above benefit obligations are as follows:
 
Pension Benefits
 
Other Postretirement Benefits
 
2017
 
2016
 
2017
 
2016
Annual discount rate used to determine benefit obligation
3.71
%
 
4.22
%
 
3.74
%
 
4.30
%
Assumed annual rate of future salary increases for projected benefit obligation
3.00
%
 
3.00
%
 
3.00
%
 
3.00
%
 
A 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017. 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 Company would increase the postretirement benefit obligation by $1.6 million at December 31, 2017 and by $0.8  million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for the Company would decrease the postretirement benefit obligation by $1.4 million at December 31, 2017 and by $0.7 million at December 31, 2016.  A one percent increase in the assumed health care cost trend rate for Consolidated SCE&G would increase the postretirement benefit obligation by $1.3 million at December 31, 2017 and by $0.6  million at December 31, 2016. A one percent decrease in the assumed health care cost trend rate for Consolidated SCE&G would decrease the postretirement benefit obligation by $1.1 million at December 31, 2017 and by $0.6 million at December 31, 2016.

Funded Status
 
 
The Company
 
Consolidated SCE&G
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Fair value of plan assets
 
$
849.6

 
$
793.6

 

 

 
$
781.3

 
$
732.9

 

 

Benefit obligation
 
933.2

 
904.3

 
$
289.2

 
$
274.7

 
793.0

 
768.4

 
$
216.6

 
$
207.2

Funded status
 
$
(83.6
)
 
$
(110.7
)
 
$
(289.2
)
 
$
(274.7
)
 
$
(11.7
)
 
$
(35.5
)
 
$
(216.6
)
 
$
(207.2
)
 
Amounts recognized on the consolidated balance sheets were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Current liability
 

 

 
$
(13.5
)
 
$
(12.6
)
 

 

 
$
(10.8
)
 
$
(10.4
)
Noncurrent liability
 
$
(83.6
)
 
$
(110.7
)
 
(275.7
)
 
(262.1
)
 
$
(11.7
)
 
$
(35.5
)
 
(205.8
)
 
(196.8
)
 
Amounts recognized in accumulated other comprehensive loss were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Net actuarial loss
 
$
8.8

 
$
10.4

 
$
3.5

 
$
2.5

 
$
2.1

 
$
1.9

 
$
1.5

 
$
1.0

Prior service cost
 
0.1

 
0.1

 

 

 

 

 

 

Total
 
$
8.9

 
$
10.5

 
$
3.5

 
$
2.5

 
$
2.1

 
$
1.9

 
$
1.5

 
$
1.0


Amounts recognized in regulatory assets were as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
December 31,
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
 
2017
 
2016
Net actuarial loss
 
$
194.8

 
$
236.1

 
$
43.3

 
$
34.7

 
$
171.4

 
$
208.8

 
$
35.9

 
$
29.3

Prior service cost
 
1.2

 
2.5

 

 

 
1.0

 
2.2

 

 

Total
 
$
196.0

 
$
238.6

 
$
43.3

 
$
34.7

 
$
172.4

 
$
211.0

 
$
35.9

 
$
29.3

 
    

103


In connection with the joint ownership of Summer Station, costs related to the pension benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $21.4 million and $23.4  million, respectively, and was recorded within deferred debits. The unfunded postretirement benefit obligation attributable to Santee Cooper as of December 31, 2017 and 2016 totaled $14.7 million and $15.8 million, respectively, and also was recorded within deferred debits.
 
Changes in Fair Value of Plan Assets
Pension Benefits

 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2017
 
2016
Fair value of plan assets, January 1
 
$
793.6

 
$
781.7

 
$
732.9

 
$
720.1

Actual return on plan assets
 
128.4

 
68.1

 
110.4

 
60.5

Benefits paid
 
(72.4
)
 
(56.2
)
 
(62.0
)
 
(47.7
)
Fair value of plan assets, December 31
 
$
849.6

 
$
793.6

 
$
781.3

 
$
732.9

 
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. SCANA 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, 2017 and 2016 and the target allocation for 2018 are as follows: 
 
 
Percentage of Plan Assets
 
 
Target
Allocation
 

December 31,
Asset Category
 
2018
 
2017
 
2016
Equity Securities
 
58
%
 
58
%
 
57
%
Fixed Income
 
33
%
 
31
%
 
32
%
Hedge Funds
 
9
%
 
11
%
 
11
%
 
For 2018, 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.
 
Fair Value Measurements
 
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, 2017 and 2016, fair value measurements, and the level within the fair value hierarchy in which the measurements fall, were as follows:

104


 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2017
 
2016
Investments with fair value measure at Level 2:
 
 
 
 
 
 
 
 
   Mutual funds
 
$
120

 
$
125

 
$
110

 
$
115

   Short-term investment vehicles
 
17

 
16

 
16

 
15

   US Treasury securities
 
15

 
18

 
14

 
17

   Corporate debt securities
 
91

 
82

 
84

 
76

   Municipals
 
17

 
14

 
15

 
13

Total assets in the fair value hierarchy
 
260

 
255

 
239

 
236

 
 
 
 
 
 
 
 
 
Investments at net asset value:
 
 
 
 
 
 
 
 
   Common collective trust
 
498

 
453

 
458

 
418

   Joint venture interests
 
92

 
86

 
84

 
79

Total investments at fair value
 
$
850

 
$
794

 
$
781

 
$
733


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 no transfers of fair value amounts into or out of Levels 1, 2 or 3 during 2017 or 2016.

Mutual funds held by the plan are open-ended 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 securities and municipals 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.
 
Expected Cash Flows
 
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
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
2018
 
$
66.9

 
$
13.8

 
$
66.9

 
$
11.0

2019
 
64.6

 
14.6

 
64.6

 
11.7

2020
 
63.9

 
15.4

 
63.9

 
12.3

2021
 
66.5

 
16.0

 
66.5

 
12.8

2022
 
72.0

 
16.5

 
72.0

 
13.1

2023-2027
 
303.0

 
87.3

 
303.0

 
69.6


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 plan are expected to be made for the foreseeable future based on current market conditions and assumptions.

105



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.
 
Components of Net Periodic Benefit Cost
The Company
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Service cost
 
$
21.7

 
$
20.7

 
$
24.1

 
$
4.5

 
$
4.4

 
$
5.3

Interest cost
 
37.4

 
39.4

 
38.2

 
11.5

 
12.1

 
11.4

Expected return on assets
 
(54.7
)
 
(55.9
)
 
(62.0
)
 
n/a

 
n/a

 
n/a

Prior service cost amortization
 
1.6

 
3.9

 
4.1

 

 
0.3

 
0.4

Amortization of actuarial losses
 
16.3

 
14.8

 
13.6

 
1.0

 
0.5

 
2.1

Net periodic benefit cost
 
$
22.3

 
$
22.9

 
$
18.0

 
$
17.0

 
$
17.3

 
$
19.2

Consolidated SCE&G
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Service cost
 
$
18.1

 
$
16.9

 
$
19.3

 
$
3.7

 
$
3.6

 
$
4.4

Interest cost
 
31.9

 
33.4

 
32.2

 
9.5

 
9.9

 
9.4

Expected return on assets
 
(46.7
)
 
(47.4
)
 
(52.2
)
 
n/a

 
n/a

 
n/a

Prior service cost amortization
 
1.4

 
3.4

 
3.4

 

 
0.3

 
0.3

Amortization of actuarial losses
 
13.9

 
12.5

 
11.4

 
0.8

 
0.4

 
1.7

Net periodic benefit cost
 
$
18.6

 
$
18.8

 
$
14.1

 
$
14.0

 
$
14.2

 
$
15.8


In connection with regulatory orders, SCE&G recovers current pension expense through a rate rider that may be adjusted annually (for retail electric operations) or through cost of service rates (for gas operations). For retail electric operations, current pension expense is recognized based on amounts collected through its 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&G amortizes certain previously deferred pension costs. See Note 2.
 
Other changes in plan assets and benefit obligations recognized in OCI (net of tax) were as follows:
The Company
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current year actuarial (gain) loss
 
$
(1.0
)
 
$
0.6

 
$
2.7

 
$
1.1

 
$
0.8

 
$
(1.2
)
Amortization of actuarial losses
 
(0.6
)
 
(0.6
)
 
(0.4
)
 
(0.1
)
 

 
(0.1
)
Amortization of prior service cost
 

 
(0.1
)
 
(0.1
)
 

 

 
(0.1
)
Total recognized in OCI
 
$
(1.6
)
 
$
(0.1
)
 
$
2.2

 
$
1.0

 
$
0.8

 
$
(1.4
)
Consolidated SCE&G
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current year actuarial (gain) loss
 
$
0.3

 

 
$
0.2

 
$
0.5

 
$
0.3

 
$
(0.3
)
Amortization of actuarial losses
 
(0.1
)
 
$
(0.1
)
 
(0.1
)
 

 

 

Amortization of prior service cost
 

 

 
(0.1
)
 

 

 

Total recognized in OCI
 
$
0.2

 
$
(0.1
)
 

 
$
0.5

 
$
0.3

 
$
(0.3
)


106


Other changes in plan assets and benefit obligations recognized in regulatory assets were as follows:
The Company
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current year actuarial (gain) loss
 
$
(27.1
)
 
$
29.4

 
$
9.2

 
$
9.4

 
$
11.1

 
$
(18.0
)
Amortization of actuarial losses
 
(14.1
)
 
(12.7
)
 
(11.9
)
 
(0.8
)
 
(0.4
)
 
(1.8
)
Amortization of prior service cost
 
(1.4
)
 
(3.4
)
 
(3.7
)
 

 
(0.3
)
 
(0.3
)
Total recognized in regulatory assets
 
$
(42.6
)
 
$
13.3

 
$
(6.4
)
 
$
8.6

 
$
10.4

 
$
(20.1
)
Consolidated SCE&G
 
Pension Benefits
 
Other Postretirement Benefits
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Current year actuarial (gain) loss
 
$
(24.8
)
 
$
26.3

 
$
12.2

 
$
7.3

 
$
9.2

 
$
(14.0
)
Amortization of actuarial losses
 
(12.5
)
 
(11.2
)
 
(10.4
)
 
(0.7
)
 
(0.3
)
 
(1.5
)
Amortization of prior service cost
 
(1.3
)
 
(3.0
)
 
(3.1
)
 

 
(0.2
)
 
(0.3
)
Total recognized in regulatory assets
 
$
(38.6
)
 
$
12.1

 
$
(1.3
)
 
$
6.6

 
$
8.7

 
$
(15.8
)

Significant Assumptions Used in Determining Net Periodic Benefit Cost
 
Pension Benefits
 
Other Postretirement Benefits
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Discount rate
4.22
%
 
4.68
%
 
4.20
%
 
4.30
%
 
4.78
%
 
4.30
%
Expected return on plan assets
7.25
%
 
7.50
%
 
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

 
6.60
%
 
7.00
%
 
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

 
2021

 
2021

 
2020


The estimated amounts to be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are as follows for the Company. For Consolidated SCE&G such amounts are insignificant :
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
Actuarial loss
 
$
0.5

 
$
0.1


The estimated amounts to be amortized from regulatory assets into net periodic benefit cost in 2018 are as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of Dollars
 
Pension Benefits
 
Other Postretirement Benefits
 
Pension Benefits
 
Other Postretirement Benefits
Actuarial loss
 
$
10.2

 
$
1.8

 
$
9.0

 
$
1.5

Prior service cost
 
0.4

 

 
0.4

 

Total
 
$
10.6

 
$
1.8

 
$
9.4

 
$
1.5


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&G participates in this plan. Contributions are matched 100% up to 6% of an employee’s eligible earnings. Such matching contributions made by the Company totaled $27.9 million in 2017, $27.5 million in 2016 and $26.2  million in 2015. These matching contributions included those made by Consolidated SCE&G, which totaled $23.4 million in 2017, $22.9 million in 2016 and $21.8 million in 2015. Employee deferrals, matching contributions, and earnings on all contributions are fully vested and nonforfeitable at all times.


107



9.             SHARE-BASED COMPENSATION
 
The LTECP provides for grants 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 currently authorizes the issuance of up to five million shares of SCANA’s common stock, no more than one million of which may be granted in the form of restricted stock.
 
Compensation cost is measured based on the grant-date fair value of the instruments issued and is recognized over the period that an employee provides service in exchange for the award. Share-based payment awards do not have non-forfeitable rights to dividends or dividend equivalents. To the extent that the awards themselves do not vest, dividends or dividend equivalents which would have been paid on those awards do not vest.
 
The 2015-2017, 2016-2018 and 2017-2019 performance cycles provide for performance measurement 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 are liability awards payable in cash, and 70% of the awards were granted in performance shares, each of which has a value that is equal to, and changes with, the value of a share of SCANA common stock. Dividend equivalents are accrued on the performance shares and the restricted share units. Performance awards and related dividend equivalents are subject to forfeiture in the event of termination of employment prior to the end of the cycle, subject to certain exceptions. Payouts of performance share awards are determined by SCANA’s performance against pre-determined measures of TSR as compared to a peer group of utilities (weighted 50% ) and growth in GAAP-adjusted net earnings per share (weighted 50% ). 
 
Compensation cost of liability awards is recognized over their respective three -year performance periods based on the estimated fair value of the award, which is periodically updated based on expected ultimate cash payout, and is reduced by estimated forfeitures. Cash-settled liabilities related to performance cycles totaled approximately $ 28.0 million in 2017, $ 18.4 million in 2016 and $ 20.8 million in 2015 for the Company and approximately $ 20.2 million in 2017, $ 13.2 million in 2016 and $ 6.3 million in 2015 for Consolidated SCE&G.
 
Fair value adjustments for all performance cycles resulted in compensation expense (benefit) recognized in the statements of operations totaling approximately $ (9.0) million in 2017, $ 25.6 million in 2016 and $ 18.0 million in 2015 for the Company, of which approximately $ (6.3) million in 2017, $ 17.3 million in 2016 and $ 12.2 million in 2015 for Consolidated SCE&G (including amounts allocated from SCANA Services). Such fair value adjustments also resulted in capitalized compensation costs of $ (1.3) million in 2017, $ 3.3 million in 2016 and $ 2.3 million in 2015 for the Company and $ (0.9) million in 2017, $ 3.1 million in 2016 and $ 0.6 million in 2015 for Consolidated SCE&G. At December 31, 2017, unrecognized compensation cost, which is expected to be recognized over a weighted-average period of 18 months , was $ 5.4 million for the Company and $ 4.1 million for Consolidated SCE&G. Large declines in stock price and relative performance in 2017 resulted in reductions of liabilities previously accrued with respect to open performance cycles. In the event of consummation of the merger, additional compensation cost arising from these liability awards may also be recognized.

10.          COMMITMENTS AND CONTINGENCIES

Abandoned Nuclear Project

SCE&G, on behalf of itself and as agent for Santee Cooper, entered into the EPC Contract with the Consortium in 2008 for the design and construction of Unit 2 and Unit 3. SCE&G's ownership share in these units is 55% . As discussed below, 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, and others more fully discussed below, were the subject of comprehensive analyses performed by the Company and Santee Cooper (see Contractor Bankruptcy Proceedings and Related Uncertainties below). Based on the results of the Company's analysis, and in light of Santee Cooper's decision to suspend construction on Unit 2 and Unit 3, on July 31, 2017, the Company determined to stop the construction of the units and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means.


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EPC Contract and BLRA Matters

The Nuclear Project and SCE&G’s related recovery of financing costs through rates has been subject to review and approval by the SCPSC as provided for in the BLRA. Under the BLRA, the SCPSC approved, among other things, a milestone schedule and a capital costs estimates schedule for Unit 2 and Unit 3. Pursuant to the BLRA, this approval constituted a final and binding determination that the units were used and useful for utility purposes, and that the capital costs associated with them were prudent utility costs and expenses and were properly included in rates, so long as Unit 2 and Unit 3 were constructed or were being constructed within the parameters of the approved milestone schedule, including specified contingencies, and the approved capital costs estimates schedule. Subject to the same conditions, the BLRA provides that SCE&G may apply to the SCPSC annually for an order to recover through revised rates SCE&G’s weighted average cost of capital applied to all or part of the outstanding balance of construction work in progress concerning the Nuclear Project. As of December 31, 2017, financing costs on $3.5 billion of SCE&G's construction costs for the Nuclear Project, excluding related transmission assets, have been reflected in revised rates under the BLRA, with the last revised rates increase having gone into effect in November 2016. SCE&G estimates that revised rates collections that have accumulated as of December 31, 2017, including collections related to transmission assets expected to be placed into service, total approximately $1.9 billion .

As a result of the decision to abandon the Nuclear Project, amounts reclassified from construction work in progress into regulatory assets, net of impairments described below, are summarized as follows:
Unrecovered Nuclear Project Costs
Millions of dollars
Nuclear Project costs as of September 30, 2017, prior to impairment loss and excluding transmission assets
$
4,730

Less Impairment loss recorded in the third quarter of 2017 (See below)
210

Balance of unrecovered Nuclear Project costs as of September 30, 2017
4,520

Less Impairment loss recorded in the fourth quarter of 2017 (See below)
460

Less Nuclear Project and switchyard assets transferred for use by Unit 1
84

Balance of unrecovered Nuclear Project costs as of December 31, 2017 (See Note 2)
$
3,976


    The SCPSC granted initial approval of the construction schedule and related forecasted capital costs in 2009. The NRC issued combined Construction and Operating Licenses in March 2012. In November 2012, and again in September 2015 and November 2016 (see discussion below), the SCPSC approved SCE&G's requested updates to the milestone schedule, revised contractual substantial completion dates, and increases in capital and other costs. As further discussed below, under the current regulatory construct in South Carolina, approval by the SCPSC of cost recovery under the abandonment provisions of the BLRA or through other means will be required as a consequence of the Company’s determination on July 31, 2017 to cease construction of the Nuclear Project.
    
October 2015 Amendment and WEC's Engagement of Fluor

On October 27, 2015, SCE&G, Santee Cooper and the Consortium amended the EPC Contract. The amendment became effective in December 2015, at which time Fluor began serving as a subcontracted construction manager for the Consortium. The October 2015 Amendment provided SCE&G and Santee Cooper an option to fix the total amount to be paid to the Consortium for its entire scope of work on the project (excluding a limited amount of work within the time and materials component of the contract price) after June 30, 2015 at $6.082 billion (SCE&G’s 55% portion being approximately $3.345 billion). This total amount to be paid would be reduced by amounts paid since June 30, 2015. SCE&G, on behalf of itself and as agent for Santee Cooper, elected the fixed price option, subject to SCPSC approval, on July 1, 2016.

Among other things, the October 2015 Amendment revised the contractual guaranteed substantial completion dates of Unit 2 and Unit 3 to August 31, 2019 and August 31, 2020, respectively, and provided for development of a revised construction milestone payment schedule. In February 2017, WEC notified the Company and Consolidated SCE&G that the contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively, which were reflected in the October 2015 Amendment, would not be met. Instead, WEC provided further revised estimated substantial completion dates of April 2020 and December 2020.

November 2016 SCPSC Order

In May 2016, SCE&G petitioned the SCPSC for approval of the updated construction and capital cost schedules for 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

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SCPSC also approved SCE&G's election of the fixed price option. 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 order was not appealed.

The construction schedule approved by the SCPSC in November 2016 provided for contractual guaranteed substantial completion dates of August 31, 2019 and August 31, 2020 for Unit 2 and Unit 3, respectively. The approved capital cost schedule included incremental capital costs that totaled $831 million , raising SCE&G's total project capital cost as then approved to an estimated amount of approximately $6.8 billion including owner’s costs and transmission, or $7.7 billion with escalation and AFC. In addition, the SCPSC approved revising SCE&G’s allowed ROE for the Nuclear Project from 10.5% to 10.25% . This revised ROE was to be applied prospectively for the purpose of calculating revised rates sought by SCE&G under the BLRA on and after January 1, 2017. No such revised rates have been sought since that time.

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.

In connection with the bankruptcy filing, SCE&G, Santee Cooper, WEC and WECTEC entered into an Interim Assessment Agreement under which engineering and construction continued on the project and under which SCE&G and Santee Cooper were provided the right to discuss project status with Fluor and other subcontractors and vendors and to obtain from them relevant project information and documents that had been previously contractually unavailable in order for SCE&G and Santee Cooper to perform comprehensive analyses regarding whether or how to proceed with the Nuclear Project. As part of the Interim Assessment Agreement, and to avoid an immediate rejection of the EPC Contract upon the filing of the bankruptcy case, WEC and WECTEC required SCE&G and Santee Cooper to make estimated weekly payments to WEC, WECTEC, subcontractors and vendors, irrespective of the fixed price provisions of the EPC Contract, to permit the time to conduct analyses. SCE&G and Santee Cooper agreed to pay specified costs incurred by the Consortium, Fluor, other subcontractors and vendors for work performed or services rendered while the Interim Assessment Agreement remained in effect.

During the period of the Interim Assessment Agreement, as amended and extended, SCE&G and Santee Cooper evaluated the various elements of the Nuclear Project, including forecasted costs and completion dates, while construction continued and SCE&G and Santee Cooper continued to make payments for such work.

As part of its evaluation, SCE&G considered that, as a result of the bankruptcy process (including WEC and WECTEC's public announcements that they could not perform under the terms of the EPC Contract), the EPC Contract would likely be rejected and that the benefit of the fixed-price terms provided by the EPC Contract would be lost. As such, any cost overruns that would have been absorbed by the Consortium would become the responsibility of SCE&G and Santee Cooper. Additionally, these cost increases and other costs identified by SCE&G would not be fully recoverable from the Consortium or from Toshiba under its payment guaranty or the related Toshiba Settlement, discussed below, and such costs would likely substantially exceed the amount of the Consortium's payment obligations guaranteed by Toshiba.

SCE&G also considered that even the newly revised substantial completion dates identified by WEC of April and December 2020 for Unit 2 and Unit 3, respectively, likely would not be met. As such, the electricity to be produced by each of the units would not qualify for nuclear production tax credits under Section 45J of the IRC. SCE&G's 55% share of these nuclear production tax credits for both Unit 2 and Unit 3 could have totaled as much as approximately $1.4 billion. Failure to meet the newly revised substantial completion dates identified by WEC would result in the nuclear production tax credits not being earned.

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. The Proofs of Claim are based upon the anticipatory repudiation and material breach by the Consortium of the EPC Contract, and assert against WEC and WECTEC any and all claims that are based thereon or that may be related thereto. These claims were sold to Citibank on September 27, 2017 as part of the 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.


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Toshiba Settlement and Subsequent Monetization

Payment and performance obligations under the EPC Contract are joint and several obligations of WEC and WECTEC, and in connection with the October 2015 Amendment, Toshiba, WEC’s parent company, reaffirmed its guaranty of WEC’s payment obligations. In satisfaction of such guaranty obligations, on July 27, 2017, the Toshiba Settlement was executed under which Toshiba was to make periodic settlement payments from October 2017 through September 2022 in the total amount of approximately $2.2 billion ( $1.2 billion for SCE&G’s 55% share). The $2.2 billion is subject to offset for payments by WEC that have the effect of satisfying the liens on the project discussed below.

On September 27, 2017, the scheduled payments under the Toshiba Settlement, exclusive of the payment due in October 2017, were purchased by Citibank for a one-time upfront payment of $1.847 billion (approximately $1.016 billion for SCE&G's 55% share), including amounts related to the contractor liens discussed below. The initial payment was then received from Toshiba on October 2, 2017, as scheduled, in the amount of $150 million ( $82.5 million for SCE&G's 55% share). SCE&G's share of amounts received, net of certain expenses, total $1.095 billion . The purchase agreement 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. The proceeds received under or arising from the monetization of the Toshiba Settlement were recorded as cash and as a regulatory liability on the accompanying consolidated balance sheets, as the net value of the proceeds will be utilized to benefit SCE&G's customers in a manner to be determined by the SCPSC. While this determination is pending, SCE&G has utilized portions of the proceeds to repay maturing commercial paper balances, which short-term borrowings had been incurred primarily for the construction of Unit 2 and Unit 3 prior to the decision to stop their construction. See further discussion in Note 4.

A number of subcontractors and vendors to the Consortium 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. SCE&G is contesting the filed liens. Payments under the Toshiba Settlement are subject to reduction if WEC pays creditors holding these liens directly. Under these circumstances, SCE&G and Santee Cooper, each in its pro rata share, would be required to make Citibank whole for the reduction. On January 2, 2018, the purchase agreement among SCE&G, Santee Cooper and Citibank was amended to limit the amount that SCE&G and Santee Cooper could be required to reimburse Citibank for valid subcontractor and vendor liens to $60 million ($ 33 million for SCE&G's 55% share).

Determination to Stop Construction and Related Regulatory, Political and Legal Developments

The BLRA provides that, in the event of abandonment prior to plant completion, costs incurred, including AFC, and a return on those costs, may be recoverable through rates, if the SCPSC determines that the decision to abandon the Nuclear Project was prudent. Based on the evaluation previously discussed, and in light of Santee Cooper's decision to suspend construction, on July 31, 2017, the Company determined to stop construction of Unit 2 and Unit 3 and to pursue recovery of costs incurred in connection with such construction under the abandonment provisions of the BLRA or through other means. On July 31, 2017, SCE&G gave WEC a five-day notice of termination of the Interim Assessment Agreement and notified WEC of its determination to stop construction of Unit 2 and Unit 3.

On August 1, 2017, SCE&G senior management provided an allowable ex parte briefing to the SCPSC regarding the Nuclear Project and this decision, and SCE&G also filed a petition with the SCPSC which included its plan of abandonment and certain proposed actions which would mitigate related customer rate increases, including a proposal to return to customers the net value of proceeds received by SCE&G under or arising from the monetization of the Toshiba Settlement. Through this petition, SCE&G had sought recovery of such costs expended on the construction of the Nuclear Project, including certain costs incurred subsequent to SCE&G's last revised rates update, and certain other costs under the abandonment provisions of the BLRA. Subsequently, SCE&G’s management met with various stakeholders and members of the South Carolina General Assembly, including legislative leaders, to discuss the abandonment of the Nuclear Project and to hear their concerns. In response to those concerns, and to allow for adequate time for governmental officials to conduct their reviews, SCE&G voluntarily withdrew its petition to abandon the project from the SCPSC on August 15, 2017.

In August 2017, special committees of the South Carolina General Assembly, both in the House of Representatives and in the Senate, began conducting public hearings regarding the decision to abandon the Nuclear Project. Members of SCE&G's senior management, along with representatives from Santee Cooper, the ORS and other interested parties, testified before these committees. Several legislative proposals adverse to the Company and Consolidated SCE&G resulted from the work of these committees and certain adverse proposals have been or are being considered by the General Assembly in 2018. In January 2018, these committees reconvened for the purpose of considering the effects of the proposed merger discussed below

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on Nuclear Project stakeholders. On January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA.
 
In September 2017, the Company was served with a subpoena issued by the United States Attorney’s Office for the District of South Carolina seeking documents relating to the Nuclear Project. The subpoena requires the Company to produce a broad range of documents related to the project. Also in September 2017, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. In October 2017, the staff of the SEC's Division of Enforcement also issued a subpoena for documents related to an investigation they are conducting related to the Nuclear Project. The Company and Consolidated SCE&G intend to fully cooperate with these investigations. Also in connection with the abandonment of the Nuclear Project, various state or local governmental authorities have attempted and may further attempt to challenge, reverse or revoke one or more previously-approved tax or economic development incentives, benefits or exemptions and may attempt to apply such action retroactively. No assurance can be given as to the timing or outcome of these matters.

On September 26, 2017, the South Carolina Office of Attorney General issued an opinion stating, among other things, that "as applied, portions of the BLRA are constitutionally suspect," including the abandonment provisions. Also on September 26, 2017, the ORS filed the Request with the SCPSC asking for an order directing SCE&G to immediately suspend all revised rates collections from customers which were previously approved by the SCPSC pursuant to the authority of the BLRA. In the Request, the ORS relied upon the opinion from the Office of Attorney General to assert that it is not just and reasonable or in the public interest to allow SCE&G to continue collecting revised rates. Further, the ORS noted the existence of an allegation that SCE&G failed to disclose information to the ORS that should have been disclosed and that would have appeared to provide a basis for challenging prior requests, and asserted that SCE&G should not be allowed to continue to benefit from nondisclosure. The ORS also asked for an order that, if the BLRA is found to be unconstitutional or the South Carolina General Assembly amends or revokes the BLRA, then SCE&G should make credits to future bills or refunds to customers for prior revised rates collections. SCE&G estimates that revised rates collections, including collections related to transmission assets expected to be placed into service, currently total approximately $445 million annually, and such amounts accumulated as of December 31, 2017 total approximately $1.9 billion .

On September 28, 2017, SCE&G filed a Motion to Dismiss the Request and a Request for Briefing Schedule and Hearing on Motion to Dismiss. On September 28, 2017, the SCPSC deferred action on the Request and ordered a hearing officer to establish a briefing schedule and hearing date on SCE&G's motion. On October 17, 2017, the ORS filed a motion with the SCPSC to amend the Request, in which the ORS asked the SCPSC to consider the most prudent manner by which SCE&G will enable its customers to realize the value of the monetized Toshiba Settlement payments and other payments made by Toshiba towards satisfaction of its obligations to SCE&G. Parties who filed to intervene in the matter or who filed a letter in support of the request by the ORS include the Governor, the state's Office of Attorney General and Speaker of the House of Representatives, the Electric Cooperatives of South Carolina, the SCEUC, certain large industrial customers, and several environmental groups. After conducting a hearing to consider SCE&G's motion, the SCPSC denied the motion on December 20, 2017 and requested that the ORS carry out an inspection, audit and examination of SCE&G's revenue requirements to assist the SCPSC in determining whether SCE&G's present schedule of rates is fair and reasonable and also ordered that a hearing be scheduled to consider the Request. The hearing has not yet been scheduled. SCE&G intends to continue vigorously contesting the Request, but cannot give any assurance as to the timing or outcome of this matter. See also Note 2.

Proposals to Resolve Outstanding Issues

On November 16, 2017, SCE&G announced for public consideration a proposal to resolve outstanding issues relating to the Nuclear Project. Under the proposal, SCE&G electric customers were to receive a 3.5% electric rate reduction, the addition of an existing 540-MW natural gas fired power plant by SCE&G with the acquisition cost borne by SCANA shareholders, and the addition of approximately 100-MW of large scale solar energy by SCE&G. The proposal also provided for the recovery of the nuclear construction costs (net of the proceeds of the Toshiba Settlement not utilized for liquidation of

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project liens) over 50 years. While SCE&G’s proposal was not formally submitted for regulatory approval, discussions with key stakeholders over the ensuing weeks indicated that SCE&G's proposal would not be sufficient to resolve the outstanding issues.

On January 2, 2018, SCANA entered into the Merger Agreement with Dominion Energy, and on January 12, 2018, SCE&G and Dominion Energy filed the Joint Petition requesting SCPSC approval of the merger or a finding that either the merger is in the public interest or that there is an absence of harm arising from the merger. In this petition, the parties commit to providing an up-front, one time rate credit to SCE&G's electric customers totaling approximately $1.3 billion within 90 days of the merger's closing, providing at least a 5% reduction in customer bills, shortening the amortization period for costs related to the Nuclear Project to 20 years, forgoing recovery of approximately $1.7 billion in costs related to the Nuclear Project, and adding an existing 540-MW natural gas fired power plant by SCE&G with no initial investment borne by customers. No assurance can be given as to the timing or outcome of efforts to consummate the Merger Agreement or to obtain approval of the Joint Petition.

Impairment Considerations

Under the current regulatory construct in South Carolina, pursuant to the BLRA or through other means, the ability of SCE&G to recover costs incurred in connection with Unit 2 and Unit 3, and a reasonable return on them, will be subject to review and approval by the SCPSC. In light of the contentious nature of the reviews by legislative committees and others, the adverse impact that would result if proposed legislation is enacted, and the Request being considered by the SCPSC that could result in the suspension of rates currently being collected under the BLRA, as well as the return of such amounts previously collected, there is significant uncertainty as to SCE&G’s ultimate ability to fully recover its costs of Unit 2 and Unit 3 and a return on them from its customers. SCE&G continues to contest the specific challenges described above. However, based on the consideration of those challenges, and particularly in light of SCE&G's proposed solution announced on November 16, 2017 and details in the Joint Petition filed by SCE&G and Dominion Energy with the SCPSC on January 12, 2018, the Company and Consolidated SCE&G have determined that a disallowance of recovery of part of the cost of the abandoned plant is both probable and reasonably estimable under applicable accounting guidance. In addition, the Company and Consolidated SCE&G have determined that full recovery of certain other related costs deferred within regulatory assets is less than probable. As a result, as of December 31, 2017, the Company and Consolidated SCE&G have recognized a pre-tax impairment loss totaling $1.118 billion ( $690 million net of tax). With the exception of the $210 million loss recorded in the third quarter of 2017 as explained below, this impairment loss was recorded in the fourth quarter of 2017. A discussion of this impairment loss follows:

A pre-tax impairment loss was recorded with respect to disallowance of unrecovered nuclear project costs of approximately $670 million . This amount includes $210 million recorded in the third quarter of 2017, which represented costs of approximately $1.2 billion that had been expended on the project, exclusive of transmission costs, but which had not yet been determined to be prudent by the SCPSC in connection with revised rates proceedings under the BLRA, offset by the amount of approximately $1 billion , which amount represents the recovery of the Toshiba Settlement proceeds that are in excess of amounts from that settlement that the Company and Consolidated SCE&G estimated may be necessary to satisfy certain project liens. This impairment loss also includes $180 million , which amount arises from SCE&G’s entry into an agreement in the fourth quarter of 2017 to purchase in 2018 an existing 540-MW combined cycle gas generating station along with SCE&G's commitment to regulators and the public that the recovery of the initial capital investment in the facility would not be sought from customers. The remaining $280 million of this impairment loss was recorded after consideration of the regulatory and political developments described above.
A pre-tax impairment loss was recorded in the aggregate amount of $361 million to write off costs which had been previously deferred, primarily as regulatory assets, in connection with the Nuclear Project. Such regulatory assets included deferred losses on interest rate swaps for which debt will not be issued due to the abandonment of the Nuclear Project, carrying costs on deferred tax assets arising from the capitalization of interest costs for tax purposes, net deferred costs and tax benefits related to foregone domestic production activities deductions (net of uncertain tax positions and credits) taken with respect to the project, and taxes associated with equity AFC.
Finally, an $87 million pre-tax impairment loss was recorded in order to reduce to estimated fair value the carrying value of nuclear fuel acquired for use in Unit 2 and Unit 3.

With the exception of the $87 million related to nuclear fuel, the above impairment loss reflects impacts similar to those that may have resulted had the proposed solution announced November 16, 2017 been implemented. That proposal is presented by SCE&G as a less-favored alternative to the merger benefits and cost recovery plan in the January 12, 2018 Joint

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Petition. It is reasonably possible that a change in the estimated impairment loss could occur in the near term. If the merger benefits and cost recovery plan outlined in the Joint Petition is implemented (upon closing of the merger as contemplated in the Merger Agreement), an additional impairment loss and other charges totaling as much as approximately $1.7 billion would be expected to be recorded. This additional impairment loss would result from the write-off of unrecovered Nuclear Project costs of approximately $856 million recorded within regulatory assets and the recording of additional liabilities for customer refunds totaling approximately $1.875 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. If instead the Joint Petition is not approved and the Request by the ORS is approved, and if the BLRA is found to be unconstitutional or the General Assembly amends or revokes the BLRA, the Company and Consolidated SCE&G may be required to record an additional impairment loss and other charges totaling as much as approximately $4.8 billion . This additional impairment loss would result from the write-off of the remaining unrecovered Nuclear Project costs of $3.976 billion recorded within regulatory assets and the refund of revised rates collections under the BLRA described above of approximately $1.9 billion , net of approximately $1.062 billion , which amount represents the monetization of guaranty settlement of $1.095 billion recorded within regulatory liabilities less amounts that may be required to settle contractor liens. The Company and Consolidated SCE&G do not currently anticipate that any of the $1.9 billion in revenue previously collected will be subject to refund; however, no assurance can be given as to the outcome of this matter.

Liquidity Considerations

              As a result of the decision to stop construction of Unit 2 and Unit 3, downgrades by credit ratings agencies have recently occurred.  The Company and Consolidated SCE&G have significant obligations that must be paid within the next 12 months, including long-term debt maturities and capital lease payments of $727 million for the Company (including $723 million for Consolidated SCE&G), short-term borrowings of $350 million for the Company (including $252 million for Consolidated SCE&G), interest payments of approximately $335 million for the Company (including $259 million for Consolidated SCE&G), and future minimum payments for operating leases of $34 million for the Company (including $26 million for Consolidated SCE&G). Working capital requirements, such as those for fuel supply and similar obligations, also arise due to the lag between when such amounts are paid and when related collection of such costs through customer rates occurs.

              Management believes as of the date of issuance of these financial statements that it has access to available sources of cash to pay obligations when due over the next 12 months. These sources include committed, long-term lines of credit that expire in December 2020 totaling $1.8 billion for the Company (including $1.2 billion for Consolidated SCE&G). In addition, as of the date of issuance of these financial statements, SCE&G continues to collect in customer rates amounts previously approved under the BLRA, as well as amounts provided for in other orders related to non-BLRA electric and gas rates. However, as further described below, SCANA's credit rating has fallen below investment grade, which has constricted its ability and that of Consolidated SCE&G to issue commercial paper.

As described above, on January 31, 2018, the South Carolina House of Representatives passed a bill (H. 4375) that would create an experimental rate which would effectively suspend collections from rates previously approved by the SCPSC under the BLRA. This experimental rate would remain in effect during the pendency of administrative proceedings currently before the SCPSC or any appeal therefrom. In addition, the South Carolina Senate passed a joint resolution (S. 954) which, if enacted, would prohibit the SCPSC from holding a hearing on the merits for a docket in which requests were made pursuant to the BLRA (other than an administrative or procedural hearing prior to such hearing on the merits), and would prohibit any final determination on any such requests, before November 1, 2018, and would require the SCPSC to issue a final order for such docket no later than December 21, 2018. Any bill must be approved by both legislative chambers and be signed by, or allowed to become law without the signature of, the Governor before it would be enacted. Such regulatory, legislative or judicial proceedings outside of the Company’s and Consolidated SCE&G’s control may result in the temporary or permanent suspension of the approximately $445 million annually of rates being collected currently under the BLRA, the return of such amounts previously collected of $1.9 billion , or the requirement that SCE&G's share of payments received from the Toshiba Settlement ( $1.095 billion ) be placed in escrow or be refunded to customers. Neither the Company nor Consolidated SCE&G can predict if or when either of these bills could become law or what additional actions, if any, may be proposed or taken, including other legislative actions related to the BLRA.

Were the SCPSC to grant the relief sought by the ORS in the Request or grant similar relief resulting from legislative action, and as further discussed above in Impairment Considerations, an additional impairment loss or other charges totaling as much as approximately $4.8 billion may be required. Such an impairment loss or other charges would further stress the Company’s and Consolidated SCE&G’s equity to total capitalization ratio and may result in the Company’s and Consolidated SCE&G’s ratio of equity to total capitalization falling below minimum levels prescribed in the Company’s credit agreements. In such an event, the Company’s and Consolidated SCE&G’s ability to borrow under their commercial paper programs and

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credit facilities and their ability to pay future dividends would likely be limited or may trigger events of default under such agreements.

Known and knowable conditions and events when considered in the aggregate as of the date of issuance of these financial statements do not suggest it is probable that the Company and Consolidated SCE&G will not be able to meet obligations as they come due over the next 12 months. However, possible future actions related to rates or refunds could have a material adverse effect on the Company’s and Consolidated SCE&G’s financial condition, liquidity, results of operations and cash flows such that management’s conclusion with respect to its ability to pay obligations when due could change.

Claims and Litigation

Following the Company’s decision to stop construction of Unit 2 and Unit 3, putative derivative and class action lawsuits have been filed in multiple state circuit courts and federal district court on behalf of customers, shareholders and SCANA (in the case of the derivative shareholder actions), against SCANA, SCE&G, or both, and in certain cases some of their officers and/or directors. The plaintiffs allege various causes of action, including but not limited to waste, breach of fiduciary duty, negligence, unfair trade practices, unjust enrichment, conspiracy, fraud, constructive fraud, misrepresentation and negligent misrepresentation, promissory estoppel, constructive trust, and money had and received, among other causes of action. Plaintiffs generally seek compensatory and consequential damages and statutory treble damages and such further relief as the court deems just and proper. In addition, certain plaintiffs seek a declaration that SCE&G may not charge its customers to reimburse itself for past and continuing costs of the Nuclear Project. Certain plaintiffs also seek to freeze or appoint a receiver for certain of SCE&G’s assets, including all money SCE&G has received under the Toshiba payment guaranty and related settlement agreement and money to be collected from customers for the Nuclear Project.

Putative class action lawsuits have been filed on behalf of investors in federal court against SCANA and certain of its current and former executive officers and directors. The plaintiffs allege, among other things, that defendants violated Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and two suits allege violations of the Racketeer Influenced and Corrupt Organizations Act. In one suit, plaintiff alleges that director defendants violated Section 14(a) of the Exchange Act and SEC Rule 14a-9 by allowing or causing misleading proxy statements to be issued. The plaintiffs in each of these suits seek compensatory and consequential damages and such further relief as the court deems proper.

Lawsuits seeking class action status have also been filed on behalf of investors in the Court of Common Pleas in the Counties of Lexington and Richland, South Carolina, against SCANA, its CEO and directors, Dominion Energy and Sedona Corp. The plaintiffs allege, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that unfairly deprived plaintiffs of the true value of their SCANA stock, and that Dominion Energy and Sedona Corp. aided and abetted these actions. Among other remedies, the plaintiffs in each case seek to enjoin the merger and rescind the Merger Agreement. In addition, two of the lawsuits seek in the alternative, should the merger be completed, an award of unspecified monetary damages.

A complaint has been filed by Fairfield County against SCE&G making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of the implied duty of good faith and fair dealing, and unfair trade practices related to SCE&G’s termination of the FILOT agreement. Plaintiff seeks injunctive relief to prevent SCE&G from terminating the FILOT agreement; actual and consequential damages; treble damages; punitive damages; and attorneys’ fees.

The Company has also been served with subpoenas issued by the United States Attorney’s Office for the District of South Carolina and the staff of the SEC's Division of Enforcement seeking documents relating to the Nuclear Project. In addition, the state's Office of Attorney General, the Speaker of the House of Representatives, and the Chair and Vice-Chair of the South Carolina House Utility Ratepayer Protection Committee have requested that SLED conduct a criminal investigation into the handling of the Nuclear Project by SCANA and SCE&G. The Company and Consolidated SCE&G intend to fully cooperate with any such investigations.

On January 26, 2018, the DOR notified the Company that it was initiating an audit of the Company's sales and use tax returns for the periods September 1, 2008 through December 31, 2017. Based on an introductory meeting regarding that audit on February 8, 2018, the Company understands that the DOR's position is that the exemption for sales and use tax for purchases related to the Nuclear Project should not apply because Unit 2 and Unit 3 will not be placed into service and no electricity will be manufactured for sale. The Company intends to vigorously contest the DOR's position.

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, they cannot predict the timing or outcome of these matters or others that may

115


arise, and adverse outcomes from some of these matters would not be covered by insurance. As noted above, the various claims for damages do not specify an amount for those damages and the number of plaintiffs that are ultimately certified in the potential class actions lawsuits is unknown. In addition, each of the cases referred to above is in its early stages. For these reasons, the Company and Consolidated SCE&G cannot provide any estimate or range of potential loss for these matters at this time, and no accrual for these potential losses has been included in the consolidated financial statements. However, outcomes could have a material adverse effect 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 anticipates will be resolved without a material impact on the Company's and Consolidated SCE&G's results of operations, cash flows or financial condition.

Nuclear Insurance
 
Under Price-Anderson, SCE&G (for itself and on behalf of Santee-Cooper) maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Unit 1.  Price-Anderson provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident.  Each nuclear plant is insured against this liability to a maximum of $450 million by ANI with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. Each reactor licensee is liable for up to $127.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $18.9 million of the liability per reactor would be assessed per year. SCE&G’s maximum assessment, based on its two-thirds ownership of Unit 1, would be $84.8 million per incident, but not more than $12.6 million per year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years.

SCE&G currently maintains insurance policies (for itself and on behalf of Santee Cooper) with NEIL. The policies provide coverage to Unit 1 for property damage and outage costs up to $2.75 billion resulting from an event of nuclear origin and up to $2.33 billion resulting from an event of a non-nuclear origin. 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’s portion of the retrospective premium assessment would not exceed $22.3 million . SCE&G currently maintains an excess property insurance policy (for itself and on behalf of Santee Cooper) with EMANI. The policy provides coverage to Unit 1 for property damage and outage costs up to $415 million resulting from an event of a non-nuclear origin. The EMANI policy permits retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $2.0 million .
 
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from an incident at Unit 1 exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear or other incident. However, if such an incident were to occur, it likely would have a material impact on the Company’s and Consolidated SCE&G's results of operations, cash flows and financial position.

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, 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 SO 2 and NO X emission allowance programs with respect to coal plant emissions and also have constructed additional pollution control equipment at its coal-fired electric generating plants. These actions are expected to address many of the rules and regulations discussed herein.

116



On August 3, 2015, the EPA issued a revised standard for new power plants by re-proposing NSPS under the CAA for emissions of CO 2 from newly constructed fossil fuel-fired units. The final rule requires all new coal-fired power plants to meet a carbon emission rate of 1,400 pounds CO 2 per MWh and new natural gas units to meet 1,000 pounds CO 2 per MWh. While most new natural gas plants will not be required to include any new technologies, no new coal-fired plants could be constructed without partial carbon capture and sequestration capabilities. The Company and Consolidated SCE&G are monitoring the final 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 rule included state-specific goals for reducing national CO 2 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. In a separate but related action, the EPA issued an Advance Notice of Proposed Rulemaking on December 18, 2017, to solicit information from the public about a potential future rulemaking to limit greenhouse gas emissions from existing units. The Company and Consolidated SCE&G expect any costs incurred to comply with such rule to be recoverable through rates.

In July 2011, the EPA issued the CSAPR to reduce emissions of SO 2 and NO X from power plants in the eastern half of the United States. The CSAPR replaces the CAIR and requires a total of 28 states to reduce annual SO 2 emissions and annual and ozone season NO X emissions to assist in attaining the ozone and fine particle National Ambient Air Quality Standards. The rule establishes an emissions cap for SO 2 and NO X and limits the trading for emission allowances by separating affected states into two groups with no trading between the groups. The State of South Carolina has chosen to remain in the CSAPR program, even though recent court rulings exempted the state. This allows the state to remain compliant with regional haze standards. Air quality control installations that SCE&G and GENCO have already completed have positioned them to comply with the existing allowances set by the CSAPR. Any costs incurred to comply with CSAPR are expected to be recoverable through rates.

In April 2012, the EPA's MATS rule containing new standards for mercury and other specified air pollutants became effective. The MATS rule has been the subject of ongoing litigation even while it remains in effect. Rulings on this litigation are not expected to have an impact on SCE&G or GENCO due to plant retirements, conversions, and enhancements. SCE&G and GENCO are in compliance with the MATS rule and expect to remain in compliance.

The CWA provides for the imposition of effluent limitations that require treatment for wastewater discharges. Under the CWA, compliance with applicable limitations is achieved under state-issued NPDES permits such that, as a facility’s NPDES permit is renewed, any new effluent limitations would be incorporated. The ELG Rule had become 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

117


storage ponds and other CCR management facilities at SCE&G's and GENCO's coal-fired generating facilities. SCE&G and GENCO have already closed or have begun the process of closure of all of their ash storage ponds and have previously recognized AROs for such ash storage ponds under existing requirements. SCE&G has three ponds and three landfills that are governed by the CCR rule. 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.

The Nuclear Waste Act 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&G 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, 2016, the federal government has not accepted any spent fuel from Unit 1, and it remains unclear when the repository may become available. SCE&G has constructed an independent spent fuel storage installation to accommodate the spent nuclear fuel output for the life of Unit 1. SCE&G 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 DHEC and the EPA. SCE&G anticipates that major remediation activities at all these sites will continue at least through 2019 and will cost an additional $9.9 million , which is accrued in Other within Deferred Credits and Other Liabilities on the consolidated balance sheet. SCE&G expects to recover any cost arising from the remediation of MGP sites through rates. At December 31, 2017, deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $24.6 million and are included in regulatory assets.

Operating Lease Commitments

The Company and Consolidated SCE&G are obligated under various operating leases for land, office space, furniture, equipment, rail cars, a purchase power agreement, and for the Company, airplanes. Leases expire at various dates through 2057.
 
 
Rent Expense
Millions of dollars
 
2017
 
2016
 
2015
The Company
 
$
10.0

 
$
10.2

 
$
11.1

Consolidated SCE&G
 
11.4

 
12.2

 
12.3

 
 
Future Minimum Rental Payments
Millions of dollars
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
The Company
 
$
34

 
$
30

 
$
6

 
$
6

 
$
5

 
$
31

Consolidated SCE&G
 
26

 
23

 
1

 
1

 

 
17



118


Guarantees
 
SCANA issues guarantees on behalf of its consolidated subsidiaries to facilitate commercial transactions with third parties. These guarantees are in the form of performance guarantees, primarily for the purchase and transportation of natural gas, standby letters of credit issued by financial institutions 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 is included in the consolidated financial statements.  At December 31, 2017, the maximum future payments (undiscounted) that SCANA could be required to make under guarantees totaled approximately $1.8 billion .
 
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 the Company’s regulated utility operations.  As of December 31, 2017, SCE&G has recorded AROs of approximately $208 million for nuclear plant decommissioning (see Note 1). In addition, the Company has recorded AROs of approximately $360 million , including $321 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
 
2017
 
2016
 
2017
 
2016
Beginning balance
 
$
558

 
$
520

 
$
522

 
$
488

Liabilities incurred
 

 

 

 

Liabilities settled
 
(10
)
 
(11
)
 
(9
)
 
(11
)
Accretion expense
 
25

 
23

 
23

 
22

Revisions in estimated cash flows
 
(5
)
 
26

 
(7
)
 
23

Ending balance
 
$
568

 
$
558

 
$
529

 
$
522


Revisions in estimated cash flows in 2017 primarily related to ash pond retirement obligations settled and updates in the timing of cash flows as work is completed. Such revisions in 2016 related to changes in the expected timing of ARO settlements due to changes in the estimated useful lives of certain electric utility properties identified as part of a customary depreciation study.

11.          AFFILIATED TRANSACTIONS
 
The Company:

The Company received cash distributions from equity-method investees of $2.8 million in 2017, $3.7 million in 2016 and $4.0 million in 2015. The Company made investments in equity-method investees of $4.6 million in 2017, $5.5 million in 2016 and $4.1 million in 2015.

The Company and Consolidated SCE&G:
 
SCE&G owns 40% of Canadys Refined Coal, LLC, which is involved in the manufacturing and sale of refined coal to reduce emissions. SCE&G accounts for this investment using the equity method. The net of the total purchases and total sales are recorded in Other expenses on the consolidated statements of operations (for the Company) and of comprehensive income (for Consolidated SCE&G).


119



Millions of Dollars
 
2017
 
2016
 
2015
Purchases from Canadys Refined Coal, LLC
 
$
162.1

 
$
161.8

 
$
233.2

Sales to Canadys Refined Coal, LLC
 
161.1

 
160.8

 
232.0

Millions of Dollars
 
2017
 
2016
Receivable from Canadys Refined Coal, LLC
 
$
4.9

 
$
16.0

Payable to Canadys Refined Coal, LLC
 
4.9

 
16.1


Consolidated SCE&G:

SCE&G purchases natural gas and related pipeline capacity from SCANA Energy to serve its retail gas customers and for certain electric generation requirements.

SCANA Services, on behalf of itself and its parent company, provides the following services to Consolidated SCE&G, which are rendered at direct or allocated cost: information systems, telecommunications, customer support, marketing and sales, human resources, corporate compliance, purchasing, financial, risk management, public affairs, legal, investor relations, gas supply and capacity management, strategic planning, general administrative, and retirement benefits. In addition, SCANA Services processes and pays invoices for Consolidated SCE&G and is reimbursed. Costs for these services include amounts capitalized. Amounts expensed are recorded in Other operation and maintenance - nonconsolidated affiliate and Other expenses on the consolidated statements of comprehensive income (loss).
Millions of Dollars
 
2017
 
2016
 
2015
Purchases from SCANA Energy
 
$
127.4

 
$
111.5

 
$
128.5

Direct and Allocated Costs from SCANA Services
 
302.8

 
337.7

 
300.0

Millions of Dollars
 
2017
 
2016
Payable to SCANA Energy
 
$
10.0

 
$
8.8

Payable to SCANA Services
 
42.0

 
63.5


Prior to January 31, 2015, CGT was a wholly-owned subsidiary of SCANA and transported natural gas to SCE&G to serve retail gas customers and certain electric generation requirements.  SCE&G's purchases from CGT totaled approximately $3.4 million in 2015. 

Borrowings from and investments in an affiliated money pool are described in Note 4. SCE&G's participation in SCANA's noncontributory defined benefit pension plan and unfunded postretirement health care and life insurance programs is described in Note 8.

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. In addition, All Other includes gains from the sales of CGT and SCI (see Note 1) and their operating results prior to their sale in the first quarter of 2015. CGT and SCI were nonreportable segments during all periods presented. External revenue and intersegment revenue for All Other related to CGT and SCI were not significant during any period presented.
 
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.

120



Management uses operating income (loss) to measure segment profitability for its regulated operations and evaluates utility plant, net, for segments 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 of 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 the depreciation and amortization reported on a consolidated basis. Expenditures for Assets are adjusted for AFC and revisions to estimated cash flows related to AROs, and totals not allocated to other segments. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.

Disclosure of Reportable Segments 

The Company:
Millions of dollars
Electric
Operations
 
Gas
Distribution
 
Gas
Marketing
 
All
Other
 
Adjustments/
Eliminations
 
Consolidated
Total
2017
 
 
 
 
 
 
 
 
 
 
 
External Revenue
$
2,659

 
$
874

 
$
874

 

 

 
$
4,407

Intersegment Revenue
5

 
2

 
127

 
$
389

 
$
(523
)
 

Operating Income (Loss)
(161
)
 
186

 
n/a

 

 
51

 
76

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
957

 
148

 
n/a

 

 
48

 
1,153

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
)
 

 
 
 
 
 
 
 
 
 
 
 
 
2015
 

 
 

 
 

 
 

 
 

 
 

External Revenue
$
2,551

 
$
810

 
$
1,018

 
$
5

 
$
(4
)
 
$
4,380

Intersegment Revenue
6

 
2

 
128

 
413

 
(549
)
 

Operating Income
876

 
152

 
n/a

 
236

 
44

 
1,308


121


Interest Expense
17

 
23

 
1

 
1

 
276

 
318

Depreciation and Amortization
277

 
77

 
2

 
16

 
(14
)
 
358

Income Tax Expense
9

 
32

 
18

 
1

 
333

 
393

Net Income (Loss)
n/a

 
n/a

 
28

 
185

 
533

 
746

Segment Assets
10,883

 
2,606

 
201

 
998

 
2,458

 
17,146

Expenditures for Assets
1,087

 
203

 
2

 
15

 
(154
)
 
1,153

Deferred Tax Assets
5

 
29

 
15

 

 
(49
)
 


Consolidated SCE&G:
Millions of dollars
 
Electric
Operations
 
Gas
Distribution
 
Adjustments/
Eliminations
 
Consolidated
Total
2017
 
 
 
 
 
 
 
 
External Revenue
 
$
2,664

 
$
406

 

 
$
3,070

Operating Income (Loss)
 
(161
)
 
71

 

 
(90
)
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
 
957

 
56

 

 
1,013

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
)
 

 
 
 
 
 
 
 
 
 
2015
 
 

 
 

 
 

 
 

External Revenue
 
$
2,557

 
$
373

 

 
$
2,930

Operating Income
 
876

 
58

 

 
934

Interest Expense
 
17

 

 
$
231

 
248

Depreciation and Amortization
 
277

 
28

 
(11
)
 
294

Segment Assets
 
10,883

 
757

 
3,125

 
14,765

Expenditures for Assets
 
1,087

 
57

 
(136
)
 
1,008

Deferred Tax Assets
 
5

 
n/a

 
(5
)
 


13.          OTHER INCOME (EXPENSE), NET

Components of other income (expense), net are as follows:
 
 
The Company
 
Consolidated SCE&G
Millions of dollars
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
Other income
 
$
79

 
$
64

 
$
75

 
$
45

 
$
29

 
$
31

Other expense
 
(46
)
 
(38
)
 
(60
)
 
(25
)
 
(24
)
 
(31
)
Allowance for equity funds used during construction
 
23

 
29

 
27

 
15

 
26

 
25

Other income (expense), net
 
$
56

 
$
55

 
$
42

 
$
35

 
$
31

 
$
25



122



14.          QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company
Millions of dollars, except per share amounts
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Annual
2017
 
 

 
 

 
 

 
 

 
 

Total operating revenues
 
$
1,173


$
1,001


$
1,076


$
1,157


$
4,407

Operating income (loss)
 
316


249


120


(609
)

76

Net Income (Loss)
 
171


121


34


(445
)

(119
)
Earnings (Loss) per share
 
1.19


0.85


0.24


(3.11
)

(0.83
)
 
 
 
 
 
 
 
 
 
 
 
2016
 
 

 
 

 
 

 
 

 
 

Total operating revenues
 
$
1,172

 
$
905

 
$
1,093

 
$
1,057

 
$
4,227

Operating income
 
331

 
221

 
348

 
253

 
1,153

Net Income
 
176

 
105

 
189

 
125

 
595

Earnings per share
 
1.23

 
0.74

 
1.32

 
0.87

 
4.16

Consolidated SCE&G
Millions of dollars
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Annual
2017
 
 

 
 

 
 

 
 

 
 

Total operating revenues
 
$
719

 
$
756

 
$
856

 
$
739

 
$
3,070

Operating income (loss)
 
222

 
246

 
123

 
(681
)
 
(90
)
Net Income (Loss)
 
112

 
126

 
42

 
(452
)
 
(172
)
Earnings Available (Loss Attributable) to Common Shareholder
 
109

 
123

 
39

 
(456
)
 
(185
)
 
 
 
 
 
 
 
 
 
 
 
2016
 
 

 
 

 
 

 
 

 
 

Total operating revenues
 
$
717

 
$
692

 
$
882

 
$
695

 
$
2,986

Operating income
 
236

 
222

 
359

 
196

 
1,013

Net Income
 
116

 
113

 
204

 
93

 
526

Earnings Available to Common Shareholder
 
113

 
110

 
201

 
89

 
513


See Note 10 for a discussion of the impairment loss that was booked in the third quarter and the fourth quarter of 2017.

15.          SUBSEQUENT EVENT

On January 2, 2018, SCANA, Sedona Corp. and Dominion Energy entered into the Merger Agreement pursuant to which Sedona Corp. (a wholly-owned subsidiary of Dominion Energy) agreed to merge into SCANA in a stock-for-stock transaction in which SCANA shareholders would receive 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock. The completion of the merger is subject to a variety of closing conditions, including the receipt of approvals from SCANA's shareholders and is also subject to consents and approvals or findings from governmental entities, which may impose conditions that could have an adverse effect on the Company or Consolidated SCE&G or could cause either SCANA or Dominion Energy to abandon the merger. The completion of the merger is also subject to an absence of substantive changes in certain South Carolina laws, including the BLRA, that would reasonably be expected to have an adverse effect on SCANA or its subsidiaries, or if any governmental entity enacts any order or there is any change in law which imposes any material change to the terms, conditions or undertakings set forth in the Joint Petition or any significant changes to the economic value of the Joint Petition. See also Note 10.


123


ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
Not Applicable.
 
ITEM 9A.  CONTROLS AND PROCEDURES
 
SCANA:
 
Evaluation of Disclosure Controls and Procedures:
 
As of December 31, 2017, SCANA 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 SCANA’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, 2017, SCANA's disclosure controls and procedures were effective.

Management’s Evaluation of Internal Control Over Financial Reporting:

As of December 31, 2017, SCANA conducted an evaluation under the supervision and with the participation of its management, including its CEO and CFO, of any change in SCANA'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, 2017. There has been no change in SCANA’s internal controls over financial reporting during the quarter ended December 31, 2017 that has materially affected or is reasonably likely to materially affect SCANA’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 SCANA is responsible for establishing and maintaining adequate internal control over financial reporting. SCANA’s internal control system was designed by or under the supervision 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 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.
 
SCANA’s management assessed the effectiveness of SCANA’s internal control over financial reporting as of December 31, 2017.  In making this assessment, SCANA 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, SCANA’s management believes that, as of December 31, 2017, 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.

124


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 Stockholders of
SCANA Corporation
Cayce, South Carolina



Opinion on 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, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards 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, 2017, of the Company and our report dated February 22, 2018, expressed an unqualified opinion on those financial statements and financial statement schedule and included an emphasis-of-matter paragraph regarding legal, legislative, and regulatory matters that may result in material impacts to results and the liquidity of the Company as a result of the abandoned Nuclear Project.

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 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 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 22, 2018
 


125


SCE&G:
 
Evaluation of Disclosure Controls and Procedures:
 
As of December 31, 2017, 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, 2017, SCE&G's disclosure controls and procedures were effective.

Management’s Evaluation of Internal Control Over Financial Reporting:
 
As of December 31, 2017, 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, 2017. There has been no change in SCE&G’s internal controls over financial reporting during the quarter ended December 31, 2017 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 designed by or under the supervision of SCE&G’s management, including its CEO and CFO, to provide reasonable assurance to SCE&G’s management 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, 2017. 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, 2017, 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
 
SCANA: A list of SCANA's executive officers is in Part I of this annual report on Form 10-K at page 34. As permitted by Form 10-K General Instruction G(3), the other information required by this Item will be incorporated by reference to SCANA's definitive proxy statement for the 2018 annual meeting of shareholders or included in an amendment to this Form 10-K to be filed not later than 120 days after December 31, 2017, which is the end of the fiscal year for SCANA.

SCE&G: Not applicable. 


126



ITEM 11.  EXECUTIVE COMPENSATION
 
SCANA: As permitted by Form 10-K General Instruction G(3), the information required by this Item will be incorporated by reference to SCANA's definitive proxy statement for the 2018 annual meeting of shareholders or included in an amendment to this Form 10-K to be filed not later than 120 days after December 31, 2017, which is the end of the fiscal year for SCANA.

SCE&G: Not applicable.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
 
SCANA: As permitted by Form 10-K General Instruction G(3), the information required by this Item will be incorporated by reference to SCANA's definitive proxy statement for the 2018 annual meeting of shareholders or included in an amendment to this Form 10-K to be filed not later than 120 days after December 31, 2017, which is the end of the fiscal year for SCANA.

Equity securities issuable under SCANA’s compensation plans at December 31, 2017 are summarized as follows:
Plan Category
Number of
securities
to be issued
upon exercise
of outstanding
options, warrants
and rights
 
 
Weighted-average
exercise price of outstanding options,
warrants
and rights
 
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column (a))
 
(a)
 
 
(b)
 
(c)
Equity compensation plans approved by security holders:
-

 
 
 
 
 

2015 Long-Term Equity Compensation Plan
454,023

(1)  
 
n/a
 
4,545,977

Non-Employee Director Compensation Plan
n/a

 
 
n/a
 
154,635

Equity compensation plans not approved by security holders
n/a

 
 
n/a
 
n/a

Total
454,023

 
 
n/a
 
4,700,612

 
(1) Represents unearned non-vested performance share awards from the 2015-2017, 2016-2018 and 2017-2019 performance periods, assuming a target level payout.

SCE&G: Not applicable.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
SCANA: As permitted by Form 10-K General Instruction G(3), the information required by this Item will be incorporated by reference to SCANA's definitive proxy statement for the 2018 annual meeting of shareholders or included in an amendment to this Form 10-K to be filed not later than 120 days after December 31, 2017, which is the end of the fiscal year for SCANA.

SCE&G: Not applicable.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

SCANA and SCE&G:
 
The Audit Committee Charter requires 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 may pre-approve the rendering of services on behalf of the Audit Committee. Decisions by the Chairman to pre-approve the rendering of services are presented to the Audit Committee at its next scheduled meeting.
 

127



Independent Registered Public Accounting Firm’s Fees
 
The following table sets forth the aggregate fees, all of which were approved by the Audit Committee, charged to the Company and Consolidated SCE&G for the fiscal years ended December 31, 2017 and 2016 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
 
 
The Company
 
Consolidated SCE&G
 
 
2017
 
2016
 
2017
 
2016
Audit Fees (1)
 
$
3,670,360

 
$
2,857,000

 
$
3,127,191

 
$
2,316,288

Audit-Related Fees (2)
 
168,229

 
171,710

 
139,172

 
117,146

Total Fees
 
$
3,838,589

 
$
3,028,710

 
$
3,266,363

 
$
2,433,434


(1)  Fees for audit services billed in 2017 and 2016 consisted of audits of annual financial statements, comfort letters for securities underwriters, statutory and regulatory audits, consents and other services related to SEC filings, and accounting research.
 
(2)  Fees primarily for employee benefit plan audits and non-statutory audit services.

PART IV
 
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
(a)    The following 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 following the signature page. Certain of such exhibits which have heretofore been filed with the SEC and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.
 
Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA’s employee stock purchase plan will be furnished under cover of Form 11-K to the SEC when the information becomes available.
 
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% of the total 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 instruments to the SEC upon request.


128


Schedule II—Valuation 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
 
 

 
 

 
 

 
 

 
 

2017
 
$
6

 
$
13

 

 
$
13

 
$
6

2016
 
5

 
12

 

 
11

 
6

2015
 
7

 
12

 

 
14

 
5

Reserves other than those deducted from assets on the balance sheet:
 
 

 
 

 
 

 
 

 
 

Reserve for injuries and damages
 
 

 
 

 
 

 
 

 
 

2017
 
$
9

 
$
8

 

 
$
8

 
$
9

2016
 
6

 
5

 

 
2

 
9

2015
 
5

 
11

 

 
10

 
6

 
 
 
 
 
 
 
 
 
 
 
SCE&G:
 
 

 
 

 
 

 
 

 
 

Reserves deducted from related assets on the balance sheet:
 
 

 
 

 
 

 
 

 
 

Uncollectible accounts
 
 

 
 

 
 

 
 

 
 

2017
 
$
3

 
$
8

 

 
$
7

 
$
4

2016
 
3

 
6

 

 
6

 
3

2015
 
4

 
6

 

 
7

 
3

Reserves other than those deducted from assets on the balance sheet:
 
 

 
 

 
 

 
 

 
 

Reserve for injuries and damages
 
 

 
 

 
 

 
 

 
 

2017
 
$
8

 
$
8

 

 
$
8

 
$
8

2016
 
5

 
5

 

 
2

 
8

2015
 
3

 
11

 

 
9

 
5



129


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.
 
SCANA CORPORATION
 
 
BY:
/s/ J. E. Addison
 
 
J. E. Addison, Chief Executive Officer and President
 
 
 
 
DATE:
February 22, 2018
 
 
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 thereof.
  
/s/ J. E. Addison
 
J. E. Addison, Chief Executive Officer and President
 
(Principal Executive Officer)
 
 
 
 
 
/s/ I. N. Griffin
 
I. N. Griffin, Senior Vice President and Chief Financial Officer
 
(Principal Financial Officer)
 
 
 
 
 
/s/ J. E. Swan, IV
 
J. E. Swan, IV
Vice President and Controller
 
(Principal Accounting Officer)
 
 
Directors*:
G. E. Aliff
L. M. Miller
J. A. Bennett
J. W. Roquemore
J. F. A. V. Cecil
M. K. Sloan
S. A. Decker
A. Trujillo
D. M. Hagood
 
 
 
 

*   Signed on behalf of each of these persons by Jim Odell Stuckey, Attorney-in-Fact
 
DATE: February 22, 2018


130


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/ J. E. Addison
 
J. E. Addison, Chief Executive Officer
 
 
 
 
DATE:
February 22, 2018
 
 
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. 
/s/ J. E. Addison
 
J. E. Addison Chief Executive Officer
 
(Principal Executive Officer)
 
 
 
 
 
/s/ I. N. Griffin
 
I. N. Griffin
Senior Vice President and Chief Financial Officer
 
(Principal Financial Officer)
 
 
 
 
 
/s/ J. E. Swan, IV
 
J. E. Swan, IV
Vice President and Controller
 
(Principal Accounting Officer)
 
 
Directors*:
G. E. Aliff
L. M. Miller
J. A. Bennett
J. W. Roquemore
J. F. A. V. Cecil
M. K. Sloan
S. A. Decker
A. Trujillo
D. M. Hagood
 
 
 
 

*   Signed on behalf of each of these persons by Jim Odell Stuckey, Attorney-in-Fact
 
DATE: February 22, 2018

131


EXHIBIT INDEX
Exhibit
 
Applicable to
Form 10-K of
 
 
No.
 
SCANA
 
SCE&G
 
Description
*2.01

 
X
 
 
 
Agreement and Plan of Merger by and among Dominion Energy, Sedona Corp., and SCANA, dated as of January 2, 2018 ( Filed as Exhibit 2.1 to Form 8-K on January 5, 2018 (File No. 001-08809 (SCANA) ) and incorporated by reference herein)
3.01

 
X
 
 
 
Restated Articles of Incorporation of SCANA, as adopted on April 26, 1989 (Filed as Exhibit 3-A to Registration Statement No. 33-49145 and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
3.02

 
X
 
 
 
Articles of Amendment dated April 27, 1995 ( Filed as Exhibit 4-A to Registration Statement No. 33-62421  and incorporated by reference herein)
3.03

 
X
 
 
 
Articles of Amendment effective April 25, 2011 ( Filed as Exhibit 4.03 to Registration Statement No. 333-174796  and incorporated by reference herein)
3.04

 
 
 
X
 
Restated Articles of Incorporation of SCE&G, as adopted on December 30, 2009 ( Filed as Exhibit 1 to Form 8-A (File No. 000-53860 ) and incorporated by reference herein)
3.05

 
X
 
 
 
By-Laws of SCANA as amended and restated as of December 30, 2016 ( Filed as Exhibit 3.05 to Form 10-K for the period ended December 31, 2016 (File No. 001-08809 ) and incorporated by reference herein)
3.06

 
 
 
X
 
By-Laws of SCE&G as revised and amended on February 22, 2001 ( Filed as Exhibit 3.05 to Registration Statement No. 333-65460  and incorporated by reference herein)
4.01

 
X
 
X
 
Articles of Exchange of SCE&G and SCANA (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

 
 
 
X
 
Indenture dated as of April 1, 1993 from SCE&G 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). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.04

 
 
 
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). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.05

 
 
 
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). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
4.06

 
 
 
X
 
Third Supplemental Indenture to Indenture referred to in Exhibit 4.04 dated as of September 1, 2013 ( Filed as Exhibit 4.12 to Post-Effective Amendment to Registration Statement No. 333-184426-01  and incorporated by reference herein)
10.01

 
X
 
X
 
Engineering, Procurement and Construction Agreement, dated May 23, 2008, between SCE&G, for itself and as Agent for the South Carolina Public Service Authority and a Consortium consisting of Westinghouse Electric Company LLC and Stone & Webster, Inc. ( Filed as Exhibit 10.01 to Amendment No. 2 of Form 10-Q/A for the quarter ended June 30, 2008 filed on May 25, 2017 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
10.02

 
X
 
X
 
Contract for AP1000 Fuel Fabrication and Related Services between Westinghouse Electric Company LLC and SCE&G for V. C. Summer AP1000 Nuclear Plant Units 2 & 3 (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 10.01 to Form 10-Q/A for the quarter ended June 30, 2011 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G) ) and incorporated by reference herein)

132


10.03

 
X
 
X
 
Amendment to EPC Contract referred to in Exhibit 10.01 dated October 27, 2015 ( Filed as Exhibit 10.05 to Form 10-Q for the quarter ended September 30, 2015 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
**10.04

 
X
 
X
 
SCANA Executive Deferred Compensation Plan (including amendments through November 25, 2014) ( Filed as Exhibit 10.03 to Form 10-K for the year ended December 31, 2014 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
**10.05

 
X
 
X
 
SCANA Supplemental Executive Retirement Plan (including amendments through December 31, 2009) ( Filed as Exhibit 99.05 to Registration Statement No. 333-174796  and incorporated by reference herein)
**10.06

 
X
 
X
 
**10.07

 
X
 
X
 
SCANA Long-Term Equity Compensation Plan effective February 19, 2015 ( Filed as Exhibit 4.05 to Registration Statement No. 333-204218  and incorporated by reference herein)
**10.08

 
X
 
X
 
SCANA Supplementary Executive Benefit Plan (including amendments through December 31, 2009) ( Filed as Exhibit 99.07 to Registration Statement No. 333-174796  and incorporated by reference herein)
**10.09

 
X
 
X
 
SCANA Short-Term Annual Incentive Plan (including amendments through December 31, 2009) ( Filed as Exhibit 99.08 to Registration Statement No. 333-174796  and incorporated by reference herein)
**10.10

 
X
 
X
 
SCANA Supplementary Key Executive Severance Benefits Plan (including amendments through December 31, 2009) ( Filed as Exhibit 99.09 to Registration Statement No. 333-174796  and incorporated by reference herein)
**10.11

 
X
 
X
 
Description of SCANA Whole Life Option (Filed as Exhibit 10-F for the year ended December 31, 1991, under cover of Form SE (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G)) and incorporated by reference herein). (Filed on paper - hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.12

 
 
 
X
 
Service Agreement between SCE&G and SCANA Services, Inc., effective January 1, 2004 ( Filed as Exhibit 99.10 to Registration Statement No. 333-174796  and incorporated by reference herein)
10.13

 
X
 
 
 
Form of Indemnification Agreement ( Filed as Exhibit 10.01 to Form 10-Q dated June 30, 2012 (File No. 001-08809 ) and incorporated by reference herein)
10.14

 
X
 
 
 
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among SCANA; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; Morgan Stanley 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., Mizuho Bank, 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)
10.15

 
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 Issuing Bank 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 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 99.2 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
10.16

 
X
 
X
 
Amended and Restated Three-Year Credit Agreement dated as of December 17, 2015, by and among SCE&G; the lenders identified therein; Wells Fargo Bank, National Association, as Swingline Lender and Agent; Morgan Stanley Bank, N.A., as Issuing Bank; Bank of America, N.A. as Issuing Bank 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 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 99.3 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G) ) and incorporated by reference herein)

133


10.17

 
X
 
X
 
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among Fuel Company; the lenders identified therein; Wells Fargo Bank, National Association, as Swingline Lender and Agent; 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., Mizuho Bank, LTD., MUFG Union Bank, N.A., TD Bank N.A. and UBS Securities, LLC, as Documentation Agents ( Filed as Exhibit 99.4 to Form 8-K on December 22, 2015 (File No. 001-08809 (SCANA); (File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
10.18

 
X
 
 
 
Second Amended and Restated Five-Year Credit Agreement dated as of December 17, 2015, by and among PSNC Energy; the lenders identified therein; Wells Fargo Bank, National Association, as Issuing Bank, Swingline Lender and Agent; 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., 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 Form 8-K on December 22, 2015 (File No. 001-08809 ) and incorporated by reference herein)
10.19

 
X
 
X
 
Settlement Agreement dated as of July 27, 2017, by and among Toshiba Corporation, SCE&G and Santee Cooper ( Filed as Exhibit 99.2 to Form 8-K dated July 27, 2017 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
10.20

 
X
 
X
 
Trade Confirmation dated September 25, 2017, between SCE&G, Santee Cooper and Citibank, N.A., and associated Assignment and Purchase Agreement, dated September 27, 2017, by and among SCE&G, Santee Cooper and Citibank, N. A. ( Filed as Exhibit 10.03 to Form 10-Q for the quarter ended September 30, 2017 (File No. 001-08809 (SCANA); File No. 001-03375 (SCE&G) ) and incorporated by reference herein)
12.01

 
X
 
X
 
21.01

 
X
 
 
 
23.01

 
X
 
 
 
23.02

 
 
 
X
 
24.01

 
X
 
 
 
Power of Attorney  (Filed herewith)
24.02

 
 
 
X
 
Power of Attorney  (Filed herewith)
31.01

 
X
 
 
 
31.02

 
X
 
 
 
31.03

 
 
 
X
 
31.04

 
 
 
X
 
32.01

 
X
 
 
 
32.02

 
 
 
X
 
101. INS***
 
X
 
X
 
XBRL Instance Document
101. SCH***
 
X
 
X
 
XBRL Taxonomy Extension Schema
101. CAL***
 
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.
** Management Contract or Compensatory Plan or Arrangement
*** 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, and otherwise is not subject to liability under these sections.


134


Exhibit 10.06

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SECTION 11. EXECUTION

IN WITNESS WHEREOF, the Company has caused this SCANA Corporation Director
Compensation and Deferral Plan to be executed by its duly authorized officer to be effective on
the 25th day of August , 2016.

SCANA Corporation

By: /s/ M. K. Phalen
Title: Senior Vice President, Administration






ATTEST:
/s/ G. Champion
Vice President, Corporate Secretary


Exhibit 12.01
COMPUTATION OF RATIOS
December 31, 2017

BOND RATIO
    
SCANA and SCE&G:
Dollars in Millions
 
 
 
Year Ended December 31, 2017
 
 
 
Net earnings as defined in SCE&G's bond indenture dated April 1, 1993 (Mortgage)
 
$
1,342.7

*
Divide by annualized interest charges on:
 
 
 
Bonds outstanding under the Mortgage
$
256.4

 
 
Total annualized interest charges
256.4

 
 
Bond Ratio
 
5.24

 
* Net earnings as defined excludes the recognition of expense due to the nonrecoverability of investment; therefore, it excludes the impairment loss.
 
 
 


RATIO OF EARNINGS TO FIXED CHARGES
Dollars in Millions
 
SCANA
 
SCE&G
Years Ended December 31,
 
2017
2016
2015
2014
2013
 
2017
2016
2015
2014
2013
Fixed Charges as defined:
 
 
 
 
 
 
 
 
 
 
 
 
Interest on debt
 

$377.6


$356.8


$327.8


$318.2


$305.9

 

$300.2


$284.6


$258.4


$237.6


$226.4

Amortization of debt premium, discount and expense (net)
 
4.0

4.5

4.7

9.7

5.3

 
2.9

3.5

3.7

4.4

4.2

Interest component on rentals
 
3.3

3.5

3.7

4.1

4.9

 
3.8

4.0

4.1

4.0

4.5

Total Fixed Charges (A)
 

$384.9


$364.8


$336.2


$332.0


$316.1

 

$306.9


$292.1


$266.2


$246.0


$235.1

Earnings as defined:
 
 
 
 
 
 
 
 
 
 
 
 
Pretax income (loss) from continuing operations
 

($230.7
)

$865.6


$1,138.4


$786.0


$693.8

 

($342.6
)

$774.1


$711.0


$676.0


$579.7

Total fixed charges above
 
384.9

364.8

336.2

332.0

316.1

 
306.9

292.1

266.2

246.0

235.1

Pretax equity in (earnings) losses of investees
 
8.9

(0.7
)
0.8

(1.4
)
(3.2
)
 
4.6

3.1

5.0

5.3

3.5

Cash distributions from equity investees
 
2.7

3.7

4.0

7.4

9.6

 
-

-

-

-

-

Total Earnings (Loss) (B)
 
$165.8
$1,233.4
$1,479.4
$1,124.0
$1,016.3
 

($31.1
)

$1,069.3


$982.2


$927.3


$818.3

Ratio of Earnings (Loss) to Fixed Charges (B/A)
 
0.43

3.38

4.40

3.39

3.22

 
(0.10)

3.66

3.69

3.77

3.48

Amount of Earnings Deficiency Below Fixed Charges
 

$219.1

 
 
 
 
 

$338.0

 
 
 
 
 



Exhibit 21.01

Each of the following subsidiaries of SCANA is incorporated in the state of South Carolina, except as otherwise indicated.
South Carolina Electric & Gas Company
South Carolina Generating Company, Inc.
South Carolina Fuel Company, Inc.
Public Service Company of North Carolina, Incorporated
SCANA Energy Marketing, Inc.
SCANA Services, Inc.
SCANA Communications Holdings, Inc., incorporated in the State of Delaware
SCANA Corporate Security Services, Inc.

 



Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 333-191691, 333-204218 and 333-213797 on Form S-8 and Registration Statement Nos. 333-206629 and 333-213798 on Form S-3 of our reports dated February 22, 2018, relating to the consolidated financial statements and financial statement schedule of SCANA Corporation and subsidiaries (the “Company”) (which report expresses an unqualified opinion and includes an emphasis-of-matter paragraph regarding legal, legislative, and regulatory matters that may result in material impacts to results and the liquidity of the Company as a result of the abandoned Nuclear Project), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of SCANA Corporation for the year ended December 31, 2017.

/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 22, 2018








Exhibit 23.02

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-206629-01 on Form S-3 of our report dated February 22, 2018, relating to the consolidated financial statements and financial statement schedule of South Carolina Electric & Gas Company and affiliates (which report expresses an unqualified opinion and includes an emphasis-of-matter paragraph regarding legal, legislative, and regulatory matters that may result in material impacts to results and the liquidity of the Company as a result of the abandoned Nuclear Project), appearing in this Annual Report on Form 10-K of South Carolina Electric & Gas Company for the year ended December 31, 2017.


/s/DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 22, 2018
    
    



Exhibit 24.01
POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned, being a director or officer of SCANA Corporation (“SCANA”), hereby constitutes and appoints Jimmy E. Addison, Iris N. Griffin and Jim Odell Stuckey, and each of them, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead in any and all capacities, to sign an Annual Report for SCANA’s fiscal year ended December 31, 2017, on Form 10-K under the Securities Exchange Act of 1934, as amended, or such other form as any such attorney-in-fact may deem necessary or desirable, and any amendments to the foregoing (collectively, the “Annual Report”), each in such form as they or any one of them may approve, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done so that such Annual Report shall comply with the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations adopted or issued pursuant thereto, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or their substitute or resubstitute, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned has hereunto set his or her hand this 22nd day of February 2018.


/s/G. E. Aliff
 
/s/J. A. Bennett
G. E. Aliff
 
J. A. Bennett
Director
 
Director
 
 
 
 
 
 
/s/J. F. A. V. Cecil
 
/s/S. A. Decker
J. F. A. V. Cecil
 
S. A. Decker
Director
 
Director
 
 
 
 
 
 
/s/D. M. Hagood
 
/s/L. M. Miller
D. M. Hagood
 
L. M. Miller
Director
 
Director
 
 
 
 
 
 
/s/J. W. Roquemore
 
/s/M. K. Sloan
J. W. Roquemore
 
M. K. Sloan
Director
 
Director
 
 
 
 
 
 
/s/A. Trujillo
 
 
A. Trujillo
 
 
Director
 
 
 
 
 



Exhibit 24.02

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned, being a director or officer of South Carolina Electric & Gas Company (“SCE&G”), hereby constitutes and appoints Jimmy E. Addison, Iris N. Griffin and Jim Odell Stuckey, and each of them, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead in any and all capacities, to sign an Annual Report for SCE&G’s fiscal year ended December 31, 2017, on Form 10-K under the Securities Exchange Act of 1934, as amended, or such other form as any such attorney-in-fact may deem necessary or desirable, and any amendments to the foregoing (collectively, the “Annual Report”), each in such form as they or any one of them may approve, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done so that such Annual Report shall comply with the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations adopted or issued pursuant thereto, as fully and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or their substitute or resubstitute, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF, each of the undersigned has hereunto set his or her hand this 22nd day of February 2018.


/s/G. E. Aliff
 
/s/J. A. Bennett
G. E. Aliff
 
J. A. Bennett
Director
 
Director
 
 
 
 
 
 
/s/J. F. A. V. Cecil
 
/s/S. A. Decker
J. F. A. V. Cecil
 
S. A. Decker
Director
 
Director
 
 
 
 
 
 
/s/D. M. Hagood
 
/s/L. M. Miller
D. M. Hagood
 
L. M. Miller
Director
 
Director
 
 
 
 
 
 
/s/J. W. Roquemore
 
/s/M. K. Sloan
J. W. Roquemore
 
M. K. Sloan
Director
 
Director
 
 
 
 
 
 
/s/A. Trujillo
 
 
A. Trujillo
 
 
Director
 
 
 
 
 






Exhibit 31.01
 
CERTIFICATION
 
I, Jimmy E. Addison, certify that:
 
1.             I have reviewed this annual report on Form 10-K of SCANA Corporation;
 
2.             Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.             Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.             The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.             The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 22, 2018
/s/Jimmy E. Addison
 
Jimmy E. Addison, Chief Executive Officer and President
 
 
 





Exhibit 31.02
 
CERTIFICATION
 
I, Iris N. Griffin, certify that:
 
1.             I have reviewed this annual report on Form 10-K of SCANA Corporation;
 
2.             Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.             Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.             The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.             The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
February 22, 2018
/s/Iris N. Griffin
 
Iris N. Griffin
 
Senior Vice President and Chief Financial Officer
 





Exhibit 31.03
 
CERTIFICATION
 
I, Jimmy E. Addison, certify that:
 
1.             I have reviewed this annual report on Form 10-K of South Carolina Electric & Gas Company;
 
2.             Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.             Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.             The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.             The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
February 22, 2018
/s/Jimmy E. Addison
 
Jimmy E. Addison
 
Chief Executive Officer






Exhibit 31.04 
CERTIFICATION
 
I, Iris N. Griffin, certify that:
 
1.             I have reviewed this annual report on Form 10-K of South Carolina Electric & Gas Company;
 
2.             Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.             Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.             The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a)           Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b)           Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c)           Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d)           Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5.             The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a)           All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b)           Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
February 22, 2018
/s/Iris N. Griffin
 
Iris N. Griffin
 
Senior Vice President and Chief Financial Officer





Exhibit 32.01 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002


 
In connection with the Annual Report of SCANA Corporation (the “Company”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 22, 2018
 
 
 
 
 
 
 
 
/s/Jimmy E. Addison
 
/s/Iris N. Griffin
Jimmy E. Addison
 
Iris N. Griffin
Chief Executive Officer and President
 
Senior Vice President and Chief Financial Officer







Exhibit 32.02
 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of South Carolina Electric & Gas Company (the “Company”) on Form 10-K for the year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we certify pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


February 22, 2018
 
 
 
 
 
 
 
 
/s/Jimmy E. Addison
 
/s/Iris N. Griffin
Jimmy E. Addison
 
Iris N. Griffin
Chief Executive Officer
 
Senior Vice President and Chief Financial Officer