SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report: September 6, 1995
SCANA Corporation
(Exact name of registrant as specified in its charter)
South Carolina 1-8809 57-0784499
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
1426 Main Street, Columbia, South Carolina 29201
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (803) 748-3000
(Former name or former address, if changed since last report.)
Item 5. Other Events.
During the second quarter of 1995, as reported in SCANA's Form
10-Q for the quarter ended June 30, 1995, SCANA's oil and gas
subsidiary, SCANA Petroleum Resources, Inc. (Petroleum Resources)
changed from the successful efforts method to the full cost method
of accounting for its oil and gas operations. The Company believes
the full cost method provides a better matching of revenues and
expenses given the change in Petroleum Resources' primary focus
from a purchaser of producing oil and gas properties to a developer
of reserves on its own or others' properties. The financial
statements of prior periods have been restated to apply the new
method retroactively. The following restatements of information
previously included in SCANA's Annual Report on Form 10-K for the
year ended December 31, 1994 are included herein:
Financial statements for the three-year period ended December
31, 1994, footnotes thereto and an independent auditors'
report thereon;
Management's Discussion and Analysis for the three-year period
ended December 31, 1994;
Selected Financial Data as of and for each of the five years
ended December 31, 1994 and as of and for the year ended
December 31, 1984; and
Ratios of earnings to fixed charges (SEC method) for each of
the five years ended December 31, 1994.
The restatements also reflect the effect of a two-for-one
stock split effective May 11, 1995 and reported in Form 8-K dated
April 28, 1995.
Capitalized terms used in this Report, other than in the
Financial Statements and Supplementary Data, have the meanings set
forth on page 4 of SCANA Corporation's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, unless the context
requires otherwise.
2
TABLE OF CONTENTS
Page
Selected Financial Data....................................... 4
Management's Discussion and Analysis
of Financial Condition and Results of Operations............ 6
Financial Statements and Supplementary Data................... 15
Independent Auditors' Report.................................. 16
Consolidated Balance Sheets................................... 17
Capitalization and Liabilities................................ 18
Consolidated Statements of Income and
Retained Earnings........................................... 19
Consolidated Statements of Cash Flows......................... 20
Consolidated Statements of Capitalization..................... 21
Notes To Consolidated Financial Statements.................... 22
Signatures.................................................... 44
Exhibit Index................................................. 45
3
SELECTED FINANCIAL DATA
For the Years Ended December 31, 1994 1993 1992 1991 1990 1984
Statement of Income Data (Thousands of dollars except statistics and per share amounts)
Operating Revenues:
Electric $ 975,388 $ 940,121 $ 829,477 $ 867,215 $ 851,146 $ 755,502
Gas 342,672 320,195 305,275 276,742 292,380 378,491
Transit 4,002 3,851 3,623 3,869 4,033 3,178
Total Operating Revenues 1,322,062 1,264,167 1,138,375 1,147,826 1,147,559 1,137,171
Operating Expenses:
Fuel used in electric generation
and purchased power 255,240 242,793 213,474 234,683 223,972 235,246
Gas purchased for resale 220,923 208,695 191,577 171,869 191,939 289,212
Other operation and maintenance 293,721 290,891 281,242 270,213 265,887 184,727
Depreciation and amortization 119,177 112,844 108,315 102,669 97,801 74,914
Taxes 173,448 163,633 133,987 146,032 142,003 153,776
Total Operating Expenses 1,062,509 1,018,856 928,595 925,466 921,602 937,875
Operating Income 259,553 245,311 209,780 222,360 225,957 199,296
Other Income (29,749) 27,335 11,960 (1,231) 54,874 17,647
Income Before Interest Charges and
Preferred Stock Dividends 229,804 272,646 221,740 221,129 280,831 216,943
Interest Charges, Net 108,397 101,189 97,600 91,458 92,317 78,248
Preferred Stock Cash Dividends of
Subsidiary 5,955 6,217 6,473 6,706 6,911 16,877
Net Income $ 115,452 $ 165,240 $ 117,667 $ 122,965 $ 181,603 $ 121,818
Percent of Operating Income (Loss)
Before Income Taxes
Electric 88% 90% 85% 89% 89% 87%
Gas 14% 13% 18% 14% 14% 15%
Transit (2%) (3%) (3%) (3%) (3%) (2%)
Common Stock Data
Weighted Average Number of Common
Shares Outstanding (Thousands) 94,762 90,407 82,950 80,722 81,764 79,801
Earnings Per Weighted Average Share of
Common Stock $1.22 $1.83 $1.42 $1.52 $2.22 $1.53
Dividends Declared Per Share of Common
Stock $1.41 $1.37 $1.34 $1.31 $1.26 $1.03
Common Shares Outstanding (Year-End)
(Thousands) 96,035 93,239 87,821 81,569 81,764 80,592
Book Value Per Share of Common Stock
(Year-End) $14.15 $14.13 $13.08 $12.46 $12.28 $ 9.66
4
December 31, 1994 1993 1992 1991 1990 1984
Balance Sheet Data (Thousands of dollars except statistics and per share amounts)
Utility Plant, Net $3,293,667 $3,004,075 $2,810,279 $2,664,651 $2,549,763 $2,205,297
Total Assets $4,314,508 $4,016,902 $3,538,314 $3,286,338 $3,144,936 $2,506,996
Common Equity $1,359,141 $1,317,495 $1,149,087 $1,016,104 $1,003,877 $ 778,251
Preferred Stock (Not subject
to purchase or sinking
fund requirements) 26,027 26,027 26,027 26,027 26,027 26,262
Preferred Stock, Net (Subject
to purchase or sinking
fund requirements) 49,528 52,840 56,154 59,469 62,704 152,974
Long-Term Debt, Net 1,537,624 1,424,399 1,204,754 1,122,396 938,933 900,878
Total Capitalization $2,972,320 $2,820,761 $2,436,022 $2,223,996 $2,031,541 $1,858,365
Other Statistics
Electric:
Customers (Year-End) 476,412 468,874 461,900 453,660 446,516 378,963
Territorial sales (Million KWH) 16,838 16,880 15,794 15,695 15,385 12,590
Residential:
Average annual use per
customer (KWH) 13,048 14,077 13,037 13,246 13,330 12,061
Average annual rate
per KWH $.0743 $.0707 $.0695 $.0700 $.0707 $.0757
Generating Capability - Net MW
(Year-End) 3,876 3,864 3,912 3,912 3,891 3,959
Territorial Peak Demand - Net MW 3,444 3,557 3,380 3,300 3,222 2,596
Gas:
Customers (Year-End) 238,614 234,736 231,153 225,819 220,817 189,544
Sales (Thousand Therms) 781,109 717,417 761,721 694,801 711,821 737,059
Residential:
Average annual use per
customer (therms) 543 605 577 521 497 618
Average annual rate
customer (therms) 543 605 577 521 497 618
Average annual rate
per therm $.84 $.76 $.74 $.77 $.77 $.69
5
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less regulatory
protection. The transition began with the enactment of the Public
Utility Regulatory Policies Act of 1978 which facilitated the entry
of competitors into the electric generation business.
Subsequently, the National Energy Policy Act (NEPA) was enacted in
1992 to promote competition among utility and nonutility generators
in the wholesale electric generation market. Recent initiatives in
some states to lessen regulation and promote competition,
particularly with regard to retail transmission access, also have
accelerated the utility industry's transition.
Future deregulation of electric wholesale and retail markets
will create opportunities to compete for new and existing customers
and markets. As a result, profit margins and asset values of some
utilities could be adversely affected.
The pace of deregulation, the future market price of
electricity, and the regulatory actions which may be taken by the
Public Service Commission of South Carolina (PSC) in response to
the changing environment cannot be predicted. However, the Company
is aggressively pursuing actions to position itself strategically
for the transformed environment. To enhance its flexibility and
responsiveness to change, the Company's electric and gas utility,
SCE&G, reorganized its operations around Strategic Business Units.
Maintaining a competitive cost structure is of paramount importance
in the utility's strategic plan. SCE&G has undertaken a variety of
initiatives, including reductions in operations and maintenance
costs and in staffing levels. SCE&G believes that these actions as
well as numerous others that have been and will be taken
demonstrate its ability and commitment to succeed in the new
operating environment to come.
LIQUIDITY AND CAPITAL RESOURCES
The cash requirements of the Company arise primarily from
SCE&G's operational needs, the Company's construction program and
the need to fund the activities or investments of the Company's
nonregulated subsidiaries. The ability of the Company's regulated
subsidiaries to replace existing plant investment, as well as to
expand to meet future demand for electricity and gas, will depend
upon their ability to attract the necessary financial capital on
reasonable terms. The Company's 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 the regulated
subsidiaries expand their construction programs, it is necessary to
seek increases in rates. As a result, the Company's future
financial position and results of operations will be affected by
the regulated subsidiaries' ability to obtain adequate and timely
rate relief.
Due to continuing customer growth, SCE&G entered into a
contract with Duke/Fluor Daniel in 1991 to design, engineer and
build a 385 MW coal-fired electric generating plant near Cope,
South Carolina in Orangeburg County. Construction of the plant
began in November 1992 and is expected to be complete in late 1995
with commercial operation beginning in early 1996. The estimated
cost of the Cope plant, excluding financing costs and allowance for
funds used during construction (AFC), but including an allowance
for escalation, is $450 million. In addition, the transmission
lines for interconnection with the Company's system are expected to
cost $26 million. Until the completion of the new plant, SCE&G is
contracting for additional capacity as necessary to ensure that the
energy demands of its customers can be met.
As discussed in Note 2B of Notes to Consolidated Financial
Statements, on June 7, 1993 the PSC issued an order granting SCE&G
a 7.4% annual increase in retail electric rates which was
implemented in two phases over a two year period: phase one,
effective June 1993, producing $42.0 million annually, and phase
two, effective June 1994, producing $18.5 million annually, based
on a test year.
6
The estimated primary cash requirements for 1995, excluding
requirements for fuel liabilities and short-term borrowings, and
the actual primary cash requirements for 1994 are as follows:
1995 1994
(Thousands of Dollars)
Property additions and construction
expenditures, excluding allowance for
funds used during construction (AFC) $348,530 $471,175
Acquisition of oil and gas producing
properties - 47,189
Nuclear fuel expenditures 23,084 27,429
Maturing obligations, redemptions and
sinking and purchase fund requirements 25,630 30,373
Total $397,244 $576,166
Approximately 31% of total cash requirements (excluding
dividends) was provided from internal sources in 1994 as compared
to 28% in 1993.
The Company has in effect a program for the issuance from time
to time of unsecured medium-term debt securities. The proceeds
from the sales of these securities may be used to fund additional
business activities in nonutility subsidiaries, to reduce short-
term debt incurred in connection therewith or for general corporate
purposes. In December 1994, a shelf registration statement filed
with the Securities and Exchange Commission became effective
providing for the issuance of up to an additional $250 million in
medium-term notes. At December 31, 1994 the Company had available
for issuance $317.6 million.
SCE&G's First and Refunding Mortgage Bond Indenture, dated
April 1, 1945 (Old Mortgage), contains provisions prohibiting the
issuance of additional bonds thereunder (Class A Bonds) unless net
earnings (as therein defined) for 12 consecutive months out of the
15 months prior to the month of issuance are at least twice the
annual interest requirements on all Class A Bonds to be outstanding
(Bond Ratio). For the year ended December 31, 1994 the Bond Ratio
was 3.52. The issuance of additional Class A Bonds is restricted
also to an additional principal amount equal to 60% of unfunded net
property additions (which unfunded net property additions totaled
approximately $499.8 million at December 31, 1994), Class A Bonds
issued on the basis of retirements of Class A Bonds (no earned
retirement credits were remaining at December 31, 1994), and Class
A Bonds issued on the basis of cash on deposit with the Trustee.
SCE&G has placed a new bond indenture (New Mortgage) dated
April 1, 1993 on substantially all of its electric properties under
which its future mortgage-backed debt (New Bonds) will be issued.
New Bonds are expected to be issued under the New Mortgage on the
basis of a like principal amount of Class A Bonds issued under the
Old Mortgage which have been deposited with the Trustee of
the New Mortgage (of which $57 million were available for such
purpose as of December 31, 1994), until such time as all presently
outstanding Class A Bonds are retired. Thereafter, New Bonds will
be issuable on the basis of property additions in a principal
amount equal to 70% of the original cost of electric and common
plant properties (compared to 60% of value for Class A Bonds under
the Old Mortgage), cash deposited with the Trustee, and retirement
of New Bonds. New Bonds will be issuable under the New 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 the annual interest
requirements on all outstanding bonds (including Class A Bonds) and
New Bonds to be outstanding (New Bond Ratio). For the year ended
December 31, 1994 the New Bond Ratio was 4.85.
7
The following additional financing transactions have
occurred since December 31, 1993:
On January 14, 1994 the Company closed unsecured bank
loans totaling $60 million due January 13, 1995, and used
the proceeds to pay off a loan in a like total amount. In
January 1995 the Company refinanced the loans with an
unsecured bank loan of $60 million due January 12, 1996 at
an initial interest rate of 6.44%, subject to reset
quarterly at LIBOR plus ten basis points.
On July 21, 1994 SCE&G issued $100 million of First Mortgage
Bonds, 7.70% series due July 15, 2004 to repay short-term
borrowings in a like amount.
On November 3, 1994 SCE&G issued $30 million of Pollution
Control Facilities Revenue Bonds due November 1, 2024. The
proceeds from the sale of the bonds are being used to defray
the cost of constructing certain facilities for the disposal
of solid waste at SCE&G's Cope Generating Station under
construction in Orangeburg County, South Carolina.
Without the consent of at least a majority of the total
voting power of SCE&G's preferred stock, SCE&G may not issue or
assume any unsecured indebtedness if, after such issue or
assumption, the total principal amount of all such unsecured
indebtedness would exceed 10% of the aggregate principal amount of
all of SCE&G's secured indebtedness and capital and surplus;
provided, however, that no such consent shall be required to enter
into agreements for payment of principal, interest and premium for
securities issued for pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, SCE&G and
GENCO must obtain FERC authority to issue short-term indebtedness.
The FERC has authorized SCE&G to issue up to $200 million of
unsecured promissory notes or commercial paper with maturity
dates of 12 months or less, but not later than December 31, 1997.
GENCO has not sought such authorization.
The Company had $479.1 million authorized lines of credit and
had unused lines of credit of $455.1 million at December 31, 1994.
In addition, SCE&G has a credit agreement for a maximum of $75
million to finance nuclear and fossil fuel inventories, with $24.4
million available at December 31, 1994.
SCE&G's Restated Articles of Incorporation prohibit issuance
of additional shares of preferred stock without consent of the
preferred stockholders unless net earnings (as defined therein) for
the 12 consecutive months immediately preceding the month of
issuance are at least one and one-half times the aggregate of all
interest charges and preferred stock dividend requirements
(Preferred Stock Ratio). For the year ended December 31, 1994
the Preferred Stock Ratio was 2.29.
In December 1994 a registration statement was declared
effective by the SEC pursuant to which the Company will be able to
issue 4,000,000 additional shares of common stock under the Stock
Purchase-Savings Program (SPSP).
During 1994 the Company issued 1,190,876 shares of the
Company's common stock under the DRP. In addition, the Company
issued 1,562,708 shares of its common stock pursuant to its SPSP.
The Company has authorized and reserved for issuance, pursuant to
effective registration statements, 2,940,772 and 4,182,132 shares
of common stock pursuant to the DRP and the SPSP, respectively.
8
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. of Greenville, South
Carolina for $91.5 million. On March 4, 1994 the Company and
Liberty amended the agreement to exclude certain projects then
under construction, and the sales price was reduced to $49.6
million. The transaction was closed on May 27, 1994. Certain
other assets of SCANA Development Corporation are being sold to
other parties. These transactions did not have a material impact
on the Company's financial position or results of operations.
MPX Systems Inc., a wholly owned subsidiary of SCANA, through
a joint venture with ITC Transmission Systems, a Georgia-based
telecommunications holding company, is constructing a fiber optic
network through Texas, Louisiana, Mississippi, Alabama and
Georgia. The network, which will consist of more than 900 miles of
fiber optic lines, is expected to be completed by June 1995 at a
cost of $58 million. In addition, MPX is pursuing Personal
Communication Services licenses for wireless communications in the
Southeast through a joint venture with ITC Personal Communications,
Inc., Intercel PCS Services, Inc., and South Atlantic PCS
Corporation. A $40 million construction loan obtained by the joint
venture has been guaranteed in part by SCANA Corporation. All new
ventures currently capitalize on the fiber infrastructure in place
and provide for expansion of the network.
The Company anticipates that its 1995 cash requirements of
$397.2 million will be met through internally generated funds
(approximately 42% excluding dividends), the sales of additional
equity securities and the incurrence of additional short-term and
long-term indebtedness. The timing and amount of such financing
will depend upon market conditions and other factors. Actual 1995
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
As required by the "ceiling test" under the full cost method
of accounting for oil and gas operations, reserve adjustments of
$94.1 million and $1.7 million were recorded during the years ended
December 31, 1994 and 1992, respectively. These adjustments were
non-cash in nature and had no impact on the liquidity of Petroleum
Resources or of the Company.
The Company expects that it has or can obtain adequate sources
of financing to meet its projected cash requirements.
Environmental Matters
The Clean Air Act requires electric utilities to reduce
substantially emissions of sulfur dioxide and nitrogen oxide by the
year 2000. These requirements are being phased in over two
periods. The first phase has a compliance date of January 1, 1995
and the second, January 1, 2000. The Company meets all
requirements of Phase I and, therefore, will not have to implement
changes until compliance with Phase II requirements is necessary.
The Company then will most likely meet its compliance requirements
through the burning of natural gas and/or lower sulfur coal, the
addition of scrubbers to coal-fired generating units, and the
purchase of sulfur dioxide emission allowances. At December 31,
1994, the Company had purchased $19.4 million in emission
allowances and had commitments to purchase $6.8 million in emission
allowances in 1995. Low nitrogen oxide burners will be installed
to reduce nitrogen oxide emissions.
The Company is continuing to refine a compliance plan that
must be filed with the U.S. Environmental Protection Agency (EPA)
by January 1, 1996. The Company currently estimates that air
emissions control equipment will require capital expenditures of
$158 million over the 1995-1999 period to retrofit existing
facilities and an increased operation and maintenance cost of
approximately $1 million per year. To meet compliance
requirements through the year 2004, the Company anticipates
total capital expenditures of $287 million.
9
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a national
permit program. Discharge permits have been issued for all and
renewed for nearly all of SCE&G's and GENCO's generating units.
Concurrent with renewal of these permits, the permitting agency has
implemented more rigorous control programs. The Company has been
developing compliance plans to meet the additional parameters of
control, and compliance has involved updating wastewater treatment
technologies. Amendments to the Clean Water Act proposed recently
in Congress include several provisions which could prove costly to
SCE&G. These include limitations to mixing zones and the
implementation of technology-based standards.
The South Carolina Solid Waste Policy and Management Act of
1991 requires promulgation of regulations addressing specified
subjects, one of which affects the management of industrial solid
waste. This regulation will establish minimum criteria for
industrial landfills as mandated under the Act. The proposed
regulation, if adopted as a final regulation in its present form,
could significantly impact SCE&G's and GENCO's engineering, design
and operation of existing and future ash management facilities.
Potential cost impacts could be substantial.
As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program to
identify and assess current and former operations sites that could
require environmental cleanup. As site assessments are initiated,
an estimate is made of the amount of expenditures, if any,
necessary to investigate and clean up each site. These estimates
are refined as additional information becomes available; therefore,
actual expenditures could differ significantly from the original
estimates. Amounts estimated and accrued to date for site
assessments and cleanup relate primarily to regulated operations;
such amounts have been deferred and are being amortized and
recovered through rates over a ten-year period for electric
operations and a eight-year period for gas operations. Such
deferred amounts totaled $20.2 million and $19.6 million at
December 31, 1994 and 1993, respectively. Estimates to date
include, among other things, the costs associated with the matters
discussed in the following paragraphs.
SCE&G, the Company's principal subsidiary, owns five
decommissioned manufactured gas plant sites which contain residues
of by-product chemicals. SCE&G has maintained an active review of
the sites to monitor the nature and extent of the residual
contamination.
In September 1992 the EPA notified SCE&G, the City of
Charleston and the Charleston Housing Authority of their potential
liability for the investigation and cleanup of the Calhoun Park
Area Site in Charleston, South Carolina. This site originally
encompassed approximately 18 acres and included properties which
were the locations for industrial operations, including a wood
preserving (creosote) plant and one of SCE&G's decommissioned
manufactured gas plants. The original scope of this investigation
has been expanded to approximately 30 acres, including adjacent
properties owned by the National Park Service and the City of
Charleston, and private properties. The site has not been placed
on the National Priority List, but may be added before cleanup is
initiated. The potentially responsible parties (PRP) have agreed
with the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigations process to be
compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study (RI/FS) and a corresponding Scope
of Work. Actual field work began November 1, 1993 after final
approval and authorization was granted by the EPA. SCE&G is also
working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the City's aquarium site. In 1994 the City of
Charleston notified SCE&G that it considers SCE&G to be responsible
for a $43.5 million increase in costs of the aquarium project
attributable to delays resulting from contamination of the Calhoun
Park Area Site. SCE&G believes it has meritorious defenses against
this claim and does not expect its resolution to have a material
impact on its financial position or results of operations.
10
SCE&G has been listed as a PRP and has recorded liabilities,
which are not considered material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina, the Aqua-Tech
Environmental, Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina.
The Arkansas Department of Pollution Control And Ecology
(ADPCE) has identified SCE&G as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from ADPCE has been received concerning this
issue. SCE&G does not believe that the resolution of this issue
will have a material effect on SCE&G's results of operations or
financial position.
Regulatory Matters
On June 7, 1993 the PSC issued an order on SCE&G's pending
electric rate proceeding allowing an authorized return on common
equity of 11.5%, resulting in a 7.4% annual increase in retail
electric rates, or a projected $60.5 million annually, based on a
test year. These rates were implemented in two phases over a two-
year period: phase one, effective June 1993, producing $42.0
million annually, and phase two, effective June 1994, producing
$18.5 million annually, based on a test year.
SCE&G anticipates filing for electric rate relief in 1995.
The filing is anticipated to encompass primarily the remaining cost
of completing the construction of the Cope Generating Station.
The Company's regulated business operations are likely to be
impacted by NEPA and FERC Order No. 636. NEPA is designed to
create a more competitive wholesale power supply market by creating
"exempt wholesale generators" and by potentially requiring
utilities owning transmission facilities to provide transmission
access to wholesalers. Order No. 636 is intended to deregulate the
markets for interstate sales of natural gas by requiring that
pipelines provide transportation services that are equal in quality
for all gas suppliers whether the customer purchases gas from the
pipeline or another supplier. In the opinion of the Company, it
will be able to meet successfully the challenges of these altered
business climates and does not anticipate there to be any
materially adverse impact on the results of its operations, its
financial position or its business prospects.
Other
The Company's net investment in oil and gas properties is
subject to a quarterly ceiling limitation calculation that is based
on the future net revenues from forecasted production of proved oil
and gas reserves valued at current or contract prices. Carrying
values of proved reserves in excess of the ceiling limitation are
expensed currently.
In an effort to limit exposure to changing natural gas prices,
in January 1995 the Company entered into a series of forward
contracts relating to natural gas production. These forward
contracts have the effect of stabilizing the price that the Company
will receive on approximately sixty percent of its forecasted
natural gas production for the years 1995-2001. The forward
contracts are at an average price of $1.88 per dekatherm. If
market prices exceed the forward contracts' prices at the time of
delivery, the Company will forego additional revenues to the extent
of the price differential for the quantities subject to such
forward contracts. However, the Company believes these forward
contracts are appropriate in light of current market conditions and
that the forward contracts reduce the Company's exposure to price
risk. The Company remains exposed to price risk for any production
that is not subject to such forward contracts.
11
RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share of common stock, the percent increase
(decrease) from the previous year and the rate of return earned on
common equity for the years 1992 through 1994 were as follows:
1994 1993 1992
Earnings per weighted average share $1.22 $1.83 $1.42
Percent increase (decrease) in earnings
per share (33.3%) 28.9% (6.6%)
Return earned on common equity (year-end) 8.5% 12.5% 10.2%
1994 Earnings per share and return on common equity
decreased in 1994 primarily due to operations at Petroleum
Resources, the Company's oil and natural gas exploration
and production subsidiary. Petroleum Resources reported a
net loss of $54.9 million for 1994 as compared to net
income of $8.4 million for 1993. The change results
primarily from charges recorded from application of the
ceiling test (Note 1M).
1993 Earnings per share and return on common equity
increased in 1993 primarily due to a higher electric sales
margin and additional nonoperating income.
The Company's financial statements include 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) as noncash items both of which have
the effect of increasing reported net income. AFC represented
approximately 8.3% of income before income taxes in 1994, 5.8% in
1993 and 5.3% in 1992.
In 1994 SCANA's Board of Directors raised the quarterly cash
dividend on common stock to 35.25 cents per share from 34.25
cents per share. The increase, effective with the dividend
payable on April 1, 1994, raised the indicated annual dividend
rate to $1.41 per share from $1.37. SCANA has increased the
dividend rate on its common stock in 41 of the last 42 years.
Electric Operations
1994 The increase in the electric sales margin from 1993
to 1994 is primarily the result of an increase in retail electric
rates phased in over a two-year period
beginning June 1993 and an increase in industrial sales,
which more than offset the negative impact of a six percent
decrease in residential sales of electricity due to milder
weather in 1994.
1993 The increase in electric sales margin from 1992 to
1993 is primarily a result of increased residential and
commercial KWH sales due to weather and customer growth,
an increase in retail electric rates beginning in June
1993 and the recording in 1992 of a $14.6 million reserve
against earnings related to the August 31, 1992 retail
electric rate ruling from the Supreme Court (see Note 2G
of Notes to Consolidated Financial Statements).
12
An increase of 7,538 electric customers to 476,412 total
customers contributed to a 1994 peak demand of 3,444 MW on
January 19. The all time peak demand record of 3,557 MW was set
on July 29, 1993.
Gas Operations
1994 The 1994 gas sales margin increased from 1993
primarily as a result of lower gas costs which allowed
Pipeline Corporation to compete successfully with
alternate fuel suppliers in industrial markets. Higher oil
prices and a stronger economy had a positive impact on
industrial sales which increased for both SCE&G and Pipeline
Corporation.
1993 In 1993 the gas sales margin decreased from 1992 as a
result of higher gas prices which reducedPipeline Corporation's
sales due to the competitiveness of
alternate fuels. This reduction was partially offset by
increases in higher margin residential and commercial sales
and increased transportation volumes.
Other Operating Expenses
1994 Other operation and maintenance expenses increased for
1994 primarily due to an increase in the costs of
postretirement benefits other than pensions which are
accrued in accordance with Financial Accounting Standards
Board Statement No. 106 (See Note 1J of Notes to
Consolidated Financial Statements.) The increase in
depreciation and amortization expenses is attributable to
property additions and to increases in depreciation rates.
The increase in other taxes reflects an increase in
SCE&G's property taxes of approximately $5 million.
1993 Other operation and maintenance expenses increased for
1993 primarily due to the implementation of Financial
Accounting Standards Board Statement No. 106 (see Note 1J
of Notes to Consolidated Financial Statements) pursuant to
the June 1993 PSC electric rate order and the amortization
of environmental expenses. The depreciation and
amortization increase reflects additions to plant in
service. The increase in income taxes corresponds to the
increase in income and reflects the increase in the
corporate tax rate from 34% to 35% retroactive to January
1, 1993.
Other Income
Other income, net of income taxes, decreased approximately
$56.3 million in 1994 primarily due to operations at Petroleum
Resources which reported a net loss of $54.9 million for the
year. The change results primarily from charges recorded from
application of the ceiling test (Note 1M).
The Company's net investment in oil and gas properties is
subject to a quarterly ceiling limitation calculation that is
based on the future net revenues from forecasted production of
proved oil and gas reserves valued at current or contract prices.
Carrying values of proved reserves in excess of the ceiling
limitation are expensed currently.
13
In an effort to limit exposure to changing natural gas
prices, in January 1995 the Company entered into a series of
forward contracts relating to natural gas production. These
forward contracts have the effect of stabilizing the price that
the Company will receive on approximately sixty percent of its
forecasted natural gas production for the years 1995-2001. The
forward contracts are at an average price of $1.88 per dekatherm.
If market prices exceed the forward contracts' prices at the time
of delivery, the Company will forego additional revenues to the
extent of the price differential for the quantities subject to
such forward contracts. However, the Company believes these
forward contracts are reasonable in light of current market
conditions and that the forward contracts reduce the Company's
exposure to price risk. The Company remains exposed to price
risk for any production that is not subject to such forward
contracts.
Interest Expense
1994 The increase in interest expense (excluding the debt
component of AFC) is primarily attributable to the issuance
of $100 million of First Mortgage Bonds in July
and $30 million of Pollution Control Facilities Revenue
Bonds in November, both to finance utility construction, and
to the issuance of long-term debt during 1993.
1993 Interest on long-term debt increased approximately
$5.6 million in 1993 compared to 1992 due to the issuance
of $72.4 million medium-term notes during the
latter part of 1992 and $60 million medium-term notes in
July 1993 to finance acquisitions of natural gas reserves
and the issuance of $200 million of SCE&G's First Mortgage
Bonds to finance utility construction. The resulting
increases more than offset the interest savings resulting
from the redemption and refinancing of $382 million of
First and Refunding Mortgage Bonds with the proceeds from
the issuance of $400 million of First Mortgage Bonds by
SCE&G at lower interest rates.
14
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditor's Report....................................... 18
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1994 and 1993... 19
Consolidated Statements of Income and Retained Earnings for
the years ended December 31, 1994, 1993 and 1992............. 21
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1993 and 1992............................. 22
Consolidated Statements of Capitalization as of
December 31, 1994 and 1993................................... 23
Notes to Consolidated Financial Statements..................... 25
Supplemental financial statement schedules are omitted because of the
absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or in the
notes thereto.
15
INDEPENDENT AUDITORS' REPORT
SCANA CORPORATION:
We have audited the accompanying Consolidated Balance Sheets
and Consolidated Statements of Capitalization of SCANA
Corporation and subsidiaries (Company) as of December 31, 1994
and 1993 and the related Consolidated Statements of Income and
Retained Earnings and of Cash Flows for each of the three years
in the period ended December 31, 1994. These financial
statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements
present fairly, in all material respects, the financial position
of the Company at December 31, 1994 and 1993, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1994 in conformity with generally
accepted accounting principles.
As discussed in Note 1A, the financial statements have been
restated to reflect the change from the successful efforts method
to the full cost method of accounting for the Company's oil and
gas operations.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 6, 1995 (September 6, 1995
as it relates to the restated
financial statements discussed
in Note 1A)
16
CONSOLIDATED BALANCE SHEETS
December 31, 1994 1993
ASSETS (Thousands of Dollars)
Utility Plant (Notes 1, 3 and 4):
Electric $3,424,951 $3,328,915
Gas 467,576 451,493
Transit 3,785 3,769
Common 77,327 72,804
Total 3,973,639 3,856,981
Less accumulated depreciation and amortization 1,333,360 1,259,689
Total 2,640,279 2,597,292
Construction work in progress 582,628 349,530
Nuclear fuel, net of accumulated amortization 43,591 29,087
Acquisition adjustment-gas, net of accumulated amortization 27,169 28,166
Utility Plant, Net 3,293,667 3,004,075
Nonutility Property and Investments (Net of accumulated
depreciation and depletion)(Note 1) 317,309 370,104
Current Assets:
Cash and temporary cash investments (Note 8) 10,934 20,766
Receivables 183,180 174,121
Inventories (at average cost):
Fuel (Notes 3 and 4) 60,273 62,977
Materials and supplies 47,463 46,890
Prepayments 19,853 21,826
Accumulated deferred income taxes 18,629 8,607
Total Current Assets 340,332 335,187
Deferred Debits:
Emission allowances 19,409 -
Unamortized debt expense 13,488 13,076
Unamortized deferred return on plant investment (Note 1) 10,614 14,860
Nuclear plant decommissioning fund (Note 1) 30,383 25,103
Other (Notes 1 and 10) 289,306 254,497
Total Deferred Debits 363,200 307,536
Total $4,314,508 $4,016,902
17
December 31, 1994 1993
CAPITALIZATION AND LIABILITIES (Thousands of Dollars)
Stockholders' Investment (Note 5):
Common equity $1,359,141 $1,317,495
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027
Total Stockholders' Investment 1,385,168 1,343,522
Preferred Stock, Net (Subject to purchase or sinking
funds)(Notes 6 and 8) 49,528 52,840
Long-Term Debt, Net (Notes 3, 4 and 8) 1,537,624 1,424,399
Total Capitalization 2,972,320 2,820,761
Current Liabilities:
Short-term borrowings (Notes 8 and 9) 183,027 43,019
Current portion of long-term debt (Note 3) 38,055 34,322
Current portion of preferred stock (Note 6) 2,418 2,504
Accounts payable 117,959 129,495
Estimated rate refunds and related interest (Note 2) - 2,509
Customer deposits 13,768 13,498
Taxes accrued 46,670 50,063
Interest accrued 25,226 21,784
Dividends declared 35,530 33,637
Other 17,220 12,649
Total Current Liabilities 479,873 343,480
Deferred Credits:
Accumulated deferred income taxes (Notes 1 and 7) 561,703 560,098
Accumulated deferred investment tax credits (Notes 1 and 7) 91,349 94,981
Accumulated reserve for nuclear plant decommissioning (Note 1) 30,383 25,103
Other (Note 1) 178,880 172,479
Total Deferred Credits 862,315 852,661
Commitments and Contingencies (Note 10) - -
Total $4,314,508 $4,016,902
See Notes to Consolidated Financial Statements.
18
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the Years Ended December 31, 1994 1993 1992
(Thousands of Dollars
except per share amounts)
Operating Revenues (Notes 1 and 2):
Electric $ 975,388 $ 940,121 $ 829,477
Gas 342,672 320,195 305,275
Transit 4,002 3,851 3,623
Total Operating Revenues 1,322,062 1,264,167 1,138,375
Operating Expenses:
Fuel used in electric generation 235,136 229,736 206,151
Purchased power 20,104 13,057 7,323
Gas purchased for resale 220,923 208,695 191,577
Other operation (Note 1) 229,996 223,239 215,800
Maintenance (Note 1) 63,725 67,652 65,442
Depreciation and amortization (Note 1) 119,177 112,844 108,315
Income taxes (Notes 1 and 7) 94,510 90,007 60,947
Other taxes 78,938 73,626 73,040
Total Operating Expenses 1,062,509 1,018,856 928,595
Operating Income 259,553 245,311 209,780
Other Income (Note 1):
Other income (loss), net of income taxes (37,925) 18,406 6,465
Allowance for equity funds used during construction 8,176 8,929 5,495
Total Other Income (29,749) 27,335 11,960
Income Before Interest Charges
and Preferred Stock Dividends 229,804 272,646 221,740
Interest Charges (Credits):
Interest on long-term debt, net 108,804 98,695 93,052
Other interest expense 6,749 8,672 8,819
Allowance for borrowed funds used
during construction (Note 1) (7,156) (6,178) (4,271)
Total Interest Charges, Net 108,397 101,189 97,600
Income Before Preferred Stock Cash
Dividends of Subsidiary 121,407 171,457 124,140
Preferred Stock Cash Dividends of
Subsidiary (At stated rates) (5,955) (6,217) (6,473)
Net Income 115,452 165,240 117,667
Retained Earnings at Beginning of Period, as
previously reported 506,380 462,893 457,393
Adjustments for the cumulative effect on prior
periods of applying retroactively the full
cost method of accounting for oil and gas (Note 1A) (15,550) (12,809) (12,886)
Balance at beginning of period, as adjusted 490,830 450,084 444,507
Common Stock Cash Dividends Declared (Note 5) (133,911) (124,494) (112,090)
Retained Earnings at End of Year $ 472,371 $ 490,830 $ 450,084
Net Income $ 115,452 $ 165,240 $ 117,667
Weighted Average Number of Common Shares
Outstanding (Thousands) 94,762 90,407 82,950
Earnings Per Weighted Average Share of Common Stock $1.22 $1.83 $1.42
See Notes to Consolidated Financial Statements.
19
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1994 1993 1992
(Thousands of Dollars)
Cash Flows From Operating Activities:
Net income $115,452 $165,240 $117,667
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization 272,106 163,263 127,072
Amortization of nuclear fuel 13,487 18,156 23,190
Deferred income taxes, net (9,282) 63,729 (10,743)
Deferred investment tax credits, net (3,632) (3,658) (3,667)
Net regulatory asset - adoption of SFAS No. 109 (1,951) (31,531) -
Dividends declared on preferred stock of subsidiary 5,955 6,217 6,473
Allowance for funds used during construction (15,332) (15,107) (9,766)
Unamortized loss on reacquired debt (60) (17,063) (81)
Nuclear refueling accrual (4,881) (6,086) 11,862
Equity in (earnings) losses of investees (230) (319) 652
Over (under) collections, fuel adjustment clause (16,966) (14,308) 7,482
Emission allowances (19,409) - -
Changes in certain current assets and liabilities:
(Increase) decrease in receivables (9,059) (35,244) (8,918)
(Increase) decrease in inventories 2,131 (10,995) (234)
Increase (decrease) in accounts payable (11,536) 28,109 7,282
Increase (decrease) in estimated rate
refunds and related interest (2,509) (15,302) 17,811
Increase (decrease) in taxes accrued (3,393) (14,941) 1,691
Increase (decrease) in interest accrued 3,442 (7,511) 663
Other, net (11,423) 3,955 12,354
Net Cash Provided From Operating Activities 302,910 276,604 300,790
Cash Flows From Investing Activities:
Utility property additions and construction expenditures (404,600) (322,381) (277,636)
(Increase) decrease in nonutility property and investments:
Acquisition of oil and gas producing properties (47,189) (122,621) (74,766)
Nonutility property (115,541) (82,066) (35,956)
Investments (19,006) (4,066) (2,591)
Sale of Real Estate Assets 79,439 - -
Principal noncash item:
Allowance for funds used during construction 15,332 15,107 9,766
Net Cash Used For Investing Activities (491,565) (516,027) (381,183)
Cash Flows From Financing Activities:
Proceeds:
Issuance of mortgage bonds 100,000 600,000 -
Issuance of common stock 63,317 129,066 126,809
Issuance of notes and loans 60,000 148,059 154,254
Issuance of pollution control bonds 30,000 - -
Other long-term debt - 3,005 -
Repayments:
Mortgage bonds - (430,000) (35,890)
Notes (75,545) (72,040) (95,272)
Other long-term debt (11,430) (1,195) (255)
Preferred stock (3,398) (3,295) (3,199)
Dividend payments:
Common stock (131,925) (122,129) (109,383)
Preferred stock (6,048) (6,247) (6,558)
Short-term borrowings, net 140,008 1,863 20,390
Fuel financings, net 13,844 (18,948) (6,628)
Net Cash Provided By Financing Activities 178,823 228,139 44,268
Net Decrease in Cash and Temporary Cash Investments (9,832) (11,284) (36,125)
Cash and Temporary Cash Investments, January 1 20,766 32,050 68,175
Cash and Temporary Cash Investments, December 31 $ 10,934 $ 20,766 $ 32,050
Supplemental Cash Flows Information:
Cash paid for - Interest $110,347 $113,010 $100,340
- Income taxes 90,012 93,337 81,819
Noncash Financing Activities:
Department of Energy decontamination and
decommissioning obligation - 4,965 -
See Notes to Consolidated Financial Statements.
20
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1994 1993
Common Equity (Note 5): (Thousands of Dollars)
Common stock, without par value, authorized 150,000,000 shares; issued
and outstanding, 1994 - 96,035,020 shares and 1993 - 93,238,914 shares $ 886,770 $ 826,665
Retained earnings 472,371 490,830
Total Common Equity 1,359,141 46% 1,317,495 47%
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5):
$100 Par Value - Authorized 200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
$100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767
$50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1%
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8):
$100 Par Value - Authorized 1,550,000 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
7.70% 89,984 92,992 101.00 - 101.00 8,998 9,299
8.12% 126,835 131,899 102.03 - 102.03 12,684 13,190
216,819 224,891
$50 Par Value - Authorized 1,627,074 shares
Shares Outstanding Redemption Price
Eventual
Series 1994 1993 Current Through Minimum
4.50% 19,088 20,800 51.00 - 51.00 954 1,040
4.60% 2,334 3,834 50.50 - 50.50 117 192
4.60%(A) 28,052 30,052 51.00 - 51.00 1,403 1,503
4.60%(B) 78,200 81,600 50.50 - 50.50 3,910 4,080
5.125% 73,000 74,000 51.00 - 51.00 3,650 3,700
6.00% 86,400 89,600 50.50 - 50.50 4,320 4,480
8.72% 127,956 160,000 51.00 12-31-98 50.00 6,398 8,000
9.40% 190,245 197,191 51.175 - 51.175 9,512 9,860
605,275 657,077
$25 Par Value - Authorized 2,000,000 shares; none outstanding in 1994 and 1993
Total Preferred Stock (Subject to purchase or sinking funds) 51,946 55,344
Less: Current portion, including sinking fund requirements 2,418 2,504
Total Preferred Stock, Net (Subject to purchase or sinking funds) 49,528 2% 52,840 2%
21
December 31, 1994 1993
Long-Term Debt (Notes 3, 4 and 8): (Thousands of Dollars)
SCANA Corporation:
Bank Notes, due 1996 (6.44%, reset quarterly) 60,000 60,000
Medium-term Notes:
Year of
Series Maturity
5.76% 1998 20,000 20,000
7.17% 1999 42,400 42,400
6.60% 1999 30,000 30,000
6.15% 2000 20,000 20,000
6.51% 2003 20,000 20,000
South Carolina Electric & Gas Company:
First Mortgage Bonds:
Year of
Series Maturity
6% 2000 100,000 100,000
6 1/4% 2003 100,000 100,000
7.70% 2004 100,000 -
7 1/8% 2013 150,000 150,000
7 1/2% 2023 150,000 150,000
7 5/8% 2023 100,000 100,000
First and Refunding Mortgage Bonds:
Year of
Series Maturity
4 7/8% 1995 16,000 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 145,000 145,000
8 7/8% 2021 155,000 155,000
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,660 6,760
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365
Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 -
Capitalized Lease Obligations, due 1991-1997 (various rates between
5 3/4% and 10%) 1,842 2,897
Installment Note Payable, due 1996 1,452 2,277
Department of Energy Decontamination and Decommissioning Obligation 3,922 4,634
South Carolina Generating Company, Inc.:
Berkeley County Pollution Control
Facilities Revenue Bonds, due 2014 (6.50%) 35,850 35,850
Note, 7.78%, due 2011 67,400 71,100
South Carolina Fuel Company, Inc.:
Nuclear and Fossil Fuel Liability 50,594 36,750
South Carolina Pipeline Corporation:
Notes, 6.72%, due 2013 23,750 25,000
Note, 9.27%, due 1991-1994 - 8,000
SCANA Development Corporation:
Notes, due 1994-2004 (various rates between 8.5% and 12.0%) - 1,770
Bank Loans, due 1994-1998 (various rates between 6% and 6.25%) 3,246 13,839
Total Long-Term Debt 1,580,601 1,464,762
Less - Current maturities, including sinking fund requirements 38,055 34,322
- Unamortized discount 4,922 6,041
Total Long-Term Debt, Net 1,537,624 51% 1,424,399 50%
Total Capitalization $2,972,320 100% $2,820,761 100%
See Notes to Consolidated Financial Statements.
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
SCANA Corporation (Company), a South Carolina corporation,
is a public utility holding company within the meaning of the
Public Utility Holding Company Act of 1935 but is exempt from
registration under such Act.
On April 27, 1995, the Company's Board of Directors approved
a two-for-one split of the Company's Common Stock effective at
the close of business May 11, 1995. The weighted average number
of common shares outstanding, earnings per weighted average share
of common stock and cash dividends declared per share of common
stock have been restated to reflect the stock split for all
periods reported.
During the second quarter of 1995, SCANA Petroleum Resources
changed from the successful efforts method to the full cost
method of accounting for its oil and gas operations. The Company
believes the full cost method provides a better matching of
revenues and expenses given the change in Petroleum Resources'
primary focus from a purchaser of producing oil and gas
properties to a developer of reserves on its own or others'
properties. The financial statements have been restated to apply
the new method retroactively. The effects of the accounting
change on the income statements for the years ended December 31,
1994, 1993 and 1992, respectively, are as follows:
Increase (Decrease)
(In thousands, except per share amounts)
Year Ended December
Effect on-- 1994 1993 1992
Other income, net of
income taxes $(35,747) $(2,741) $ 77
Net income $(35,747) $(2,741) $ 77
Earnings Per Weighted
Average Share of
Common Stock* $ (.38) $ (.03) $ -
* The effect on prior periods has been adjusted for a two-for-one stock
split effective May 11, 1995.
The balances of retained earnings as of December 31, 1994, 1993
and 1992 have been reduced for the effect (net of income taxes)
of applying retroactively the new method of accounting.
23
The accompanying Consolidated Financial Statements reflect
the consolidation of the accounts of the Company and its wholly
owned subsidiaries:
Regulated utilities
South Carolina Electric Gas Company (SCE&G)
South Carolina Fuel Company, Inc.
South Carolina Generating Company, Inc. (GENCO)
South Carolina Pipeline Corporation (Pipeline Corporation)
Nonregulated businesses
SCANA Petroleum Resources, Inc. (Petroleum Resources)
SCANA Hydrocarbons, Inc.
Suburban Propane Group, Inc.
MPX Systems, Inc. (MPX)
Primesouth, Inc.
ServiceCare, Inc.
SCANA Development Corporation
SCANA Capital Resources, Inc.
Investments in joint ventures in real estate and
telecommunications are reported using the equity method of
accounting. Significant intercompany balances and transactions
have been eliminated in consolidation.
In January 1994 the Company signed an agreement to sell
substantially all of the real estate assets of SCANA Development
Corporation to Liberty Properties Group, Inc. (Liberty) of
Greenville, South Carolina for $91.5 million. On March 4, 1994
the Company and Liberty amended the agreement to exclude certain
projects then under construction, and the sales price was reduced
to $49.6 million. The transaction was closed on May 27, 1994.
Certain other assets of SCANA Development Corporation are being
sold to other parties. These transactions did not have a
material impact on the Company's financial position or results of
operations.
B. System of Accounts
The accounting records of the Company's regulated
subsidiaries are maintained in accordance with the Uniform System
of Accounts prescribed by the Federal Energy Regulatory
Commission (FERC) and as adopted by the Public Service Commission
of South Carolina (PSC).
C. Utility Plant
Utility plant is stated substantially at original cost. The
costs of additions, renewals and betterments to utility plant,
including direct labor, material and indirect charges for
engineering, supervision and an allowance for funds used during
construction, 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, along
with the cost of removal, less salvage, to accumulated
depreciation. The costs of repairs, replacements and renewals of
items of property determined to be less than a unit of property
are charged to maintenance expense.
24
SCE&G, operator of the V. C. Summer Nuclear Station (Summer
Station), and the South Carolina Public Service Authority (PSA)
are joint owners of Summer Station in the proportions of two-
thirds and one-third, respectively. The parties share the op-
erating costs and energy output of the plant in these
proportions. Each party, however, provides its own financing.
Plant in service related to SCE&G's portion of Summer Station
was approximately $923.1 million and $920.2 million as of
December 31, 1994 and 1993, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was
approximately $297.9 million and $285.3 million as of December
31, 1994 and 1993, respectively. SCE&G's share of the direct
expenses associated with operating Summer Station is included in
"Other operation" and "Maintenance" expenses.
D. Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC), a
noncash item, reflects the period cost of capital devoted to
plant under construction. This accounting practice results in
the inclusion, as a component of construction cost, of 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 composite rates of 8.5%, 9.3% and 9.6% for 1994, 1993 and
1992, respectively. These rates do not exceed the maximum
allowable rate as calculated under FERC Order No. 561. Interest
on nuclear fuel in process and sulfur dioxide emission allowances
is capitalized at the actual interest amount.
E. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that
date, SCE&G ceased the deferral of carrying costs associated with
400 MW of electric generating capacity previously removed from
rate base and began amortizing the accumulated deferred carrying
costs on a straight-line basis over a ten-year period.
Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1994, 1993 and 1992.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the
accounting period in which the meters are read.
Fuel costs for electric generation are collected through the
fuel cost component in retail electric rates. The fuel cost
component contained in electric rates is established by the PSC
during semiannual fuel cost hearings. Any difference between
actual fuel costs and that contained in the fuel cost component
is deferred and included when determining the fuel cost component
during the next semiannual fuel cost hearing. SCE&G had
undercollected through the electric fuel cost component
approximately $3.5 million at December 31, 1994 and overcollected
approximately $9.2 million at December 31, 1993 which are
included in "Deferred Debits-Other" and "Deferred Credits-Other",
respectively.
Customers subject to the gas cost adjustment clause are billed
based on a fixed cost of gas determined by the PSC during annual
gas cost recovery hearings. Any difference between actual gas
cost and that contained in the rates is deferred and included
when establishing gas costs during the next annual gas cost
recovery hearing. At December 31, 1994 and 1993 the Company had
undercollected through the gas cost recovery procedure
approximately $16.3 million and $12.0 million, respectively,
which are included in "Deferred Debits-Other."
25
G. Depreciation, Depletion and Amortization
Provisions for depreciation are recorded using the straight-
line method for financial reporting purposes and are based on the
estimated service lives of the various classes of property. The
composite weighted average depreciation rates were as follows:
1994 1993 1992
SCE&G 3.01% 2.97% 3.00%
GENCO 2.70% 2.64% 2.63%
Pipeline Corporation 2.79% 2.62% 2.62%
Aggregate of Above 2.98% 2.92% 2.96%
Nuclear fuel amortization, which is included in "Fuel used
in electric generation" and is recovered through the fuel cost
component of SCE&G's rates, is recorded using the units-of-
production method. Provisions for amortization of nuclear fuel
include amounts necessary to satisfy obligations to the United
States Department of Energy under a contract for disposal of
spent nuclear fuel.
The acquisition adjustment relating to the purchase of
certain gas properties in 1982 is being amortized over a 40-year
period using the straight-line method.
Depreciation, depletion and amortization (DD&A) of the
capitalized costs of oil and gas producing properties is provided
for on the units-of-production basis. Units-of-production rates
are based on estimated proved reserves.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
The expenditures (on a before-tax basis) related to SCE&G's share
of decommissioning activities are currently estimated, in 2022
dollars assuming a 4.5% annual rate of inflation, to be $545.3
million including partial reclamation costs. SCE&G is providing
for its share of estimated decommissioning costs of Summer
Station over the life of Summer Station. SCE&G's method of
funding decommissioning costs is referred to as COMReP (Cost of
Money Reduction Plan). Under this plan, funds collected through
rates ($3.2 million and $2.5 million in 1994 and 1993,
respectively) are used to purchase insurance policies on the
lives of key Company personnel. Through the purchase of
insurance contracts, SCE&G is able to take advantage of income
tax benefits and accrue earnings on the fund on a tax-deferred
basis at a rate higher than can be achieved using more
traditional funding approaches. Amounts for decommissioning
collected through electric rates, insurance proceeds, and
interest on proceeds less expenses are transferred by SCE&G to an
external trust fund in compliance with the financial assurance
requirements of the Nuclear Regulatory Commission. Management
intends for the fund, including earnings thereon, to provide for
all eventual decommissioning expenditures on an after-tax basis.
Thus, the trust's sources of decommissioning funds under the
COMReP program include investment components of life insurance
policy proceeds, return on investments, and the cash transfers
from SCE&G described above. SCE&G records its liability for
decommissioning costs in deferred credits.
26
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the
electric utility industry regarding the recognition, measurement
and classification of decommissioning costs for financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
In addition, pursuant to the National Energy Policy Act
passed by Congress in 1992, SCE&G has recorded a liability for
its estimated share of amounts required by the U.S. Department of
Energy for its decommissioning fund. SCE&G will recover the
costs associated with this liability, totaling $4.3 million at
December 31, 1994, through the fuel cost component of its rates;
accordingly, these amounts have been deferred and are included in
"Deferred Debits-Other" and "Long-Term Debt, Net."
I. Income Taxes
The Company and its subsidiaries file consolidated Federal
and State income tax returns. Income taxes are allocated to all
subsidiaries based on their contributions to consolidated taxable
income.
The Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," effective
January 1, 1993. Prior years' financial statements have not been
restated. Deferred tax assets and liabilities were adjusted from
the amounts recorded at December 31, 1992 under prior standards
to the amounts required at January 1, 1993 under Statement No.
109 at currently enacted income tax rates. The adjustments were
charged or credited to regulatory assets or liabilities if the
Company expected to recover the resulting additional income tax
expense from, or pass through the resulting reductions in income
tax expense to, customers of the Company's regulated
subsidiaries; otherwise, they were charged or credited to income
tax expense. The cumulative effect of adopting Statement No. 109
on retained earnings as of January 1, 1993, as well as the effect
of adoption on net income for the year ended December 31, 1993,
was not material. At December 31, 1993 the combined effect of
adopting Statement No. 109 and adjusting deferred tax assets and
liabilities for the change in 1993 of the corporate Federal
income tax rate from 34% to 35% resulted in balances of $100.8
million in regulatory assets (included in "Deferred Debits-
Other") and $69.3 million in regulatory liabilities (included in
"Deferred Credits-Other") for the Company's regulated
subsidiaries.
In accordance with Statement No. 109, deferred tax assets
and liabilities are recorded for the tax effects of 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 rates through
charges or credits to regulatory assets or liabilities if they
are expected to be recovered from, or passed through to,
customers of the Company's regulated subsidiaries; otherwise,
they are charged or credited to income tax expense.
Prior to the adoption of Statement No. 109 on January 1,
1993, the Company recorded a deferred income tax provision on all
material timing differences between the inclusion of items in
pretax financial income and taxable income each year, except for
those which were expected to be passed through to, or collected
from, customers of the Company's regulated subsidiaries.
Accumulated deferred income taxes were generally not adjusted for
changes in enacted tax rates.
27
J. Pension Expense
The Company has a noncontributory defined benefit pension
plan covering substantially all permanent employees. Benefits
are based on years of accredited service and the employee's
average annual base earnings received during the last three years
of employment. The Company's policy has been to fund pension
costs accrued to the extent permitted by the applicable Federal
income tax regulations as determined by an independent actuary.
Net periodic pension cost for the years ended December 31,
1994, 1993 and 1992 included the following components:
1994 1993 1992
(Thousands of Dollars)
Service cost--benefits earned during the period $ 8,684 $ 7,629 $ 7,174
Interest cost on projected benefit obligation 21,711 20,413 19,628
Adjustments:
Return on plan assets 2,365 (50,389) (28,607)
Net amortization and deferral (29,760) 25,936 8,096
Net periodic pension cost $ 3,000 $ 3,589 $ 6,291
The determination of net periodic pension cost is based upon the
following assumptions:
1994 1993 1992
Annual discount rate 7.25% 8.0% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 4.75% 5.5% 5.5%
The following table sets forth the funded status of the plan at December
31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $205,364 $204,794
Nonvested benefit obligation 13,966 14,085
Accumulated benefit obligation $219,330 $218,879
Plan assets at fair value
(invested primarily in equity
and debt securities) $347,702 $351,648
Projected benefit obligation 246,318 295,718
Plan assets greater than
projected benefit obligation 101,384 55,930
Unrecognized net transition liability 11,307 10,713
Unrecognized prior service costs 9,374 9,294
Unrecognized net gain (102,284) (64,607)
Pension asset recognized in
Consolidated Balance Sheets $ 19,781 $ 11,330
28
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1994, 1993
and 1992.
1994 1993 1992
Annual discount rate used to determine
benefit obligations 8.0% 7.25% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 2.5% 4.75% 5.5%
The change in the annual discount rate used to determine
benefit obligations from 7.25% to 8.0% and the change in the
expected salary increase rate from 4.75% to 2.5% as of December
31, 1994 decreased the projected benefit obligation and increased
the unrecognized net gain by approximately $67.7 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. The costs of postretirement benefits
other than pensions are accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.6 million and
$4.3 million, net of payments to current retirees, for the years
ended December 31, 1994 and 1993, respectively.
Net periodic postretirement benefit cost for the years ended
December 31, 1994 and 1993, included the following components:
1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,417 $ 1,908
Interest cost on accumulated postretirement benefit
obligation 6,644 5,502
Adjustments:
Return on plan assets - -
Amortization of unrecognized transition
obligation 3,344 3,344
Other net amortization and deferral 860 -
Net periodic postretirement benefit cost $13,265 $10,754
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1994 1993
Annual discount rate 7.25% 8.0%
Health care cost trend rate 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 5.25% 6.0%
29
The following table sets forth the funded status of the plan
at December 31, 1994 and 1993:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 59,174 $ 40,865
Other fully eligible participants 4,995 6,841
Other active participants 24,889 25,767
Accumulated postretirement benefit obligation 89,058 73,473
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (89,058) (73,473)
Unrecognized net transition liability 61,581 64,925
Unrecognized prior service costs 3,453 -
Unrecognized net loss 11,156 4,284
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(12,868) $ (4,264)
The accumulated postretirement benefit obligation is based upon the
plan's benefit provisions and the following assumptions:
1994 1993
Assumed health care cost trend rate used to
measure expected costs 12.0% 11.25%
Ultimate health care cost trend rate
(to be achieved in 2004) 6.0% 5.25%
Annual discount rate 8.0% 7.25%
Annual rate of salary increases 2.5% 4.75%
The effect of a one-percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31,
1994 and the accumulated postretirement benefit obligation
as of December 31, 1994 would be to increase such amounts by
$210,000 and $3.3 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on
Reacquired Debt
Long-term debt premium, discount and expense are being
amortized as components of "Interest on long-term debt, net" over
the terms of the respective debt issues. Gains or losses on
reacquired debt that is refinanced are deferred and amortized
over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore, actual expenditures could differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period for electric operations and an eight-year period for gas
operations. Such deferred amounts totaled $20.2 million and
$19.6 million at December 31, 1994 and 1993, respectively, and
are included in "Deferred Debits-Other."
30
M. Oil and Gas
The Company follows the full cost method of accounting for
its oil and gas operations and, accordingly, capitalizes all
costs it incurs in the acquisition, exploration and development
of oil and gas properties. The Company amortizes capitalized
costs on the unit-of-production method, based on total estimated
proved recoverable reserves. The Company accounts for normal
dispositions of oil and gas properties as adjustments to
capitalized costs and does not recognize any gain or loss.
In addition, the capitalized costs are subject to a "ceiling
test," which limits such costs to the aggregate of the estimated
present value of future net cash flows from proven oil and gas
reserves, plus the lower of cost or fair market value of unproved
properties.
N. Gas Futures Contracts
The Company sells gas futures and forward contracts,
purchases options, and enters into over-the-counter agreements to
hedge price risks for the majority of Petroleum Resources'
production. Gains and losses on the above are recognized
concurrently with the revenue from the associated gas sales.
O. Temporary Cash Investments
The Company considers temporary cash investments having
original maturities of three months or less to be cash
equivalents. Temporary cash investments are generally in the
form of commercial paper, certificates of deposit and repurchase
agreements.
P. Reclassifications
Certain amounts from prior periods have been reclassified to
conform with the 1994 presentation.
2. RATE MATTERS:
A. On October 27, 1994 the PSC issued an order approving
SCE&G's request to recover through a billing surcharge to its gas
customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge, which was
effective with the first billing cycle in November 1994, provides
for the recovery of approximately $16.2 million representing
substantially all site assessment and cleanup costs for SCE&G's
gas operations that had previously been deferred.
B. On June 7, 1993 the PSC issued an order on SCE&G's
pending electric rate proceeding allowing an authorized return on
common equity of 11.5%, resulting in a 7.4% annual increase in
retail electric rates, or a projected $60.5 million annually,
based on a test year. These rates were implemented in two phases
over a two-year period: phase one, effective June 1993,
producing $42.0 million annually, and phase two, effective June
1994, producing $18.5 million annually, based on a test year.
C. On September 14, 1992 the PSC issued an order granting
SCE&G a $.25 increase in transit fares from $.50 to $.75 in both
Columbia and Charleston, South Carolina; however, the PSC also
required $.40 fares for low income customers and denied SCE&G's
request to reduce the number of routes and frequency of
service. The new rates were placed into effect on October
5, 1992. SCE&G has appealed the PSC's order to the Circuit
Court.
31
D. Effective with the first billing cycle in December 1991,
SCE&G's gas rate schedules for its residential, small commercial
and small industrial customers have included a weather
normalization adjustment (WNA). The WNA minimizes fluctuations
in gas revenues due to abnormal weather conditions and is subject
to annual review by the PSC. The PSC order was based on a
return on common equity of 12.25%. On August 26, 1994, the PSC
ordered that the WNA be made permanent.
E. In May 1989 the PSC approved a volumetric and direct
billing method for Pipeline Corporation to recover take-or-pay
costs incurred from its interstate pipeline suppliers pursuant
to FERC-approved final and nonappealable settlements. In
December 1992 the Supreme Court approved Pipeline Corporation's
full recovery of the take-or-pay charges imposed by its suppliers
and treatment of these charges as a cost of gas. However, the
Supreme Court declared the PSC-approved "purchase deficiency"
methodology for recovery of these costs to be unlawful
retroactive ratemaking and remanded the docket to the PSC to
reconsider its recovery methodology. On April 30, 1994 the PSC
issued an order involving Pipeline Corporation's recovery of
take-or-pay cost incurred pursuant to FERC-approved settlements
with its upstream interstate pipeline supplier. This order
provided a mechanism for Pipeline Corporation to recover its
take-or-pay cost volumetrically over a period of approximately 30
months. SCE&G receives a credit for payments made prior to the
April 30 order which is netted against the current volumetric
surcharge. That net cost is recovered by SCE&G through its
purchased gas adjustment clause.
F. On August 8, 1990 the PSC issued an order, effective
November 1, 1990, approving changes in Pipeline Corporation's gas
rate design for sales for resale service and upholding the
"value-of-service" method of regulation for its direct industrial
service. Direct industrial customers seeking "cost-of-service"
based rates initiated two separate appeals to the Circuit Court,
which reversed and remanded to the PSC its August 8, 1990 order.
Pipeline Corporation appealed that decision to the Supreme Court
which, on January 10, 1994, reversed the two Circuit Court
decisions and reinstated the PSC Order. The Supreme Court held
that the industrial customer group's appeal was premature and
failed to exhaust administrative remedies. Additionally, the
Supreme Court interpreted the rate-making statutes of South
Carolina to give discretion to the PSC in selecting the
methodology to be used in setting rates for natural gas service.
G. On July 3, 1989 the PSC granted SCE&G approximately $21.9
million of a requested $27.2 million annual increase in retail
electric revenues based upon an allowed return on common equity
of 13.25%. The Consumer Advocate appealed the decision to the
Supreme Court which, on August 31, 1992, found that the evidence
in the record of that case did not support a return on common
equity higher than 13.0% and remanded to the PSC a portion of its
July 1989 order for a determination of the proper return on
common equity consistent with the Supreme Court's opinion. On
January 19, 1993 the PSC issued an order allowing a return on
common equity of 13.0%, approving a refund based on the
difference in rates created by the difference between the 13.0%
and the 13.25% return on common equity and making other
nonmaterial adjustments to the calculation of cost-of-service.
The total refund, before interest and income taxes, was
approximately $14.6 million and was charged against 1992
"Electric Revenues." The refund plus interest was made during
1993.
32
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including
the amounts due under the nuclear and fossil fuel agreement (see
Note 4), and sinking fund requirements for the years 1995 through
1999 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $ 38,055 1998 $60,174
1996 147,248 1999 92,584
1997 38,306
Approximately $14.8 million of the portion of long-term debt
payable in 1995 may be satisfied by either deposit and
cancellation of bonds issued upon the basis of property additions
or bond retirement credits, or by deposit of cash with the
Trustee.
In January 1995 the Company arranged for an unsecured bank
loan of $60 million, due January 12, 1996 at an initial interest
rate of 6.44%, subject to reset quarterly at LIBOR plus ten basis
points. Proceeds from the loans were used to repay bank loans
totaling $60 million due January 13, 1995; accordingly, such
loans are included in long-term debt at December 31, 1994.
Substantially all utility plant and fuel inventories are
pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories are financed through the
issuance of short-term commercial paper. These short-term
borrowings are supported by an irrevocable revolving credit
agreement which expires July 31, 1996. Accordingly, the amounts
outstanding have been included in long-term debt. The credit
agreement provides for a maximum amount of $75 million that may
be outstanding at any time.
Commercial paper outstanding totaled $50.6 million and $36.8
million at December 31, 1994 and 1993 at weighted average
interest rates of 6.06% and 3.47%, respectively.
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not
Subject to Purchase or Sinking Funds):
The changes in "Common Stock," without par value, during
1994, 1993 and 1992 are summarized as
follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1991 81,568,654 $571,597
Issuance of common stock 6,252,608 127,406
Balance December 31, 1992 87,821,262 699,003
Issuance of common stock 5,417,652 127,662
Balance December 31, 1993 93,238,914 826,665
Issuance of common stock 2,796,106 60,105
Balance December 31, 1994 96,035,020 $886,770
33
The Restated Articles of Incorporation of the Company do not
limit the dividends that may be payable on its common stock.
However, the Restated Articles of Incorporation of SCE&G and the
Indenture underlying its First and Refunding Mortgage Bonds
contain provisions that may limit the payment of cash dividends
on its common stock. In addition, with respect to hydroelectric
projects, the Federal Power Act may require the appropriation of
a portion of the earnings therefrom. At December 31, 1994
approximately $13.2 million of retained earnings were restricted
as to payment of cash dividends on common stock.
Cash dividends on common stock were declared at an annual
rate per share of $1.41, $1.37 and $1.34 for 1994, 1993 and 1992,
respectively.
6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
The call premium of the respective series of preferred stock
in no case exceeds the amount of the annual dividend.
Retirements under sinking fund requirements are at par values.
At any time when dividends have not been paid in full or
declared and set apart for payment on all series of preferred
stock, SCE&G may not redeem any shares of preferred stock (unless
all shares of preferred stock then outstanding are redeemed) or
purchase or otherwise acquire for value any shares of preferred
stock except in accordance with an offer made to all holders of
preferred stock. SCE&G may not redeem any shares of preferred
stock (unless all shares of preferred stock then outstanding are
redeemed) or purchase or otherwise acquire for value any shares
of preferred stock (except out of monies set aside as purchase
funds or sinking funds for one or more series of preferred stock)
at any time when it is in default under the provisions of the
purchase fund or sinking fund for any series of preferred stock.
The aggregate annual amounts of purchase fund or sinking fund
requirements for preferred stock for the years 1995 through 1999
are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1995 $2,418 1998 $2,440
1996 2,482 1999 2,440
1997 2,440
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 1994, 1993 and 1992 are summarized as follows:
Number Thousands
of Shares of Dollars
Balance December 31, 1991 998,404 $61,838
Shares Redeemed:
$100 par value (6,098) (610)
$50 par value (51,777) (2,589)
Balance December 31, 1992 940,529 58,639
Shares Redeemed:
$100 par value (7,374) (737)
$50 par value (51,187) (2,558)
Balance December 31, 1993 881,968 55,344
Shares Redeemed:
$100 par value (8,072) (807)
$50 par value (51,802) (2,591)
Balance December 31, 1994 822,094 $51,946
34
7. INCOME TAXES:
Total income tax expense for 1994, 1993 and 1992 is as follows:
1994 1993 1992
(Thousands of Dollars)
Current taxes:
Federal $62,033 $59,590 $67,240
State 13,178 6,409 8,146
Total current taxes 75,211 65,999 75,386
Deferred taxes, net:
Federal (9,006) 21,743 (11,848)
State (86) 6,003 413
Total deferred taxes (9,092) 27,746 (11,435)
Investment tax credits:
Amortization of amounts deferred (credit) (3,631) (3,659) (3,659)
Total income tax expense $62,488 $90,086 $60,292
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income
tax rate (35% for 1994 and 1993 and 34% for 1992) to pretax
income is reconciled as follows:
1994 1993 1992
(Thousands of Dollars)
Net income $115,452 $165,240 $117,667
Total income tax expense:
Charged to operating expenses 94,510 90,007 60,947
Charged (credited) to other income (32,022) 79 (655)
Preferred stock dividends 5,955 6,217 6,473
Total pretax income $183,895 $261,543 $184,432
Income taxes on above at statutory
Federal income tax rate $ 64,363 $ 91,540 $ 62,707
Increases (decreases) attributable to:
Allowance for funds used during
construction (excluding nuclear fuel) (2,862) (3,125) (1,868)
Deferred return on plant investment,
net of amortization 1,486 1,486 1,444
Depreciation differences 2,860 2,794 2,129
Amortization of investment tax credits (3,631) (3,659) (3,659)
State income taxes (less Federal income
tax effect) 8,510 8,068 5,649
Deferred income tax flowback at higher
than statutory rates (4,327) (4,411) (5,565)
Alternate fuel production tax credit (1,274) (1,373) (275)
Other differences, net (2,637) (1,234) (270)
Total income tax expense $ 62,488 $ 90,086 $ 60,292
The Omnibus Budget Reconciliation Act was signed into
law on August 10, 1993, increasing the corporate tax rate from
34% to 35% effective January 1, 1993. The impact of this change
on the Company's financial position and results of operations was
not material.
35
The tax effects of significant temporary differences comprising
the Company's net deferred tax liability of $543.1 million at
December 31, 1994 and $551.5 million at December 31, 1993
determined in accordance with Statement No. 109 (see Note 1I) are
as follows:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 56,588 $ 58,839
Cycle billing 17,521 15,084
Nuclear operations expenses 206 4,908
Deferred compensation 5,513 5,315
Other post retirement benefits 3,187 1,631
Other 8,392 11,102
Total deferred tax assets 91,407 96,879
Deferred tax liabilities:
Property, plant and equipment (including
DD&A and basis differences) 598,313 611,785
Pension expense 9,022 6,266
Deferred fuel revenue 7,803 931
Reacquired debt 7,146 7,574
Other 12,197 21,814
Total deferred tax liabilities 634,481 648,370
Net deferred tax liability $543,074 $551,491
"Total deferred taxes" charged (credited) to income tax expense result
from timing differences in recognition of the following items (thousands of
dollars):
1992
Charged (credited) to expense:
Property, plant and equipment
(including DD&A and basis differences) $ 7,475
Deferred fuel revenue (2,958)
Property taxes 562
Cycle billing (1,321)
Take-or-pay contracts (1,118)
Nuclear refueling accrual (4,430)
Electric rate refund (6,571)
Injuries and damages (1,377)
Other, net (1,697)
Total deferred taxes $(11,435)
The Internal Revenue Service has examined and closed consolidated
Federal income tax returns of the Company through 1989 and is
currently examining the 1990, 1991 and 1992 Federal income tax
returns. No adjustments are currently proposed by the examining
agent. The Company does not anticipate that any adjustments
which might result from this examination will have a significant
impact on the earnings or financial position of the Company.
36
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the
Company's financial instruments at December 31, 1994 and 1993
are as follows:
1994 1993
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Cash and temporary
cash investments $ 10,934 $ 10,934 $ 20,766 $ 20,766
Investments 24,858 27,099 5,312 15,235
Short-term borrowings 183,027 183,027 43,019 43,019
Total long-term debt 1,575,679 1,490,852 1,458,721 1,551,873
Total preferred stock
(subject to purchase
or sinking funds) 51,946 49,348 55,344 51,618
The information presented herein is based on pertinent
information available to the Company as of December 31, 1994
and 1993. Although the Company is not aware of any factors that
would significantly affect the estimated fair value amounts, such
financial instruments have not been comprehensively revalued
since December 31, 1994, and the current estimated fair value may
differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate the
fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial
paper, repurchase agreements, treasury bills and notes are valued
at their carrying amount.
Fair values of investments and long-term debt are based on
quoted market prices for similar instruments, or for those
instruments for which there are no quoted market prices
available, fair values are based on net present value
calculations. Investments which are not considered to be
financial instruments (goodwill) have been excluded from the
carrying amount and estimated fair value. Settlement of long-
term debt may not be possible or may not be a prudent management
decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or
sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in
an actual sale or settlement have not been taken into
consideration.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its lines
of credit. Commercial paper borrowings are for 270 days or less.
Details of lines of credit and short-term borrowings at December
31, 1994, 1993 and 1992 and for the years then ended are as
follows:
1994 1993 1992
(Millions of Dollars)
Authorized lines of credit at year-end $479.1 $335.0 $288.9
Unused lines of credit at year-end $455.1 $308.0 $262.8
Short-term borrowings outstanding at
year-end:
Bank loans $ 71.1 $ 42.0 $ 41.1
Weighted average interest rate 6.50% 3.71% 4.49%
Commercial paper $111.2 $ 1.0 -
Weighted average interest rate 6.04% 3.35% -
37
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCE&G entered into a contract with Duke/Fluor Daniel in 1991
to design, engineer and build a 385 MW coal-fired electric
generating plant near Cope, South Carolina in Orangeburg County.
Construction of the plant began in November 1992 and is expected
to be complete in late 1995 with commercial operation beginning
in early 1996. The estimated cost of the Cope plant, excluding
financing costs and AFC but including an allowance for
escalation, is $450 million. In addition, the transmission lines
for interconnection with SCE&G's system are expected to cost $26
million.
Under the Duke/Fluor Daniel contract SCE&G must make
specified monthly minimum payments. These minimum payments do
not include amounts for inflation on a portion of the contract
which is subject to escalation (approximately 34% of the total
contract amount). The aggregate amount of such required minimum
payments remaining at December 31, 1994 is as follows (thousands
of dollars):
1995 $ 59,766
1996 5,603
Total $ 65,369
Through December 31, 1994 SCE&G had paid $310 million under the
contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with
public liability for a nuclear incident, currently establishes
the liability limit for third-party claims associated with any
nuclear incident at $8.9 billion. Each reactor licensee is
currently liable for up to $79.3 million per reactor owned for
each nuclear incident occurring at any reactor in the United
States, provided that not more than $10 million of the liability
per reactor would be assessed per year. SCE&G's maximum
assessment, based on its two-thirds ownership of Summer Station,
would be approximately $52.9 million per incident, but not more
than $6.7 million per year.
SCE&G currently maintains policies (for itself and on behalf
of the PSA) with American Nuclear Insurers (ANI) and Nuclear
Electric Insurance Limited (NEIL) providing combined primary and
excess property and decontamination insurance coverage of $1.9
billion for any losses at Summer Station. SCE&G pays annual
premiums and, in addition, could be assessed a retrospective
premium assessment not to exceed 7.5 times its annual premium in
the event of property damage loss to any nuclear generating
facility covered under the NEIL program. Based on the current
annual premium, this retrospective premium assessment would not
exceed $8.2 million.
To the extent that insurable claims for property damage,
decontamination, repair and replacement and other costs and
expenses arising from a nuclear incident at Summer Station 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 incident at
Summer Station. If such an incident were to occur, it could have
a materially adverse impact on the Company's financial position.
38
C. Environmental
As described in Note 1L of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, an estimate is made of the amount of expenditures, if
any, necessary to investigate and clean up each site. These
estimates are refined as additional information becomes
available; therefore, actual expenditures could differ
significantly from the original estimates. Amounts estimated and
accrued to date for site assessments and cleanup relate primarily
to regulated operations; such amounts have been deferred and are
being amortized and recovered through rates over a ten-year
period for electric operations and an eight-year period for gas
operations.
In September 1992 the Environmental Protection Agency (EPA)
notified SCE&G, the City of Charleston and the Charleston Housing
Authority of their potential liability for the investigation and
cleanup of the Calhoun Park Area Site in Charleston, South
Carolina. This site originally encompassed approximately 18
acres and included properties which were the locations for
industrial operations, including a wood preserving (creosote)
plant and one of SCE&G's decommissioned manufactured gas plants.
The original scope of this investigation has been expanded to
approximately 30 acres, including adjacent properties owned by
the National Park Service and the City of Charleston, and private
properties. The site has not been placed on the National
Priority List, but may be added before cleanup is initiated. The
potentially responsible parties (PRP) have agreed with the EPA to
participate in an innovative approach to site investigation and
cleanup called "Superfund Accelerated Cleanup Model," allowing
the pre-cleanup site investigations process to be compressed
significantly. The PRPs have negotiated an administrative order
by consent for the conduct of a Remedial
Investigation/Feasibility Study (RI/FS) and a corresponding Scope
of Work. Actual field work began November 1, 1993 after final
approval and authorization was granted by EPA. SCE&G is also
working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the city's aquarium site. In 1994 the City of
Charleston notified SCE&G that it considers SCE&G to be
responsible for a $43.5 million increase in costs of the aquarium
project attributable to delays resulting from contamination of
the Calhoun Park Area Site. SCE&G believes it has meritorious
defenses against this claim and does not expect its resolution to
have a material impact on its financial position or results of
operations.
D. Emission Allowances
The Company has entered into an agreement with a broker of
sulfur dioxide emission allowances to purchase $6.8 million of
allowances at a fixed price during 1995.
E. Personal Communication Services licenses
MPX is pursuing Personal Communication Services licenses for
wireless communications in the Southeast through a joint venture.
A $40 million construction loan obtained by the joint venture has
been guaranteed by SCANA Corporation.
F. Oil and Gas Forward Contracts
In an effort to limit exposure to changing natural gas
prices, in January 1995 the Company entered into a series of
forward contracts relating to natural gas production. These
forward contracts have the effect of stabilizing the price that
the Company will receive on approximately sixty percent of its
forecasted natural gas production for the years 1995-2001. The
forward contracts are at an average price of $1.88 per dekatherm.
39
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1994, 1993 and 1992 and
for the years then ended is as follows:
1994
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $975,388 $342,672 $ 4,002 $1,322,062
Operating expenses,
excluding depreciation
and amortization 640,528 292,227 10,577 943,332
Depreciation and
amortization 102,647 16,304 226 119,177
Total operating expenses 743,175 308,531 10,803 1,062,509
Operating income (loss) $232,213 $ 34,141 $ (6,801) 259,553
Add - Other income (loss), net (29,749)
Less - Interest charges 108,397
- Preferred stock dividends 5,955
Net income $ 115,452
Capital expenditures:
Identifiable $364,007 $ 20,079 $ 347 $ 384,433
Utilized for overall Company operations 20,167
Total $ 404,600
Identifiable assets at
December 31, 1994:
Utility plant, net $2,897,954 $315,746 $ 1,791 $3,215,491
Inventories 98,669 17,026 495 116,190
Total $2,996,623 $332,772 $ 2,286 3,331,681
Other assets 982,827
Total assets $4,314,508
40
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,121 $320,195 $ 3,851 $1,264,167
Operating expenses,
excluding depreciation
and amortization 621,339 274,936 9,737 906,012
Depreciation and
amortization 97,849 14,820 175 112,844
Total operating expenses 719,188 289,756 9,912 1,018,856
Operating income (loss) $ 220,933 $ 30,439 $(6,061) 245,311
Add - Other income, net 27,335
Less - Interest charges 101,189
- Preferred stock dividends 6,217
Net income $ 165,240
Capital expenditures:
Identifiable $ 279,082 $ 28,761 $ 604 $ 308,447
Utilized for overall Company operations 13,934
Total $ 322,381
Identifiable assets at
December 31, 1993:
Utility plant, net $2,628,374 $312,437 $ 1,673 $2,942,484
Inventories 77,805 22,019 463 100,287
Total $2,706,179 $334,456 $ 2,136 3,042,771
Other assets 974,131
Total assets $4,016,902
41
1992
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 829,477 $305,275 $ 3,623 $1,138,375
Operating expenses,
excluding depreciation
and amortization 554,897 256,178 9,205 820,280
Depreciation and
amortization 93,978 14,174 163 108,315
Total operating expenses 648,875 270,352 9,368 928,595
Operating income (loss) $ 180,602 $ 34,923 $(5,745) 209,780
Add - Other income, net 11,960
Less - Interest charges 97,600
- Preferred stock dividends 6,473
Net income $ 117,667
Capital expenditures:
Identifiable $ 234,918 $ 33,495 $ 346 $ 268,759
Utilized for overall Company operations 8,877
Total $ 277,636
Identifiable assets at
December 31, 1992:
Utility plant, net $2,456,691 $299,591 $ 1,240 $2,757,522
Inventories 82,717 8,155 481 91,353
Total $2,539,408 $307,746 $ 1,721 2,848,875
Other assets 689,439
Total assets $3,538,314
42
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1994
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $347,309 $296,046 $361,329 $317,378 $1,322,062
Operating
income (000) 69,398 50,048 86,708 53,399 259,553
Net income (000) 51,442 30,254 16,701 17,055 115,452
Earnings per weighted
average share of
common stock
as reported .55 .32 .18 .17 1.22
1993
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues (000) $321,840 $280,382 $359,453 $302,492 $1,264,167
Operating
income (000) 63,714 45,370 84,638 51,589 245,311
Net income (000) 43,421 28,138 62,710 30,971 165,240
Earnings per weighted
average share of
common stock
as reported .49 .32 .69 .33 1.83
43
SCANA Corporation
SIGNATURES
Pursuant to the requirements 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.
SCANA Corporation
(Registrant)
September 6, 1995 By: s/K. B. Marsh
K. B. Marsh, Vice President-
Finance, Secretary and Treasurer
44
SCANA CORPORATION
EXHIBIT INDEX Sequentially
Numbered
Number Pages
1. Underwriting Agreement
Not Applicable
2. Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Not Applicable
4. Instruments Defining the Rights of Security
Holders, Including Indentures (Filed as Exhibit
4 to Form 8-K dated April 27, 1995)
12. Statements Re Computation of Ratios (Filed herewith)..... 46
16. Letter Re Change in Certifying Accountant
Not Applicable
17. Letter Re Director Resignation
Not Applicable
20. Other Documents or Statements to Security Holders
Not Applicable
23. Consents of Experts and Counsel (Filed herewith)......... 47
24. Power of Attorney
Not Applicable
27. Financial Data Schedule
(Filed herewith)
99. Additional Exhibits
Not Applicable
45