Item 1. Business................................................ 5
Item 2.
ITEM 2. PROPERTIES
SCANA owns no significant property other than the capital stock of each of its subsidiaries. It holds, directly or indirectly, all of the capital stock of each of its subsidiaries except for the preferred stock of SCE&G, the preferred securities of SCE&G Trust I and 30% of an indirect subsidiary in liquidation. It also has an investment in one LLC which operates a cogeneration facility in Charleston, South Carolina.
SCE&G's bond indentures, securing the First and Refunding Mortgage Bonds and First Mortgage Bonds issued thereunder, constitute direct mortgage liens on substantially all of its property. GENCO's Williams Station is subject to a first mortgage lien.
For a brief description of the properties of the Company's other subsidiaries, which are not significant as defined in Rule 1-02 of Regulation S-X, see Item 1, BUSINESS-SEGMENTS OF BUSINESS-Nonregulated Businesses.
ELECTRIC PROPERTIES
Information on electric generating facilities, all of which are owned by SCE&G except as noted, is as follows:
(1) SCE&G placed in service in June 2002 a gas turbine generator project. Two combined-cycle turbines burn natural gas or fuel oil to produce 341 MW of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 MW turbines at the Urquhart Generating Station. Unit 3 remains as the only coal-fired steam unit at the site. (2) The steam unit at Williams Station is owned by GENCO. (3) Represents SCE&G's two-thirds portion of the Summer Station (one-third owned by Santee Cooper). (4) This plant is leased from the DOE and is dedicated to DOE's Savannah River Site steam needs. "Net Generating Capability" for this plant is expected average hourly output. The lease expires on October 1, 2005. Although a formal contract is required, DOE has indicated orally and in writing their intention to extend the contract with SCE&G to October 1, 2014. (5) SCE&G is currently constructing a combined cycle generating facility in Jasper County. This facility is scheduled to begin operation in mid-2004 and will produce 875 MW of electric energy. (6) Columbia Hydro was conveyed to the City of Columbia in October 2002 as part of a franchise agreement. SCE&G will continue to operate the plant for the City until 2005.
* SCE&G receives shaft horse power from Cogen South, LLC to operate SCE&G's generator. Cogen South, LLC is owned 50% by SCANA and 50% by MeadWestvaco.
SCE&G owns 445 substations having an aggregate transformer capacity of 22.7 million KVA (kilovolt-ampere). The transmission system consists of 3,165 miles of lines and the distribution system consists of 17,166 pole miles of overhead lines and 4,363 trench miles of underground lines.
NATURAL GAS PROPERTIES
SCE&G's natural gas system consists of approximately 13,006 miles of distribution mains and related service facilities. SCE&G also has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 70 MMCF per day. These facilities can store the equivalent of 298 MMCF of natural gas.
SCPC's natural gas system consists of approximately 1,965 miles of transmission pipeline of up to 24 inches in diameter which connect its resale customers' distribution systems with transmission systems of Southern Natural and Transco. SCPC owns two LNG plants, one located near Charleston, South Carolina and the other in Salley, South Carolina. The Charleston facility can liquefy up to 6 MMCF per day and store the liquefied equivalent of 980 MMCF of natural gas. The Salley facility can store the liquefied equivalent of 900 MMCF of natural gas and has no liquefying capabilities. On peak days, the Charleston facility can regasify up to 60 MMCF per day and the Salley facility can regasify up to 90 MMCF.
PSNC Energy's natural gas system consists of approximately 803 miles of transmission pipeline of up to 24 inches in diameter that connect its distribution systems with Transco. PSNC Energy's distribution system consists of approximately 7,637 miles of distribution mains and related service facilities. PSNC Energy owns one LNG plant with storage capacity of 1,000 MMCF and the capacity to liquefy approximately 100 MMCF per day. PSNC Energy also owns, through a wholly owned subsidiary, 33.21% of Cardinal Pipeline Company, LLC, which owns a 105-mile transmission pipeline in North Carolina. In addition, PSNC Energy owns, through a wholly owned subsidiary, 17% of Pine Needle LNG Company, LLC. Pine Needle owns and operates a liquefaction, storage and regasification facility in North Carolina.
In September 2002 SCG received approval from FERC to purchase an undivided ownership interest in the Southern Natural Gas 13.25 mile, 30-inch diameter parallel pipelines, the Twin 30s, and associated rights-of-way and permits, equivalent to the capacity of 190,000 MCF per day. The Twin 30s extend from Elba Island to Port Wentworth, Georgia. This pipeline is the sole means by which regasified LNG is transported from Southern Natural's LNG facility.
FERC also approved SCG's proposal to construct 18.2 miles of 20 inch diameter transmission pipeline and appurtenant facilities from an interconnection with the Twin 30s at Port Wentworth in Chatham County, Georgia to the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of the pipeline is expected to begin in the first half of 2003.
TRANSIT PROPERTIES
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005. SCE&G will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The following Legal Proceedings were pending at December 31, 2002. These proceedings affect the Company and, to the extent indicated, they also affect SCE&G or PSNC Energy.
Rate and Other Regulatory Matters
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually. On January 2, 2003 the NCUC issued an order approving PSNC Energy's request to increase the benchmark cost of gas from $0.410 to $0.460 rate per therm effective for service rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas to $0.595 per therm effective March 1, 2003.
Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005.
Environmental Matters
SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. As of December 31, 2002 SCE&G had spent approximately $2.2 million related to these sites and expects to spend an additional $5.9 million.
PSNC Energy owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. PSNC Energy's associated actual costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties. In September 2002 an allocation agreement was reached relieving PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a liability and associated regulatory asset of $7.8 million, which reflects the estimated remaining liability at December 31, 2002. Amounts incurred through December 31, 2002 that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
Pending or Threatened Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of SCANA filed suit against SCANA in South Carolina Circuit Court seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.
In 2001 the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of Supplier and its guarantor to meet contractual obligations related to credit support provisions, the Company terminated the contract. Attempts to negotiate a new contract between the parties were not successful. In February 2003, the Company received notification from Supplier of its request for binding arbitration under the original contract. The Company is confident of the propriety of its actions and will vigorously pursue its position in such arbitration proceedings. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
The principal market for SCANA common stock is the New York Stock Exchange. The ticker symbol used is SCG. The corporate name SCANA is used in newspaper stock listings. The total number of shares of SCANA common stock outstanding at February 28, 2003 was 110,832,747. The number of common shareholders of record at February 28, 2003 was 40,170.
All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has no market. During 2002 and 2001 SCE&G paid $152.5 million and $157.3 million, respectively, in cash dividends to SCANA. During 2002 and 2001 PSNC Energy paid $14.5 million and $18.3 million, respectively, in cash distributions/dividends to SCANA.
Additional information regarding these debt and equity securities can be found in the Notes to Consolidated Financial Statements for SCANA (Notes 6, 7 and 9), SCE&G (Notes 5, 6 and 8) and PSNC Energy (Notes 7 and 8).
The Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2002 approximately $40.6 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock of SCE&G.
Equity securities issuable under the Company's compensation plans at December 31, 2002 are summarized as follows:
(1) Consists solely of the SCANA Corporation Director Compensation and Deferral Plan. Non-employee directors receive an annual retainer, of which 60% is required to be paid in SCANA Common Stock. Non-employee directors may elect to receive the remaining retainer and any meeting attendance and conference fees in SCANA Common Stock.
(1) Reflects acquisition of PSNC Energy effective January 1, 2000. (2) Reflects write-down for goodwill impairment in 2002 for adoption of SFAS 142. (3) Other Statistics for 2000 exclude the effect of the change in accounting for unbilled revenues, where applicable. (4) Interruptible deliveries for 1998 includes volumes from the Houston office of SEMI, which was closed in 1999.
SCANA CORPORATION
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 53
Item 8. Financial Statements and Supplementary Data................... 55
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility and nonutility regulatory environment, (3) changes in the economy, especially in areas served by the Company's subsidiaries, (4) the impact of competition from other energy suppliers, (5) growth opportunities for the Company's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in the Company's accounting policies, (8) weather conditions, especially in areas served by the Company's subsidiaries, (9) performance and marketability of the Company's investments in telecommunications companies, (10) performance of the Company's pension plan assets, (11) inflation, (12) changes in environmental regulations, (13) volatility in commodity natural gas markets and (14) the other risks and uncertainties described from time to time in the Company's periodic reports filed with the SEC. The Company disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina, electric restructuring efforts remain stalled, and consideration of electric restructuring legislation is unlikely in 2003. Further, while several companies have announced their intent to site merchant generating plants in the Company's service territory, economic events, environmental concerns and other factors have slowed those efforts. In view of the potential for deregulation, the Company has continued efforts to renew franchise agreements with municipalities within its current service area. Effective October 2002, SCE&G secured a 30-year franchise to provide the City of Columbia, South Carolina, with electric and natural gas services. Columbia is one of the largest cities in SCE&G's service area. Previously, SCE&G reached franchise agreements with the cities of North Charleston (franchise expires in 2021), Charleston (franchise expires in 2026) and numerous other municipalities. In addition, in May 2001 SCE&G signed an electric supply contract with North Carolina Electric Membership Corporation to supply 350 MW in each of 2004 and 2005 and 250 MW annually in 2006 through 2012. These energy sales are recallable for SCE&G's native load, if necessary.
At the federal level, energy legislation passed both houses of Congress in 2002, though significant differences between the House and Senate versions were not reconciled before the legislative session adjourned. Some of the more stringent provisions of this legislation would have required, among other things, that one percent of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent in 2019, be generated from renewable energy resources. Renewable energy resources, as defined in some versions of the legislation, would have excluded hydroelectric generation. Substantial penalties would have been levied for failure to comply. Electric cooperatives and municipal utilities would have been exempt from these requirements. The Company expects similar legislation will be introduced in Congress in 2003. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.
In June 2002 implementation of GridSouth Transco LLC (GridSouth) was suspended pending the issuance and evaluation of new FERC directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant change to the NOPR may occur and that implementation, presently scheduled for September 2004, may be delayed, any rules standardizing the markets may have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. The Company is currently evaluating this NOPR to determine what effect it will have on SCE&G's operations. Additional directives from FERC are expected in 2003.
Gas Distribution
The Company has secured franchise agreements with several municipalities within its current service areas to provide natural gas services. See previous discussion at Electric Operations. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact the Company's ability to retain large commercial and industrial customers on a monthly basis.
Gas Transmission
In September 2002 SCG Pipeline, Inc. (SCG) received approval from FERC to acquire an interest in an existing pipeline and to build a pipeline from Elba Island, Georgia to Jasper County, South Carolina. When operational, SCG will provide interstate transportation services for natural gas to markets in southeastern Georgia and South Carolina. SCG will transport natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG, Inc. at Elba Island, near Savannah, Georgia. The endpoint of SCG's pipeline will be at the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of the pipeline is expected to begin in the first half of 2003, with completion expected in the fall of 2003.
SCPC supplies natural gas to SCE&G, for its resale to gas distribution customers and for certain electric generation needs. Gas transmission also sells natural gas to large commercial and industrial customers in South Carolina, and it faces the same competitive pressures as gas distribution for these classes of customers.
Retail Gas Marketing
In April 2002 Georgia's Natural Gas Consumer's Relief Act of 2002 (the Act) became law. The Act attempts to resolve many of the consumer protection and other public policy issues surrounding Georgia's natural gas market with the following significant provisions:
o creates a regulated provider selected through a bidding process to serve low-income and high credit risk customers, o allows Georgia's 42 non-profit Electric Membership Corporations (EMCs) to establish natural gas affiliates that may seek certification as marketers of natural gas, o establishes new service quality standards and assignment of interstate assets, and o grants to the GPSC the authority to temporarily regulate rates if more than 90% of customers in a specific area of the state are served by three or fewer marketers.
In June 2002 SCANA Energy won GPSC approval to become the State's regulated provider. In this capacity, SCANA Energy serves low-income customers generally at below-market rates, subsidized by Georgia's Universal Service Fund, and extends service generally at above-market rates to high credit risk customers who have been denied service by other marketers. SCANA Energy began serving these customers on September 1, 2002, and at December 31, 2002, approximately 11,000 customers were being served by SCANA Energy under this program.
In June 2002 the fourth largest marketer in Georgia's natural gas market declared bankruptcy. In July 2002 a subsidiary of Southern Company completed its purchase of the bankrupt marketer's Georgia operations. Southern Company, through another subsidiary, sells electricity to approximately two million customers in Georgia. In addition, affiliates of two EMCs have been certified by the GPSC as gas marketers. These new entrants to Georgia's natural gas market may help stabilize the market, although it is unclear what impact these entrants may have on the Company's competitive position. At December 31, 2002 the three largest marketers (which include SCANA Energy) served approximately 80% of Georgia's natural gas market.
SCANA Energy and SCANA's other natural gas distribution, transmission and marketing segments maintain gas inventory and also utilize forward contracts and financial instruments, including futures contracts and options, to manage their exposure to fluctuating commodity natural gas prices. (See Note 11 of Notes to Consolidated Financial Statements.) As a part of this risk management process, at any given time a portion of SCANA's projected natural gas needs has been purchased or otherwise placed under contract. This factor and others (e.g., the level of bad debts experienced) are, in the aggregate, used to establish retail pricing levels at SCANA Energy. As a result of the regulatory actions discussed above and other downward pricing pressures inherent in the competitive market, SCANA Energy may be unable to sustain its current level of customers and/or pricing, thereby reducing expected margins and profitability.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash requirements arise primarily from the operational needs of SCANA subsidiaries, the Company's construction program, the investments of SCANA's subsidiaries and payment of dividends. The ability of SCANA'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. SCANA'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 continue their ongoing construction programs, the Company expects to seek increases in rates. The Company's future financial position and results of operations will be affected by the regulated subsidiaries' ability to obtain adequate and timely rate and other regulatory relief, if requested.
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
The estimated primary cash requirements for 2003 and the actual primary cash requirements for 2002, excluding requirements for non-nuclear fuel purchases, short-term borrowings and dividends, are as follows:
Millions of dollars 2003 2002 - ------------------------------------------------------------- -------------
Property additions and construction expenditures, net of AFC $838 $681 Nuclear fuel expenditures 30 13 Investments 20 62 Maturing obligations, redemptions and sinking and purchase fund requirements 374 1,082 - ------------------------------------------------------------- ------------- Total $1,262 $1,838 ============================================================= =============
Approximately 28% of total cash requirements was provided from internal sources in 2002 as compared to 41% in 2001.
The Company's contractual cash obligations as of December 31, 2002 are summarized as follows:
Contractual Cash Obligations
Less than After December 31, 2002 Total 1year 1-3 years 4-5 years 5 years - ----------------- ----- ----- --------- --------- ------- (Millions of dollars)
Long-term and short-term debt (including interest) $5,215 $759 $1,048 $409 $2,999 Preferred stock sinking funds 10 1 2 1 6 Capital leases 3 2 1 - - Operating leases 76 16 33 19 Other commercial commitments 2,518 1,249 571 173 525
Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. At September 30, 2002, other commercial commitments included amounts for a take-and-pay natural gas contract with a 15 year term beginning in 2004. That contract was terminated in December 2002, and amounts due under the contract totaling $4.2 billion over the 15 year term have been removed from contractual cash obligations. See Note 12E of Notes to Consolidated Financial Statements.
In addition to these commercial commitments, the Company is party to certain New York Mercantile Exchange (NYMEX) futures contracts for which any unfavorable market movements through December 31, 2002 are funded in cash. These derivatives are accounted for as cash flow hedges under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and their effects are reflected within other comprehensive income until such time as the anticipated sales transactions occur.
In addition to the above contractual cash commitments, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan has been adequately funded, with no contributions having been required since 1997. Cash benefit payments under the health care and life insurance benefit plan have been approximately $10 million per year in recent years, and similar payments are expected in the future.
The Company anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. Sales of additional equity securities may also occur. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.
Financing Limits and Related Matters
The Company's issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. The following describes the financing programs currently utilized by the Company.
SCANA Corporation
SCANA has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued.
At December 31, 2002 SCANA had $163 million of unused lines of credit, comprised of $50 million of committed lines, expiring in 2003, and $113 million of uncommitted lines. There were no amounts outstanding under SCANA's lines of credit at December 31, 2002 and 2001. On January 3, 2003 SCANA obtained an additional $50 million committed line of credit, expiring in 2004. On January 8, 2003, SCANA renegotiated an existing $78 million uncommitted line of credit to allow SCE&G to share in this line of credit.
The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed interest payments, and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement, and may replace it with a new swap also designated as a fair value hedge.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters.
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 18 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, 2002 the Bond Ratio was 5.51. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70% of unfunded net property additions (which unfunded net property additions totaled approximately $522 million at December 31, 2002), (ii) retirements of Class A Bonds (which retirement credits totaled $187.2 million at December 31, 2002), and (iii) cash on deposit with the Trustee.
SCE&G is also subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are 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. At December 31, 2002 approximately $1.3 billion Class A Bonds were on deposit with the Trustee of the New Mortgage and are available to support the issuance of additional 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, 2002 the New Bond Ratio was 5.36.
SCE&G's Restated Articles of Incorporation (the Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders 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 on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2002, the Preferred Stock Ratio was 1.72.
The Articles also require the consent of at least a majority of the total voting power of SCE&G's preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus (the ten percent test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2002 the ten percent test would have limited issuances of unsecured indebtedness to approximately $366.7 million. Unsecured indebtedness at December 31, 2002 totaled approximately $127.6 million.
At December 31, 2002 SCE&G had $250 million of unused committed lines of credit comprised of $175 million expiring in 2003 and $75 million expiring in 2005. These lines of credit support the issuance of commercial paper. SCE&G's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.40% and 1.95%, respectively. On January 8, 2003 a credit agreement was reached allowing SCE&G to share an existing $78 million SCANA uncommitted line of credit. In addition, Fuel Company has a credit agreement for a maximum of $125 million expiring in 2003 with the full amount available at December 31, 2002. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding totaled $50.1 million at December 31, 2002 and 2001, at weighted average interest rates of 1.38% and 2.06%, respectively. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G.
Public Service Company of North Carolina, Incorporated
PSNC Energy has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. While issuance of these securities requires customary approvals discussed above, the Indenture under which they are issued contains no specific limit on the amount which may be issued. PSNC Energy expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.
At December 31, 2002 PSNC Energy had $125 million unused committed lines of credit, expiring in 2003, under a credit agreement supporting the issuance of commercial paper. PSNC Energy had total commercial paper outstanding of $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had no commercial paper outstanding at December 31, 2001.
Financing Transactions
The following financing transactions have occurred since January 1, 2002:
o On January 31, 2002 SCANA issued $250 million of medium-term notes maturing February 1, 2012 and bearing a fixed interest rate of 6.25%. Also on January 31, 2002 SCANA issued $150 million of two-year floating rate notes maturing February 1, 2004. The interest rate on the floating rate notes is reset quarterly based on three-month LIBOR plus 62.5 basis points. Proceeds from these issuances were used to refinance $400 million of two-year floating rate notes that matured February 8, 2002, which had been issued to finance SCANA's acquisition of PSNC Energy.
o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625% and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of SCE&G's construction program and to redeem on March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8 7/8% Series due August 15, 2021.
o On April 24, 2002 SCANA redeemed $202 million of floating rate medium-term notes that were set to mature January 24, 2003. The notes were bearing interest at a rate of 2.90% when redeemed.
o On July 15, 2002 SCANA retired at maturity $300 million of floating rate medium-term notes. The notes were bearing interest at a rate of 4.063% at maturity.
o On August 15, 2002 SCANA issued $100 million one-year floating rate medium-term notes maturing August 15, 2003. The interest rate on the notes is reset quarterly based on three-month LIBOR plus 87.5 basis points. The proceeds were used for general corporate purposes.
o On October 16, 2002 SCANA sold 6 million shares of common stock and received net proceeds of approximately $146 million. On October 17, 2002 SCANA made an equity contribution to SCE&G of $150 million.
o On November 8, 2002 the South Carolina Jobs - Economic Development Authority (JEDA) issued, and SCE&G borrowed the proceeds of, an aggregate of $90.4 million principal amount of tax exempt industrial revenue bonds (the Bonds). The Bonds bear interest at rates ranging from 4.2% to 5.45%, with maturities ranging from 2012 to 2032. Proceeds from the Bonds were used to refund an aggregate amount of $62.3 million principal amount of pollution control revenue bonds and to pay the costs of solid waste disposal facilities at two of SCE&G's electric generating plants.
o On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.
o The Company received payments to terminate swaps totaling $29.3 million and $6.5 million in 2002 and 2001, respectively. These amounts are being amortized over the ten year term of the underlying debt they formerly hedged. At December 31, 2002 the estimated fair value of the Company's swaps totaled $9.0 million related to combined notional amounts of $344.9 million.
Other Information
SCE&G placed in service a $264 million gas turbine generator project in Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn natural gas to produce 341 MW of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 MW turbines at the Urquhart Generating Station.
In May 2002 SCE&G began construction of an 875 MW generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility is expected to begin commercial operation in mid-2004. SCG will transport natural gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.
In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the above Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At December 31, 2002 SCE&G had not yet borrowed under the agreement.
ENVIRONMENTAL MATTERS
Electric Operations
The Clean Air Act Amendments of 1990 (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by the year 2000. The Company remains in compliance with these requirements. In 1998 the EPA required the State of South Carolina, among other states, to modify its state implementation plan (SIP) to address the issue of NOx pollution. The State's SIP requires additional emissions reductions in 2004 and beyond. Further, the EPA has indicated that it will propose regulations by December 2003 for stricter limits on mercury and other toxic pollutants generated by coal-fired plants. To comply with these state and federal regulations, SCE&G and GENCO expect to incur capital expenditures of approximately $131 million over the 2003-2007 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1.8 million per year. To meet compliance requirements for the years 2008 through 2012, the Company anticipates additional capital expenditures of approximately $125 million.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the Department of Justice has brought suit against a number of utilities in federal court alleging violations of the CAA. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA that maintenance activities undertaken by the utilities over the past 20 or more years constitute "major modifications" which would have required the installation of costly Best Available Control Technology (BACT). The Company and SCE&G have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including an exemption for routine repair, replacement or maintenance. The Company has analyzed each of the activities covered by the EPA's requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. It is possible that the EPA will commence enforcement actions against SCE&G, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. The Company believes that any assertions relative to the Company's and SCE&G's compliance with the CAA would be without merit. However, if successful, such assertions could have a material adverse effect on the Company's financial position, cash flows and results of operations.
The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. 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 a more rigorous program of monitoring and controlling thermal discharges and strategies for toxicity reduction in wastewater streams. The Company is developing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act in 2003. Such legislation may include limitations to mixing zones, the implementation of technology-based standards for main condenser cooling water including intake and discharge structures and toxicity-based standards. These provisions, if passed, could have a material impact on the results of operations and cash flows of SCE&G and GENCO.
Gas Distribution
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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 solely to regulated operations and are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. The deferral includes the estimated costs associated with the following matters.
o SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
o SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. SCE&G has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.
In addition, PSNC Energy owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other PRPs. In September 2002 an allocation agreement was reached relieving PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a liability and associated regulatory asset of $7.8 million, which reflects the estimated remaining liability at December 31, 2002. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
REGULATORY MATTERS - STATE
Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded. It is expected that cash flows and the financial position of the Company would not be materially affected by the discontinuation of the accounting treatment. The Company reported approximately $296 million and $114 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $137 million and $43 million, respectively, on its balance sheet at December 31, 2002.
The Company's generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in these assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company's results of operations in the period in which they would be recorded. As of December 31, 2002 the Company's net investment in fossil and hydro and nuclear generation assets was approximately $1,921 million and $546 million, respectively.
South Carolina Electric & Gas Company
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters.
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
On December 31, 2002 the SCPSC issued an order approving SCE&G's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart Generating Station in 2002. As a result, SCE&G transferred approximately $12.5 million from fuel used in electric generation to electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh.
Gas
SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G.
SCE&G's cost of gas component in effect during the years ended December 31, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001 $.728 November-December 2002 $.793 March-October 2001 $.596 November-December 2001
In March 2003 the SCPSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from $.728 per therm to $.928 per therm, effective with the first billing cycle in March 2003.
In 1994 the SCPSC 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 MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005. SCE&G will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility. The cost of the franchise agreement is recorded in other regulatory assets.
Public Service Company of North Carolina, Incorporated
PSNC Energy is subject to the jurisdiction of the NCUC as to gas rates, issuance of securities (other than notes with a maturity of two years or less or renewals of notes with a maturity of six years or less), accounting and other matters.
PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the deferred cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually.
PSNC Energy's benchmark cost of gas in effect during the years ended December 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001 $.215 February-June 2002 $.750 February-March 2001 $.350 July-October 2002 $.650 April-August 2001 $.410 November-December 2002 $.500 September-October 2001 $.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.460 to $.595 per therm effective March 1, 2003.
In April 2000 the NCUC issued an order permanently approving PSNC Energy's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows PSNC Energy to collect from its customers amounts approximating the amounts paid for natural gas.
A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed by the end of 2002. At December 31, 2002 approximately $16.9 million had been spent on this project. The unused portion of PSNC Energy's expansion fund is recorded in prepaid assets.
In December 1999 the NCUC issued an order approving SCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events.
South Carolina Pipeline Corporation
SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In an August 2002 order, the SCPSC found that for the period January 2001 through March 2002 SCPC's gas purchasing policies and practices were prudent and that SCPC properly adhered to the gas cost recovery provisions of its gas tariff.
REGULATORY MATTERS - FEDERAL
SCANA is a registered public utility holding company under PUHCA. SCANA and its subsidiaries are subject to the jurisdiction of the SEC as to financings, acquisitions and diversifications, affiliate transactions and other matters. A customary three-year renewal of the Company's financing and other authorizations under PUHCA was received on February 12, 2003.
The Company's regulated business operations were impacted by FERC Order No. 2000 and other related initiatives of the FERC. Order No. 2000 required each utility under FERC jurisdiction that operates an electric transmission system to submit plans for the possible formation of a regional transmission organization. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In June 2002 GridSouth implementation was suspended pending the issuance and evaluation of new FERC directives.
In July 2002 FERC issued a NOPR on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and which will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant changes to the NOPR may occur and that implementation, presently scheduled for September 2004, may not occur for some time, any rules standardizing the markets may have significant impact on the Company's access to or cost of power for its native load customers and on the Company's marketing of power outside its service territory. The Company is currently evaluating this NOPR to determine what effect it will have on its operations. Additional directives from FERC are expected later in 2003.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of the Company's accounting policies which are new or most critical in terms of reporting financial condition or results of operations.
SFAS 71- The Company's regulated utilities are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," which require them to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. At December 31, 2002 the Company had recorded approximately $296 million and $114 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities. Management believes the regulatory assets are recoverable through rates. The state commissions which regulate the utilities have reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery by the state commissions. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to state commission approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of the Company's Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected.
Certain of the Company's regulatory assets and liabilities arise from its environmental assessment program, which identifies and evaluates current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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. Regulatory assets and liabilities related to environmental cleanup affect primarily the Gas Distribution segment and are due to the costs associated with current and former MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of our utilities and retail gas operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, we record estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2002 and 2001, accounts receivable include unbilled revenues of $107.7 million and $81.1 million, respectively. Total revenues for 2002 and 2001 were $2.95 billion and $3.45 billion, respectively.
Allowance for Funds Used During Construction (AFC) - AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and is depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred. AFC primarily affects the Electric Operations segment due to its capital-intensive construction program, and to a lesser extent, AFC affects the Gas Distribution and Gas Transmission segments. AFC represented approximately 9.1% of income before income taxes, gains, losses, impairments and the cumulative effect of an accounting change in 2002, 7.2% in 2001 and 2.3% in 2000. Because the equity component of AFC is not taxable, increased AFC reduces the Company's effective tax rate. See Results of Operations for additional discussion.
Provisions for Bad Debts and Allowances for Doubtful Accounts - As of each balance sheet date, the Company evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. The distribution segments of the Company's regulated utilities have an established write-off history, and the regulated service areas enable the utilities to reliably estimate their respective provision for bad debts. The Company's Retail Gas Marketing segment operates in Georgia's natural gas market. As such, estimation of the provision for bad debts related to this segment is subject to greater imprecision. In 2002, the Retail Gas Marketing segment expensed approximately $6.2 million related to bad debt, which represents approximately 1.6% of its gross revenue. Had an additional 1% of gross revenues been reserved for bad debts, net income in 2002 would have been reduced by approximately $2.4 million.
Nuclear Decommissioning - Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change SCE&G's accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, as well as changes in financial assumptions such as discount rates and timing of cash flows. See also the discussion of the Company's adoption of SFAS 143, "Accounting for Asset Retirement Obligations," below. Changes in any of these estimates could significantly impact the Company's financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
SCE&G's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.
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 are used to pay premiums on insurance policies on the lives of certain Company personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Pension Accounting - SCANA follows SFAS 87, "Employers Accounting for Pensions," in accounting for its defined benefit pension plan. SCANA's plan is fully funded and as such, net pension income is reflected in the financial statements (see Results of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and returns on assets. Net pension income of $25.8 million recorded in 2002 reflects the use of a 7.5% discount rate and an assumed 9.5% long-term return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable.
Due to poor performance in the stock market in recent years, the Company has determined to adjust its assumed long-term return on assets to 9.25% for 2003. Lower interest rates have also led to a reduction in the discount rate as of December 31, 2002 to 6.5%. Had those assumptions been in place in 2002, net pension income would have been reduced by approximately $5.3 million.
In determining the appropriate discount rate, the Company considers the market indices of high-quality long-term fixed income securities. As such, the Company selected the above discount rate of 6.5% as being within a reasonable range of Moody's "Aa" interest rate as of December 31, 2002. This same discount rate was also selected for determination of OPEB liabilities discussed below.
The following information with respect to pension assets should also be noted:
The Company determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any calculated values, "market related" values or other modeling techniques. In developing the expected long-term rate of return assumptions, the Company evaluated input from actuaries and from pension fund investment advisors, including such advisors' review of the plan's historical 10, 16 and 24 year cumulative actual returns of 10.15%, 10.80% and 12.32%, respectively, which have all been in excess of related broad indices. The Company anticipates that investment managers will continue to generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While management believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate have significantly reduced the level of pension income, the pension trust has been and remains adequately funded, and no contributions have been required since 1997. As such, recent declines in pension income have had no impact on the Company's cash flows. Based on stress testing performed by the Company's actuaries, management does not anticipate the need to make pension contributions until at least 2008.
Accounting for Postretirement Benefits other than Pensions - Similar to its pension accounting, SCANA follows SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCANA used a discount rate of 7.5% and recorded a net SFAS 106 cost of $18.3 million for 2002. Had the selected discount rate been 6.5%, the expense for 2002 would have been approximately $1.2 million higher.
SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and Other Intangible Assets," the Company performed a valuation analysis of its investment in SCPC (Gas Transmission segment) using a discounted cash flow analysis and of PSNC Energy (Gas Distribution segment) using an independent appraisal. The analysis for SCPC indicated that the fair value of related goodwill exceeded its carrying amount. The independent appraisal made various assumptions related to cash flow projections, discount rates, weighted average cost of capital and market multiples for comparable companies. The analysis indicated that the carrying amount of PSNC Energy's acquisition adjustment (goodwill) exceeded its fair value, and as a result, the Company recorded an impairment charge of $230 million as the cumulative effect of an accounting change, effective January 1, 2002. SFAS 142 requires the Company to perform valuation analyses annually. Such analyses will incorporate updated assumptions similar to those used for the initial valuations.
SFAS 143 - SFAS 143 provides guidance for recording and disclosing liabilities related to the future obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from acquisition, construction, development and normal operations. The Company adopted SFAS 143 effective January 1, 2003. Because such obligation relates solely to the Company's regulated electric utility, adoption of SFAS 143 will have no impact on results of operations; however, the Company will record an ARO of approximately $110 million, which exceeds the previously recorded reserve for nuclear plant decommissioning of approximately $87 million.
In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.
The Company's regulated operations record cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, the Company estimates that approximately $325 million of its accumulated depreciation balance is related to this regulatory liability.
OTHER MATTERS
Unconsolidated Special Purpose Entities
Although SCANA invests in securities and business ventures, it does not hold investments in unconsolidated special purpose entities such as those described in SFAS 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," and it does not engage in off-balance sheet financing or similar transactions other than incidental operating leases in the normal course of business, generally for office space, furniture and equipment.
Synthetic Fuel Investments
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of December 31, 2002 is approximately $2 million, and through December 31, 2002, they had generated and passed through to SCE&G approximately $58 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced and consumed by SCE&G have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1B of Notes to Consolidated Financial Statements.
Nuclear License Extension
In August 2002 SCE&G filed an application with the NRC for a 20-year license extension for its Summer Station. If approved, the extension would allow the plant to operate through 2042. SCE&G estimates that it will incur approximately $12 million in costs related to the application process.
Radio Service Network
In April 2002 SCI sold its 800 Mhz radio service network within South Carolina to Motorola, Inc.
Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of SCANA filed suit against SCANA in South Carolina Circuit Court, seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.
In 2001 the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of Supplier and its guarantor to meet contractual obligations related to credit support provisions, the Company terminated the contract. Attempts to negotiate a new contract between the parties were not successful. In February 2003, the Company received notification from Supplier of its request for binding arbitration under the original contract. The Company is confident of the propriety of its actions and will vigorously pursue its position in such arbitration proceedings. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.
Telecommunications Investments
At December 31, 2002 SCH, a wholly owned, indirect subsidiary of SCANA, held investments in the marketable equity and debt securities of the following companies in the amounts noted in the following table.
Investee Securities Basis - --------------- ------------------------------------------------ --------------- (Millions of dollars)
ITC Holding 3.1 million shares common stock $5.8 645,153 shares series A preferred stock, convertible into 2.6 million shares of common stock 7.2 133,664 shares series B preferred stock, convertible into 534,656 shares of common stock 4.0
ITC^DeltaCom 566,010 shares of common stock 1.1 149,077 shares series A 8% preferred stock, convertible in 2005 into 2.6 million shares of common stock 12.7 Warrants to purchase 506,861.8 shares of common stock 1.1
Knology 7.2 million shares series A preferred stock, convertible into 7.5 million shares of common stock 14.1 14.8 million shares series C preferred stock, convertible into 14.8 million shares of common stock 35.1 21.7 million shares series E preferred stock, convertible into 21.7 million shares of common stock 40.6 $43.6 million face amount, 12% senior unsecured notes due 2009, including accrued interest 43.6
In 2002 SCH sold the 39.3 million shares it held in DTAG through a series of market transactions. See additional information at Results of Operations.
ITC Holding Company (ITC Holding) holds ownership interests in several Southeastern communications companies. As these securities are not actively traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services.
In June 2002 ITC^DeltaCom announced plans for a reorganization and entered into Chapter 11 bankruptcy. As a result the Company wrote off its investments in ITC^DeltaCom in the second quarter and recorded an aggregate impairment charge of approximately $7.0 million (after tax). The bankruptcy court accepted the reorganization plan, and ITC^DeltaCom emerged from bankruptcy on October 29, 2002. In connection with ITC^DeltaCom's emergence from bankruptcy, SCH provided $14.9 million in preferred equity financing. The common shares owned by SCH have a market value of $1.3 million, thus an unrealized gain of $0.2 million has been recorded in Other Comprehensive Income. The preferred shares owned by SCH are classified as held to maturity due to their debt features, and the market value is not readily determinable.
In July 2002 Knology negotiated a potential exchange of its Knology Broadband discount notes for a combination of new notes and new preferred stock. In contemplation of the anticipated exchange, the Company recorded an impairment loss of approximately $0.3 million (after-tax) in the second quarter. Because the exchange offer did not result in the requisite minimum tender of notes, in the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which reflected the same terms of exchange. The bankruptcy court accepted the reorganization plan, and in connection with Knology's emergence from bankruptcy, SCH purchased an additional 6.5 million shares of series C preferred stock for approximately $19.5 million. The market value of Knology securities as of December 31, 2002 is not readily determinable.
RESULTS OF OPERATIONS
Earnings (Loss) and Dividends
Earnings (loss) per share of common stock and cash dividends declared for 2002, 2001 and 2000 were as follows:
2002 2001 2000 ----------------------------------------------------------------------------- ----------------------------------------------------------------------------- Earnings (loss) derived from: Continuing operations $2.38 $2.15 $2.12 Gains from sales of investments and assets .24 3.42 - Investment impairments (1.79) (.42) - Cumulative effects of accounting changes, net of taxes (2.17) - .28 ------------------------------------------------------------------------------ Earnings (loss) per weighted average share $(1.34) $5.15 $2.40 ============================================================================== Cash dividends declared (per share) $1.30 $1.20 $1.15 ===============================================================================
o 2002 vs 2001 Earnings derived from continuing operations increased $.23 primarily due to improved margins from sales of electricity of $.36, lower interest expense of $.14, improved results from non-regulated subsidiaries of $.08, increased allowance for funds used during construction of $.06, lower depreciation and amortization expense of $.02 and other items totaling $.03. These factors were partially offset by higher operations and maintenance expense of $.24 (including $.07 due to lower pension income), lower gas margins of $.15 and higher property taxes of $.07.
o 2001 vs 2000 Earnings derived from continuing operations increased $.03, primarily as a result of improved results from retail gas marketing of $.03, improved results from energy marketing of $.09, completion of repairs at Summer Station in 2000 of $.04, the elimination of the imputed interest expense related to the PSNC Energy acquisition in 2000 of $.05 and other items totaling $.02. These improvements were partially offset by a decrease in electric margin of $.11 and a decrease in regulated gas margin of $.09.
In 2002 the Company recorded an impairment charge of $1.72 per share related to the other than temporary decline in market value of the Company's investment in DTAG. In addition, the Company recorded an impairment charge of $.07 per share related to the other than temporary decline in market value of its investment in ITC^DeltaCom (see Note 11 of Notes to Consolidated Financial Statements). Also, as required by SFAS 142 the Company recorded as the cumulative effect of an accounting change an impairment charge of $2.17 per share related to the acquisition adjustment associated with PSNC Energy (see Note 1G of Notes to Consolidated Financial Statements). In addition, the Company recognized gains of $.09 per share from the sale of the Company's radio service network and $.15 per share in connection with its sale of DTAG shares.
In 2001 the Company recognized a gain of $3.38 per share in connection with the exchange of its investment in Powertel, which was acquired by DTAG in May 2001. The Company also recognized a gain of $.04 per share in connection with the sale of the assets of SCANA Security in March 2001. The Company also recorded impairment charges related to investments in ITC^DeltaCom of $.34 per share, a developer of micro-turbine technology of $.04 per share and a lime production plant of $.04 per share.
In 2000 the cumulative effect of an accounting change resulted from the initial recording of unbilled revenues by SCANA's retail utility subsidiaries (see Note 2 of Notes to Consolidated Financial Statements).
Pension Income
For the last several years, the market value of the Company's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. However, pension income for 2002 decreased significantly compared to 2001 and 2000, primarily as a result of a less favorable investment market. Pension income during these periods, excluding amounts attributable to Santee Cooper (see Note 5), was recorded on the Company's financial statements as follows:
Millions of dollars 2002 2001 2000 - --------------------------------------------------- ---------------------- - --------------------------------------------------- ---------------------- Income Statement Impact: Reduction in employee benefit costs $10.9 $22.6 $22.6 Increase in other income 11.1 12.7 12.8 Balance Sheet Impact: Reduction in capital expenditures 3.1 6.2 5.8 Increase in amount due to Santee Cooper .7 1.8 2.0 - --------------------------------------------------- ---------------------- - --------------------------------------------------- ---------------------- Total Pension Income $25.8 $43.3 $43.2 =================================================== ======================
See also the discussion of pension accounting in Critical Accounting Policies and New Accounting Standards.
Allowance for Funds Used During Construction (AFC)
The Company's financial statements include the effects of the recording of 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 9.1% of income before income taxes, gains, losses, impairments and the cumulative effect of an accounting change in 2002, 7.2% in 2001 and 2.3% in 2000.
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G, GENCO and Fuel Company. Electric operations sales margins (including transactions with affiliates) for 2002, 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000 - --------------------------------------------- ---------------- ---------------
Operating revenues $1,379.5 $1,368.7 $1,343.8 Less: Fuel used in generation (329.6) (283.3) (294.9) Purchased power (42.1) (138.1) (82.5) - --------------------------------------------- ---------------- --------------- Margin $1,007.8 $947.3 $966.4 ============================================= ================ ===============
o 2002 vs 2001 Margin increased $31.9 million due to more favorable weather and $30.5 million due to customer growth. Fuel used in generation increased and purchased power decreased due to completion of the Urquhart Station repowering project in June 2002 and fewer plant outages during 2002.
o 2001 vs 2000 Sales margin decreased $32.1 million due to milder weather and $12.6 million due to the impact of the slowing economy. These decreases were partially offset by $25.6 million from customer growth.
Increases (decreases) from the prior year in MWh sales volume by classes were as follows:
Classification (in thousands) 2002 % Change 2001 % Change - ------------------------------------------------------------- ------------
Residential 735.6 11.3% (170.5) (2.5%) Commercial 370.5 5.9% (16.8) - Industrial 158.0 2.5% (317.7) (4.8%) Sales for resale (excluding interchange) 333.7 29.9% (108.3) (8.8%) Other 1.1 0.2% (18.9) (3.4%) - ----------------------------------------- ----------- Total territorial 1,598.9 7.7% (632.2) (3.0%) NMST (1,441.7) (67.1%) 208.0 10.0% - ----------------------------------------- ----------- Total 157.2 0.7% (424.2) (2.0%) ============================================================= ============
o 2002 vs 2001 Territorial sales volume increased primarily due to more favorable weather. The decrease in NMST volumes reflects the Company's recording of buy-resale transactions in Other Income in 2002.
o 2001 vs 2000 Territorial sales volume decreased primarily due to milder weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G and PSNC Energy. Gas distribution sales margins (including transactions with affiliates) for 2002, 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000 - ------------------------------------------- ------------- -------------
Operating revenues $653.9 $793.6 $745.9 Less: Gas purchased for resale (401.0) (537.8) (486.3) - ------------------------------------------- ------------- ------------- Margin $252.9 $255.8 $259.6 =========================================== ============= =============
Sales margin decreased slightly over the three year period primarily as a result of the slowing economy and increased competition with alternate fuels.
Increases (decreases) from the prior year in DT sales volume by classes, including transportation gas, were as follows:
Classification (in thousands) 2002 % Change 2001 % Change - ----------------------------------------- ------------------------- ------------
Residential 3,707.2 11.6% (7,068.1) (18.1%) Commercial 1,344.2 5.7% (2,613.2) (10.0%) Industrial 1,668.4 8.5% (2,860.0) (12.7%) Transportation gas 1,986.2 7.0% (3,318.6) (10.5%) Sales for resale 0.1 6.1% 1.0 * - ----------------------------------------- -------------- Total 8,706.1 8.4% (15,858.9) (13.3%) ========================================= ========================= ============ *Not meaningful
o 2002 vs 2001 Residential and commercial sales volume increased primarily due to more favorable weather. Industrial and transportation gas volumes increased in 2002 after the volatility of the natural gas market in 2001 had resulted in interruptible customers using their alternate fuel sources during that year.
o 2001 vs 2000 Residential sales volume decreased due to higher gas prices. Industrial and transportation gas decreased due to the volatility of the natural gas market resulting in interruptible customers using alternate fuel sources.
Gas Transmission
Gas Transmission is comprised of the operations of SCPC. Gas transmission sales margins (including transactions with affiliates) for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000 - --------------------------------------------- ------------- -------------
Operating revenues $479.1 $478.0 $489.0 Less: Gas purchased for resale (442.4) (434.1) (434.7) - --------------------------------------------- ------------- ------------- Margin $36.7 $43.9 $54.3 ============================================= ============= =============
o 2002 vs 2001 Sales margin decreased $9.6 million due to the unfavorable competitive position of natural gas relative to alternate fuels in the first quarter, which was partially offset by a favorable competitive position in the remaining quarters of $1.4 million and increased sales for electric generation of $1.0 million.
o 2001 vs 2000 Sales margin decreased primarily as a result of decreased volume of sales to industrial customers due to competitive pricing of alternate fuels and a slowing economy of $8.5 million, decreased volume of sales to electric generation due to milder weather of $1.4 million and reduced margins in sales for resale as a result of milder weather of $0.5 million.
Increases (decreases) from the prior year in DT sales volume by classes including transportation were as follows:
Classification (in thousands) 2002 % Change 2001 % Change ------------------------------------- --------------------------------------
Commercial 46.1 64.5% (42.2) (37.2%) Industrial 17,402.5 59.6% (10,127.6) (25.8%) Transportation 770.2 25.8% 725.1 32.1% Sales for resale 4,299.7 8.2% (9,529.6) (15.3%) ------------------------------------- ---------------- Total 22,518.5 26.5% (18,974.3) (18.3%) ===================================== ======================================
o 2002 vs 2001 Industrial volumes increased 3,732.2 thousand DTs due to increased electric generation and 4,395.8 thousand DTs due to the emergence from bankruptcy of a large industrial customer. The remaining increase is primarily due to improved competition with alternate fuels. Sales for resale volumes increased due to more favorable weather.
o 2001 vs 2000 Commercial and industrial volumes decreased primarily due to increased gas to gas competition. Transportation volumes increased due to increased gas to gas competition. Sales for resale volumes decreased due to milder weather.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA Energy Marketing, Inc., which operates in Georgia's natural gas market. Retail Gas Marketing revenues and net income for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000 ------------------------------------ --------------- ----------------
Operating revenues $379.5 $453.8 $412.8 Net income 14.3 6.8 3.2 ------------------------------------ --------------- ----------------
o 2002 vs 2001 Operating revenues decreased primarily as a result of lower average retail prices and lower volumes. Net income increased primarily due to lower bad debt expense of $8.1 million, lower interest and depreciation expense of $1.6 million and lower effective tax rate of $0.8 million, which were partially offset by a decrease in gas margin of $2.1 million and higher operating expenses of $0.9 million.
o 2001 vs 2000 Operating revenues increased due to higher average retail prices. Net income increased primarily as a result of increases in gross margins on gas sales.
Delivered volumes for 2002, 2001 and 2000 totaled approximately 33.8 million, 36.0 million and 43.1 million DT, respectively.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing operations, excluding SCANA Energy. Energy Marketing operating revenues and net income (loss) for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000 ------------------------------------- --------------- ----------------
Operating revenues $316.8 $613.4 $677.9 Net income (loss) (.8) 3.4 (3.1) ------------------------------------- --------------- ----------------
o 2002 vs 2001 Operating revenues decreased primarily due to lower natural gas prices and lower volumes. Net income decreased $5.3 million primarily from the decreased activity and subsequent closing of SCANA Energy Trading, LLC and $1.7 million due to lower margins related to decreased gas prices and decreased volumes. These decreases were partially offset by increases of $1.3 million due to the closing of the unprofitable Midwest office in 2001 and $1.5 million lower bad debt expense.
o 2001 vs 2000 Operating revenues decreased $104.8 million primarily due to the closing of the Midwest and California offices in 2001, which was partially offset $40.3 million by higher average retail prices. Net income improved primarily due to improved margins.
Delivered volumes for 2002, 2001 and 2000 totaled approximately 86.2 million, 114.6 million and 149.6 million DT, respectively. The decrease in volumes for 2001 resulted from the closing of the Midwest and California offices.
Other Operating Expenses
Increases (decreases) in other operating expenses were as follows:
Millions of dollars 2002 % Change 2001 % Change - ------------------------------------------ -------------------------------------
Other operation and maintenance $41.4 8.6% $3.5 0.7% Depreciation and amortization (3.8) (1.7%) 7.2 3.3% Other taxes 11.6 10.1% 1.5 21.3% - ------------------------------------------ ----------- Total $49.2 6.0% $12.2 1.5% ========================================== =====================================
o 2002 vs 2001 Other operation and maintenance expenses increased primarily due to lower pension income of $11.6 million, increased labor and benefits of $19.2 million, increased nuclear refueling maintenance of $4.0 million, increased cost at Cogen South of $3.1 million, higher property insurance of $2.6 million, increased amortization of environmental costs of $3.0 million and increased storm damage expenses of $1.8 million. These increases were partially offset by lower bad debt expense of $7.0 million. Depreciation and amortization decreased primarily due to implementation of SFAS 142 and the resulting elimination of amortization expense related to goodwill of $14.0 million - see Note 1G of Notes to Consolidated Financial Statements, which was partially offset by increases for the completion of the Urquhart Station repowering project in June 2002 of $4.8 million and normal net property additions of $5.4 million. Other taxes increased primarily due to increased property taxes.
o 2001 vs 2000 Other operation and maintenance expenses increased primarily as a result of increases in employee benefits. Depreciation and amortization increased primarily as a result of normal increases in utility plant. Other taxes increased primarily due to increased property taxes.
Other Income
Increases (decreases) in other income, excluding the equity component of AFC, were as follows:
Millions of dollars 2002 % Change 2001 % Change - ------------------------------------------ ---------------------------------
Gain on sale of investments $(521.7) * $545.3 * Gain on sale of assets 4.1 33.3% 10.5 * Impairment of investments (228.8) * (61.9) * Other income 8.6 21.7% 0.4 1.0% - ------------------------------------------ ---------- Total $(737.8) * $494.3 * ========================================== ================================= *Not meaningful
o 2002 vs 2001 Gain on sale of investments was higher in 2001 than 2002 primarily as a result of the gain of $545.3 million recognized in May 2001 in connection with the exchange of the Company's investment in Powertel for shares of DTAG, and the March 2001 gain of $7.8 million on the sale of the assets of SCANA Security. In 2002, the Company recognized gains of $15.6 million and $23.6 million in connection with the sale of the Company's radio service network and the sale of all DTAG stock. Impairment of investments increased due to the impairment writedowns of the Company's investments in DTAG and ITC^DeltaCom.
o 2001 vs 2000 Other income increased primarily as a result of the gain recognized in May 2001 in connection with the exchange of the Company's investment in Powertel for shares of DTAG, and the March 2001 gain on the sale of the assets of SCANA Security. These gains were partially offset by impairments related to investments in ITC^DeltaCom, a developer of micro-turbine technology and a lime production plant.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows:
Millions of dollars 2002 % Change 2001 % Change ---------------------------------------------------------------------------
Interest on long-term debt, net $(18.8) (8.4%) $17.8 8.6% Other interest expense (4.0) (39.6%) (14.4) (58.8)% ------------------------------------------- ---------- Total $(22.8) (9.8%) $3.4 1.5% ===========================================================================
o 2002 vs 2001 Interest expense decreased by $18.8 million as a result of lower interest rates, by $2.0 million due to decreased borrowings and by $1.4 million due to lower amortization of debt expense which occurred as a result of debt payoffs.
o 2001 vs 2000 Interest expense increased by $20.0 million due to increased borrowings. Such increase was partially offset by decreases of $6.0 million due to declining variable interest rates, $5.2 million due to the Company's use of interest rate swap contracts to convert higher fixed rate debt to lower variable rate debt and by $5.4 million due to a decrease in the principal and weighted average interest rate on short-term debt.
Income Taxes
Income taxes decreased approximately $268.9 million in 2002 compared to 2001 and increased approximately $163.8 million in 2001 compared to 2000. Changes in income taxes are primarily due to changes in Other Income described above. The Company's effective tax rate for 2002, excluding the cumulative effect of accounting change, was approximately 26.7%, which reflects the impact of higher equity AFC and the change in tax regulations effective in 2002 allowing for the tax deductibility of certain dividends paid on SCANA stock held in the Company's Stock Purchase Savings Plan .
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for purposes other than trading.
Interest rate risk - The tables below provide information about long-term debt issued by the Company and other financial instruments that are sensitive to changes in interest rates. For debt obligations the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
In addition, at December 31, 2002 the Company held investments in the 12% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $43.6 million. As these notes are not actively traded, determination of their fair value is not practicable.
Commodity price risk - The tables below provide information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair values represent quoted market prices.
As of December 31, 2002 Millions of dollars, except weighted average settlement price and strike price
Natural Gas Derivatives: Expected Maturity in 2003 - --------------------------- --------------------------------- Settlement Contract Fair Price (a) Amount Value Futures Contracts: Long($) 4.65 15.6 18.7 Short($) 4.62 3.6 4.5
Strike Contract Price Amount (a) Options: Purchased put (short)($) 4.25 8.8 Purchased call (long)($) 4.11 16.5 Sold put (long) ($) 2.30 2.7 - --------------------------- ----------- ---- ----------------
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of various types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as NYMEX futures contracts or options, and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. The Company's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including the Company's Risk Management Officer, and senior officers of the Company, provides assurance to the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions that are allowed.
The NYMEX futures information above includes those financial positions of both Energy Marketing and SCPC. Certain derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.
Beginning in January 2003, PSNC Energy initiated a hedging program for gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. PSNC Energy will include in its PGA the results of its hedging program, and will seek approval of this accounting treatment from the NCUC during the annual prudence review in 2003. The offset to the change in fair value of these derivatives will be recorded as a regulatory asset or liability.
Equity price risk - Investments in telecommunications companies' equity securities (excluding preferred stock with significant debt characteristics) are carried at market value or, if market value is not readily determinable, at cost. The carrying value of the Company's investments in such securities totaled $109.1 million at December 31, 2002. A temporary decline in value of ten percent would result in a $10.9 million reduction in fair value and a corresponding adjustment, net of tax effect, to the related equity account for unrealized gains/losses, a component of Other Comprehensive Income (Loss). An other than temporary decline in value of ten percent would result in a $10.9 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditors' Report.............................................. 56
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001........... 57
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000 .................................. 59
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000................................... 60
Consolidated Statements of Capitalization as of December 31, 2002 and 2001...................................................... 61
Consolidated Statements of Comprehensive Income and Changes in Common Equity for the Years Ended December 31, 2002, 2001 and 2000 ....... 63
Notes to Consolidated Financial Statements............................. 64
INDEPENDENT AUDITORS' REPORT
SCANA Corporation:
We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of SCANA Corporation (Company) as of December 31, 2002 and 2001 and the related Consolidated Statements of Operations, Comprehensive Income (Loss) and Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2002. Our audits also include the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2002 and 2001 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information as set forth therein.
As discussed in Notes 1 and 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," effective January 1, 2002 and changed its method of accounting for operating revenues associated with its regulated utility operations effective January 1, 2000.
s/Deloitte & Touche LLP Columbia, South Carolina February 7, 2003
SCANA Corporation CONSOLIDATED BALANCE SHEETS - ------------------------------------------------------------------------------ December 31, (Millions of dollars) 2002 2001 - ------------------------------------------------------------------------------ Assets Utility Plant (Note 6): Electric $5,228 $4,855 Gas 1,593 1,536 Other 184 187 - ------------------------------------------------------------------------------ Total 7,005 6,578 Accumulated depreciation and amortization (2,476) (2,364) - ------------------------------------------------------------------------------ Total 4,529 4,214 Construction work in progress 677 544 Nuclear fuel, net of accumulated amortization 38 45 Acquisition adjustments, net of accumulated amortization (Notes 2 & 3) 230 460 - ------------------------------------------------------------------------------ Utility Plant, Net 5,474 5,263 - ------------------------------------------------------------------------------
Nonutility Property, Net of Accumulated Depreciation 95 93 Investments (Note 11) 231 194 - ------------------------------------------------------------------------------ Nonutility Property and Investments, Net 326 287 - ------------------------------------------------------------------------------
Current Assets: Cash and temporary investments (Note 11) 397 212 Receivables, net of allowance for uncollectible accounts of $17 and $37 486 424 Inventories (at average cost): Fuel 166 164 Materials and supplies 61 59 Emission allowances 10 13 Prepayments 40 21 Investments (Note 11) - 664 - ------------------------------------------------------------------------------ Total Current Assets 1,160 1,557 - ------------------------------------------------------------------------------
Deferred Debits: Environmental 27 34 Nuclear plant decommissioning fund 87 79 Pension asset, net (Note 5) 265 239 Other regulatory assets 269 210 Other 146 153 - ------------------------------------------------------------------------------ Total Deferred Debits 794 715 - ------------------------------------------------------------------------------ Total $7,754 $7,822 ==============================================================================
(1) Rate at repayment (2) Current rate, based on three-month LIBOR + 87.5 basis points reset quarterly (3) Fixed rate debt hedged by variable interest rate swap (4) Current rate, based on three-month LIBOR + 62.5 basis points reset quarterly
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
SCANA Corporation (the Company), a South Carolina corporation, is a registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935, as amended (PUHCA). The Company, through wholly owned subsidiaries, is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to wholesale and retail customers in South Carolina, North Carolina and Georgia. The Company is also engaged in other energy-related businesses, holds investments in telecommunications companies and provides fiber optic communications in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of the Company, the following wholly owned subsidiaries, and three other wholly owned subsidiaries in liquidation.
Regulated businesses Nonregulated businesses South Carolina Electric & Gas Company (SCE&G) SCANA Energy Marketing, Inc. South Carolina Fuel Company, Inc. (Fuel Company) SCANA Communications, Inc.(SCI) South Carolina Generating Company, Inc. (GENCO) ServiceCare, Inc. South Carolina Pipeline Corporation (SCPC) Primesouth, Inc. Public Service Company of North Carolina, SCANA Resources, Inc. Incorporated (PSNC Energy) SCANA Services, Inc. SCG Pipeline, Inc.
Certain investments are reported using the cost or equity method of accounting, as appropriate. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 2002, approximately $296 million and $114 million of regulatory assets and liabilities, respectively, as shown below.
December 31, Millions of dollars 2002 2001 - ------------------------------------------------------------- --------------- - ------------------------------------------------------------- --------------- Accumulated deferred income taxes, net $95 $98 Under- (over-) collections - Electric Fuel and Gas Cost Adjustment Clauses 61 46 Deferred environmental remediation costs 27 35 Deferred non-conventional fuel tax benefits, net (40) (17) Storm damage reserve (32) (26) Franchise agreements 65 - Other 6 8 - ------------------------------------------------------------- --------------- - ------------------------------------------------------------- --------------- Total $182 $144 ============================================================= ===============
Accumulated deferred income taxes represent deferred income tax liabilities applicable to utility operations that have not been reflected in customer rates for which future recovery is probable, offset by deferred income tax assets, which will be reflected in customer rates as a result of reduced revenue requirements due to the amortization of deferred investment tax credits.
Under- (over-) collections - fuel adjustment clauses represent amounts over- or under-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment clause (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) or North Carolina Utilities Commission (NCUC) during annual hearings (see Note 1F).
Deferred environmental remediation costs represent costs associated with the assessment and clean up of environmental sites at manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by SCE&G are being recovered through rates, and such costs, totaling approximately $18 million, are expected to be fully recovered by the end of 2005. A portion of the costs incurred at sites owned by PSNC Energy are also being recovered through rates, and management believes the remaining costs of approximately $7.8 million will be recoverable in the future. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million.
Deferred non-conventional fuel tax benefits represent the deferral of partnership losses and other expenses, offset by the accumulated deferred income tax credits associated with two SCE&G partnerships involved in converting coal to alternate fuel. Under a plan approved by the SCPSC, any net tax credits generated from non-conventional fuel produced and consumed by SCE&G and ultimately passed through to SCE&G have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a ten-year period. The accumulated storm damage reserve can be applied to offset actual storm damage costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina.
The SCPSC and the NCUC have reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC or the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in rate orders received by the Company. However, ultimate recovery is subject to SCPSC or NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected.
C. 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).
D. Utility Plant and Major Maintenance
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.
SCE&G, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating 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 $962.4 million and $963.0 million as of December 31, 2002 and 2001, respectively. Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $417.9 million and $407.4 million as of December 31, 2002 and 2001, respectively. SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses and totaled approximately $76.4 million for the year ended December 31, 2002.
Planned major maintenance other than that related to nuclear outages is expensed when incurred. The only major maintenance that is accrued in advance of the time the costs are actually incurred is that related to the nuclear refueling outages for which such accounting treatment and rate recovery of expenses accrued thereunder has been approved by the SCPSC. Nuclear outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage immediately upon completion of the preceding outage. For the outage ended June 2002, SCE&G accrued approximately $0.5 million per month from January 2001 through June 2002 and is now accruing approximately $0.6 million per month for its portion of the outage scheduled in October 2003. Total outage costs for the planned outage in October 2003 are estimated to be approximately $17 million, of which SCE&G will be responsible for approximately $11.3 million. As of December 31, 2002, SCE&G had accrued $3.8 million.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.3%, 8.8% and 8.3% for 2002, 2001 and 2000, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered, but not yet billed. Prior to January 1, 2000 revenues related to regulated electric and gas services were recorded only as customers were billed (see Note 2). Unbilled revenues totaled approximately $107.7 million and $81.1 million as of December 31, 2002 and 2001, respectively.
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 SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. SCE&G had undercollected through the electric fuel cost component approximately $25.3 million and $47.4 million at December 31, 2002 and 2001, respectively, which amounts are included in "Deferred Debits - Other regulatory assets."
Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the SCPSC during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2002 and 2001 SCE&G had undercollected through the gas cost recovery procedure approximately $24.6 million and $12.2 million, respectively, which amounts are also included in "Deferred Debits - Other regulatory assets." At December 31, 2002 PSNC Energy had undercollected through the gas cost recovery procedure approximately $10.6 million which amount is also included in "Deferred Debits - Other regulatory assets." At December 31, 2001 PSNC Energy had overcollected through the gas cost recovery procedure approximately $13.8 million which amount is included in "Deferred Credits - Other regulatory liabilities."
SCE&G's and PSNC Energy's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property.
The composite weighted average depreciation rates for utility plant assets were as follows:
2002 2001 2000 - --------------------------------------- -------------- --------------- SCE&G 2.93% 2.98% 2.98% GENCO 2.66% 2.71% 2.67% SCPC 2.14% 2.60% 2.58% PSNC Energy 4.29% 4.06% 4.15% Aggregate of Above 3.06% 3.09% 3.09%
Nuclear fuel amortization, which is included in "Fuel used in electric generation" and 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 Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. The Company considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. These amounts are related to acquisition adjustments of approximately $466 million recorded on the books of PSNC Energy (Gas Distribution segment) and approximately $40 million recorded on the books of SCPC (Gas Transmission segment). The Company has no other intangible assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization of acquisition adjustments during all periods presented in the consolidated statements of operations, net income (loss) and basic and diluted earnings (loss) per share would have been as follows:
In connection with implementation of SFAS 142, the Company performed a valuation analysis of its investment in SCPC using a discounted cash flow analysis and of PSNC Energy using an independent appraisal. The analysis of the investment in PSNC Energy indicated that the carrying amount of PSNC Energy's acquisition adjustment exceeded its fair value by approximately $230 million as of January 1, 2002. As a result, the Company recorded an impairment charge of $230 million ($2.17 loss per share) in 2002. The charge is reflected on the statement of operations as the cumulative effect of an accounting change.
H. Nuclear Decommissioning
SCE&G's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.
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 in each of 2002, 2001 and 2000) are used to pay premiums on insurance policies on the lives of certain Company personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
SCE&G records its liability for decommissioning cost in deferred credits. See also discussion below related to the adoption of SFAS 143, "Accounting for Asset Retirements Obligations," effective January 1, 2003.
In addition to the above, pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, SCE&G has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $2.0 million and $2.4 million at December 31, 2002 and 2001, respectively, has been included in "Long-Term Debt, net." SCE&G is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other."
I. Income and Other Taxes
The Company files a consolidated federal income tax return. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such 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.
The Company records excise taxes billed and collected, as well as local franchise and similar taxes as liabilities until they are remitted to the respective taxing authority. As such, no excise taxes are included in revenues or expenses in the statements of operations.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt and are being amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and amortized over the term of the replacement debt.
K. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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 solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. Deferred amounts for PSNC Energy totaled $7.8 million and $9.1 million at December 31, 2002 and 2001, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 12C.
L. 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.
M. Commodity Derivatives
Beginning January 1, 2001 the Company began recognizing assets or liabilities for the energy-related derivatives contracts entered into by its subsidiaries when the contracts are executed. The Company records derivatives contracts at their fair value in accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and adjusts fair value each reporting period. The Company derives fair value of most of the energy-related derivatives contracts from markets where they are actively traded and quoted. For other derivatives contracts the Company uses published market surveys and in certain cases, independent parties to obtain quotes concerning fair value. Market quotes tend to be more plentiful for those derivatives contracts maturing in two years or less. The vast majority of the Company's derivatives contracts do not extend beyond two years. (See Note 11). SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.
N. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141 requires all acquisitions to be accounted for utilizing the purchase method. SFAS 142 addresses how goodwill and other intangible assets should be accounted for after they have been recorded in the financial statements. (See Notes 1G and 2).
In June 2001, FASB issued SFAS 143, which becomes effective for financial statements issued for fiscal years beginning after June 15, 2002. Accordingly, the Company adopted this standard effective January 1, 2003. SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods.
The Company has determined that it should recognize an ARO related to the decommissioning and dismantling of Summer Station, and effective January 1, 2003, will record an ARO of approximately $110 million, which amount exceeds the previously recorded reserve for nuclear plant decommissioning of $87 million, and a net capital asset of approximately $20 million. Due to the application of SFAS 71, the difference between these amounts will be recorded in regulatory accounts and will have no impact on the Company's results of operations or cash flows.
In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.
The Company's regulated operations record cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, the Company estimates that approximately $325 million of its accumulated depreciation balance is related to this regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective January 1, 2002. This statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. The Company will adopt SFAS 145 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt SFAS 146 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" was issued in December 2002 and amends SFAS 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company will adopt the disclosure provisions of SFAS 148 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
O. Stock Option Plan
Under the SCANA Corporation Long-Term Equity Compensation Plan, certain employees and non-employee directors may receive incentive and nonqualified stock options and other forms of equity compensation. The Company accounts for this equity-based compensation using the intrinsic value method under APB 25, "Accounting for Stock Issued to Employees," and related interpretations. In addition, the Company has adopted the disclosure provisions of SFAS 123, "Accounting for Stock-Based Compensation" and, effective January 1, 2003, the provisions of SFAS 148 "Accounting for Stock-Based Compensation - Transition and Disclosure."
P. Earnings Per Share
Earnings (loss) per share amounts have been computed in accordance with SFAS 128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed as net income divided by the weighted average number of shares of common stock outstanding during the period after giving effect to securities considered to be dilutive potential common stock. The Company uses the treasury stock method in determining total dilutive potential common stock.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002.
R. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. Accounting ChangeS
As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to the acquisition adjustment recorded in connection with its investment in PSNC Energy. This charge is reflected on the Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1G.
Effective January 1, 2000 the Company changed its method of accounting for operating revenues associated with its regulated utility operations from cycle billing to full accrual. The cumulative effect of this change was $29 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period.
3. ACQUISITION
Effective January 1, 2000 the Company acquired PSNC Energy in a business combination accounted for as a purchase. PSNC Energy is a public utility engaged primarily in purchasing, transporting, distributing and selling natural gas to approximately 384,000 residential, commercial and industrial customers in 27 of its 28 franchised counties in North Carolina. Pursuant to the Agreement and Plan of Merger, PSNC Energy shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million. In connection with the acquisition, 16.3 million shares of SCANA common stock were repurchased for approximately $488 million. The results of operations of PSNC Energy are included in the accompanying financial statements as of January 1, 2000, the effective date of the acquisition. The total cost of the acquisition was approximately $700 million, which exceeded the fair value of the net assets acquired by approximately $466 million (see Note 1G).
4. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
In December 2002 the SCPSC issued an order approving SCE&G's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart Generating Station in 2002. As a result, SCE&G transferred approximately $12.5 million from fuel used in electric generation to electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the above retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh. This reduction is effective for service rendered on or after February 1, 2003.
Gas
SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G.
SCE&G's cost of gas component in effect during the years ended December 31, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001 $.728 November-December 2002 $.793 March-October 2001 $.596 November-December 2001
The SCPSC allows SCE&G to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been recorded in deferred debits. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005. SCE&G will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility. The cost of the franchise agreement is recorded in other regulatory assets.
Public Service Company of North Carolina, Incorporated
PSNC Energy's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. PSNC Energy revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the delivered cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews PSNC Energy's gas purchasing practices annually.
PSNC Energy's benchmark cost of gas in effect during the years ended December 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001 $.215 February-June 2002 $.750 February-March 2001 $.350 July-October 2002 $.650 April-August 2001 $.410 November-December 2002 $.500 September-October 2001 $.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003.
In April 2000 the NCUC issued an order permanently approving PSNC Energy's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows PSNC Energy to collect from its customers amounts approximating the amounts paid for natural gas.
A state expansion fund, established by the North Carolina General Assembly and funded by refunds from PSNC Energy's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved PSNC Energy's requests for disbursement of up to $28.4 million from PSNC Energy's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. PSNC Energy estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed by the end of 2002. Through December 31, 2002 approximately $16.9 million had been spent on this project. The unused portion of PSNC Energy's expansion fund is recorded in prepaid assets.
In December 1999 the NCUC issued an order approving SCANA's acquisition of PSNC Energy. As specified in the order, PSNC Energy reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events.
South Carolina Pipeline Corporation
SCPC's purchased gas adjustment for cost recovery and gas purchasing policies are reviewed annually by the SCPSC. In an August 2002 order, the SCPSC found that for the period January 2001 through March 2002 SCPC's gas purchasing policies and practices were prudent and that SCPC properly adhered to the gas cost recovery provisions of its gas tariff.
5. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Employee Benefit Plans
The Company sponsors a noncontributory defined benefit pension plan which covers substantially all permanent employees. The Company's policy has been to fund the plan to the extent permitted by the applicable federal income tax regulations as determined by an independent actuary.
Effective July 1, 2000 the Company's pension plan was amended to provide a cash balance formula. With certain exceptions employees were allowed to either remain under the final average pay formula or elect the cash balance formula. Under the final average pay formula, benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. Under the cash balance formula, the monthly benefit earned under the final average pay formula at July 1, 2000 was converted to a lump sum amount for each employee and increased by transition credits for eligible employees. Under the cash balance formula, benefits based upon this opening balance increase going forward as a result of compensation credits and interest credits. The effect of this plan amendment was to reduce the Company's net periodic benefit income for the year ended December 31, 2000 by approximately $3.7 million.
In addition to pension benefits, the Company provides certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for the applicable benefits.
Effective July 1, 2000 PSNC Energy's pension and postretirement benefit plans were merged with SCANA's plans.
In connection with the joint ownership of Summer Station, as of December 31, 2002 and 2001 the Company has recorded within deferred credits a $9.1 million and $8.4 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the pension plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2002 and 2001, the Company has also recorded a $6.4 million and $6.0 million receivable, respectively from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.
As allowed by SFAS 87, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," are set forth in the following tables:
Health Care Trends
The determination of net periodic other postretirement health care benefit cost is based on the following assumptions:
2002 2001 2000 -------------------------------------------------- ---------- ----------
Health care cost trend rate 10.0% 8.5% 7.5% Ultimate health care cost trend rate 5.0% 5.0% 5.5% Year achieved 2011 2009 2005
The effects of a one-percentage-point increase or decrease in the assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic other postretirement health care benefit cost and the accumulated other postretirement benefit obligation for health care benefits are as follows:
Millions of dollars 1% 1% Increase Decrease -------------- -----------------
Effect on health care benefit cost $0.1 $(0.1) Effect on postretirement benefit obligation 1.4 (1.7)
Due to poor performance in the stock market in recent years, the Company has determined to adjust its long-term expected return on assets to 9.25% for 2003. In developing the expected long-term rate of return assumptions, management evaluated the plan's historical cumulative actual returns over several periods, which have all been in excess of related broad indices, and management anticipates that the plan's investment managers will continue to generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While the Company believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate have significantly reduced the level of pension income, the pension trust has been and remains adequately funded, and no contributions have been required since 1997. As such, recent declines in pension income have had no impact on the Company's cash flows.
Long-Term Equity Compensation Plan
The Long-Term Equity Compensation Plan (the Plan) became effective January 1, 2000. The Plan provides for grants of incentive and nonqualified stock options, stock appreciation rights, restricted stock, performance shares and performance units to certain key employees and non-employee directors. The Plan currently authorizes the issuance of up to five million shares of the Company's common stock, no more than one million of which may be granted in the form of restricted stock.
A summary of activity related to grants of nonqualified stock options follows:
Weighted Number of Average Options Exercise Price ----------------------------------------- ----------------- ------------------ Outstanding - December 31, 1999 - - Granted 160,508 $25.53 ----------------------------------------- ----------------- Outstanding - December 31, 2000 160,508 25.53 Granted 716,368 27.43 Exercised - n/a Forfeited (74,595) 26.93 ----------------------------------------- ----------------- Outstanding - December 31, 2001 802,281 27.10 ----------------------------------------- ----------------- Granted 1,116,638 27.56 Exercised (103,677) 27.12 Forfeited (97,332) 27.38 ----------------------------------------- ----------------- ----------------------------------------- ----------------- Outstanding - December 31, 2002 1,717,910 27.38 ----------------------------------------- -----------------
One-third of the options vest on each anniversary of the date of grant until full vesting occurs. The options expire ten years after the grant date. Information about outstanding and exercisable options as of December 31, 2002 follows:
At December 31, 2001 exercisable options totaled 47,275 at a weighted average exercise price of $25.53. No options were exercisable at December 31, 2000.
The Company applies the intrinsic value method prescribed by APB 25 and related interpretations in accounting for grants made under the Plan. Because all options were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates, no compensation expense has been recognized in connection with such grants. If the Company had determined compensation expense for the issuance of options based on the fair value method described in SFAS 123, "Accounting for Stock-Based Compensation," pro forma net income (loss) and earnings (loss) per share would have been as presented below:
For purposes of the above pro forma information, the weighted average fair value at grant date (the value at grant date of the right to purchase stock at a fixed price for an extended time period) for options granted in 2002, 2001 and 2000 was $4.67, $5.13 and $4.43, respectively, and was estimated using the Black-Scholes Option pricing model with the following weighted average assumptions.
2002 2001 2000 ---- ---- ---- Expected life of options (years) 7 7 10 Risk free interest rate 4.64% 5.08% 5.99% Volatility of underlying stock 21% 22% 21% Dividend yield of underlying stock 4.4% 4.2% 4.4%
6. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund requirements for the years 2003 through 2007 are summarized as follows:
Year Amount Year Amount ---------------- ----------------- ------------------ ----------------- (Millions of dollars)
2003 $413 2006 $177 2004 352 2007 71 2005 197 ---------------- ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt payable in 2003 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 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million with such borrowings being repaid over ten years from the initial borrowing. At December 31, 2002 SCE&G had not yet borrowed under the agreement.
On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with SCE&G. In consideration for the electric franchise agreement, SCE&G paid the City $25 million over seven years (1996-2002) and donated to the City the existing transit assets in Charleston.
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia. As part of the transfer agreement, SCE&G will pay the City $32 million over eight years (2002-2009) in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005.
SCE&G has a three-year revolving line of credit totaling $75 million, expiring in 2005, in addition to other lines of credit that provide liquidity for issuance of commercial paper. The three-year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million.
On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.
Substantially all of SCE&G's utility plant is pledged as collateral in connection with long-term debt.
7. SHORT-TERM BORROWINGS
Details of lines of credit (including uncommitted lines of credit) and short-term borrowings at December 31, 2002 and 2001, are as follows:
Millions of dollars 2002 2001 - --------------------------------------------------------- ---------------
Lines of credit $588.0 $588.0 Unused lines of credit $588.0 $588.0 Short-term borrowings outstanding Commercial paper (270 or fewer days) $208.8 $164.8 Weighted average interest rate 1.40% 1.97%
The Company pays fees to banks as compensation for committed lines of credit.
Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by a 364-day revolving credit agreement which expires December 16, 2003. The credit agreement provides for a maximum amount of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper amounts outstanding have been classified as short-term debt.
Fuel Company commercial paper outstanding totaled $50.1 million and $50.1 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.38% and 2.06%, respectively.
SCE&G's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, at weighted average interest rates of 1.40% and 1.95%, respectively.
PSNC Energy's commercial paper outstanding totaled $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had no commercial paper outstanding at December 31, 2001.
8. COMMON EQUITY
The Company's Restated Articles of Incorporation do not limit the dividends that may be paid on its common stock. However, the Restated Articles of Incorporation of SCE&G contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2002 approximately $41 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.
In October 2002, six million shares of SCANA common stock were sold, generating net proceeds of approximately $146 million.
Cash dividends on common stock were declared during 2002, 2001 and 2000 at an annual rate per share of $1.30, $1.20 and $1.15, respectively.
The accumulated balances related to each component of other comprehensive income (loss) were as follows:
Unrealized Cash flow Accumulated other gains (losses) hedging comprehensive Million of dollars on securities activities Income (loss) - -------------------------------------------------------------------------------- Balance, December 31, 1999 $336 - $336 Other comprehensive loss (197) - (197) - -------------------------------------------------------------------------------- Balance, December 31, 2000 139 - 139 Other comprehensive loss (226) $(26) (252) - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Balance, December 31, 2001 (87) (26) (113) Other comprehensive income 87 27 114 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Balance, December 31, 2002 $- $1 $1 ================================================================================
During 2002, $87 million was reclassified from unrealized gains (losses) on securities into net income (loss) as a result of the recording of an impairment in the value of the Deutsche Telekom AG investment. The Company also recognized a loss of approximately $20.6 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2002.
During 2001, $354 million was reclassified from unrealized gains (losses) on securities into net income as a result of the exchange of (available for sale) shares of Powertel, Inc., for shares of Deutsche Telekom AG (DTAG). Also in 2001, $(36) million was reclassified from unrealized gains (losses) on securities into net income as a result of the recording of an impairment of the ITC^DeltaCom, Inc. investment. The Company recognized a loss of approximately $17.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2001.
There were no realized gains or losses on securities for the year ended December 31, 2000.
9. PREFERRED STOCK
Retirements under sinking fund requirements are at par values. The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 2003 through 2007 is $2.7 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend.
The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2002, 2001 and 2000 are summarized as follows:
Number of Shares Millions of Dollars - ------------------------------------------------------------------------------ Balance at December 31, 1999 231,487 $11.6 Shares Redeemed - $50 par value (11,200) (0.6) - ------------------------------------------------------------------------------ Balance at December 31, 2000 220,287 11.0 Shares Redeemed - $50 par value (10,803) (0.5) - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Balance at December 31, 2001 209,484 10.5 Shares Redeemed - $50 par value (9,511) (0.5) - ------------------------------------------------------------------------------ Balance at December 31, 2002 199,973 $10.0 ==============================================================================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of SCE&G, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred Securities, Series A (the "Preferred Securities"). SCE&G owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from SCE&G a like amount of its 7.55% Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is such Junior Subordinated Debentures of SCE&G. Accordingly no financial statements of the Trust are presented. The financial statements of the Trust are consolidated in the financial statements of SCE&G. The Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with SCE&G's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and SCE&G's obligations under the Indenture pursuant to which the Junior Subordinated Debentures were issued, provides a full and unconditional guarantee by SCE&G of the Trust's obligations under the Preferred Securities.
The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55% Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time. Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions.
10. INCOME TAXES
Total income tax expense attributable to income (before cumulative effects of accounting changes) for 2002, 2001 and 2000 is as follows:
Millions of dollars 2002 2001 2000 - -------------------------------------------------------------------------------- Current taxes: Federal $174.6 $91.2 $88.2 State 9.0 11.2 9.2 Foreign 1.0 - - - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total current taxes 184.6 102.4 97.4 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Deferred taxes, net: Federal (178.5) 182.5 29.8 State .8 1.7 4.7 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total deferred taxes (177.7) 184.2 34.5 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Investment tax credits: Deferred - State 5.0 5.0 5.0 Amortization of amounts deferred - State (1.7) (1.5) (1.3) Amortization of amounts deferred - Federal (4.0) (4.0) (4.0) - -------------------------------------------------------------------------------- Total investment tax credits (0.7) (0.5) (0.3) - -------------------------------------------------------------------------------- Non-conventional fuel tax credits: Deferred - Federal 29.8 18.7 9.4 - -------------------------------------------------------------------------------- Total income tax expense $36.0 $304.8 $141.0 ================================================================================
The difference between actual income tax expense and the amount calculated from the application of the statutory 35% federal income tax rate to pre-tax income (before cumulative effects of accounting changes) is reconciled as follows:
The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments:
o Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount.
o Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. For investments for which the fair value is not readily determinable, fair value is considered to approximate carrying value. The carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices.
o Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration.
Investments
SCANA and certain of its subsidiaries hold investments in marketable securities, some of which are subject to SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," mark-to-market accounting and some of which are considered cost basis investments for which determination of fair value historically has been considered impracticable. Equity holdings subject to SFAS 115 are categorized as "available for sale" and are carried at quoted market, with any unrealized gains and losses credited or charged to other comprehensive income (loss) within common equity on the Company's balance sheet. Debt securities and preferred stock with significant debt characteristics are categorized as "held to maturity" and are carried at amortized cost. When indicated, and in accordance with its stated accounting policy, SCANA performs periodic assessments of whether any decline in the value of these securities to amounts below SCANA's cost basis is other than temporary. When other than temporary declines occur, write-downs are recorded through operations, and new (lower) cost bases are established.
At December 31, 2002 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of SCANA, held investments in the equity and debt securities of the following companies in the amounts noted in the table below.
In 2002 SCH sold the 39.3 million shares it held in DTAG through a series of market transactions, receiving after-tax proceeds of approximately $433 million. In connection with these sales, SCH determined that the decline in value of its investment in DTAG was other than temporary, and SCH recorded impairment losses totaling approximately $182 million.
ITC Holding Company (ITC Holding) holds ownership interests in several Southeastern communications companies. As these securities are not actively traded, determination of their fair value is not practicable. ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services.
In June 2002 ITC^DeltaCom announced plans for a reorganization and entered into Chapter 11 bankruptcy. As a result the Company wrote off its investments in ITC^DeltaCom in the second quarter and recorded an aggregate impairment charge of approximately $7.0 million (after tax). The bankruptcy court accepted the reorganization plan, and ITC^DeltaCom emerged from bankruptcy on October 29, 2002. In connection with ITC^DeltaCom's emergence from bankruptcy, SCH provided $14.9 million in preferred equity financing. The common shares owned by SCH have a market value of $1.3 million, thus an unrealized gain of $0.2 million has been recorded in Other Comprehensive Income. The preferred shares owned by SCH are classified as held to maturity due to their debt features, and the market value is not readily determinable.
In July 2002 Knology negotiated a potential exchange of its Knology Broadband discount notes for a combination of new notes and new preferred stock. In contemplation of the anticipated exchange, the Company recorded an impairment loss of approximately $0.3 million (after-tax) in the second quarter. Because the exchange offer did not result in the requisite minimum tender of notes, in the third quarter Knology filed a prepackaged Chapter 11 bankruptcy plan which reflected the same terms of exchange. The bankruptcy court accepted the reorganization plan, and in connection with Knology's emergence from bankruptcy, SCH purchased an additional 6.5 million shares of series C preferred stock for approximately $19.5 million . The market value of Knology securities as of December 31, 2002 is not readily determinable.
Derivatives
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in the fair value of derivative instruments are either recognized in earnings or reported as a component of other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The fair value of the derivative instruments is determined by reference to quoted market prices of listed contracts, published quotations or quotations from independent parties.
Policies and procedures and risk limits are established to control the level of market, credit, liquidity and operational and administrative risks assumed by the Company. The Company's Board of Directors has delegated to a Risk Management Committee the authority to set risk limits, establish policies and procedures for risk management and measurement, and oversee and review the risk management process and infrastructure. The Risk Management Committee, which is comprised of certain officers, including the Company's Risk Management Officer, and senior officers of the Company, provides assurance to the Board of Directors with regard to the management of risk and brings to the Board's attention any areas of concern. Written policies define the physical and financial transactions that are approved, as well as the authorization requirements and limits for transactions that are allowed.
Commodities
The Company uses derivative instruments to hedge anticipated future purchases of natural gas, which create market risks of different types. Instruments designated as cash flow hedges are used to hedge risks associated with fixed price obligations in a volatile price market and risks associated with price differentials at different delivery locations. The basic types of financial instruments utilized are exchange-traded instruments, such as New York Mercantile Exchange futures contracts or options and over-the-counter instruments such as swaps, which are typically offered by energy and financial institutions.
As a result of adopting SFAS 133, the Company recorded a credit to other comprehensive income (loss) of approximately $23.0 million, net of tax, as the effect of the change in accounting principle (transition adjustment) on January 1, 2001. This amount represents the reclassification of unrealized gains that were deferred and reported as liabilities at December 31, 2000. Substantially all of this amount was reclassified into earnings in 2001 as a component of gas cost.
The Company recognized losses of approximately $20.6 million and $17.1 million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2002 and 2001, respectively. These losses were recorded in cost of gas. The Company estimates that most of the December 31, 2002 unrealized gain balance of $2.2 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2003 as a decrease to realized gas cost if market prices remain stable. As of December 31, 2002, all of the Company's cash flow hedges settle by their terms before the end of 2005.
SCPC's tariffs include a purchased gas adjustment (PGA) clause that provides for the recovery of actual gas costs incurred. The SCPSC has ruled that the results of SCPC's hedging activities are to be included in the PGA. As such, costs of related derivatives that SCPC utilizes to hedge its gas purchasing activities are recoverable through its weighted average cost of gas calculation. The offset to the change in fair value of these derivatives is recorded as a regulatory asset or liability.
The Company also utilizes certain derivative instruments that do not qualify as hedges. The change in fair value of these derivatives is recorded in net income (loss), and was insignificant in 2002, 2001 and 2000.
Interest Rates
The Company uses interest rate swap agreements to manage interest rate risk. These swap agreements provide for the Company to pay variable and receive fixed interest payments, and are designated as fair value hedges of certain debt instruments. The Company may terminate a swap agreement, and may replace it with a new swap also designated as a fair value hedge.
Payments received to terminate a swap are recorded as a basis adjustment to long term debt, and are amortized as reductions to interest expense over the term of the underlying debt. The fair value of interest rate swaps is reflected within other deferred debits on the balance sheet. The fair value of the debt that is hedged is recorded in long-term debt. Receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred.
The Company received payments to terminate swaps totaling $29.3 million and $6.5 million in 2002 and 2001, respectively. These amounts are being amortized over the ten year term of the underlying debt they formerly hedged. At December 31, 2002 the estimated fair value of the Company's swaps totaled $9.0 million related to combined notional amounts of $344.9 million.
12. COMMITMENTS AND CONTINGENCIES
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001 is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.
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 $9.5 billion. Each reactor licensee is currently liable for up to $88.1 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 $58.7 million per incident, but not more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is expected to renew with only modest changes in 2003. This has no impact on SCE&G at present due to the "grandfathered" status of existing licensees that are covered under the past act until such time as it is renewed.
SCE&G currently maintains policies (for itself and on behalf of Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.5 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 would have a material adverse impact on the Company's results of operations, cash flows and financial position.
C. Environmental
South Carolina Electric & Gas Company
At SCE&G, site assessment and cleanup costs are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million at December 31, 2002. The deferral includes the estimated costs associated with the following matters.
SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. SCE&G has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.
Public Service Company of North Carolina, Incorporated
PSNC Energy owns, or has owned, all or portions of seven sites in North Carolina on which MGPs were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. PSNC Energy's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties (PRP). In September 2002 an allocation agreement was reached relieving PSNC Energy of liability for two of the seven sites. PSNC Energy has recorded a liability and associated regulatory asset of $7.8 million, which reflects the estimated remaining liability at December 31, 2002. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.
D. Franchise Agreements
See Note 6 for a discussion of the electric and gas franchise agreements between SCE&G and the cities of Columbia and Charleston.
E. Claims and Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of SCANA filed suit against SCANA in South Carolina Circuit Court, seeking unspecified damages. The suit alleges the existence of a contract for the sale of assets to the plaintiff and various causes of action associated with that contract. The Company is confident in its position and intends to vigorously defend the lawsuit. The Company does not believe that the resolution of this issue will have a material impact on its results of operations, cash flows or financial position.
In 2001 the Company entered into, in the ordinary course of business, a 15 year take-and-pay contract with an unaffiliated natural gas supplier (Supplier) to purchase 190,000 DT of natural gas per day beginning in the spring of 2004. In December 2002, as a result of the failure of Supplier and its guarantor to meet contractual obligations related to credit support provisions, the Company terminated the contract. Attempts to negotiate a new contract between the parties were not successful. In February 2003, the Company received notification from Supplier of its request for binding arbitration under the original contract. The Company is confident of the propriety of its actions and will vigorously pursue its position in such arbitration proceedings. The Company further believes that the resolution of these claims will not have a material adverse impact on its results of operations, cash flows or financial condition.
The Company is also engaged in various other claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.
F. Operating Lease Commitments
The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2013. Rent expense totaled approximately $11.5 million, $12.1 million and $8.8 million in 2002, 2001 and 2000, respectively. Future minimum rental payments under such leases are as follows:
Millions of dollars 2003 $15.9 2004 12.3 2005 10.6 2006 10.0 2007 9.7 Thereafter 17.3 ------ $75.8
At December 31, 2002 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $11.5 million.
G. Purchase Commitments
Purchase commitments including those commitments under forward contracts for natural gas purchases, gas transportation capacity agreements and coal supply contracts are as follows:
Millions of dollars 2003 $1,249.2 2004 317.5 2005 145.5 2006 107.7 2007 93.0 Thereafter 604.8 $2,517.7
Forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts.
13. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are described below. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Nonregulated sales and transfers are recorded at current market prices.
Electric Operations is comprised of the electric portion of SCE&G, GENCO and Fuel Company and is primarily engaged in the generation, transmission and distribution of electricity. SCE&G's electric service territory extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. Sales of electricity to industrial, commercial and residential customers are regulated by the SCPSC. SCE&G is also regulated by FERC. GENCO owns and operates the Williams Station generating facility and sells all of its electric generation to SCE&G. GENCO is regulated by FERC. Fuel Company acquires, owns and provides financing for the fuel and emission allowances required for the operation of SCE&G and GENCO generation facilities.
Gas Distribution, comprised of the local distribution operations of SCE&G and PSNC Energy, is engaged in the purchase and sale, primarily at retail, of natural gas. SCE&G's operations extend to 33 counties in South Carolina covering approximately 22,000 square miles. PSNC Energy's operations cover 27 counties in North Carolina and approximately 12,000 square miles. Gas Transmission is comprised of SCPC, which is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies (including SCE&G), and directly to industrial customers in 40 counties throughout South Carolina. SCPC also owns LNG liquefaction and storage facilities. Both of these segments are regulated in their respective states of operations.
Retail Gas Marketing markets natural gas in Georgia's restructured natural gas market. Energy Marketing markets electricity and natural gas to industrial, large commercial and wholesale customers, primarily in the Southeast.
Telecommunications Investments holds investments in telecommunication companies.
The Company's regulated reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However Electric Operations' product differs from the other segments, as does its generation process and method of distribution. The gas segments differ from each other primarily based on the class of customers each serves and the marketing strategies resulting from those differences. The marketing segments differ from each other primarily based on their respective markets and customer type.
Revenues and assets from segments below the quantitative thresholds are attributable to SCE&G's transit operations, which are regulated by the SCPSC, and to ten other direct and indirect wholly owned subsidiaries of the Company. These subsidiaries conduct nonregulated operations in energy-related and telecommunications industries. None of these subsidiaries met any of the quantitative thresholds for determining reportable segments in 2002, 2001 or 2000.
Management uses operating income to measure segment profitability for regulated operations. For nonregulated operations management uses net income (loss) for this purpose. Accordingly, SCE&G does not allocate interest charges or income tax expense (benefit) to the Electric Operations or Gas Distribution segments. Similarly, management evaluates utility plant for segments attributable to SCE&G and total assets for SCE&G as a whole, as well as for other operating segments. Therefore, SCE&G does not allocate accumulated depreciation, common and non-utility plant, or deferred tax assets to reportable segments. However GENCO and PSNC Energy do have interest charges, income taxes and deferred tax assets, which are included in Electric Operations and Gas Distribution, respectively. Interest income is not reported by segment and is not material. For 2002 and 2000, adjustments to net income and income tax expense include the cumulative effects of the accounting changes described in Note 2.
The Consolidated Financial Statements report operating revenues which are comprised of the energy-related reportable segments. Revenues from non-reportable segments and investment income from Telecommunications Investments are included in Other Income. Therefore the adjustments to total revenue remove revenues from non-reportable segments. Adjustments to Net Income consist of SCE&G's unallocated net income.
Segment assets include utility plant only (excluding accumulated depreciation) for SCE&G's Electric Operations, Gas Distribution and Transit Operations, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include accumulated depreciation, common and non-utility plant and non-fixed assets for SCE&G.
Adjustments to Interest Expense, Income Tax Expense (Benefit), Deferred Tax Assets and Expenditures for Assets include primarily the totals from SCANA or SCE&G that are not allocated to the segments. Interest Expense is also adjusted to eliminate inter-affiliate charges. Adjustments to depreciation and amortization consist of non-reportable segment expenses, which are not included in the depreciation and amortization reported on a consolidated basis. Deferred Tax Assets are also adjusted to remove the non-current portion of those assets. Expenditures for Assets are also adjusted for AFC.
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
(1) The cumulative effect of accounting change is attributable to the adoption of SFAS 142. The amount of the cumulative effect was finalized in the fourth quarter 2002 and, as prescribed in the standard, was recorded effective January 1, 2002. See Note 1G.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................... 90
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..........103
Item 8. Financial Statements and Supplementary Data.........................103
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements included in this discussion and analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in SCE&G's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions, especially in areas served by SCE&G, (9) performance of SCANA Corporation's pension plan assets and the impact on SCE&G's results of operations, (10) inflation, (11) changes in environmental regulations and (12) the other risks and uncertainties described from time to time in SCE&G's periodic reports filed with the SEC. SCE&G disclaims any obligation to update any forward-looking statements.
COMPETITION
Electric Operations
In South Carolina, electric restructuring efforts remain stalled, and consideration of electric restructuring legislation is unlikely in 2003. Further, while several companies have announced their intent to site merchant generating plants in SCE&G's service territory, economic events, environmental concerns and other factors have slowed those efforts. In view of the potential for deregulation, SCE&G has continued efforts to renew franchise agreements with municipalities within its current service area. Effective October 2002, SCE&G secured a 30-year franchise to provide the City of Columbia, South Carolina, with electric and natural gas services. Columbia is one of the largest cities in SCE&G's service area. Previously, SCE&G reached franchise agreements with the cities of North Charleston (franchise expires in 2021), Charleston (franchise expires in 2026) and numerous other municipalities. In addition, in May 2001 SCE&G signed an electric supply contract with North Carolina Electric Membership Corporation to supply 350 MW in each of 2004 and 2005 and 250 MW annually in 2006 through 2012. These energy sales are recallable for our native load, if necessary.
At the federal level, energy legislation passed both houses of Congress in 2002, though significant differences between the House and Senate versions were not reconciled before the legislative session adjourned. Some of the more stringent provisions of this legislation would have required, among other things, that one percent of the electric energy sold by retail electric suppliers, beginning in 2005, escalating to ten percent in 2019, be generated from renewable energy resources. Renewable energy resources, as defined in some versions of the legislation, would have excluded hydroelectric generation. Substantial penalties would have been levied for failure to comply. Electric cooperatives and municipal utilities would have been exempt from these requirements. SCE&G expects similar legislation will be introduced in Congress in 2003. SCE&G cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.
In June 2002 implementation of GridSouth Transco LLC (GridSouth) was suspended pending the issuance and evaluation of new FERC directives. In July 2002 FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant change to the NOPR may occur and that implementation, presently scheduled for September 2004, may be delayed, any rules standardizing the markets may have a significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. SCE&G is currently evaluating this NOPR to determine what effect it will have on SCE&G's operations. Additional directives from FERC are expected in 2003.
Gas Distribution
SCE&G has secured franchise agreements with several municipalities within its current service areas to provide natural gas services. See previous discussion at Electric Operations. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact SCE&G's ability to retain large commercial and industrial customers on a monthly basis.
LIQUIDITY AND CAPITAL RESOURCES
SCE&G's cash requirements arise primarily from its operational needs, funding its construction program and payment of dividends to SCANA. The ability of SCE&G to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. SCE&G recovers 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 SCE&G continues its ongoing construction program, SCE&G expects to seek increases in rates. SCE&G's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief, if requested.
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
The estimated primary cash requirements for 2003 and the actual primary cash requirements for 2002, excluding requirements for non-nuclear fuel purchases, short-term borrowings and dividends, and including notes payable to affiliated companies, are as follows:
Millions of dollars 2003 2002 - -------------------------------------------------------------------------------
Property additions and construction expenditures, net of AFC $619 $575 Nuclear fuel expenditures 30 13 Investments 20 9 Maturing obligations, redemptions and sinking and purchase fund requirements 107 170 - ------------------------------------------------------------------------------- Total $776 $767 ===============================================================================
Approximately 33% of total cash requirements was provided from internal sources in 2002 as compared to 68% in 2001.
SCE&G's contractual cash obligations as of December 31, 2002 are summarized as follows:
Included in other commercial commitments are estimated obligations for coal supply purchases. Actual purchases are included in fuel used in electric generation and recovered through electric rates.
SCE&G anticipates that its contractual cash obligations will be met through internally generated funds and the incurrence of additional short-term and long-term indebtedness. SCE&G expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the foreseeable future.
Financing Limits and Related Matters
SCE&G's issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including SCPSC and the SEC. The following paragraphs describe the financing programs currently utilized by SCE&G.
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 18 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, 2002 the Bond Ratio was 5.51. The Old Mortgage allows the issuance of Class A Bonds up to an additional principal amount equal to (i) 70% of unfunded net property additions (which unfunded net property additions totaled approximately $522 million at December 31, 2002), (ii) retirements of Class A Bonds (which retirement credits totaled $187.2 million at December 31, 2002), and (iii) cash on deposit with the Trustee.
SCE&G is also subject to a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are 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. At December 31, 2002 approximately $1.3 billion Class A Bonds were on deposit with the Trustee of the New Mortgage and are available to support the issuance of additional 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, 2002 the New Bond Ratio was 5.36.
SCE&G's Restated Articles of Incorporation (the Articles) prohibit issuance of additional shares of preferred stock without the consent of the preferred shareholders 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 on all shares of preferred stock outstanding immediately after the proposed issue (Preferred Stock Ratio). For the year ended December 31, 2002 the Preferred Stock Ratio was 1.72.
The Articles also require the consent of at least a majority of the total voting power of SCE&G's preferred stock before SCE&G may issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed ten percent of the aggregate principal amount of all of SCE&G's secured indebtedness and capital and surplus (the ten percent test). No such consent is required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes. At December 31, 2002 the ten percent test would have limited issuances of unsecured indebtedness to approximately $366.7 million. Unsecured indebtedness at December 31, 2002 totaled approximately $127.6 million.
At December 31, 2002 SCE&G had $250 million of unused committed lines of credit comprised of $175 million, expiring in 2003 and $75 million expiring in 2005. These lines of credit support the issuance of commercial paper. SCE&G's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.40% and 1.95%, respectively. On January 8, 2003 a credit agreement was reached allowing SCE&G to share an existing $78 million SCANA uncommitted line of credit. In addition, Fuel Company has a credit agreement for a maximum of $125 million expiring in 2003 with the full amount available at December 31, 2002. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding totaled $50.1 million at December 31, 2002 and 2001, at weighted average interest rates of 1.38% and 2.06%, respectively. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G.
During the formation of GENCO in 1994, SCE&G's $36 million Berkeley County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition, holders of Berkeley Bonds may have recourse against SCE&G in the event of default by GENCO.
Financing Transactions
The following financing transactions have occurred since January 1, 2002:
o On January 31, 2002 SCE&G issued $300 million of first mortgage bonds having an annual interest rate of 6.625% and maturing February 1, 2032. The proceeds from the sale of these bonds were used to reduce short-term debt primarily incurred as a result of SCE&G's construction program and to redeem on March 11, 2002 its $103.5 million First and Refunding Mortgage Bonds, 8 7/8% Series due August 15, 2021.
o On October 17, 2002 SCE&G received an equity contribution of $150 million from SCANA, which was used to pay off short-term debt primarily incurred as a result of SCE&G's construction program .
o On November 8, 2002 the South Carolina Jobs - Economic Development Authority (JEDA) issued, and SCE&G borrowed the proceeds of, an aggregate of $90.4 million principal amount of tax-exempt Industrial revenue bonds (the Bonds). The Bonds bear interest at rates ranging from 4.2% to 5.45%, with maturities ranging from 2012 to 2032. Proceeds from the Bonds were used to refund an aggregate amount of $62.3 million principal amount of pollution control revenue Bonds and to pay the costs of solid waste disposal facilities at two of SCE&G's electric generating plants.
o On January 23, 2003 SCE&G issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.
Other Information
SCE&G placed in service a $264 million gas turbine generator project in Aiken County, South Carolina in June 2002. Two combined-cycle turbines burn natural gas to produce 341 MW of new electric generation and use exhaust heat to replace coal-fired steam that powers two existing 75 MW turbines at the Urquhart Generating Station.
In May 2002 SCE&G began construction of an 875 MW generation facility in Jasper County, South Carolina, to supply electricity to its South Carolina customers. The facility will include three natural gas combustion-turbine generators and one steam-turbine generator. The $450 million facility is expected to begin commercial operation in mid-2004 and SCG Pipeline, Inc., an affiliate, will transport natural gas to the facility.
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.
In 2002 SCE&G entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows SCE&G to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the above Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At December 31, 2002 SCE&G had not yet borrowed under the agreement.
ENVIRONMENTAL MATTERS
Electric Operations
The Clean Air Act Amendments of 1990 (CAA) required electric utilities to reduce emissions of sulfur dioxide and nitrogen oxides (NOx) substantially by the year 2000. SCE&G remains in compliance with these requirements. In 1998 the EPA required the State of South Carolina, among other states, to modify its state implementation plan (SIP) to address the issue of NOx pollution. The State's SIP requires additional emissions reductions in 2004 and beyond. Further, the EPA has indicated that it will propose regulations by December 2003 for stricter limits on mercury and other toxic pollutants generated by coal-fired plants. To comply with these state and federal regulations, SCE&G expects to incur capital expenditures of approximately $22 million over the 2003-2007 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1 million per year. To meet compliance requirements for the years 2008 through 2012, SCE&G anticipates additional capital expenditures of approximately $70 million.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the Department of Justice has brought suit against a number of utilities in federal court alleging violations of the CAA. Prior to the suits, those utilities had received requests for information under Section 114 of the CAA and were issued Notices of Violation. The basis for these suits is the assertion by the EPA that maintenance activities undertaken by the utilities over the past 20 or more years constitute "major modifications" which would have required the installation of costly Best Available Control Technology (BACT). The Company and SCE&G have received and responded to Section 114 requests for information related to Canadys, Wateree and Williams Stations. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including an exemption for routine repair, replacement or maintenance. SCE&G has analyzed each of the activities covered by the EPA's requests and believes each of these activities is covered by the exemption for routine repair, replacement and maintenance. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. It is possible that the EPA will commence enforcement actions against SCE&G, and the EPA has the authority to seek penalties at the rate of up to $27,500 per day for each violation. The EPA also could seek installation of BACT (or equivalent) at the three plants. SCE&G believes that any assertions relative to the Company's and SCE&G's compliance with the CAA would be without merit. However, if successful, such assertions could have a material adverse effect on SCE&G's financial position, cash flows and results of operations.
The Clean Water Act, as amended, provides for the imposition of effluent limitations that require treatment for wastewater discharges. 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 generating units. Concurrent with renewal of these permits, the permitting agency has implemented a more rigorous program of monitoring and controlling thermal discharges and strategies for toxicity reduction in wastewater streams. SCE&G is developing compliance plans for these initiatives. Congress is expected to consider further amendments to the Clean Water Act in 2003. Such legislation may include limitations to mixing zones, the implementation of technology-based standards for main condenser cooling water including intake and discharge structures and toxicity-based standards. These provisions, if passed, could have a material impact on the results of operations and cash flows of SCE&G.
Gas Distribution
SCE&G maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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 solely to regulated operations and are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. The deferral includes the estimated costs associated with the following matters:
o SCE&G owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. SCE&G anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, SCE&G has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
o SCE&G owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. SCE&G is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. SCE&G anticipates that major remediation activities for these three sites will be completed before 2006. SCE&G has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.
REGULATORY MATTERS - STATE
Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, SCE&G may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on SCE&G's results of operations in the period the write-off would be recorded. It is expected that cash flows and the financial position of SCE&G would not be materially affected by the discontinuation of the accounting treatment. SCE&G reported approximately $262 million and $109 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $123 million and $37 million, respectively, on its balance sheet at December 31, 2002.
SCE&G's generation assets would be exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, SCE&G could be required to write down its investment in these assets. SCE&G cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect SCE&G's results of operations in the period in which they would be recorded. As of December 31, 2002, SCE&G's net investment in fossil and hydro and nuclear generation assets was approximately $1,731 million and $546 million, respectively.
SCE&G is subject to the jurisdiction of the SCPSC as to retail electric and gas rates, service, accounting, issuance of securities (other than short-term borrowings) and other matters.
Electric
In January 2003 the SCPSC issued an order granting SCE&G an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, SCE&G may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually, without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
On December 31, 2002 the SCPSC issued an order approving SCE&G's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart Generating Station in 2002. As a result, SCE&G transferred approximately $12.5 million from fuel used in electric generation to electric utility plant.
In May 2002 the SCPSC issued an order approving SCE&G's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of SCE&G's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the retail rate increase, the SCPSC approved SCE&G's request to reduce the fuel component to 1.678 cents per KWh.
Gas
SCE&G's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by SCE&G.
SCE&G's cost of gas component in effect during the years ended December 31, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001 $.728 November-December 2002 $.793 March-October 2001 $.596 November-December 2001
In March 2003 the SCPSC issued an order approving SCE&G's request for an out-of-period adjustment to increase the cost of gas component of its rates for natural gas service from .728 cents per therm to .928 cents per therm, effective with the first billing cycle in March 2003.
In 1994 the SCPSC 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 MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for SCE&G's gas operations that had previously been deferred. In October 2002, as a result of the annual review, the SCPSC reaffirmed SCE&G's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.
Transit
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, SCE&G will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. SCE&G will continue to operate the plant for the City until 2005. SCE&G will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility. The cost of the franchise agreement is recorded in other regulatory assets.
REGULATORY MATTERS - FEDERAL
SCE&G's regulated business operations were impacted by FERC Order No. 2000 and other related initiatives of the FERC. Order No. 2000 required each utility under FERC jurisdiction that operates an electric transmission system to submit plans for the possible formation of a regional transmission organization. In March 2001 FERC gave provisional approval to SCE&G and two other southeastern electric utilities to establish GridSouth as an independent regional transmission company, responsible for operating and planning the utilities' combined transmission systems. In June 2002 GridSouth implementation was suspended pending the issuance and evaluation of new FERC directives.
In July 2002 FERC issued a NOPR on Standard Market Design which proposes sweeping changes to the country's existing regulatory framework governing transmission, open access and energy markets and which will attempt, in large measure, to standardize the national energy market. While it is anticipated that significant changes to the NOPR may occur and that implementation, presently scheduled for September 2004, may not occur for some time, any rules standardizing the markets may have significant impact on SCE&G's access to or cost of power for its native load customers and on SCE&G's marketing of power outside its service territory. SCE&G is currently evaluating this NOPR to determine what effect it will have on SCE&G's operations. Additional directives from FERC are expected later in 2003.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of SCE&G's accounting policies which are new or most critical in terms of reporting financial condition or results of operations.
SFAS 71 - SCE&G is subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. At December 31, 2002 SCE&G had recorded approximately $262 million and $109 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities. Management believes the regulatory assets are recoverable through rates. The SCPSC has reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by SCE&G. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, SCE&G may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of SCE&G's Electric Distribution and Gas Distribution segments in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected.
Certain of SCE&G's regulatory assets and liabilities arise from its environmental assessment program, which identifies and evaluates current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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. Regulatory assets and liabilities related to environmental cleanup affect primarily the Gas Distribution segment and are due to the costs associated with current and former MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, we record estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2002 and 2001, accounts receivable include unbilled revenues of $43.9 million and $39.1 million, respectively. Total revenues for 2002 and 2001 were $1.68 billion and $1.72 billion, respectively.
Allowance for Funds Used During Construction (AFC) - AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and is depreciated as a component of plant cost in establishing rates for utility services. SCE&G calculated AFC using composite rates of 7.8%, 8.8% and 8.1% for 2002, 2001 and 2000, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred. AFC primarily affects the Electric Operations segment due to its capital-intensive construction program, and to a lesser extent, AFC affects the Gas Distribution segment. AFC represented approximately 9.4% of income before income taxes in 2002, 6.5% in 2001 and 1.7% in 2000. Because the equity component of AFC is not taxable, increased AFC reduces SCE&G's effective tax rate. See Results of Operations for additional discussion.
Provisions for Bad Debts and Allowances for Doubtful Accounts - As of each balance sheet date, SCE&G evaluates the collectibility of accounts receivable and records allowances for doubtful accounts based on estimates of the level of actual write-offs which might be experienced. These estimates are based on, among other things, comparisons of the relative age of accounts and consideration of actual write-off history. SCE&G's Electric Distribution and Gas Distribution segments have an established write-off history and a regulated service area that enables it to reliably estimate its provision for bad debts.
Nuclear Decommissioning - Accounting for decommissioning costs for nuclear power plants involves significant estimates related to costs to be incurred many years in the future. Among the factors that could change SCE&G's accounting estimates related to decommissioning costs are changes in technology, changes in regulatory and environmental remediation requirements, as well as changes in financial assumptions such as discount rates and timing of cash flows. See also the discussion of SCE&G's adoption of SFAS 143, "Accounting for Asset Retirement Obligations," below. Changes in any of these estimates could significantly impact SCE&G's financial position and cash flows (although changes in such estimates should be earnings-neutral, because these costs are expected to be collected from ratepayers).
SCE&G's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the NRC under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.
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 are used to pay premiums on insurance policies on the lives of certain Company and affiliate personnel. SCE&G is the beneficiary of these policies. Through these insurance contracts, SCE&G is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. 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. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
Pension Accounting - SCE&G follows SFAS 87, "Employers' Accounting for Pensions," in accounting for its defined benefit pension plan. SCE&G's plan is fully funded and as such, net pension income is reflected in the financial statements (see Results of Operations). SFAS 87 requires the use of several assumptions, the selection of which may have a large impact on the resulting benefit recorded. Among the more sensitive assumptions are those surrounding discount rates and returns on assets. Net pension income of $25.5 million recorded in 2002 reflects the use of a 7.5% discount rate and an assumed 9.5% long-term return on plan assets. SCE&G believes that these assumptions were, and that the resulting pension income amount was, reasonable.
Due to poor performance in the stock market in recent years, SCE&G has determined to adjust its assumed long-term return on assets to 9.25% for 2003. Lower interest rates have also led to a reduction in the discount rate as of December 31, 2002 to 6.5%. Had those assumptions been in place in 2002, net pension income would have been reduced by approximately $5.2 million.
In determining the appropriate discount rate, SCE&G considers the market indices of high-quality long-term fixed income securities. As such, SCE&G selected the above discount rate of 6.5% as being within a reasonable range of Moodys "Aa" interest rate as of December 31, 2002. This same discount rate was also selected for determination of OPEB liabilities discussed below.
The following information with respect to pension assets should also be noted:
SCE&G determines the fair value of substantially all of its pension assets utilizing market quotes rather than utilizing any calculated values, "market related" values or other modeling techniques. In developing the expected long-term rate of return assumptions, SCE&G evaluated input from actuaries and from pension fund investment advisors, including such advisors' review of the plan's historical 10, 16 and 24 year cumulative actual returns of 10.15%, 10.80% and 12.32%, respectively, which have all been in excess of related broad indices. SCE&G anticipates that the investment managers will continue to generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While management believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to the targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate have significantly reduced the level of pension income, the pension trust has been and remains adequately funded, and no contributions have been required since 1997. As such, recent declines in pension income have had no impact on SCE&G's cash flows. Based on stress testing performed by SCE&G's actuaries, management does not anticipate the need to make pension contributions until at least 2008.
Accounting for Postretirement Benefits other than Pensions - Similar to its pension accounting, SCE&G follows SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," in accounting for its postretirement medical and life insurance benefits. This plan is unfunded, so no assumptions related to return on assets impact the net expense recorded; however, the selection of discount rates can significantly impact the actuarial determination of net expense. SCE&G used a discount rate of 7.5% and recorded a net SFAS 106 cost of $13.6 million for 2002. Had the selected discount rate been 6.5%, the expense would have been approximately $0.9 million higher.
SFAS 143 - SFAS 143 provides guidance for recording and disclosing liabilities related to the future obligations to retire assets (ARO). SFAS 143 applies to the legal obligation associated with the retirement of long-lived tangible assets that result from acquisition, construction, development and normal operations. SCE&G adopted SFAS 143 effective January 1, 2003. Because such obligation relates solely to SCE&G's regulated electric operations, adoption of SFAS 143 will have no impact on results of operations; however, SCE&G will record an ARO of approximately $110 million, which exceeds the previously recorded reserve for nuclear plant decommissioning of approximately $87 million.
In addition to the ARO for Summer Station, SCE&G believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. SCE&G believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.
SCE&G records cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, SCE&G estimates that approximately $225 million of its accumulated depreciation balance is related to this regulatory liability.
OTHER MATTERS
Synthetic Fuel Investments
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel, the use of which fuel qualifies for federal income tax credits. The aggregate investment in these partnerships as of December 31, 2002 is approximately $2 million, and through December 31, 2002, they had generated and passed through to SCE&G approximately $58 million in such tax credits. Under a plan approved by the SCPSC, any tax credits generated and ultimately passed through to SCE&G from synfuel produced and consumed by SCE&G have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions. See Note 1B of Notes to Consolidated Financial Statement.
Nuclear License Extension
In August 2002 SCE&G filed an application with the NRC for a 20-year license extension for its Summer Station. If approved, the extension would allow the plant to operate through 2042. SCE&G estimates that it will incur approximately $12 million in costs related to the application process.
Claims and Litigation
SCE&G is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to SCE&G.
RESULTS OF OPERATIONS
Net Income
Net income and the percent change from the previous year for the years 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000 - ------------------------------------------------ ------------- ---------------- Net income derived from: Continuing operations $219.6 $221.9 $231.3 Cumulative effect of accounting change, net of taxes - - 22.3 - ---------------------------------------------------------- -------------- ----- Net income $219.6 $221.9 $253.6 ========================================================== ============== ===== Percent increase (decrease) in net income 34.04% (1.04%) (12.50%) ========================================================== ============== =====
o 2002 vs 2001 Net income decreased primarily due to higher operations and maintenance expenses of $30.4 million (including $10.1 million due to lower pension income), higher property taxes of $6.5 million, and higher interest expense of $4.7 million, which were partially offset by higher electric margins of $37.3 million.
o 2001 vs 2000 Net income decreased primarily as a result of milder weather.
Pension Income
For the last several years, the market value of SCE&G's retirement plan (pension) assets has exceeded the total actuarial present value of accumulated plan benefits. However, pension income for 2002 decreased significantly compared to 2001 and 2000, primarily as a result of a less favorable investment market. Pension income during these periods, excluding amounts attributable to Santee Cooper and affiliates (see Note 4) was recorded on SCE&G's financial statements as follows:
Millions of dollars 2002 2001 2000 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Income Statement Impact: Reduction in employee benefit costs $10.5 $20.7 $20.9 Increase in other income 11.2 12.7 12.9 Balance Sheet Impact: Reduction in capital expenditures 3.1 5.9 5.7 Increase in amount due to Santee Cooper .7 1.8 2.0 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Total Pension Income $25.5 $41.1 $41.5 ==========================================================================
See also the discussion of pension accounting in Critical Accounting Policies and New Accounting Standards.
Allowance for Funds Used During Construction (AFC)
SCE&G's financial statements include the effects of the recording of an 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 9.4% of income before income taxes in 2002, 6.5% in 2001 and 1.7% in 2000.
Dividends Declared
SCE&G's Board of Directors declared the following dividends on common stock (all of which is held by SCANA) during 2002:
------------------- ------------------ -------------------- ----------------- Declaration Date Dividend Amount Quarter Ended Payment Date ------------------- ------------------ -------------------- -----------------
February 21, 2002 $34.0 million March 31, 2002 April 1, 2002 May 2, 2002 $38.0 million June 30, 2002 July 1, 2002 August 1, 2002 $40.5 million September 30, 2002 October 1, 2002 October 31, 2002 $40.5 million December 31, 2002 January 1, 2003 ------------------- ------------------ -------------------- -----------------
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and Fuel Company. Electric operations sales margins for 2002, 2001 and 2000, excluding the cumulative effect of accounting change in 2000, were as follows:
Millions of dollars 2002 2001 2000 - ---------------------------------------------- -------------- --------------
Operating revenues $1,384.8 $1,374.0 $1,343.8 Less: Fuel used in generation (257.5) (223.9) (231.6) Purchased power (151.6) (233.9) (182.7) - ---------------------------------------------- -------------- -------------- Margin $975.7 $916.2 $929.5 ============================================== ============== ==============
o 2002 vs 2001 Margins increased $31.9 million due to more favorable weather and $30.5 million due to customer growth. Fuel used in generation increased and purchased power decreased due to completion of the Urquhart Station repowering project in June 2002 and fewer plant outages during 2002.
o 2001 vs 2000 Sales margin decreased $32.1 million due to milder weather and $12.6 million due to the impact of the slowing economy. These decreases were partially offset by $25.6 million from customer growth.
Increases (decreases) from the prior year in MWh sales volume by classes were as follows:
o 2002 vs 2001 Territorial sales volume increased primarily due to more favorable weather. The decrease in NMST volumes reflects SCE&G's recording of buy-resale transactions in Other Income in 2002.
o 2001 vs 2000 Territorial sales volume decreased primarily due to milder weather.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G. Gas distribution sales margins for 2002, 2001 and 2000 were as follows:
Millions of dollars 2002 2001 2000 --------------------------------------------- -------------- ---------------
Operating revenues $298.2 $341.0 $325.1 Less: Gas purchased for resale (211.1) (251.6) (233.8) --------------------------------------------- -------------- --------------- Margin $87.1 $89.4 $91.3 ============================================= ============== ===============
Sales margin decreased slightly over the three-year period primarily as a result of the slowing economy and increased competition with alternate fuels.
Increases (decreases) from the prior year in DT sales volume by classes, including transportation gas were as follows:
Classification (in thousands) 2002 % Change 2001 % Change - ---------------------------------------- --------------------------- ---------- Residential 985.9 8.8% (3,249.4) (22.4%) Commercial 412.7 3.7% (1,511.4) (11.8%) Industrial 1,637.3 11.4% (2,828.1) (16.5%) Transportation gas (87.6) (3.6%) 375.4 18.0% -- ------ --- ----- - ----------------------------- Total 2,948.3 7.5% (7,213.5) (15.5%) ===================================================== ============= ===========
o 2002 vs 2001 Residential and commercial sales volume increased primarily due to more favorable weather. Industrial volumes increased in 2002 after the volatility of the natural gas market in 2001 had resulted in interruptible customers using their alternate fuel sources during that year.
o 2001 vs 2000 Residential sales volumes decreased due to higher gas prices. Industrial and transportation gas decreased due to the volatility of the natural gas market resulted in interruptible customers using alternate fuel sources.
Other Operating Expenses
Increases in other operating expenses were as follows:
Millions of dollars 2002 % Change 2001 % Change - ----------------------------------------- ------------------------------------
Other operation and maintenance $50.9 16.1% $7.0 2.3% Depreciation and amortization 7.1 4.4% 5.1 3.2% Other taxes 10.0 10.1% 1.5 1.5% - ----------------------------------------- ---------- Total $68.0 11.8% $13.6 2.4% ========================================= ====================================
o 2002 vs 2001 Other operation and maintenance expenses increased primarily due to lower pension income of $10.1 million, increased labor and benefits of $19.4 million, increased nuclear refueling maintenance of $4.0 million, increased cost at Cogen South of $3.1 million, higher property insurance of $2.6 million, increased amortization of environmental costs of $3.0 million and increased storm damage expenses of $1.8 million. Depreciation and amortization increased primarily due to completion of the Urquhart Station repowering project in June 2002 of $4.8 million and normal net property additions of $2.2 million. Other taxes increased primarily due to increased property taxes.
o 2001 vs 2000 Other operation and maintenance expenses increased primarily as a result of increases in employee benefit costs. Depreciation and amortization increased primarily as a result of normal increases in utility plant. Other taxes increased primarily due to increased property taxes.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of AFC, were as follows:
Millions of dollars 2002 % Change 2001 % Change - ----------------------------------------------------------------------------
Interest on long-term debt, net $9.1 8.1% $12.0 11.9% Other interest expense 1.3 22.8% (2.4) (29.6%) - ----------------------------------------- ---------- Total $10.4 8.8% $9.6 8.8% ============================================================================
Interest expense in 2002 increased by $11.9 million as a result of increased borrowings, and was partially offset by $2.8 million as a result of declining interest rates. Interest expense in 2001 increased as a result of increased borrowings.
Income Taxes
Income taxes decreased approximately $10.1 million for the year 2002 compared to 2001 and decreased approximately $9.8 million for the year ended 2001 compared to 2000. Changes in income taxes are primarily due to changes in operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for purposes other than trading.
Interest rate risk - The tables below provide information about long-term debt issued by SCE&G which is sensitive to changes in interest rates. For debt obligations the tables present principal cash flows and related weighted average interest rates by expected maturity dates. Fair values for debt represent quoted market prices.
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page
Independent Auditors' Report.............................................. 104
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001.......... 105
Consolidated Statements of Income for years ended December 31, 2002, 2001 and 2000 ............................................ 107
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000 .................................. 108
Consolidated Statements of Capitalization as of December 31, 2002 and 2001...,............................................ 109
Consolidated Statements of Common Equity for the years ended December 31, 2002, 2001 and 2000 ............................ 110
Notes to Consolidated Financial Statements............................ 111
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of South Carolina Electric & Gas Company (Company) as of December 31, 2002 and 2001 and the related Consolidated Statements of Income, Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2002 and 2001 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2000, the Company changed its method of accounting for operating revenues.
s/Deloitte & Touche LLP Columbia, South Carolina February 7, 2003
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
South Carolina Electric & Gas Company (Company), a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation, a South Carolina corporation and a registered public utility holding company within the meaning of the Public Utility Holding Company Act of 1935, as amended (PUHCA). The Company is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements reflect the accounts of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust I. Intercompany balances and transactions between the Company, Fuel Company and SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from South Carolina Pipeline Corporation (SCPC), and at December 31, 2002 and 2001, the Company had approximately $29.6 million and $23.0 million, respectively, payable to SCPC for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by South Carolina Generating Company (GENCO), under a unit power sales agreement. At December 31, 2002 and 2001 the Company had approximately $9.0 million and $9.5 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $109.5 million, $95.8 million and $100.2 million in 2002, 2001 and 2000, respectively.
Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $0.4 million, $0.7 million and $1.1 million in 2002, 2001 and 2000, respectively.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 2002, approximately $262 million and $109 million of regulatory assets and liabilities, respectively, as shown below.
December 31, Million of dollars 2002 2001 - ------------------------------------------------------------- --------------- - ------------------------------------------------------------- --------------- Accumulated deferred income taxes, net $86 $86 Under- (over-) collections - Electric Fuel and Gas Cost Adjustment Clause 50 60 Deferred environmental remediation costs 18 24 Deferred non-conventional fuel tax benefits, net (40) (17) Storm damage reserve (32) (26) Franchise agreements 64 - Other 6 9 - ------------------------------------------------------------- --------------- - ------------------------------------------------------------- --------------- Total $152 $136 ============================================================= ===============
Accumulated deferred income taxes represent deferred income tax liabilities applicable to utility operations that have not been reflected in customer rates fro which future recovery is probable, offset by deferred income tax assets, which will be reflected in customer rates as a result of reduced revenue requirements due to the amortization of deferred investment tax credits.
Under- (over-) collections - fuel adjustment clauses represent amounts over- or under-collected from customers pursuant to the fuel adjustment clause (electric customers) or gas cost adjustment (gas customers) as approved by the Public Service Commission of South Carolina (SCPSC) during annual hearings (see Note 1F).
Deferred environmental remediation costs represent costs associated with the assessment and clean up of environmental sites at manufactured gas plant sites currently or formerly owned by the Company. Costs incurred at sites owned by the Company are being recovered through rates, and such costs, totaling approximately $18 million are expected to be fully recovered by the end of 2005.
Deferred non-conventional fuel tax benefits represent the deferral of partnership losses and other expenses, offset by the accumulated deferred income tax credits associated with two of the Company's partnerships involved in converting coal to alternate fuel. Under a plan approved by the SCPSC, any net tax credits generated from non-conventional fuel produced and consumed by the Company and ultimately passed through to the Company have been and will be deferred and will be applied to offset the capital costs of projects required to comply with legislative or regulatory actions.
The storm damage reserve represents an SCPSC approved reserve account capped at $50 million to be collected through rates over a ten-year period. The accumulated storm damage reserve can be applied to offset actual storm damage costs in excess of $2.5 million in a calendar year.
Franchise agreements represent costs associated with the 30-year electric and gas franchise agreements with the cities of Charleston and Columbia, South Carolina.
The SCPSC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the SCPSC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to SCPSC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the SCPSC.
D. Utility Plant and Major Maintenance
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.
The Company, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (Santee Cooper) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company's portion of Summer Station was approximately $962.4 million and $963.0 million as of December 31, 2002 and 2001, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $417.9 million and $407.4 million as of December 31, 2002 and 2001, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses and totaled approximately $76.4 million for the year ended December 31, 2002.
Planned major maintenance other than that related to nuclear outages is expensed when incurred. The only major maintenance that is accrued in advance of the time the costs are actually incurred is that related to the nuclear refueling outages for which such accounting treatment and rate recovery of expenses accrued thereunder has been approved by the SCPSC. Nuclear outages are scheduled 18 months apart, and SCE&G begins accruing for each successive outage immediately upon completion of the preceding outage. For the outage ended June 2002, the Company accrued approximately $0.5 million per month from January 2001 through June 2002 and is now accruing approximately $0.6 million per month for its portion of the outage scheduled in October 2003. Total outage costs for the planned outage in October 2003 are estimated to be approximately $17 million, of which the Company will be responsible for approximately $11.3 million. As of December 31, 2002, the Company had accrued $3.8 million.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 7.8%, 8.8% and 8.1% for 2002, 2001 and 2000, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount incurred.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services are provided to customers and include estimated amounts for electricity and natural gas delivered but not yet billed. Prior to January 1, 2000 revenues related to regulated electric and gas services were recorded only as customers were billed (see Note 2). Unbilled revenues totaled approximately $43.9 million and $39.1 million as of December 31, 2002 and 2001, respectively.
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 SCPSC during annual fuel cost hearings. Any difference between actual fuel costs and amounts contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. The Company had undercollected through the electric fuel cost component approximately $25.3 million and $47.4 million at December 31, 2002 and 2001, respectively, which amounts are included in "Deferred Debits - Other regulatory assets."
Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the SCPSC during annual gas cost recovery hearings. Any difference between actual gas costs and amounts contained in rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 2002 and 2001 the Company had undercollected through the gas cost recovery procedure approximately $24.6 million and $12.2 million, respectively, which amounts are also included in "Deferred Debits - Other regulatory assets."
The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment which minimizes fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 2.93%, 2.98% and 2.98% for 2002, 2001 and 2000, respectively.
Nuclear fuel amortization, which is included in "Fuel used in electric generation" and recovered through the fuel cost component of the Company's rates, is recorded using the units-of-production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department of Energy (DOE) under a contract for disposal of spent nuclear fuel.
H. Nuclear Decommissioning
The Company's share of estimated site-specific nuclear decommissioning costs for Summer Station, including the cost of decommissioning plant components not subject to radioactive contamination, totals approximately $357.3 million, stated in 1999 dollars, based on a decommissioning study completed in 2000. Santee Cooper is responsible for decommissioning costs related to its one-third ownership interest in the station. The cost estimate is based on a decommissioning methodology acceptable to the Nuclear Regulatory Commission (NRC) under which the site would be maintained over a period of approximately 60 years in such a manner as to allow for subsequent decontamination that permits release for unrestricted use.
The Company'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 in each of 2002, 2001 and 2000) are used to pay premiums on insurance policies on the lives of certain Company and affiliate personnel. The Company is the beneficiary of these policies. Through these insurance contracts, the Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds, less expenses, are transferred by the Company to an external trust fund. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis.
The Company records its liability for decommissioning cost in deferred credits. See also discussion below related to the adoption of SFAS 143, "Accounting for Asset Retirements Obligations," effective January 1, 2003.
In addition to the above, pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, the Company has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $2.0 million and $2.4 million at December 31, 2002 and 2001, respectively, has been included in "Long-Term Debt, net." The Company is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other."
I. Income and Other Taxes
The Company is included in the consolidated federal income tax return of SCANA Corporation. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. Also under provisions of the income tax allocation agreement, tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including SCE&G, in the form of capital contributions. In 2002 and 2001, capital contributions of approximately $7 million and $33 million, respectively, were received by SCE&G under such provisions.
The Company records excise taxes billed and collected, as well as local franchise and similar taxes as liabilities until they are remitted to the respective taxing authority. As such, no excise taxes are included in revenues or expenses in the statements of income.
J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt and are being amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and amortized over the term of the replacement debt.
K. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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 solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million and $24.4 million at December 31, 2002 and 2001, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 11C.
L. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide emission allowances are purchased and financed by Fuel Company under a contract which requires the Company to reimburse Fuel Company for all costs and expenses relating to the ownership and financing of fuel inventories and sulfur dioxide emission allowances. Accordingly, such fuel inventories and emission allowances and fuel-related assets and liabilities are included in the Company's consolidated financial statements. (See Note 6.)
M. 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.
N. New Accounting Standards
In June 2001, FASB issued SFAS 143, which becomes effective for financial statements issued for fiscal years beginning after June 15, 2002. Accordingly, the Company adopted this standard effective January 1, 2003. SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods.
The Company has determined that it should recognize an ARO related to the decommissioning and dismantling of Summer Station and, effective January 1, 2003, will record an ARO of approximately $110 million, which amount exceeds the previously recorded reserve for nuclear plant decommissioning of $87 million, and a net capital asset of approximately $20 million. Due to the application of SFAS 71, the difference between these amounts will be recorded in regulatory accounts and will have no impact on the Company's results of operations or cash flows.
In addition to the ARO for Summer Station, the Company believes that there is legal uncertainty as to the existence of environmental obligations associated with certain transmission and distribution properties. The Company believes that any ARO related to this type of property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.
The Company records cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, the Company estimates that approximately $225 million of its accumulated depreciation balance is related to this regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective January 1, 2002. This statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements from the initial adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion (APB) 30. The Company will adopt SFAS 145 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt SFAS 146 effective January 1, 2003, and does not expect that initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002.
P. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. Accounting Change
Effective January 1, 2000 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $22 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period.
3. RATE AND OTHER REGULATORY MATTERS
Electric
In January 2003 the SCPSC issued an order granting the Company an increase in retail electric rates of 5.8% which is designed to produce additional annual revenues of approximately $70.7 million based on a test year calculation. The SCPSC authorized a return on common equity of 12.45%. The new rates were effective for service rendered on and after February 1, 2003. As a part of the order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for the Company's Cope Generating Station. Under the plan, the Company may increase depreciation of its Cope Generating Station in excess of amounts that would be recorded based upon currently approved depreciation rates, not to exceed $36 million annually without the approval of the SCPSC. Any unused portion of the $36 million in any given year may be carried forward for possible use in the following year.
In December 2002 the SCPSC issued an order approving the Company's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart Generating Station in 2002. As a result, the Company transferred approximately $12.5 million from fuel used in electric generation to electric utility plant.
In May 2002 the SCPSC issued an order approving the Company's request to increase the fuel component of rates charged to electric customers from 1.579 cents per KWh to 1.722 cents per KWh. The increase reflects higher fuel costs projected for the period May 2002 through April 2003. The increase also provided continued recovery for under-collected actual fuel costs through April 2001, including short-term purchased power costs necessitated by outages at two of the Company's base load generating plants in winter 2000-2001. The new rates were effective as of the first billing cycle in May 2002. In January 2003 in conjunction with the approval of the above retail rate increase, the SCPSC approved the Company's request to reduce the fuel component to 1.678 cents per KWh. This reduction is effective for service rendered on or after February 1, 2003.
Gas
The Company's rates are established using a cost of gas component approved by the SCPSC which may be modified periodically to reflect changes in the price of natural gas purchased by the Company.
The Company's cost of gas component in effect during the years ended December 31, 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.596 January-October 2002 $.993 January-February 2001 $.728 November-December 2002 $.793 March-October 2001 $.596 November-December 2001
The SCPSC allows the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former MGPs. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been recorded in deferred debits. In October 2002, as a result of the annual review, the SCPSC reaffirmed the Company's billing surcharge of 3.0 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2005, of the balance remaining at December 31, 2002 of $17.9 million.
Transit
On October 15, 2002 the Company transferred its transit system to the City of Columbia, South Carolina (City). As part of the transfer agreement, the Company will pay the City $32 million over eight years in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. The Company will continue to operate the plant for the City until 2005. The Company will also pay the Central Midlands Regional Transit Authority up to $3 million as matching funds for Federal Transit Administration grants for the purchase of new transit coaches and a new transit facility. The cost of the franchise agreement is recorded in other regulatory assets.
4. EMPLOYEE BENEFIT PLANS
The Company participates in SCANA's noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA's policy has been to fund the plan to the extent permitted by the applicable federal income tax regulations as determined by an independent actuary.
Effective July 1, 2000, SCANA's pension plan was amended to provide a cash balance formula. With certain exceptions, employees were allowed to either remain under the final average pay formula or elect the cash balance formula. Under the final average pay formula, benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. Under the cash balance formula, the monthly benefit earned under the final average pay formula at July 1, 2000 was converted to a lump sum amount for each employee and increased by transition credits for eligible employees. Under the cash balance formula, benefits based upon this opening balance increase going forward as a result of compensation credits and interest credits. The effect of this plan amendment was to reduce the Company's net periodic benefit income for the year ended December 31, 2000 by approximately $3.4 million.
In addition to pension benefits, the Company provides certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost. The Company provides life insurance benefits to retirees at no charge. The costs of postretirement benefits other than pensions are accrued during the years the employees render the services necessary to be eligible for the applicable benefits.
Effective July 1, 2000, PSNC Energy's pension and postretirement benefit plans were merged with SCANA's plans.
In connection with the joint ownership arrangements surrounding Summer Station, as of December 31, 2002 and 2001 the Company has recorded within deferred credits an $9.1 million and $8.4 million obligation, respectively, to Santee Cooper, representing an estimate of the net pension asset attributable to the Company's contributions to the plan that were recovered through billings to Santee Cooper for its one-third portion of shared costs. As of December 31, 2002 and 2001, the Company has also recorded a $6.4 million and $6.0 million receivable, respectively, from Santee Cooper representing an estimate of its portion of the unfunded net postretirement benefit obligation.
As allowed by SFAS 87, the Company records net periodic benefit cost (income) utilizing beginning of the year assumptions. Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," are set forth in the following tables:
Health Care Trends
The determination of net periodic other postretirement health care benefit cost is based on the following assumptions:
2002 2001 2000 - -------------------------------------------------------- --------- ----------
Health care cost trend rate 10.0% 8.5% 7.5% Ultimate health care cost trend rate 5.0% 5.0% 5.5% Year achieved 2011 2009 2005
The effects of a one-percentage-point increase or decrease in the assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic other postretirement health care benefit cost and the accumulated other postretirement benefit obligation for health care benefits are as follows:
Millions of dollars 1% 1% Increase Decrease -----------------------------
Effect on health care benefit cost $0.1 $(0.1) Effect on postretirement benefit obligation 1.4 (1.7)
Due to poor performance in the stock market in recent years, the Company has determined to adjust its long-term expected return on assets to 9.25% for 2003. In developing the expected long-term rate of return assumptions, management evaluated the plan's historical cumulative actual returns over several periods, which have all been in excess of related broad indices, and management anticipates that the plan's investment managers will continue to generate long-term returns of at least 9.25%.
The expected long-term rate of return of 9.25% is based on an asset allocation of 80% with equity managers and 20% with fixed income managers. While the Company believes that the asset allocation will return to those levels, because of market fluctuations, the actual asset allocation as of December 31, 2002 was 70% with equity managers and 30% with fixed income managers. Management regularly reviews such allocations and periodically rebalances the portfolio to our targeted allocation when considered appropriate.
While the recent investment performance and the decline in discount rate have significantly reduced the level of pension income, the pension trust has been and remains adequately funded, and no contributions have been required since 1997. As such, recent declines in pension income have had no impact on the Company's cash flows.
5. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund requirements for the years 2003 through 2007 are summarized as follows:
- ---------------- ----------------- ------------------ ----------------- Year Amount Year Amount - ---------------- ----------------- ------------------ ----------------- (Millions of dollars)
2003 $144.0 2006 $169.1 2004 138.4 2007 38.2 2005 188.4 - ---------------- ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt payable in 2003 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 2002 the Company entered into an agreement with the South Carolina Transportation Infrastructure Bank (the Bank) and the South Carolina Department of Transportation (SCDOT) that allows the Company to borrow funds from the Bank to construct a roadbed for SCDOT in connection with the Lake Murray dam remediation project. The loan agreement provides for interest-free borrowings for costs incurred not to exceed $59 million, with such borrowings being repaid over ten years from the initial borrowing. At December 31, 2002 the Company had not yet borrowed under the agreement
On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with the Company. In consideration for the electric franchise agreement, the Company has paid the City $25 million over seven years (1996-2002) and donated to the City the existing transit assets in Charleston.
On October 15, 2002 SCE&G transferred its transit system to the City of Columbia. As part of the transfer agreement, the Company will pay the City $32 million over eight years (2002-2009) in exchange for a 30-year electric and gas franchise, has conveyed transit-related property and equipment to the City and has conveyed the 10 MW Columbia Canal and Hydroelectric Plant to the City. The Company will continue to operate the plant for the City until 2005.
The Company has a three-year revolving line of credit totaling $75 million, expiring in 2005, in addition to other lines of credit that provide liquidity for issuance of commercial paper. The three-year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million.
On January 23, 2003 the Company issued $200 million First Mortgage Bonds having an annual interest rate of 5.80% and maturing on January 15, 2033. The proceeds from the sale of these bonds were used to reduce short-term debt and for general corporate purposes.
During the formation of GENCO in 1994, the Company's $36 million Berkeley County Pollution Control Facilities Revenue Bonds (Berkeley Bonds) were transferred to GENCO. SCANA is a guarantor of the Berkeley Bonds. In addition, holders of Berkeley Bonds may have recourse against the Company in the event of default by GENCO.
Substantially all utility plant is pledged as collateral in connection with long-term debt.
6. SHORT-TERM BORROWINGS
Details of lines of credit and short-term borrowings at December 31, 2002 and 2001, are as follows:
Millions of dollars 2002 2001 - -------------------------------------------------------------- ---------------
Lines of credit $300.0 $300.0 Unused lines of credit $300.0 $300.0 Short-term borrowings outstanding Commercial paper (270 or fewer days) $177.7 $164.8 Weighted average interest rate 1.40% 1.97%
The Company pays fees to banks as compensation for committed lines of credit.
Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by a 364-day revolving credit agreement which expires December 16, 2003. The credit agreement provides for a maximum amount of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper amounts outstanding have been classified as short-term debt.
Fuel Company commercial paper outstanding totaled $50.1 million and $50.1 million at December 31, 2002 and 2001, respectively, at weighted average interest rates of 1.38% and 2.06%, respectively.
The Company's commercial paper outstanding totaled $127.6 million and $114.7 million at December 31, 2002 and 2001, at weighted average interest rates of 1.40% and 1.95%, respectively.
7. RETAINED EARNINGS
The Company's Restated Articles of Incorporation contain provisions that, under certain circumstances, could limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of certain earnings therefrom. At December 31, 2002 approximately $41 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
8. PREFERRED STOCK
Retirements under sinking fund requirements are at par values. The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 2003 through 2007 is $2.7 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend.
The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2002, 2001 and 2000 are summarized as follows:
Number of Shares Millions of Dollars - -------------------------------------------------------- ----------------------- Balance at December 31, 1999 231,487 11.6 Shares Redeemed - $50 par value (11,200) (0.6) - -------------------------------------------------------- ----------------------- Balance at December 31, 2000 220,287 11.0 Shares Redeemed - $50 par value (10,803) (0.5) - -------------------------------------------------------- ----------------------- Balance at December 31, 2001 209,484 10.5 Shares Redeemed - $50 par value (9,511) (0.5) - -------------------------------------------------------- ----------------------- Balance at December 31, 2002 199,973 10.0 ======================================================== =======================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred Securities, Series A (the "Preferred Securities"). The Company owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from the Company a like amount of its 7.55% Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is such Junior Subordinated Debentures of the Company. Accordingly, no financial statements of the Trust are presented. The financial statements of the Trust are consolidated in the financial statements of the Company. The Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with the Company's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and the Company's obligations under the Indenture pursuant to which the Junior Subordinated Debentures were issued, provides a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities.
The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55% Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time. Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions.
9. INCOME TAXES
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $622.5 million at December 31, 2002 and $611.3 million at December 31, 2001 (see Note 1I), are as follows:
Millions of dollars 2002 2001 - --------------------------------------------------------------- ---------------- Deferred tax assets: Nondeductible reserves $59.1 $54.5 Unamortized investment tax credits 56.1 56.7 Deferred compensation 21.0 22.9 Cycle billing 6.3 10.6 Other 6.4 6.2 - --------------------------------------------------------------- ---------------- Total deferred tax assets 148.9 150.9 - --------------------------------------------------------------- ----------------
Deferred tax liabilities: Property, plant and equipment 644.9 647.6 Pension plan benefit income 93.0 81.1 Deferred fuel costs 19.1 22.8 Other 14.4 10.7 - --------------------------------------------------------------- ---------------- Total deferred tax liabilities 771.4 762.2 - --------------------------------------------------------------- ---------------- Net deferred tax liability $622.5 $611.3 =============================================================== ================
The Internal Revenue Service has examined and closed consolidated federal income tax returns of SCANA through 1997 and is currently examining SCANA's 1998, 1999 and 2000 federal returns. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on its results of operations, cash flows or financial position.
10. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2002 and 2001 are as follows:
The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments:
o Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount.
o Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. For investments for which the fair value is not readily determinable, fair value is considered to approximate carrying value. Early settlement of long-term debt may not be possible or may not be considered prudent.
o Short-term borrowings are valued at their carrying amount.
o The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices.
o Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration.
11. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
On October 15, 1999 FERC mandated that the Company reinforce its Lake Murray dam in order to comply with new federal safety standards and maintain the lake in case of an extreme earthquake. Construction for the project and related activities, which began in the third quarter of 2001, is expected to cost approximately $275 million and be completed in 2005. Costs incurred through December 31, 2002 totaled approximately $67 million.
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 $9.5 billion. Each reactor licensee is currently liable for up to $88.1 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. The Company's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $58.7 million per incident, but not more than $6.7 million per year.
The Price-Anderson Indemnification Act expired in August 2002, but is expected to renew with only modest changes in 2003. This has no impact on the Company at present due to the "grandfathered" status of existing licensees that are covered under the past act until such time as it is renewed.
The Company currently maintains policies (for itself and on behalf of Santee Cooper) with Nuclear Electric Insurance Limited. The policies, covering the nuclear facility for property damage, excess property damage and outage costs, permit assessments under certain conditions to cover insurer's losses. Based on the current annual premium, the Company's portion of the retrospective premium assessment would not exceed $15.5 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 the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it would have a material adverse impact on the Company's results of operations, cash flows and financial position.
C. Environmental
At the Company, site assessment and cleanup costs are recorded in deferred debits and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $17.9 million at December 31, 2002. The deferral includes the estimated costs associated with the following matters.
The Company owns a decommissioned MGP site in the Calhoun Park area of Charleston, South Carolina. The site is currently being remediated for benzene contamination in the intermediate aquifer on surrounding properties. The Company anticipates that the remaining remediation activities will be completed in 2003, with certain monitoring and retreatment activities continuing until 2007. As of December 31, 2002, the Company has spent approximately $18.4 million to remediate the Calhoun Park site. Total remediation costs are estimated to be $21.9 million.
The Company owns three other decommissioned MGP sites in South Carolina which contain residues of by-product chemicals. Two of these sites are currently being remediated under work plans approved by DHEC. The Company is continuing to investigate the remaining site and is monitoring the nature and extent of residual contamination. The Company anticipates that major remediation activities for these three sites will be completed before 2006. The Company has spent approximately $2.2 million related to these sites, and expects to incur an additional $5.9 million.
D. Franchise Agreements
See Note 5 for a discussion of the electric and gas franchise agreements between the Company and the cities of Columbia and Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.
F. Operating Lease Commitments
The Company is obligated under various operating leases with respect to office space, furniture and equipment. Leases expire at various dates through 2009. Rent expense totaled approximately $9.3 million, $9.0 million and $5.9 million in 2002, 2001 and 2000, respectively. Future minimum rental payments under such leases are as follows:
Millions of dollars 2003 $12.5 2004 10.5 2005 9.6 2006 9.6 2007 9.4 Thereafter 16.9 ----- $68.5
At December 31, 2002 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $11.3 million.
G. Purchase Commitments
Purchase commitments for coal supply and other contracts are as follows:
Millions of dollars 2003 $413.2 2004 159.7 2005 2.8 2006 2.7 2007 2.7 Thereafter 15.2 ------- $596.3
12. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments are Electric Operations and Gas Distribution. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company records intersegment sales and transfers of electricity and gas based on rates established by the appropriate regulatory authority. Non-regulated sales and transfers are recorded at current market prices.
Electric Operations is comprised of the electric portion of the Company and Fuel Company and is primarily engaged in the generation, transmission, and distribution of electricity. The Company's electric service territory extends into 24 counties covering more than 15,000 square miles in the central, southern, and southwestern portions of South Carolina. Sales of electricity to industrial, commercial, and residential customers are regulated by the SCPSC and by FERC. Fuel Company acquires, owns, and provides financing for the fuel and emission allowances required for the operation of the Company's generation facilities.
Gas Distribution, comprised of the local distribution operations of the Company, is engaged in the purchase and sale, primarily at retail, of natural gas. The Company's operations extend to 33 counties in South Carolina covering approximately 22,000 square miles.
The Company's reportable segments share a similar regulatory environment and, in some cases, overlapping service areas. However, Electric Operation's product differs from Gas Distribution, as does its generation process and method of distribution.
Management uses operating income to measure segment profitability for regulated operations. Accordingly, the Company does not allocate interest charges or income tax expense (benefit) to its segments. Similarly, management evaluates utility plant for its segments. Therefore, the Company does not allocate accumulated depreciation, common and non-utility plant, or deferred tax assets to reportable segments. Interest income is not reported by segment and is not material. In accordance with SFAS 109, the Company nets deferred tax assets and deferred tax liabilities for reporting purposes. For 2000, adjustments to net income include the cumulative effect of the accounting change described in Note 2.
The Consolidated Financial Statements report operating revenues which are comprised of the reportable segments. Revenues from non-reportable segments are included in Other Income. Therefore, the adjustments to total revenue remove revenues from non-reportable segments.
Segment assets include utility plant only (excluding accumulated depreciation) for all segments. As a result, adjustments to assets include accumulated depreciation, common and non-utility plant and non-fixed assets for the segments.
Interest Expense is adjusted to include the totals from the Company that are not allocated to the segments and to eliminate inter-segment charges. Deferred Tax Assets are not allocated to reportable segments, and are included in deferred credits, net, on the balance sheet.
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
Item 7. Management's Narrative Analysis of Results of Operations....130
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...134
Item 8. Financial Statements and Supplementary Data..................135
Public Service Company of North Carolina, Incorporated meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore is filing this form with the reduced disclosure format allowed under General Instruction I(2).
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
Statements included in this narrative analysis (or elsewhere in this annual report) which are not statements of historical fact are intended to be, and are hereby identified as, forward-looking statements for purposes of the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Readers are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, and that actual results could differ materially from those indicated by such forward-looking statements. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, but are not limited to, the following: (1) that the information is of a preliminary nature and may be subject to further and/or continuing review and adjustment, (2) changes in the utility regulatory environment, (3) changes in the economy, especially in PSNC Energy's service territory, (4) the impact of competition from other energy suppliers, (5) growth opportunities, (6) the results of financing efforts, (7) changes in PSNC Energy's accounting policies, (8) weather conditions, especially in areas served by PSNC Energy, (9) performance of SCANA Corporation's pension plan asset and its impact on PSNC Energy's results of operations, (10) inflation, (11) changes in environmental regulations, and (12) the other risks and uncertainties described from time to time in PSNC Energy's periodic reports filed with the SEC. PSNC Energy disclaims any obligation to update any forward-looking statements.
Net Income (Loss)
Net income (loss) for the years ended December 31, 2002 and 2001 was as follows:
Millions of dollars 2002 2001 - --------------------------------------------------------------- ---------------
Net income derived from: Continuing operations $22.6 $14.7 Cumulative effect of accounting change (229.6) - - --------------------------------------------------------------- --------------- Net income (loss) $(207.0) $14.7 =============================================================== ===============
Net income from continuing operations increased approximately $7.9 million, due to reduced amortization expense of $13.3 million and reduced interest expense of $0.4 million, which was partially offset by increased depreciation of $3.1 million, reduced other income of $1.7 million, higher operating expenses of $0.7 million and reduced margin of $0.4 million.
In connection with the implementation of SFAS 142, the Company performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by $230 million. As a result, PSNC Energy recorded an impairment charge of $230 million in the fourth quarter of 2002. The charge is presented on the Consolidated Statements of Operations as the Cumulative Effect of an Accounting Change.
The nature of PSNC Energy's business is seasonal. The quarters ending March 31 and December 31 are generally PSNC Energy's most profitable quarters due to increased demand for natural gas related to space heating requirements.
PSNC Energy's Board of Directors authorized payment of capital distributions to SCANA as follows:
Declaration Date Distribution Amount Quarter Ended Payment Date
February 21, 2002 $5.0 million March 31, 2002 April 1, 2002 May 2, 2002 $4.0 million June 30, 2002 July 1, 2002 August 1, 2002 $5.5 million September 30, 2002 October 1, 2002 October 31, 2002 $5.5 million December 31, 2002 January 1, 2003
Gas Distribution
Gas distribution sales margins for 2002 and 2001 were as follows:
Millions of dollars 2002 2001 Change % Change - -----------------------------------------------------------------------------
Operating revenues $355.7 $452.6 $(96.9) (21.4%) Less: Cost of gas (189.9) (286.1) 96.2 33.6% - -------------------------------------------------------- Gross margin $165.8 $166.5 $(0.7) (0.4%) =============================================================================
Gas distribution sales margin for the year ended December 31, 2002 decreased primarily due to lower natural gas usage of $1.3 million, a reduction in rates in August 2001 related to the acquisition of PSNC Energy by SCANA of $0.7 million, and lower other operating revenues of $0.6 million. The decrease was partially offset by customer growth of $2.3 million. In addition to these changes affecting margins, revenues and cost of gas also decreased in 2002 because of lower commodity natural gas prices.
Operation and Maintenance Expenses
The $1.1 million increase in operation and maintenance expenses from 2001 is primarily due to increased customer billing and other administrative costs of $3.6 million and increased labor costs of $0.5 million, which was partially offset by lower bad debt expense of $2.8 million.
Depreciation and Amortization Expenses
Depreciation and amortization expenses decreased $8.2 million primarily due to implementation of SFAS 142 which resulted in the elimination of $13.3 million of amortization expense related to goodwill, which was partially offset by increases for normal property additions of $5.1 million.
Other Income
Other income decreased $2.8 million for the year ended December 31, 2002 as compared to the same period in 2001 primarily due to reduced interest income of $1.5 million, an increased provision for bad debt for merchandise and jobbing of $0.6 million, lower equity method affiliate income of $0.3 million and other of $0.4 million.
Interest Expense
Interest expense decreased $0.6 million over 2001 due to declining interest rates.
Capital Expansion Program and Liquidity Matters
PSNC Energy's capital expansion program includes the construction of lines, systems and facilities and the purchase of related equipment. PSNC Energy's 2003 construction budget is approximately $46.7 million, compared to actual construction expenditures for 2002 of $47.8 million.
For the years 2004-2007, PSNC Energy has an aggregate of $17.1 million of long-term debt maturing. These obligations and other commitments are tabulated below.
Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Certain of these contracts relate to regulated gas businesses; therefore, the effects of such contracts on gas costs are reflected in gas rates.
On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003. On March 3, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.460 to $.595 per therm effective March 1, 2003.
Financing Limits and Related Matters
PSNC Energy's issuance of various securities including long-term and short-term debt is subject to customary approval or authorization by state and federal regulatory bodies including the NCUC and the SEC. The Indenture under which these securities are issued contains no specific limit on the amount which may be issued.
PSNC Energy finances its operations and capital needs through short-term and long-term borrowings, including, from time to time, advances from SCANA. At December 31, 2002 PSNC Energy had $125 million unused committed lines of credit, expiring in 2003, under a credit agreement supporting the issuance of commercial paper. PSNC Energy had total commercial paper outstanding of $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. PSNC Energy had no commercial paper outstanding at December 31, 2001.
PSNC Energy has two interest rate swap agreements to pay variable rates and receive fixed rates on a combined notional amount of $40.6 million at December 31, 2002. (See Note 10 of Notes to Consolidated Financial Statements.) PSNC Energy utilizes no off-balance sheet financings or similar arrangements other than incidental operating leases, generally for office furniture and equipment.
Competition
Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, the other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect the price and impact PSNC Energy's ability to retain large commercial and industrial customers on a monthly basis.
The NCUC has approved a rate structure that allows PSNC Energy to negotiate reduced rates in order to match the cost of alternate fuels to large commercial and industrial customers and recover the lost margin from other classes of customers. PSNC Energy anticipates that the need to negotiate reduced rates with these customers will continue.
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
Following are descriptions of PSNC Energy's accounting policies which are new or most critical in terms of reporting financial conditions or results of operations.
SFAS 71 - PSNC Energy is subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," which requires it to record certain assets and liabilities that defer the recognition of expenses and revenues to future periods as a result of being rate-regulated. At December 31, 2002 PSNC Energy had recorded approximately $20 million and $1 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities. Management believes the regulatory assets are recoverable through rates. The NCUC has reviewed and approved most of the items shown as regulatory assets through specific orders. Other items represent costs which were not yet approved for recovery. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by PSNC Energy. However, ultimate recovery is subject to NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, PSNC Energy may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the results of operations of PSNC Energy's Gas Distribution segment in the period the write-off would be recorded. It is not expected that cash flows or financial position would be materially affected.
Certain of PSNC Energy's regulatory assets and liabilities arise from its environmental assessment program, which identifies and evaluates current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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. Regulatory assets and liabilities related to environmental cleanup affect primarily the Gas Distribution segment and are due to the costs associated with current and former MGP sites.
Revenue Recognition / Unbilled Revenues - Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their gas meters, we record estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of gas delivered to each customer since the date of the last reading of their respective meters. Such unbilled revenues reflect consideration of estimated usage by customer class, the effects of different rate schedules, changes in weather and, where applicable, the impact of weather normalization provisions of rate structures. The accrual of unbilled revenues in this manner properly matches revenues and related costs. As of December 31, 2002 and 2001, accounts receivable include unbilled revenues of $27.7 million and $20.2 million. Total revenues for 2002 and 2001 were $355.7 million and $452.6 million.
SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and Other Intangible Assets," SCANA Corporation performed a valuation analysis of its investment in PSNC Energy (Gas Distribution segment) using an independent appraisal. SCANA obtained an independent appraisal for its initial valuation. The independent appraisal made various assumptions related to cash flow projections, discount rates, weighted average cost of capital and market multiples for comparable companies. The analysis indicated that the carrying amount of PSNC Energy's acquisition adjustment (goodwill) exceeded its fair value, and as a result, PSNC Energy recorded an impairment charge of $230 million as the cumulative effect of an accounting change, effective January 1, 2002. SFAS 142 requires PSNC Energy to perform a valuation analysis annually. Such an analysis will incorporate updated assumptions similar to those used for the initial valuation.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by PSNC Energy described below are held for purposes other than trading.
Interest rate risk - The tables below provide information about long-term debt issued by PSNC Energy and other financial instruments that are sensitive to changes in interest rates. For debt obligations, the tables present principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the figures shown reflect notional amounts and related maturities. Fair values for debt and swaps represent quoted market prices.
While a decrease in interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
Beginning in January 2003, PSNC Energy initiated a hedging program for gas purchasing activities using NYMEX futures and options. PSNC Energy's tariffs include a PGA clause that provides for the recovery of actual gas costs incurred. PSNC Energy will include in its PGA the results of its hedging program, and will seek approval of this accounting treatment from the NCUC during the annual prudence review in 2003. The offset to the change in fair value of these derivatives will be recorded as a regulatory asset or liability.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page
Independent Auditors' Reports......................................... 136
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2002 and 2001........... 137
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000............................. 138
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000.............................. 139
Consolidated Statements of Capitalization as of December 31, 2002 and 2001....................................... 140
Consolidated Statements of Comprehensive Income (Loss) and Changes in Common Equity for the Years Ended December 31, 2002, 2001 and 2000........................................ 140
Notes to Consolidated Financial Statements......................... 141
INDEPENDENT AUDITORS' REPORT
Public Service Company of North Carolina, Incorporated:
We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of Public Service Company of North Carolina, Incorporated (Company) as of December 31, 2002 and 2001, and the related Consolidated Statements of Operations, Comprehensive Income (Loss) and Changes in Common Equity and of Cash Flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in Part IV at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Notes 1 and 2 to the consolidated financial statements, the Company adopted Statement of Financial Standards No. 142, "Goodwill and Other Intangibles," effective January 1, 2002 and changed its method of accounting for operating revenues associated with its regulated utility operations effective January 1, 2000.
s/Deloitte & Touche LLP Columbia, South Carolina February 7, 2003
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
Public Service Company of North Carolina, Incorporated (Company), a public utility, was organized as a North Carolina corporation in 1938. Effective January 1, 2000 the acquisition of the Company by SCANA Corporation (SCANA), a South Carolina holding company, was consummated in a business combination accounted for as a purchase. As a result, the Company became a wholly owned subsidiary of SCANA, incorporated under the laws of South Carolina. The Company is engaged predominantly in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina.
The accompanying Consolidated Financial Statements include the accounts of the Company and its subsidiary companies, Clean Energy Enterprises, Inc., PSNC Blue Ridge Corporation, and PSNC Cardinal Pipeline Company (collectively, the "Company"). In 2000, the accounts of PSNC Production Corporation and SCANA Public Service Company LLC are also included. PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, effective January 1, 2001 (see Note 4). Investments in other affiliates in which the Company has the ability to exercise influence over operating and financial policies are accounted for under the equity method. Significant intercompany balances and transactions have been eliminated in consolidation.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation". SFAS 71 requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result, the Company has recorded, as of December 31, 2002, approximately $19.7 million and $1.1 million of regulatory assets and liabilities, respectively, as shown below.
December 31, Millions of dollars 2002 2001 - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
Accumulated deferred income taxes $(0.7) $(0.4) Under- (over-) collections - Gas Cost Adjustment Clause 10.6 (13.8) Deferred environmental remediation costs 9.0 10.2 Other regulatory assets (liabilities), net (0.3) 0.4 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $18.6 $(3.6) ================================================================================
Accumulated deferred income taxes represent deferred income tax liabilities applicable to utility operations that have not been reflected in customer rates for which future recovery is probable, offset by deferred income tax assets, which will be reflected in customer rates as a result of reduced revenue requirements due to the amortization of deferred investment tax credits.
Under- (Over-) collections - gas cost adjustment represents amounts under- or over- collected from customers pursuant to the Company's Rider D mechanism approved by the North Carolina Utilities Commission (NCUC). (See Note 1F.)
Deferred environmental remediation costs represent the costs associated with the assessment and cleanup of environmental sites at manufactured gas plant (MGP) sites currently or formerly owned by the Company. Management believes that all MGP cleanup costs will be recoverable through gas rates. (See Note 11.)
The NCUC has reviewed and approved through specific orders most of the items shown as regulatory assets. Other items represent costs which are not yet approved for recovery by the NCUC. In recording these costs as regulatory assets, management believes the costs will be allowable under existing rate-making concepts that are embodied in current rate orders received by the Company. However, ultimate recovery is subject to NCUC approval. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and could be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off would be recorded, but it is not expected that cash flows or financial position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the NCUC.
D. 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.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 12.1%, 7.0% and 6.8% for the years ended December 31, 2002, 2001 and 2000, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services are provided to customers, and include estimated amounts for natural gas delivered and facilities charges not yet billed. Unbilled revenues totaled approximately $27.7 million and $20.2 million as of December 31, 2002 and 2001, respectively.
The Company's Rider D mechanism authorizes the recovery of all prudently incurred gas costs from customers on a monthly basis. Any difference in amounts paid and collected for these costs is deferred for subsequent refund to or collection from customers, with interest. Additionally, the Company can recover its margin losses on negotiated gas sales to certain large commercial/industrial customers in any manner authorized by the NCUC. Pursuant to the operation of Rider D, the Company had undercollected from customers approximately $10.6 million at December 31, 2002 and overcollected from customers approximately $13.8 million at December 31, 2001.
The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. The Company establishes its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas as approved by the NCUC.
G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the straight-line method and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates for utility plant assets were 4.3% for the year ended December 31, 2002 and 4.1% for the years ended December 31, 2001 and 2000.
The Company adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. The Company considers the amounts categorized by the FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. These amounts are related to acquisition adjustments of approximately $466 million recorded on the books of the Company. The Company has no other significant intangible assets subject to amortization as provided in SFAS 142.
The Company considers the amounts categorized by FERC as "acquisition adjustments" to be goodwill as defined in SFAS 142 and ceased amortization of such amounts upon the adoption of SFAS 142. These amounts are related to the acquisition adjustment of approximately $466 million recorded on the books of the Company. The Company has no other intangible assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization of the acquisition adjustment during all periods presented in the condensed consolidated statements of operations, net income (loss) would have been as follows:
(Millions of dollars) 2002 2001 2000 ---- ---- ----
Net Income (Loss) as Reported $(207) $14.8 $27.8 Amortization of Acquisition Adjustment - 13.3 13.4 ----- - - ---- - ---- Net Income (Loss) as Adjusted $(207) 28.1 41.2 ====== == ==== == ====
In connection with the implementation of SFAS 142, the Company performed a valuation analysis of its acquisition adjustment using an independent appraisal. The analysis indicated that the carrying amount of the acquisition adjustment exceeded its fair value by $230 million. As a result, the Company recorded an impairment charge of $230 million in the fourth quarter of 2002. The charge is reflected on the statements of operations as the cumulative effect of an accounting change.
H. Income Taxes
The Company is included in the consolidated federal income tax return of SCANA Corporation for 2002 and 2001. Under a joint consolidated income tax allocation agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. Deferred tax assets and liabilities are recorded for the tax effects of all significant temporary differences between the book basis and tax basis of assets and liabilities at currently enacted 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; otherwise they are charged or credited to income tax expense. Also, under provisions of the income tax allocation agreement, tax benefits of the parent holding company are distributed in cash to tax paying affiliates, including PSNC Energy, in the form of capital contributions. In 2002 and 2001 capital contributions of $0.6 million and $3.1 million, respectively, were received by PSNC Energy under such provisions.
I. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium and discount are recorded in long-term debt and are amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Other issuance expense and gains or losses on reacquired debt that is refinanced are recorded in other deferred debits or credits and amortized over the term of the replacement debt. The Company amortized the redemption premium and the unamortized issuance costs on its previously refunded Series K First Mortgage Bonds over 15 years (1987-2002), in accordance with the treatment authorized by the NCUC.
J. Environmental
The Company maintains an environmental assessment program to identify and evaluate current and former operation sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the amount of expenditures, if any, deemed 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 solely to regulated operations. Such amounts are recorded in deferred debits and amortized with recovery provided through rates.
K. Cash and Temporary Investments
The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments may include repurchase agreements, U.S. Treasury bills, federal agency securities, certificates of deposit and high-grade commercial paper.
Since fiscal 1992, the Company has received refunds from its pipeline transporters for which the investment and use have been restricted by an order of the NCUC. Pursuant to an order of the NCUC, these funds are segregated from the Company's general funds and will be used for expansion of the Company's facilities into unserved territories. These refunds, along with interest earned thereon, are periodically transferred to the Office of the State Treasurer of North Carolina. The balance not transferred is reported in restricted cash and temporary investments.
L. New Accounting Standards
The Company adopted SFAS 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets," effective January 1, 2002. SFAS 141 requires all acquisitions to be accounted for utilizing the purchase method. SFAS 142 addresses how goodwill and other intangible assets should be accounted for after they have been recorded in the financial statements (see Note 1G).
In June 2001, FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which becomes effective for financial statements issued for fiscal years beginning after June 15, 2002. Accordingly, the Company adopted this standard effective January 1, 2003. SFAS No. 143 applies to legal obligations associated with the retirement of tangible long-lived assets (ARO) and requires the Company to recognize, as a liability, the fair value of an ARO in the period in which it is incurred and to accrete the liability to its present value in future periods. The Company believes that any ARO related to the Company's property would be insignificant and, due to the indeterminate life of the related assets, an ARO could not be reasonably estimated.
The Company records cost of removal as a component of accumulated depreciation for property that does not have an associated legal retirement obligation. As of December 31, 2002, the Company estimates that approximately $70 million of its accumulated depreciation balance is related to this regulatory liability.
The provisions of SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective January 1, 2002. This statement requires that one accounting model be used for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. There was no impact on the Company's financial statements for the initial adoption of SFAS 144.
SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," was issued in April 2002. The provisions of SFAS 145, among other things, discontinue treatment of gains or losses from the early extinguishment of debt as extraordinary items unless such early extinguishment meets the criteria of Accounting Principles Board Opinion No. 30. The Company will adopt SFAS 145 effective January 1, 2003 and does not expect that such initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," was issued in July 2002. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company will adopt SFAS 146 effective January 1, 2003, and does not expect that such initial adoption will have any impact on the Company's results of operations, cash flows or financial position.
M. Related Party Transactions
The Company has related party transactions with two of its subsidiaries and their investees. The Company records as cost of gas the storage costs charged by Pine Needle. These gas costs were $5.1 million, $5.3 million and $5.3 million in 2002, 2001 and 2000, respectively. The Company owed Pine Needle $0.4 million, $0.4 million and $0.5 million at December 2002, 2001 and 2000, respectively. The Company also records as gas costs transportation charges to Cardinal. These gas costs were $11.9 million, in 2002, 2001 and 2000, respectively. The Company owed Cardinal $1.0 million at December 31, 2002, 2001 and 2000, respectively.
N. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2002.
O. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. ACCOUNTING CHANGES
As a result of the January 1, 2002 adoption of SFAS 142, the Company recorded a $230 million impairment charge related to its acquisition adjustment (see Note 3). This charge is reflected on the Consolidated Statements of Operations as the cumulative effect of an accounting change. See additional information at Note 1G.
Effective January 1, 2000 the Company changed its method of accounting for operating revenues from cycle billing to full accrual. The cumulative effect of this change was $6.6 million, net of tax. Accruing unbilled revenues more closely matches revenues and expenses. Unbilled revenues represent the estimated amount customers will be charged for service rendered but not yet billed as of the end of the accounting period. Also, effective January 1, 2000, the gas costs associated with unbilled revenues are no longer deferred.
3. ACQUISITION BY SCANA CORPORATION
On February 10, 2000 the acquisition of the Company by SCANA was consummated in a business combination accounted for as a purchase. As a result the Company became a wholly owned subsidiary of SCANA. Pursuant to the Agreement and Plan of Merger, Company shareholders were paid approximately $212 million in cash and 17.4 million shares of SCANA common stock valued at approximately $488 million.
The Company recorded a utility plant acquisition adjustment of approximately $466 million, which reflected the excess of SCANA's purchase price of approximately $700 million over the fair value of the Company's net assets at January 1, 2000. The adjustment was being amortized over 35 years on the straight-line basis. See Note 1G.
4. SALE OF SUBSIDIARIES
Effective January 1, 2001 PSNC Production Corporation and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA, for $4.4 million, which approximated their net book value.
5. RATE AND OTHER REGULATORY MATTERS
The Company's rates are established using a benchmark cost of gas approved by the NCUC, which may be modified periodically to reflect changes in the market price of natural gas. The Company revises its tariffs with the NCUC as necessary to track these changes and accounts for any over- or under-collections of the deferred cost of gas in its deferred accounts for subsequent rate consideration. The NCUC reviews the Company's gas purchasing practices annually.
The Company's benchmark cost of gas in effect during the years ended December 2002 and 2001 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.300 January 2002 $.690 January 2001 $.215 February-June 2002 $.750 February-March 2001 $.350 July-October 2002 $.650 April-August 2001 $.410 November-December 2002 $.500 September-October 2001 $.350 November-December 2001
On January 2, 2003 the NCUC approved PSNC Energy's request to increase the benchmark cost of gas from $.410 to $.460 per therm effective for service rendered on and after January 1, 2003.
In April 2000 the NCUC issued an order permanently approving the Company's request to establish its commodity cost of gas for large commercial and industrial customers on the basis of market prices for natural gas. This mechanism allows the Company to collect from its customers amounts approximating the amounts paid for natural gas.
A state expansion fund, established by the North Carolina General Assembly in 1991 and funded by refunds from the Company's interstate pipeline transporters, provides financing for expansion into areas that otherwise would not be economically feasible to serve. In June 2000 the NCUC approved the Company's requests for disbursement of up to $28.4 million from the Company's expansion fund to extend natural gas service to Madison, Jackson and Swain Counties in western North Carolina. The Company estimates that the cost of this project will be approximately $31.4 million. The Madison County and Jackson County portions of the project were completed by the end of 2002. Through December 31, 2002 approximately $16.9 million had been spent on this project. The unused portion of the Company's expansion fund is recorded in prepaid assets.
In December 1999 the NCUC issued an order approving SCANA's acquisition of the Company. As specified in the NCUC order, the Company reduced its rates by approximately $1 million in each of August 2000 and August 2001, and agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained during this period to recover costs associated with materially adverse governmental actions and force majeure events.
6. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS
Employee Benefit Plans
Since July 1, 2000 the Company has participated in SCANA's noncontributory defined benefit pension plan, which covers substantially all permanent employees. SCANA's pension plan benefits for employees of the Company are calculated using a cash balance formula under which employees earn benefits through monthly compensation and interest credits. SCANA's policy has been to fund the plan to the extent permitted by the applicable federal income tax regulations as determined by an independent actuary. Also since July 1, 2000 the Company has participated in SCANA's plan to provide certain unfunded health care and life insurance benefits to active and retired employees. Retirees share in a portion of their medical care cost and are provided life insurance benefits at no charge. The cost 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 July 1, 2000 the Company and its subsidiaries sponsored a noncontributory defined benefit pension plan covering substantially all employees. The benefits were based on years of service and the employee's compensation during the five consecutive years of employment that produced the highest average pay. Contributions to the plan were determined on an annual basis, with the amount of such contributions being within the range of the minimum required funding amount and the maximum amount deductible for federal income tax purposes. Prior to July 1, 2000 the Company also provided certain health care and life insurance benefits to its employees. Retirees were required to contribute toward the costs of their medical care coverage. The costs of postretirement benefits other than pensions were accrued during the years the employees rendered the service necessary to be eligible for the applicable benefits.
For the years ended December 31, 2002 and 2001, the Company's net periodic benefit income was approximately $0.2 million and $1.2 million, respectively, for the pension plan and net periodic benefit cost was approximately $1.1 million and $2.0 million, respectively, for the postretirement plan. At the time of the plan mergers, the Company had recognized a prepaid pension cost of approximately $9.0 million and a postretirement welfare plan obligation of approximately $9.1 million. For the period July 1 through December 31, 2000, the Company's net periodic benefit income was approximately $0.6 million for the pension plan and the Company's net periodic benefit cost was approximately $0.7 million for the postretirement plan.
Disclosures required for these plans under SFAS 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits," for the six months ended June 30, 2000, which is the relevant period prior to the Plan mergers, are set forth in the following table:
Funded Status of Plans Funded status, beginning of period $6.3 $(11.2) Unrecognized actuarial loss 2.7 2.1 -- --- --- --- Net asset (liability) recognized $9.0 $(9.1) ==== ======
Health Care Trends
The determination of net periodic other postretirement health care benefit cost for the six months ended June 30, 2000 was based on the following assumptions.
Health care cost trend rate 8.00% Ultimate health care cost trend rate 5.50% Year achieved 2005
Stock Compensation Plans
Prior to SCANA's acquisition of the Company effective January 1, 2000, the Company sponsored the stock-based compensation plans described below. The Company applied the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for grants made under the plans. Because all options granted after September 30, 1997 were granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates, no compensation expense was recognized in connection with such grants. No options were granted subsequent to September 30, 1999.
The Company sponsored a 1992 Nonqualified Stock Option Plan (1992 Plan) and a 1997 Nonqualified Stock Option Plan (1997 Plan). In accordance with the 1992 Plan, options to purchase the Company's common stock could have been granted to officers and key employees of the Company at 90% of the fair market value of the stock determined on the date of the grant. Under the 1997 Plan, options to purchase the Company's common stock could have been granted to officers and key employees of the Company at the fair market value of the stock determined on the date of the grant. Options from the 1992 Plan and the 1997 Plan were exercisable beginning two years from the date of the grant and expired five years from the date of the grant. In addition, upon a change in control event, which occurred with shareholder approval of the Company's acquisition by SCANA, all outstanding options became exercisable on July 1, 1999.
As of December 31, 1999 options outstanding under the plans totaled 644,145 with a weighted average exercise price of $19.08 and a weighted average remaining contractual life of 2.6 years. Exercise prices for these options ranged from $12.86 to $21.25. All of these options were exercised in 2000.
7. LONG-TERM DEBT
The annual amounts of long-term debt maturities for the years 2003 through 2007 are summarized as follows:
- ---------------- ----------------- ------------------ ----------------- Year Amount Year Amount - ---------------- ----------------- ------------------ ----------------- (Millions of Dollars)
2003 $7.5 2006 $3.2 2004 7.5 2007 3.2 2005 3.2 - ---------------- ----------------- ------------------ -----------------
8. SHORT-TERM BORROWINGS
Millions of dollars 2002 2001 - ------------------------------------------------------------- ---------------
Lines of credit $125.0 $125.0 Unused lines of credit $125.0 $125.0 Short-term borrowings outstanding: Commercial paper (270 or fewer days) $31.1 - Weighted average interest rate 1.42% n/a
The Company pays fees to banks as compensation for committed lines of credit.
The Company's commercial paper outstanding totaled $31.1 million at December 31, 2002, at a weighted average interest rate of 1.42%. The Company had no commercial paper outstanding at December 31, 2001.
9. INCOME TAXES
The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments:
o Cash and temporary cash investments are valued at their carrying amount.
o Fair values of long-term debt are based on quoted market prices of the instruments or similar instruments. For debt instruments for which there are no quoted market prices available, fair values are based on net present value calculations. The carrying values reflect the fair values of interest rate swaps based on settlement values obtained from counterparties. Early settlement of long-term debt may not be possible or may not be considered prudent.
o Short-term borrowings are valued at their carrying amount.
Effective January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS 133 requires the Company to recognize all derivative instruments as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. SFAS 133 further provides that changes in fair value of derivative instruments are either recognized in earnings or reported as other comprehensive income (loss), depending upon the intended use of the derivative and the resulting designation. The impact on the Company of adopting SFAS 133 was not material.
The Company has two outstanding interest rate swap agreements to pay variable and receive fixed rate interest payments on a combined notional amount of $40.6 million at December 31, 2002. These swaps were designated as fair value hedges of the Company's $8.6 million, 10% senior debenture due 2004 and $32.0 million, 8.75% senior debenture due 2012.
The fair value of these interest rate swaps is reflected within other deferred debits on the balance sheet. The corresponding hedge debt is also marked to market on the balance sheet. Receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred.
11. COMMITMENTS AND CONTINGENCIES
A. Environmental
The Company owns, or has owned, all or portions of seven sites in North Carolina on which manufactured gas plants (MGPs) were formerly operated. Intrusive investigation (including drilling, sampling and analysis) has begun at two sites, and the remaining sites have been evaluated using historical records and observations of current site conditions. These evaluations have revealed that MGP residuals are present or suspected at several of the sites. The Company's actual remediation costs for these sites will depend on a number of factors, such as actual site conditions, third-party claims and recoveries from other potentially responsible parties (PRPs). In September 2002 an allocation agreement was reached relieving the Company of liability for two of the seven sites. The Company has recorded a liability and associated regulatory asset of $7.8 million, which reflects its estimated remaining liability at December 31, 2002. Amounts incurred to date that have not been recovered through gas rates are approximately $1.2 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.
B. Claims and Litigation
The Company is also engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company.
C. Purchase Commitments
As of December 21, 2002 purchase commitments under forward contracts for natural gas purchases are $175 million and $56 million for 2003 and 2004, respectively.
12. SEGMENT OF BUSINESS INFORMATION
For the years ended December 31, 2002 and 2001, Gas Distribution was the Company's sole reportable segment. Subsidiaries whose operations comprised the Energy Marketing segment were sold to an affiliate effective January 1, 2001 (see Note 4). Gas distribution uses operating income to measure profitability. The Company did not have deferred tax assets prior to 2002, and has not had intersegment revenue subsequent to 2000.
Disclosure of Reportable Segments
PART II, ITEM 9 AND PART III
SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:
SCANA: None
SCE&G: None
PSNC Energy: None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
SCANA:
The other information required by Item 10 is incorporated herein by reference, to the captions "Election of Directors: Proposal 1 - Nominees For Class I Directors," "Continuing Directors," and "Other Information - Section 16(a) Beneficial Ownership Reporting Compliance" in SCANA's definitive proxy statement for the 2003 annual meeting of shareholders which was filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934.
*Indicates position held at least since March 1, 1998
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of SCE&G's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of SCE&G are owned by its directors and officers. Based solely on a review of the copies of such forms and amendments furnished to SCE&G and written representations from the officers and directors, SCE&G believes that during 2002 all Section 16(a) filing requirements applicable to its officers, directors and greater than 10% beneficial owners were complied with, except that each of Jimmy E. Addison, H. Thomas Arthur, Sarena D. Burch, Stephen A. Byrne, Mark R. Cannon, Duane C. Harris, Neville O. Lorick, Charles B. McFadden and James E. Swan filed late his or her Form 3.
ITEM 11. EXECUTIVE COMPENSATION
SCANA: The information called for by Item 11, Executive Compensation, is incorporated herein by reference to the captions "Director Compensation," "Compensation Committee Interlocks and Insider Participation," and "Executive Compensation" in SCANA's definitive proxy statement for the 2003 annual meeting of shareholders.
(1) Payments under the Annual Incentive Plan. (2) For 2002, other annual compensation consists of automobile allowance and life insurance premiums on policies owned by named executive officers of $9,000 and $7,435 for Mr. Timmerman; $9,000 and $7,958 for Mr. Lorick; $9,000 and $1,183 for Mr. Marsh; $9,000 and $6,830 for Mr. Arthur and $9,000 and $0 for Mr. Byrne. (3) Payouts under Performance Share. (4) All other compensation for all named executive officers consists solely of matching contributions to defined contribution plans. (5) Reflects actual salary paid in 2002. Base salary of $761,000 became effective on February 21, 2002.
All the above options vest 33 1/3% on each of the first, second and third anniversaries of the date of the grant, February 21, 2002.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
(a) (d) (e)
Number of Securities Underlying Value of Unexercised Unexercised In-the-Money Options/ Option/SARs SARs at At FY-End (#) FY-End ($) (1)
Exercisable/ Exercisable/ Name Unexercisable Unexercisable - --------------------------------------------------------------------------------
W. B. Timmerman 67,007/317,594 $281,501/$1,122,564 N. O. Lorick 13,792,103,067 51,440/357,835 K. B. Marsh 19,988,106,166 85,274/374,752 H. T. Arthur 12,245/58,685 54,414/208,693 S. A. Byrne 12,245/58,685 54,414/208,693
(1)Based on the closing price of $30.96 per share on December 31, 2002, the last trading date of the fiscal year.
Defined Benefit Plans
SCANA sponsors a tax qualified defined benefit retirement plan. The plan has a mandatory cash balance benefit formula (the "Cash Balance Formula") for employees hired on or after January 1, 2000. Effective July 1, 2000, SCANA employees hired prior to January 1, 2000 were given the choice of remaining under the Retirement Plan's final average pay benefit formula or switching to the cash balance benefit option. All the executive officers named in the Summary Compensation Table elected to participate under the cash balance option of the plan.
The Cash Balance Formula benefit is expressed in the form of a hypothetical account balance. Participants electing to participate under the cash balance option had an opening account balance established for them. The opening account balance was equal to the present value of the participant's June 30, 2000 accrued benefit under the final average pay formula. Participants who had 20 years of vesting service or who had 10 years of vesting service and whose age plus service equaled at least 60 were given transition credits. For these participants, the beginning account balance was determined so that projected benefits under the cash balance option approximated projected benefits under the final average pay formula at the earliest date at which unreduced benefits are payable under the plan.
Account balances are increased monthly by interest and compensation credits. The interest rate used for accumulating account balances changes annually and is equal to the average rate for 30-year Treasuries for December of the previous calendar year. Compensation credits equal 5% of compensation under the Social Security Wage Base and 10% of compensation in excess of the Social Security Wage Base.
In addition to its Retirement Plan for all employees, SCANA sponsors Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including officers. A SERP is an unfunded plan that provides for benefit payments in addition to benefits payable under the qualified Retirement Plan in order to replace benefits lost in the Retirement Plan because of Internal Revenue Code maximum benefit limitations.
The estimated annual retirement benefits payable as life annuities at age 65 under the plans, based on projected compensation (assuming increases of 4% per year), to the executive officers named in the Summary Compensation Table are as follows: Mr. Timmerman - $474,672; Mr. Lorick - $305,292; Mr. Marsh - $367,140; Mr. Arthur - $114,516 and Mr. Byrne - $289,992.
Termination, Severance and Change in Control Arrangements
SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to assist in retaining and attracting quality leadership in key SCANA positions in the current transitional environment of the utilities industry. The trust holds SCANA contributions (if made) which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA in the event of a Change in Control (as defined in the trust). The executive officers included in the Summary Compensation Table participate in all the plans listed below which are covered by the trust.
(1) SCANA Corporation Executive Deferred Compensation Plan (2) SCANA Corporation Supplemental Executive Retirement Plan (3) SCANA Corporation Long-Term Equity Compensation Plan (4) SCANA Corporation Annual Incentive Plan (5) SCANA Corporation Key Executive Severance Benefits Plan (6) SCANA Corporation Supplementary Key Executive Severance Benefits Plan
The Key Executive Severance Benefits Plan and each of the plans listed under (1) through (4) provide for payment of benefits in a lump sum to the eligible participants immediately upon a Change in Control, unless the Key Executive Severance Benefits Plan is terminated prior to the Change in Control. In contrast, the Supplementary Key Executive Severance Benefits Plan is operative for a period of 24 months following a Change in Control where the Key Executive Severance Benefits Plan is inoperative because it was terminated before the Change in Control. The Supplementary Key Executive Severance Benefits Plan provides benefits in lieu of those otherwise provided under plans (1) through (4) if: (i) the participant is involuntarily terminated from employment without "Just Cause," or (ii) the participant voluntarily terminates employment for "Good Reason" (as these terms are defined in the Supplementary Key Executive Severance Benefits Plan).
Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Key Executive Severance Benefits Plan is operative, include an amount equal to estimated federal, state and local income taxes and any estimated applicable excise taxes owed by the plan participants on those benefits.
The benefit distributions under the Key Executive Severance Benefits Plan would include the following three benefits:
o An amount equal to three times the sum of: (i) the participant's annual base salary in effect as of the Change in Control and (ii) the officer's target annual incentive award in effect as of the Change in Control under the Annual Incentive Plan.
o An amount equal to the projected cost for medical, long-term disability and certain life insurance coverage for three years following the Change in Control as though the participant had continued to be a SCANA employee.
o An amount equal to the participant's Supplemental Executive Retirement Plan benefit accrued to the date of the Change in Control, increased by the present value of projected benefits that would otherwise accrue under the plan (based on the plan's actuarial assumptions) assuming that the participant remained employed until reaching age 65 and offset by the value of the participant's Retirement Plan benefit.
Additional benefits payable upon a Change in Control where the Key Executive Severance Benefits Plan is operable are:
o A benefit distribution of all amounts credited to the participant's Executive Deferred Compensation Plan account as of the date of the Change in Control.
o A benefit distribution under the Long-Term Equity Compensation Plan equal to 100% of the targeted performance share awards for all performance periods not completed as of the date of the Change in Control, if any.
o Under the Long-Term Equity Compensation Plan, all nonqualified stock options awarded would become immediately exercisable and remain exercisable throughout their term.
o A benefit distribution under the Annual Incentive Plan equal to 100% of the target award in effect as of the date of the Change in Control.
The benefits and their respective amounts under the Supplementary Key Executive Severance Benefits Plan would be the same except that the benefits payable with respect to the Executive Deferred Compensation Plan would be increased by the prime rate published in the Wall Street Journal most nearly preceding the date of the Change in Control, plus 3%, calculated until the end of the month preceding the month in which the benefits are distributed.
Compensation Committee Interlocks and Insider Participation
During 2002, decisions on various elements of executive compensation were made by the Human Resources Committee and the Long-Term Equity Compensation Plan Committee. No officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Human Resources Committee or the Long-Term Equity Compensation Plan Committee.
The names of the persons who serve on the Human Resources and the Long-Term Equity Compensation Plan Committee can be found at Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Information.
Director Compensation
Board Fees
Officers who are also directors do not receive additional compensation for their service as directors. Since July 1, 2000, compensation for non-employee directors has included the following:
o an annual retainer of $30,000 (60% of the annual retainer fee is paid in shares of SCANA Common Stock); o $3,500 for each board meeting attended; o $3,000 for attendance at a committee meeting held on a day other than a regular meeting of the Board; o $250 for participation in a telephone conference meeting; o $2,000 for attendance at an all-day conference; and o reimbursement for expenses incurred in connection with all of the above.
Director Compensation and Deferral Plans
Since January 1, 2001, non-employee director compensation deferrals have been governed by the SCANA Corporation Director Compensation and Deferral Plan. Amounts deferred by directors in previous years under the SCANA Voluntary Deferral Plan continue to be governed by that plan. During 2002, the only director remaining in the Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $2,567 for the year.
Under the new plan, a director may elect to defer the 60% of the annual retainer fee required to be paid in stock in a hypothetical investment in SCANA Common Stock, with distribution from the plan to be ultimately payable in actual shares of SCANA Common Stock. A director may also elect to defer the 40% of the annual retainer fee not required to be paid in stock and up to 100% of meeting attendance and conference fees with distribution from the plan to be ultimately payable in either SCANA Common Stock or cash. Amounts payable in SCANA Common Stock accrue earnings during the deferral period at SCANA's dividend rate, which amount may be elected to be paid in cash when accrued or retained to invest in hypothetical shares of SCANA Common Stock. Amounts payable in cash accrue interest earnings until paid.
During 2002, Ms. Miller and Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York elected to defer 100% of their compensation and earnings under the Director Compensation and Deferral Plan so as to acquire hypothetical shares of SCANA Common Stock. In addition, Mr. Hagood elected to defer 60% of his annual retainer and earnings under the plan to acquire hypothetical shares of SCANA Common Stock.
Endowment Plan
Upon election to a second term, a director becomes eligible to participate in the SCANA Director Endowment Plan, which provides for SCANA to make a tax deductible, charitable contribution totaling $500,000 to institutions of higher education designated by the director. The plan is intended to reinforce SCANA's commitment to quality higher education and to enhance its ability to attract and retain qualified board members. A portion is contributed upon retirement of the director and the remainder upon the director's death. The plan is funded in part through insurance on the lives of the directors. Designated in-state institutions of higher education must be approved by the Chief Executive Officer of SCANA. Any out-of-state designation must be approved by the Human Resources Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the program.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER INFORMATION
SCANA: The information called for by Item 12, Security Ownership of Certain Beneficial Owners and Management is incorporated herein by reference to the caption "Share Ownership of Directors, Nominees and Executive Officers" and "Five Percent Ownership of SCANA Common Stock" in SCANA's definitive proxy statement for the 2003 annual meeting of shareholders.
*Each of the above owns less than 1% of the shares outstanding.
All directors and executive officers as a group (19 persons) total 662,150 shares, including 434,229 shares subject to currently exercisable options and options that will become exercisable within 60 days. Total percent of class outstanding is less than one percent.
(1) Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or named executive officers, as follows: Mr. Amick-480; Mr. Bookhart-6,335; and by all directors, nominees and executive officers 6,815 in total. (2) Includes shares purchased through February 28, 2003, by the Trustee under SCANA's Stock Purchase Savings Plan. (3) Hypothetical shares acquired under the SCANA Director Compensation and Deferral Plan are not included in the above table. As of February 28, 2003, each of the following directors had acquired under the plan the number of hypothetical shares following his or her name: Messrs. Amick-5,044, Bennett-5,715, Burkhardt-5,939, Hagood-1,988, Hipp-5,327, Sloan-5,218, Stowe-5,022, York-5,567 and Ms. Miller-5,718. (4) Includes shares subject to currently exercisable options and options that will become exercisable within 60 days in the following amounts: Mr. Timmerman-195,208; Mr. Lorick-52,745; Mr. Marsh-62,040; Mr. Byrne-35,888; Mr. Arthur-35,888. (5) Hypothetical shares acquired under the SCANA Executive Deferred Compensation Plan are not included in the above table. As of February 28, 2003, each of the following officers had acquired under the plan the number of hypothetical shares following his name: Mr. Timmerman-18,681; Mr. Lorick-2,531; Mr. Marsh- 4,394; Mr. Byrne-1,484; Mr. Arthur- 2,806. (6) Serves on the Human Resources Committee. (7) Serves on the Long-Term Equity Compensation Plan Committee.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SCANA: The information called for by Item 13, Certain Relationships and Related Transactions is incorporated herein by reference to the captions "Compensation Committee Interlocks and Insider Participation" and "Related Party Transactions" in SCANA's definitive proxy statement for the 2003 annual meeting of shareholders.
Notwithstanding anything to the contrary set forth in any of the Company's previous filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, that might incorporate by reference future filings, including this Annual Report on Form 10-K, in whole or in part, the "Report on Executive Compensation", the "Performance Graph" and the "Audit Committee Report" included in SCANA's definitive proxy statement for the 2003 annual meeting of shareholders shall not be incorporated by reference into any such filings.
SCE&G: For information regarding certain relationships and related transactions, see Item 11, Executive Compensation under the heading Compensation Committee Interlocks and Insider Participation and the following:
During 2002, SCANA paid $63,911 (including the value of non-utility in- kind services provided by SCANA and its subsidiaries) to subsidiaries of The Liberty Corporation for advertising expenses. SCANA's management believes that these services, the majority of which were arranged through the use of an independent third-party advertising agency, were provided at competitive market rates.
Mr. Hipp is Chairman and Chief Executive Officer and a director of The Liberty Corporation. It is anticipated that similar transactions will occur in the future.
ITEM 14. CONTROLS AND PROCEDURES
SCANA:
As of December 31, 2002, an evaluation was performed under the supervision and with the participation of the Company's management, including the CEO and CFO, of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that the Company's disclosure controls and procedures were effective as of December 31, 2002. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2002.
SCE&G:
As of December 31, 2002, an evaluation was performed under the supervision and with the participation of SCE&G's management, including the CEO and CFO, of the effectiveness of the design and operation of SCE&G's disclosure controls and procedures. Based on that evaluation, SCE&G's management, including the CEO and CFO, concluded that SCE&G's disclosure controls and procedures were effective as of December 31, 2002. There have been no significant changes in SCE&G's internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2002.
PSNC Energy:
As of December 31, 2002, an evaluation was performed under the supervision and with the participation of PSNC Energy's management, including the CEO and CFO, of the effectiveness of the design and operation of PSNC Energy's disclosure controls and procedures. Based on that evaluation, PSNC Energy's management, including the CEO and CFO, concluded that PSNC Energy's disclosure controls and procedures were effective as of December 31, 2002. There have been no significant changes in PSNC Energy's internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2002.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this report on this Form 10-K:
(1) Financial Statements and Schedules:
The Independent Auditor's Reports on the financial statements for SCANA, SCE&G and PSNC Energy are listed under Item 8 herein.
The financial statements and supplementary financial data filed as part of this report for SCANA, SCE&G and PSNC Energy are listed under Item 8 herein.
The Financial Statement Schedules filed as part of this report for SCANA, SCE&G and PSNC Energy begin on page 166.
(2) Exhibits
Exhibits required to be filed with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit number in prior filings are incorporated herein by reference and made a part hereof.
Pursuant to rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual report for SCANA's employee stock purchase plan will be furnished under cover of Form 10-K/A to the Commission when the information becomes available.
As permitted under Item 601(b)(4)(iii)of Regulation S-K, instruments defining the rights of holders of long-term debt of less than 10% of the total consolidated assets of SCANA, for itself and its subsidiaries, of SCE&G, for itself and its subsidiaries, and of PSNC Energy, for itself and its subsidiaries, have been omitted and SCANA, SCE&G and PSNC Energy agree to furnish a copy of such instruments to the Commission upon request.
(b) Reports on Form 8-K during the fourth quarter of 2002 for SCANA, SCE&G and PSNC Energy:
SCANA Corporation: Date of report: October 9, 2002 Item reported: Item 5