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. 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 also 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.
(1) Represents SCE&G's two-thirds portion of the Summer Station (one-third owned by Santee Cooper). (2) The steam unit at Williams Station is owned by GENCO. (3) This plant is leased from the DOE and is dedicated to DOE's Savannah River Site steam needs. The reported net generating capacity for this plant is its expected average hourly output. The lease expires on October 1, 2005. Although a formal contract is required, DOE has indicated orally and in writing its intention to extend the contract with SCE&G to October 1, 2014. (4) Two combined-cycle turbines burn natural gas or fuel oil to produce 341 MW of electric generation and use exhaust heat to replace coal-fired steam that powers two 75 MW turbines at the Urquhart Generating Station. Unit 3 remains as the only coal-fired steam unit at the site. (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 operate the plant for the City and the City will receive the power 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 22.9 million KVA (kilovolt-ampere). The transmission system consists of 3,188 miles of lines, and the distribution system consists of 17,377 pole miles of overhead lines and 4,587 trench miles of underground lines.
NATURAL GAS PROPERTIES
SCE&G's natural gas system consists of approximately 13,200 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 244 MMCF of natural gas.
SCPC's natural gas system consists of approximately 1,970 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 850 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 7,830 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 regasify 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.
SCG Pipeline became operational in November 2003. SCG Pipeline provides interstate transportation of natural gas from interconnections with Southern Natural at Port Wentworth, Georgia, and from an import terminal owned by Southern LNG at Elba Island, near Savannah, Georgia, to the site of the natural gas-fired generating station that SCE&G is building in Jasper County, South Carolina. Construction of SCG Pipeline 18.2 mile, 20 inch diameter transmission pipeline and appurtenant facilities was completed in November 2003.
In August 2003 SCPC began construction of a pipeline called the South System Loop pipeline project. This pipeline will stretch 38.3 miles from SCE&G's Jasper County generation facility to Yemassee in Hampton County, South Carolina, and will provide a new supply source to SCPC's current system. Completion of the pipeline is expected in the first quarter of 2004, at a cost of approximately $25 million.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Certain legal proceedings and environmental and regulatory matters and uncertainties, some of which remain outstanding at December 31, 2003, are described below. These issues affect the Company and, to the extent indicated, they also affect SCE&G or PSNC Energy.
Rate and Other Regulatory Matters
In May 2002 the SCPSC approved 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 reflected 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. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending. In January 2003, in conjunction with the approval of a retail rate increase, the SCPSC deferred action on SCE&G's recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order.
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, 2003 totaled approximately $169 million.
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 by the end of 2004, with certain monitoring and other activities continuing until 2007. As of December 31, 2003, SCE&G has spent approximately $19.7 million to remediate the Calhoun Park site, and expects to spend an additional $2.2 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. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from the Columbia MGP. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of December 31, 2003, SCE&G has spent approximately $3.0 million related to these three sites, and expects to spend an additional $5.0 million.
PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. 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. PSNC Energy has recorded a liability and associated regulatory asset of approximately $7.0 million, which reflects the estimated remaining liability at December 31, 2003. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of contract. The contract, entered into in 1983, known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract) required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government's breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. There are two additional causes of action alleged as well - a claim for damages for breach of the implied covenant of good faith and fair dealing and a takings claim demanding just compensation for the taking of the plaintiffs' real property (necessitated by the storage). This lawsuit is one of 48 similar lawsuits brought by nuclear utilities as of January 29, 2004.
Pending or Threatened Litigation
In 1999 an unsuccessful bidder for the purchase of propane gas assets of subsidiaries 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. SCANA is confident in its position and intends to vigorously defend the lawsuit. SCANA does not believe that the resolution of this issue will have a material adverse impact on its results of operations, cash flows or financial condition.
In 2001 a subsidiary of SCANA entered into, in the ordinary course of business, a fifteen-year take-and-pay contract with an unaffiliated natural gas supplier to purchase natural gas beginning in the spring of 2004. In December 2002, as a result of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract and the supplier initiated arbitration. In December 2003, an unrelated, creditworthy third party agreed to serve as supplier for the subsidiary for the fifteen year term with similar terms and conditions and a lower daily volume, and as a result the arbitration was dismissed and both parties executed releases of claims.
A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violates the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in this complaint are the subject of a similar lawsuit that was filed against SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and SCE&G. SCE&G believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.
On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. SCE&G is confident of the propriety of its actions and intends to mount a vigorous defense. SCE&G 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, SCE&G and PSNC Energy are also engaged in various other claims and litigation incidental to their business operations which management anticipates will be resolved without material loss to any of them.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
EXECUTIVE OFFICERS OF SCANA CORPORATION
The executive officers are elected at the annual meeting of the Board of Directors, held immediately after the annual meeting of shareholders, and hold office until the next such annual meeting, unless a resignation is submitted, or unless the Board of Directors shall otherwise determine. Positions held are for SCANA and all subsidiaries unless otherwise indicated.
The principal market for SCANA common stock is the NYSE, using the ticker symbol SCG. The corporate name SCANA is used in newspaper stock listings. At February 13, 2004 SCANA common stock totaling 110,731,020 shares were held by approximately 38,843 stockholders of record.
SCANA declared quarterly dividends on its common stock of $.345 per share and $.325 per share in 2003 and 2002, respectively.
All of SCE&G's and PSNC Energy's common stock is owned by SCANA and has no market. During 2003 and 2002 SCE&G paid $149.3 million and $152.5 million, respectively, in cash dividends to SCANA. During 2003 and 2002 PSNC Energy paid $18.5 million and $14.5 million, respectively, in cash distributions/dividends to SCANA.
Each of the ratings above had a "stable" outlook. Additional information regarding these debt and equity securities is provided in Notes 4, 5 and 7 to the consolidated financial statements for the Company and SCE&G and Notes 4 and 5 to the consolidated financial statements for PSNC Energy.
Securities ratings used by Moody's and Standard & Poors are as follows:
Long-term (investment grade) Short-term --------------------------------- ------------------------------- ---------------- ---------------- --------------- --------------- Moody's (1) S&P (2) Moody's S&P ----------- ------- ------- --- Aaa AAA Prime-1 (P-1) A-1 Aa AA Prime-2 (P-2) A-2 A A Prime-3 (P-3) A-3 Baa BBB Not Prime B C D ---------------- ---------------- --------------- ---------------
(1) Additional Modifiers: 1, 2, 3 (Aa to Baa) (2) Additional Modifiers: +/- (AA to BBB)
A security rating should be evaluated independently of other ratings and is not a recommendation to buy, sell or hold securities. In addition, security ratings are subject to revision or withdrawal at any time by the assigning rating organization.
For a discussion of provisions that could limit the payment of cash dividends see Management's Discussion and Analysis of Financial Condition and Results of Operations for the Company and SCE&G and Note 6 to the consolidated financial statements for the Company and SCE&G.
For a summary of equity securities issuable under the Company's compensation plans at December 31, 2003, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Information.
(1) Reflects acquisition of PSNC Energy effective January 1, 2000. (2) Reflects write-down for goodwill impairment in 2002 upon adoption of SFAS 142. (3) Other Statistics for 2000 exclude the effect of the change in accounting for unbilled revenues, where applicable.
SCANA CORPORATION
Item 7.
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 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 bySCANA's subsidiaries, (4) the impact of competition from other energy suppliers, including competition from alternate fuels in industrial interruptible markets, (5) growth opportunities for SCANA's regulated and diversified subsidiaries, (6) the results of financing efforts, (7) changes in SCANA's accounting policies, (8) weather conditions, especially in areas served by SCANA's subsidiaries, (9) performance and marketability of SCANA's investments in telecommunications companies, (10) performance of SCANA'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 SCANA's periodic reports filed with the SEC. SCANA disclaims any obligation to update any forward-looking statements.
OVERVIEW
SCANA is a registered holding company under PUHCA. Through its wholly owned regulated subsidiaries, SCANA is primarily engaged in the generation, transmission and distribution of electricity in parts of South Carolina and the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. Through a wholly owned nonregulated subsidiary, SCANA markets natural gas to retail customers in Georgia and to wholesale customers primarily in the southeast. Other wholly owned nonregulated subsidiaries hold investments in the securities of certain telecommunications companies, perform power plant management and maintenance services, provide service contracts to homeowners on certain home appliances and heating and air conditioning units, and through a service company, provide administrative, management and other services to other subsidiaries of SCANA
Following are percentages of SCANA's revenues and net income earned by regulated and nonregulated subsidiaries and the percentage of total assets held by them.
% of Revenues 2003 2002 2001 ---- ---- ---- Regulated 73% 75% 68% Nonregulated 27% 25% 32%
% of Net Income (Loss) 2003 2002 (1) 2001(2) ---- ---- ---- Regulated 92% 10% 45% Nonregulated 8% (110%) 55%
% of Assets 2003 2002 2001 ---- ---- ---- Regulated 93% 91% 85% Nonregulated 7% 9% 15%
(1) In 2002, net income for regulated subsidiaries totaled $13.6 million and net loss for nonregulated subsidiaries totaled $155.3 million. Net income for regulated subsidiaries included an impairment charge related to the acquisition adjustment associated with PSNC Energy ($230 million, net of tax). Net loss for nonregulated subsidiaries included impairment charges for the Company's telecommunications investments ($189.2 million, net of tax), which were partially offset by gains the Company recognized from the sale of a radio service network ($9.4 million, net of tax) and the sale of DTAG shares ($15.3 million, net of tax). See Results of Operations for more information.
(2) Net income from nonregulated subsidiaries in 2001 was significantly impacted by gains the Company recognized from the sale of shares of telecommunications investments ($354.4 million, net of tax) and the sale of the assets of a subsidiary ($4.7 million, net of tax). These gains were partially offset by impairment charges related to telecommunications investments, ($35.5 million, net of tax) and other investments ($9.0 million, net of tax). See Results of Operations for more information.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G, GENCO and Fuel Company, and is primarily engaged in the generation, transmission and distribution of electricity in South Carolina. At December 31, 2003 SCE&G provided electricity to over 570,000 customers in an area of approximately 15,000 square miles. GENCO owns and operates a coal-fired generating station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements.
Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which is currently 12.45%. Demand for electricity is primarily affected by weather, customer growth and the economy. In addition, significant legislative and regulatory matters could significantly impact the results of operations and cash flows for the electric operations segment.
In South Carolina the state legislature is not actively pursuing electric restructuring. However, both houses of the U.S. Congress passed energy legislation in 2003, with the House of Representatives passing an energy conference report. The Senate failed to pass the conference report due to its inability to reach a compromise on certain key issues unrelated to utilities. If a compromise is reached in 2004, such legislation is expected to contain provisions that would repeal PUHCA and transfer additional regulatory authority to FERC. This legislation may also impose stringent requirements on retail electric suppliers to generate electricity from renewable energy resources, which sources may or may not include hydroelectric generation. In addition, largely in response to the August 2003 blackout in eight northern states and parts of Canada, the energy legislation would likely include provisions to develop and enforce reliability standards for high-voltage transmission systems and to expedite construction of transmission lines. The Company cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.
If the energy legislation stalls in 2004, or if it fails to address certain issues, FERC is expected to proceed with regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. In July 2002 FERC issued a Notice of Proposed Rulemaking on Standard Market Design (SMD) which FERC supplemented with the issuance of a "white paper" in April 2003. If implemented, the proposed rule could 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 FERC's action to determine potential effects on SCE&G's operations. Additional directives from FERC are expected, and would likely be significantly influenced by the energy legislation discussed in the preceding paragraph.
The North American Electric Reliability Council (NERC) is comprised of utilities and other market participants who voluntarily develop and comply with NERC policies and standards which govern the planning and operation of the nation's interconnected bulk power system (the Grid). Currently these policies and standards are enforceable only through voluntary compliance by NERC members. Since the August 2003 blackout, and in response to issues identified during investigation of the blackout, NERC has been developing additional reliability standards, policies, and procedures. NERC is working with the regions and utilities in North America to strengthen existing enforcement and compliance programs, and is seeking to develop contracts between the regions and utility members to require compliance with these standards. NERC is also actively pursuing federal legislation to provide it with the authority to enforce reliability standards on all market participants, not just utilities. SCE&G continues to work with NERC and directly with other utilities to develop additional reliability policies and standards and continues to comply with NERC's existing policies and standards.
Gas Distribution
The gas distribution segment is comprised of the local distribution operations of SCE&G and PSNC Energy, and is primarily engaged in the purchase, transmission and sale of natural gas in portions of North Carolina and South Carolina. At December 31, 2003 this segment provided natural gas to more than 715,000 customers in an area of approximately 34,000 square miles.
Operating results for gas distribution are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which is currently 12.25% for SCE&G and 11.4% for PSNC Energy. Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact the Company's ability to retain large commercial and industrial customers.
Gas Transmission
The gas transmission segment is comprised of SCPC. SCPC 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 throughout most of South Carolina.
Operating results for gas transmission are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which for SCPC is currently 12.5% to 16.5%. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth. SCPC supplies natural gas to SCE&G for its resale to gas distribution customers and for certain electric generation needs. SCPC also sells natural gas to large commercial and industrial customers in South Carolina and faces the same competitive pressures as the gas distribution segment for these classes of customers.
Retail Gas Marketing
SCANA Energy, a division of SEMI, comprises the retail gas marketing segment. This segment markets natural gas to over 400,000 customers throughout Georgia. SCANA Energy's competitors include affiliates of other large energy companies with experience in Georgia's energy market as well as several electric membership cooperatives. SCANA's ability to maintain its market share depends on the prices it charges customers relative to the prices charged by its competitors, its ability to continue to provide high levels of customer service and other factors. In addition, the pipeline capacity available for SCANA Energy to serve industrial and other customers is tied to the market share held by SCANA Energy in the retail market.
In December 2003 SCANA Energy signed a definitive agreement with another marketer to acquire the approximately 50,000 retail natural gas customers being served by that marketer in Georgia. The purchase, which is subject to customary closing conditions, was approved by the GPSC in January 2004 and is expected to be completed in March 2004. With this transaction, SCANA Energy's total customer base will represent about a 30 percent share of the 1.5 million customers in Georgia's natural gas market. SCANA Energy remains the second largest natural gas marketer in the state.
In 2002 SCANA Energy was selected by the GPSC to serve as Georgia's regulated provider for a two-year period. In this capacity, SCANA Energy serves low-income customers at a rate subsidized by Georgia's Universal Service Fund, and extends service to high credit risk customers who have been denied service by other marketers. At December 31, 2003 SCANA Energy's regulated division served over 40,000 customers. In 2004 the GPSC may extend SCANA Energy's term for an additional year (beginning September 1) or may conduct another bidding process, in which SCANA Energy may participate, to select a regulated provider for a new term.
In July 2003 the GPSC approved a joint stipulation between the GPSC staff, Atlanta Gas Light Company (AGL) and natural gas marketers (excluding SCANA Energy). The joint stipulation, among other things, reduces the frequency whereby AGL can recall capacity previously released to the various gas marketers and streamlines certain gas balancing processes. Though SCANA Energy believes the joint stipulation will improve operations for itself and the other gas marketers, SCANA Energy continues to advocate an alternate plan it proposed that would assign interstate asset capacity to those gas marketers choosing assignment and approved by the GPSC. The GPSC filed a request with FERC to obtain a declaratory order on whether FERC regulation would preempt or have jurisdiction over SCANA Energy's proposal. Comments were due to FERC by December 26, 2003. It is uncertain how long it will take for FERC to issue an order. However, once an order is issued the GPSC will determine what action, if any, the GPSC should take on SCANA Energy's proposal.
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 9 to the consolidated financial statements.) As a part of this risk management process, at any given time, a portion of SCANA's projected natural gas needs has been purchased or otherwise placed under contract. Since SCANA Energy operates in a competitive market, it may be unable to sustain its current levels of customers and/or pricing, thereby reducing expected margins and profitability.
Energy Marketing
The divisions of SEMI, excluding SCANA Energy, comprise the energy marketing segment. This segment markets natural gas primarily in the southeast and provides energy-related risk management services to producers and customers.
The operating results for energy marketing are primarily influenced by customer demand for natural gas and the ability to control costs. Demand for natural gas is primarily affected by the price of alternate fuels and customer growth.
RESULTS OF OPERATIONS
The Company's reported earnings (loss) are prepared in accordance with GAAP. Management believes that, in addition to reported earnings (loss) under GAAP, the GAAP-adjusted net earnings from operations provides a meaningful representation of the Company's fundamental earnings power and period-over-period financial performance. A reconciliation of reported (GAAP) earnings (loss) per share to GAAP-adjusted net earnings from operations per share is provided in the table below:
Earnings (Loss) and Dividends
Reported (GAAP) earnings (loss) per share and GAAP-adjusted net earnings from operations per share of common stock and cash dividends declared for 2003, 2002 and 2001 were as follows:
o 2003 vs 2002 GAAP-adjusted net earnings from operations increased $.12 primarily due to higher electric margins of $.35, higher gas margins of $.25 and improved results from non- regulated subsidiaries of $.04. These factors were partially offset by higher operations and maintenance expenses of $.21 (including $.07 due to lower pension income), higher depreciation and amortization expense of $.11, higher property taxes of $.07, lower equity AFC of $.02 and the dilutive effect of additional shares outstanding of $.11.
o 2002 vs 2001 GAAP-adjusted net earnings from operations increased $.23 primarily due to higher electric margins 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 expenses of $.24 (including $.07 due to lower pension income), lower gas margins of $.15 and higher property taxes of $.07.
In 2003 the Company recognized a gain of $.35 per share in connection with the sale of ITC Holding and the receipt of an investment interest in a newly formed entity (Magnolia Holding). The Company also recorded impairment charges totaling $.31 per share related to the other than temporary decline in market value of its investment in Knology.
In 2002 the Company recorded an impairment charge of $1.72 per share related to the Company's investment in DTAG. In addition, the Company recorded an impairment charge of $.07 per share related to its investment in ITC^DeltaCom. 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 to the 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. In addition, the Company 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 (which was subsequently sold) of $.04 per share.
Pension Income
Pension income was recorded on the Company's financial statements as follows:
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 2003 decreased significantly compared to 2002 and 2001, primarily as a result of a less favorable investment market. See also the discussion of pension accounting in Critical Accounting Policies.
Allowance for Funds Used During Construction (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. The Company includes an equity portion of AFC in nonoperating income and a debt portion of AFC in interest charges (credits) as noncash items, both of which have the effect of increasing reported net income. AFC represented approximately 7.2% of income before income taxes in 2003, 25.8% in 2002 and 3.0% in 2001. The ratio in 2002 was significantly higher than historical norms due to the inclusion in income before income taxes of $291 million of impairments related to the other than temporary decline in market value of the Company's investment in DTAG and ITC^DeltaCom. The ratio in 2001 was lower than historical norms due to the inclusion in income before income taxes of a gain of $545 million on the exchange of the Company's investment in Powertel for shares of DTAG. In addition to the effect of impairments, the decrease in AFC for 2003 vs 2002 is partially due to the completion of the Urquhart Station repowering project in June 2002. Also, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. At the time the expenditures were included in the rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent construction expenditures related to the Jasper County generating and Lake Murray Dam projects (see discussion at CAPITAL PROJECTS).
In addition to the effect of impairments in 2002 and the gain in 2001, the increase in AFC for 2002 vs 2001 was primarily the result of increased construction expenditures for the Urquhart Station repowering, Jasper County generating and Lake Murray Dam projects.
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G, GENCO and Fuel Company. Electric operations sales margins for 2003, 2002 and 2001 were as follows:
o 2003 vs 2002 Margin increased primarily due to the increase in retail electric base rates approved in January 2003 totaling $63.6 million and customer growth and increased consumption of $24.3 million, partially offset by $27.3 million due to less favorable weather. Fuel used in generation increased by $9.3 million due to the increased cost of natural gas and fuel oil for the Urquhart combined cycle gas turbines and by $1.1 million due to the increased cost of nuclear fuel, partially offset by $5.5 million due to planned plant outages throughout the year. Purchased Power increased due to planned plant outages throughout the year.
o 2002 vs 2001 Margin increased primarily due to more favorable weather of $31.9 million and customer growth and increased consumption of $30.5 million. 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.
MWh sales volume by classes, related to the electric margin above, were as follows:
o 2003 vs 2002 Territorial sales volume decreased primarily due to less favorable weather. NMST volumes decreased primarily due to planned outages at generation plants that reduced volumes available for resale.
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 beginning in the third quarter of 2002.
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 2003, 2002 and 2001 were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 - --------------------------------------------------------------------------------
Operating revenues $869.0 32.9% $653.9 (17.6%) $793.6 Less: Gas purchased for resale 599.3 49.5% 401.0 (25.4%) 537.8 - ----------------------------------------- ---------- --------- Margin $269.7 6.6% $252.9 (1.1%) $255.8 ===================================================== ========== ========= =====
o 2003 vs 2002 Margin increased primarily due to customer growth and increased consumption totaling $20.9 million, partially offset by a decrease in industrial usage of $4.1 million primarily due to an unfavorable competitive position of natural gas relative to alternate fuels.
o 2002 vs 2001 Margin decreased primarily as a result of the slowing economy and increased competition with alternate fuels.
DT sales volume by classes, including transportation gas, were as follows:
Classification (in thousands) 2003 % Change 2002 % Change 2001 - ------------------------------------- -------- -------- ---------- - --------------------------------------------------------------------- ----------
Residential 38,542 8.0% 35,674 11.6% 31,967 Commercial 27,715 11.2% 24,927 5.7% 23,583 Industrial 20,109 (5.4%) 21,247 8.5% 19,578 Transportation gas 25,387 (15.8%) 30,166 7.1% 28,180 Sales for resale - - 1 1 1 - -------------------------------------- ---------- ---------- ---------- Total 111,754 (0.2%) 112,015 8.4% 103,309 ======================================= ========= ============ ========== ======
o 2003 vs 2002 Residential and commercial sales volumes increased primarily due to more favorable weather. Industrial and transportation volumes decreased in 2003 primarily as a result of interruptible customers using their alternate fuel sources during the year.
o 2002 vs 2001 Residential and commercial sales volumes increased primarily due to more favorable weather. Industrial and transportation volumes increased in 2002 primarily due to the volatility of the natural gas market in 2001, resulting in interruptible customers using their alternate fuel sources during that year.
Gas Transmission
Gas Transmission is comprised of the operations of SCPC. Gas transmission sales margins (including transactions with affiliates) for 2003, 2002 and 2001 were as follows:
o 2003 vs 2002 Margin increased primarily due to the favorable competitive position of natural gas relative to alternate fuels in the first quarter of $13.6 million, partially offset by the unfavorable competitive position of natural gas relative to alternate fuels in the second, third and fourth quarters of $1.5 million.
o 2002 vs 2001 Margin decreased primarily due to the unfavorable competitive position of natural gas relative to alternate fuels in the first quarter of $9.6 million, 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.
DT sales volume by classes including transportation were as follows:
Classification (in thousands)2003 % Change 2002 % Change 2001 ------------------------------------------------------------------------------ ------------------------------------------------------------------------------
Commercial 107 (8.8%) 118 64.6% 71 Industrial 31,436 (32.5%) 46,578 59.7% 29,176 Transportation 12,865 * 3,757 25.8% 2,987 Sales for resale 47,538 (16.5%) 56,906 8.2% 52,606 -------------------------------------- --------- ---------- ---------- Total 91,946 (14.4%) 107,359 26.5% 84,840 ============================================================================== *Greater than 100%
o 2003 vs 2002 Industrial volumes decreased approximately 6.0 million DTs due to decreased electric generation and approximately 8.8 million DTs due to competitiveness with alternate fuels. Transportation volumes increased approximately 9.1 million DTs and sales for resale volumes decreased approximately 9.4 million DTs primarily as a result of new transportation contracts with resale customers in 2003.
o 2002 vs 2001 Industrial volumes increased approximately 3.7 million DTs due to increased electric generation and approximately 4.4 million 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.
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 2003, 2002 and 2001 were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 --------------------------------------------------------------------------
Operating revenues $448.3 18.1% $379.5 (16.4%) $453.8 Net income 20.1 40.6% 14.3 * 6.8 ---------------------------------------------------------------- ------------- *Greater than 100%
o 2003 vs 2002 Operating revenues increased primarily as a result of higher average retail prices and increased volumes. Net income increased primarily due to increased margins of $10.8 million, partially offset by increased bad debt expense of $3.2 million, increased interest expense of $0.5 million and higher operating expense of $0.3 million.
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 a lower effective tax rate of $0.8 million, partially offset by a decrease in gas margin of $2.1 million and higher operating expenses of $0.9 million.
Delivered volumes for 2003, 2002 and 2001 totaled approximately 35.6 million, 33.8 million and 36.0 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 2003, 2002 and 2001 were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 ----------------------------------------------------------------- ------------
Operating revenues $415.7 31.2% $316.8 (48.4%) $613.4 Net income (loss) (1.1) (37.5%) (0.8) * 3.4 ----------------------------------------------------------------- ------------ *Greater than 100%
o 2003 vs 2002 Operating revenues increased $98.9 million which reflects a $146.0 million increase due to higher natural gas prices and a $45.9 million decrease due to lower volumes. Net loss increased primarily due to lower margins of $2.5 million partially offset by lower operating expenses of $2.3 million.
o 2002 vs 2001 Operating revenues decreased primarily due to lower natural gas prices and lower volumes. Net income decreased $4.2 million which reflects decreases of $5.3 million due to the closing of SCANA Energy Trading, LLC and $1.7 million due to lower margins, partially offset by increases of $1.3 million due to the closing of the unprofitable Midwest office in 2001 and $1.5 million due to lower bad debt expense.
Delivered volumes for 2003, 2002 and 2001 totaled approximately 73.6 million, 86.2 million and 114.6 million DT, respectively. Delivered volumes decreased in 2003 compared to 2002 by approximately 2.7 million DT due to decreased industrial usage and by approximately 9.8 million DT due to fewer customers caused by a sluggish economy and related customer credit constraints. Delivered volumes decreased in 2002 compared to 2001 primarily due to the closing of SCANA Energy Trading, LLC and the Midwest office in 2001.
Other Operating Expenses
Other operating expenses were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 - ------------------------------------------ -------------------------------------
Other operation and maintenance $558.3 6.9% $522.2 8.6% $480.8 Depreciation and amortization 238.3 8.3% 220.0 (1.7%) 223.8 Other taxes 139.2 9.7% 126.9 10.1% 115.3 --------- - ------------------------------------------ ---------- --------- Total $935.8 7.7% $869.1 6.0% $819.9 ========================================== =====================================
o 2003 vs 2002 Other operation and maintenance expenses increased primarily due to lower pension income of $13.2 million, increased labor and benefit costs of $8.3 million, increased bad debt expense of $6.5 million, increased nuclear operating expenses of $4.5 million and increased other operating expenses of $3.6 million. Depreciation and amortization increased by $11.4 million due to normal net property additions, by $4.2 million due to the completion of the Urquhart Station repowering project in June 2002 and by $2.7 million due to amortization of franchise fees. Other taxes increased primarily due to increased property taxes.
o 2002 vs 2001 Other operation and maintenance expenses increased primarily due to lower pension income of $11.6 million, increased labor and benefit costs of $19.2 million, increased nuclear refueling maintenance costs 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 to the 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. Other Income
Components of other income, excluding the equity component of AFC, were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 - ---------------------------------------------------------------------------
Gain on sale of investments $59.8 * $23.6 (95.7%) $545.3 Gain on sale of assets 1.2 (92.7%) 16.4 33.3% 12.3 Impairment of investments (53.1) (81.7%) (290.7) * (61.9) Other income 47.9 (0.8%) 48.3 21.7% 39.7 - ------------------------------------ ---------- ----------- ----------- Total $55.8 * $(202.4) * $535.4 =========================================================================== *Greater than 100%
A $59.8 million gain on sale of investments was recognized in 2003 in connection with the sale of ITC Holding and the receipt of an investment interest in a newly formed entity (Magnolia Holding). In 2002 $23.6 million was recognized upon the sale of the Company's DTAG stock. Gain on sale of assets in 2002 included the sale of the Company's radio system to Motorola. Impairments recorded in 2002 included those related to DTAG and ITC^DeltaCom, while impairments in 2003 related solely to the investment in Knology.
Interest Expense
Components of interest expense, excluding the debt component of AFC, were as follows:
Millions of dollars 2003 % Change 2002 % Change 2001 ------------------------------------------------------------------------------
Interest on long-term debt, net $205.2 0.1% $205.0 (8.4%) $223.8 Other interest expense 5.8 (4.9%) 6.1 (39.6%) 10.1 ------------------------------------------ --------- --------- --------- Total $211.0 (0.1%) $211.1 (9.8%) $233.9 ==============================================================================
o 2003 vs 2002 Interest expense remained flat due to an $8.5 million decreas e as a result of lower interest rates (including the effect of swaps) which was partially offset by an $8.3 million increase due to additional borrowings.
o 2002 vs 2001 Interest expense decreased by $20.8 million as a result of lower interest rates and by $1.4 million due to lower amortization of debt expense which occurred as a result of debt reduction.
Income Taxes
Income taxes increased approximately $98.9 million in 2003 compared to 2002 and decreased approximately $268.7 million in 2002 compared to 2001. Changes in income taxes are primarily due to changes in Other Income described above. The Company's effective tax rate for 2003 was approximately 31.7%, which reflects the impact of 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. The Company's effective tax rate has also been favorably impacted in recent years by the flow-through of federal investment tax credits and the recovery of the equity portion of AFC.
LIQUIDITY AND CAPITAL RESOURCES
Cash requirements for SCANA's regulated subsidiaries arise primarily from their operational needs, funding their construction programs and payment of dividends to SCANA. The ability of the regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend on their ability to attract the necessary financial capital on reasonable terms. Regulated subsidiaries recover the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and these subsidiaries continue their ongoing construction programs, rate increases will be sought. The future financial position and results of operations of the regulated subsidiaries will be affected by their ability to obtain adequate and timely rate and other regulatory relief, if requested.
The Company's leverage ratio of debt to capital increased significantly in 2000, when SCANA issued $700 million of long-term debt in connection with the purchase of PSNC Energy. At December 31, 2003 the leverage ratio was 60%. The Company's goal is to reduce this leverage ratio to between 50% to 52%. If the agencies rating the Company's credit determine that the Company will not be able to achieve sufficient improvement in the leverage ratio, these rating agencies may downgrade the Company's debt. Such a downgrade would adversely affect the interest rate the Company may obtain when issuing debt and would increase the rates applicable to the Company's short-term commercial paper programs. In order to bring the leverage ratio in line with rating agency expectations, the Company may apply cash flows from operations, sell equity securities, pay down debt with proceeds from the sale of telecommunications investments, or a combination of the three. In addition, SCE&G anticipates finishing construction on its Jasper County generating station and placing it in commercial operation in mid-2004. Once the plant is complete, SCE&G's capital expenditure budget is expected to decline significantly.
The Company's current estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 2004-2006 are as follows:
- ---------------------------------------- -------------- -------------- Type of Facilities 2004 2005 2006 - ------------------ ---- ---- ---- (Millions of dollars) SCE&G: Electric Plant: Generation $197 $52 $135 Transmission 45 51 42 Distribution 105 113 119 Other 14 13 12 Nuclear Fuel 22 5 31 Gas 23 21 23 Common 58 16 16 Other 2 2 - - ---------------------------------------- -------------- -------------- Total SCE&G 466 273 378 PSNC Energy 50 53 53 Other Companies Combined 66 32 44 - ---------------------------------------- -------------- -------------- Total $582 $358 $475 - ---------------------------------------- -------------- --------------
Included in other commercial commitments are estimated obligations under forward contracts for natural gas purchases. Many of these forward contracts include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts. Certain of these contracts relate to regulated businesses; therefore, the effects of such contracts on fuel costs are reflected in electric or gas rates. Also included in other commercial commitments is a 15-year "take-and-pay" contract for natural gas beginning in the spring of 2004, estimated obligations for coal supply purchases and certain obligations related to the Lake Murray Dam reinforcement project.
Included in purchase obligations are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such purchase obligations without penalty.
In addition to the contractual cash obligations above, the Company sponsors a noncontributory defined benefit pension plan and an unfunded health care and life insurance benefit plan for retirees. The pension plan is adequately funded, with no contributions having been required since 1997. No further contributions are anticipated until after 2008. Cash payments under the health care and life insurance benefit plan were approximately $13 million in 2003, and similar payments are expected in the future.
In addition, the Company is party to certain NYMEX futures contracts for which any unfavorable market movements through December 31, 2003 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 the anticipated sales transactions occur.
The Company also has nuclear fuel obligations that are not listed in the contractual cash obligations above. While no specific monetary amount is specified for nuclear fuel contracts, the Company's two-thirds share of expected cost is $22.2 million for the year 2004, a total of $54.6 million for the years 2005-2007, a total of $11.9 million for the years 2008-2009 and a total of $20.0 million for the years 2010-2011.
The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station that is not listed in the contractual cash obligations above. See Note 1 to the Company's consolidated financial statements.
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.
Cash outlays for 2004 (estimated) and 2003 (actual) for certain expenditures are as follows:
Millions of dollars 2004 2003 - --------------------------------------------------------------------------------
Property additions and construction expenditures, net of AFC $559 $725 Nuclear fuel expenditures 22 25 Investments 23 17 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $604 $767 ================================================================================
Included in cash outlays are the following specific projects:
o FERC mandated that SCE&G's Lake Murray Dam be reinforced to comply with new federal safety standards. Construction for the project and related activities is expected to be complete in 2005 at a cost of approximately $275 million, of which approximately $169 million had been incurred through December 31, 2003.
o Construction continues on SCE&G's 875 MW generation plant in Jasper County, South Carolina. The plant is expected to begin commercial operation in mid-2004 and cost approximately $450 million, of which approximately $425 million had been incurred through December 31, 2003.
o SCG Pipeline completed construction of an 18.2 mile pipeline in November 2003 at a cost of approximately $30 million. The pipeline will be used to transport natural gas from Port Wentworth and Elba Island, Georgia, to SCE&G's new generation plant in Jasper County, South Carolina.
o In August 2003 SCPC began construction of the South System Loop. This pipeline will stretch 38.3 miles from SCE&G's Jasper County generating facility to Yemassee in Hampton County, South Carolina, and will provide a new supply source to SCPC's current system. Completion of the pipeline is expected in the first quarter of 2004 at a cost of approximately $25 million.
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.
At December 31, 2003 SCANA, SCE&G and PSNC Energy had available the following lines of credit and short-term borrowings outstanding:
(Millions) SCANA SCE&G PSNC Energy - --------------------------------------------------- --------------------------- - --------------------------------------------------- --------------------------- Lines of credit: Committed $100 $400 $125 Uncommitted 113 (1) 78 - (1) Short-term borrowings outstanding: Commercial paper (270 or fewer days) - 140 55 Weighted average interest rate - 1.15% 1.17%
(1) Includes a $78 million uncommitted line that either SCANA or SCE&G may use.
In addition, SCE&G has a three-year revolving line of credit totaling $75 million, expiring in 2005, that provides backup liquidity.
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.
South Carolina Electric & Gas Company
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage) and covering substantially all of its properties, prohibits the issuance of additional bonds (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, 2003 the Bond Ratio was 5.08. 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 $1,279 million at December 31, 2003), (ii) retirements of Class A Bonds (which retirement credits totaled $156.9 million at December 31, 2003), 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, 2003 approximately $924.6 million 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, 2003 the New Bond Ratio was 4.87.
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, 2003, the Preferred Stock Ratio was 1.55.
The Articles also require the consent of 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, 2003 the ten percent test would have limited issuances of unsecured indebtedness to approximately $413.5 million. Unsecured indebtedness at December 31, 2003 totaled approximately $94.4 million, and was comprised of short-term borrowings.
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, 2003 SCE&G had not borrowed under the agreement, but expects to fully draw these amounts in 2004. Any such amounts would be included in the ten percent test.
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 regulatory approval, the Indenture under which they are issued contains no specific limit on the amount which may be issued.
Financing Cash Flows
During 2003 the Company experienced net cash outflows related to financing activities of approximately $105 million primarily due to the reduction of long- and short-term debt and payment of dividends. Conversely, SCE&G experienced net cash inflows related to financing activities of approximately $106 million primarily arising from borrowings in support of SCE&G's construction program and for general corporate purposes.
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 rate 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 upon termination of such swaps are recorded as basis adjustments to long-term debt and are amortized as reductions to interest expense over the term of the underlying debt. At December 31, 2003 the estimated fair value of the Company's swaps totaled $6.3 million (gain) related to combined notional amounts of $333.1 million.
In anticipation of the issuance of debt, the Company may use interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within other deferred debits or credits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, the Company paid approximately $3.5 million upon the termination of a forward starting interest rate swap.
On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance will be used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.
On February 19, 2004 SCANA increased the quarterly cash dividend rate on SCANA common stock to $.365 per share, an increase of 5.8%. The new dividend is payable April 1, 2004 to stockholders of record on March 10, 2004.
For additional information on significant financing transactions, see the Consolidated Statements of Capitalization and Note 4 to the consolidated financial statements for the Company.
ENVIRONMENTAL MATTERS
Capital Expenditures
In the years 2001 through 2003, the Company's capital expenditures for environmental control totaled approximately $227.5 million. These expenditures were in addition to expenditures included in "Other operation and maintenance" expenses, which were approximately $29.2 million, $29.9 million, and $23.0 million during 2003, 2002 and 2001, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for the Company are $41.2 million for 2004 and $207.7 million for the four-year period 2005 through 2008. These expenditures are included in the Company's construction program, discussed in Liquidity and Capital Resources and include the matters discussed below.
Electric Operations
The 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 had indicated that it would finalize regulations by December 2004 for stricter limits on mercury and other pollutants generated by coal-fired plants.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJ has brought suit against a number of utilities in federal court alleging violations of the CAA. At least two of these suits have either been tried or have had substantive motions decided - one favorable to the industry and one not. Neither is binding as precedent on the Company. 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). SCE&G and GENCO 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. On October 27, 2003 EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The new rule represents an industry-favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to the Company is uncertain. 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 under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. The current state of continued DOJ enforcement actions is the subject of speculation industry-wide, but it is possible that the EPA will commence enforcement actions against SCE&G and GENCO, 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 enforcement actions relative to the Company's, SCE&G's or GENCO's compliance with the CAA would be without merit. However, if successful, such actions could have a material adverse effect on the Company's financial condition, cash flows and results of operations. To comply with current and anticipated state and federal regulations, SCE&G and GENCO expect to incur capital expenditures totaling approximately $204.3 million over the 2004-2008 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $2.3 million per year. To meet compliance requirements for the years 2009 through 2013, the Company anticipates additional capital expenditures totaling approximately $92.7 million.
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 2004. 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 financial condition, results of operations and cash flows of the Company, SCE&G and GENCO.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 required that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mil per KWh of net nuclear generation after April 7, 1983. Payments, which began in 1983, are subject to change and will extend through the operating life of SCE&G's Summer Station. SCE&G entered into a contract with the DOE in 1983 providing for permanent disposal of its spent nuclear fuel by the DOE. The DOE presently estimates that the permanent storage facility will not be available until 2010. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through spent fuel pool reracking, dry cask storage or other technology as it becomes available. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available.
On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of the above contract. The contract known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract) required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government's breach of contract, the plaintiffs have incurred and will continue to incur substantial costs. There are two additional causes of action alleged as well - damages for breach of the implied covenant of good faith and fair dealing and a takings claim demanding just compensation for the taking of the plaintiffs' real property (necessitated by the storage). This lawsuit is one of 48 similar lawsuits brought by nuclear utilities as of January 29, 2004.
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 $10.9 million and $17.9 million at December 31, 2003 and 2002, 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 by the end of 2004, with certain monitoring and other activities continuing until 2007. As of December 31, 2003, SCE&G has spent approximately $19.7 million to remediate the Calhoun Park site, and expects to spend an additional $2.2 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. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from the Columbia MGP. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of December 31, 2003, SCE&G has spent approximately $3.0 million related to these three sites, and expects to spend an additional $5.0 million.
In addition, PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. PSNC Energy has recorded a liability and associated regulatory asset of approximately $7.0 million, which reflects the estimated remaining liability at December 31, 2003. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
REGULATORY MATTERS
Material retail rate proceedings are described in more detail in Note 2 to the Company's consolidated financial statements.
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.
In conjunction with a January 2003 order, the SCPSC allowed SCE&G to include all Jasper County generating station project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. Once this generating station is complete, SCE&G may seek to include the remaining project expenditures in its electric rate base. Construction expenditures for the Lake Murray Dam construction project, which totaled approximately $169 million as of December 31, 2003, have not been included in electric rate base. When the Lake Murray project is completed in 2005, SCE&G will determine whether to seek inclusion of such expenditures in electric rate base.
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, 2003 is approximately $2.5 million, and through December 31, 2003, they have generated and passed through to SCE&G approximately $97.4 million in such tax credits. At December 31, 2003 SCE&G has recorded on its balance sheet $66.6 million net deferred fuel tax benefits, which include partnership losses, net of tax. In addition, Primesouth, Inc., a non-regulated subsidiary of SCANA, operates a synthetic fuel facility for a third party and receives management fees, royalties and expense reimbursements related to these services. Primesouth does not benefit from any synfuel 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, net of partnership losses and other expenses, 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 to the consolidated financial statements.
The IRS has completed and closed examinations of the Company's consolidated federal income tax returns through its tax year ended in 2000, with the exception of the Company's interest in the synthetic fuel partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it is in the process of closing this partnership examination with no changes being proposed, and that a formal closing letter is forthcoming. The IRS audit report makes no challenge to the declaration that the synthetic fuel facility was properly placed in service, and takes no issue with evidence submitted demonstrating that the facility produces a qualifying fuel.
On October 29, 2003, the IRS issued Announcement 2003-70 stating that it had completed a review of chemical change issues associated with tax credits claimed under IRC Section 29 relating to the production and sale of synthetic fuel. It further stated that it would resume the issuance of private letter rulings (PLRs) concerning synthetic fuel credits consistent with the guidelines regarding chemical change previously set forth in Revenue Procedures 2001-30 and 2001-34 and certain additional requirements related to sampling, testing and recordkeeping procedures, even though the IRS has indicated that the level of chemical change required under that guidance is not sufficient for IRC Section 29 purposes. The IRS also stated in the announcement that it would continue to issue PLRs because it recognized that many taxpayers and their investors have relied on its long standing ruling practice to make investments. In Announcement 2003-46 issued on June 27, 2003, the IRS had questioned the validity of certain test procedures and results that had been presented to it by taxpayers with interests in synfuel operations as evidence that the required significant chemical change had occurred, and had initiated a review of these test procedures and results which was completed as noted in Announcement 2003-70.
Separately, the Permanent Subcommittee on Investigations of the Government Affairs Committee of the United States Senate (Subcommittee) is conducting an investigation of potential abuses of tax credits by producers of synthetic fuel under IRC Section 29. The Subcommittee Chairman, in a memorandum commencing the investigation, has stated that he anticipates the investigation will focus on whether certain synthetic fuel producers are claiming tax credits even though their product is not a qualified synthetic fuel under Section 29 and IRS regulations. The memorandum also states that the investigation will address whether certain corporations are engaging in transactions solely to take advantage of unused Section 29 credits with no other business purpose, and the IRS' efforts to curb abuses related to these credits.
While the effect of these two developments is not clear, the Company is aware that PLRs have been issued since October 29, 2003. The Company has not had any communication with the Subcommittee staff, and with the imminent conclusion of the IRS audit, the Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.
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 into 2042. At December 31, 2003 SCE&G had capitalized approximately $8.0 million related to the application process and expects to capitalize an additional $1.0 million in 2004. SCE&G expects the extension to be granted in mid-2004.
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. As a condition to obtaining the NCUC's approval of SCANA's acquisition of PSNC Energy, PSNC Energy agreed to a moratorium on general rate cases until August 2005. General rate relief can be obtained to recover costs associated with materially adverse governmental actions and force majeure events.
The U. S. Congress passed the Pipeline Safety Improvement Act of 2002 (the Act), which directs the U. S. Department of Transportation (DOT) to establish a pipeline integrity management rule for operations of natural gas transmission pipelines that have moderate to high-density population areas within close proximity. The Act requires DOT to set stringent regulations on segments of transmission pipeline where leaks or ruptures could threaten people or property. As a result, PSNC Energy must inspect and assess the physical reliability of the approximately 500 miles of its transmission line that are covered by the Act within the initial ten-year deadline established by the Act. Depending on the assessment method used, PSNC Energy will be required to reinspect these same lines every five to seven years after the initial deadline. Total costs for compliance with the Act have not been determined.
South Carolina Pipeline Corporation
SCPC has 2,000 miles of transmission line that are covered by the Act. Total costs for compliance with the Act have not been determined.
CRITICAL ACCOUNTING POLICIES
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.
Utility Regulation
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. 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. See Note 1 of Notes to the consolidated financial statements for a description of the Company's regulatory assets and liabilities, including those associated with the Company's environmental assessment program.
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, 2003 the Company's net investments in fossil/hydro and nuclear generation assets were approximately $2,363 million and $563 million, respectively.
Revenue Recognition and Unbilled Revenues
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of 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, the Company records 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, 2003 and 2002, accounts receivable included unbilled revenues of $133.9 million and $107.7 million, respectively, compared to total revenues for 2003 and 2002 of $3.42 billion and $2.95 billion, respectively.
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 expected write-offs. These estimates are based on, among other things, comparisons of the relative age of accounts, assigned credit ratings for commercial and industrial accounts, and consideration of actual write-off history. The distribution segments of the Company's regulated utilities have established write-off histories and regulated service areas that enable the utilities to reliably estimate their respective provisions 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.
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, and changes in financial assumptions such as discount rates and timing of cash flows. SCE&G expects to receive a 20-year license extension for Summer Station that will significantly impact the eventual cost of and funding for decommissioning. 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.
Under SCE&G's method of funding decommissioning costs, 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.
Accounting for Pensions and Other Postretirement Benefits
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 $5.0 million recorded in 2003 reflects the use of a 6.5% discount rate and an assumed 9.25% long-term return on plan assets. SCANA believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 6.0% in 2003 would have lowered SCANA's pension income by approximately $1.9 million. Had the assumed long-term return on assets been reduced to 9.0% in 2003, SCANA's pension income would have been reduced by approximately $1.6 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 beginning of year discount rate of 6.5% as being within a reasonable range of interest rates for obligations rated Aa by Moody's as of January 1, 2003. This same discount rate was also selected for determination of other postemployment benefits (OPEB) costs discussed below.
The following information with respect to pension assets (and returns thereon) 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 25 year cumulative actual returns of 10.8%, 12.0% and 12.7%, respectively, all of 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 a target asset allocation of 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 investment performance in 2000-2002 and the recent 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 after 2008.
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 6.5% and recorded a net SFAS 106 cost of $17.3 million for 2003. Had the selected discount rate been 6.0%, the expense for 2003 would have been approximately $0.5 million higher.
Goodwill
In connection with the adoption, effective January 1, 2002, of SFAS 142, "Goodwill and Other Intangible Assets," the Company performed a valuation analysis of its investment in SCPC (the Company's Gas Transmission segment) using a discounted cash flow analysis and of PSNC Energy (part of the Company's 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 PSNC Energy's 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. Subsequent annual calculations required by SFAS 142 have indicated no need for further write-downs.
Asset Retirement Obligations
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 their acquisition, construction, development and normal operation. Because such obligation relates solely to the Company's regulated electric utility, adoption of SFAS 143 had no impact on results of operations; however, as of January 1, 2003, the Company recorded an ARO of approximately $111 million, which exceeded the previously recorded reserve for nuclear plant decommissioning of approximately $87 million. At December 31, 2003 such ARO totaled approximately $118 million.
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.
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," or as described in Financial Accounting Standards Board Interpretation 46, "Consolidation of Variable Interest Entities." SCANA 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.
Claims and Litigation
For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and the consolidated financial statements for the Company (Note 10), SCE&G (Note 10) and PSNC Energy (Note 8).
Telecommunications Investments
The Company's basis in telecommunications investments at December 31, 2003 totaled $47.0 million for equity securities and $62.5 million for debt securities. For a description of such investments, see Note 9 to the Company's consolidated financial statements.
ITEM 7A.
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.
At December 31, 2003 the Company held investments in the 13% senior unsecured notes (due 2009) of a telecommunications company, the cost basis of which, including accrued interest, is approximately $49.5 million. As these notes are not actively traded, determination of their fair value is not practicable.
Commodity price risk - The following tables provide information about the Company's financial instruments that are sensitive to changes in natural gas prices. Weighted average settlement prices are per 10,000 mmbtu. Fair values represent quoted market prices.
Strike Contract Price Amount (a) Options: Purchased call (long)($) 5.55 43.4
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 - ------------------------------- ----------- ----- ---------------
(a) weighted average
The Company uses derivative instruments to hedge forward purchases and sales of natural gas, which create market risks of different types. See Note 9 of the Company's consolidated financial statements.
The NYMEX futures information above includes those financial positions of Energy Marketing, SCPC and PSNC Energy. 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 and, as such, are subject to the SCPSC's annual prudency review. The offset to the change in fair value of these derivatives is recorded as a current 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 provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs. In an October 2003 order, in connection with PSNC Energy's 2003 annual prudency review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2003.
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 $50.2 million at December 31, 2003. A temporary decline in value of ten percent would result in a $5.0 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 $5.0 million reduction in fair value and a corresponding adjustment to net income, net of tax effect. The investment in preferred stock with significant debt characteristics is carried at cost of $13.0 million at December 31, 2003. A temporary decline in value of ten percent would result in a $1.3 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 $1.3 million reduction in fair value and a corresponding adjustment to net income, net of tax effect.
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, 2003 and 2002 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, 2003. 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, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 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 Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," effective January 1, 2002.
s/Deloitte & Touche LLP Columbia, South Carolina February 26, 2004
SCANA Corporation CONSOLIDATED STATEMENTS OF CAPITALIZATION
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 predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to 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 one other wholly owned subsidiary 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, which requires cost-based rate-regulated utilities to recognize in their financial statements certain 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, 2003, approximately $368 million and $519 million of regulatory assets (including environmental) and liabilities, respectively, as shown below.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections - fuel adjustment clauses, net represent amounts 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 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. Such costs, totaling approximately $10.9 million, are expected to be fully recovered by the end of 2009. A portion of the costs incurred at sites owned by PSNC Energy is also being recovered through rates, and management believes the remaining costs of approximately $7.0 million will be recoverable. Amounts incurred and deferred to date that are not currently being recovered through gas rates at PSNC Energy are approximately $2.2 million. (See Note 2).
Asset retirement obligation - nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1N).
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 SCE&G's two partnerships involved in converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships and consumed by SCE&G and ultimately passed through to SCE&G, net of partnership losses and other expenses, 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 period of approximately ten years. The accumulated storm damage reserve can be applied to offset actual incremental 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. These amounts are not earning a return, but are being amortized through cost of service over approximately 15 years.
Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists. The SCPSC and the NCUC (collectively, state commissions) 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 a state commission. 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 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 Company's results of operations, liquidity or financial position in the period the write-off would be recorded.
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 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 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 $1,002.8 million and $962.4 million as of December 31, 2003 and 2002, respectively (including amounts related to ARO). Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $449.5 million and $417.9 million as of December 31, 2003 and 2002, respectively (including amounts related to ARO). SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses and totaled approximately $74.7 million for the year ended December 31, 2003.
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. SCE&G accrued approximately $0.5 million per month from January 2001 through June 2002 for the outage period ended June 2002, and approximately $0.6 million per month from July 2002 through December 2003 for the outage period ended December 2003. Total outage costs for the fall 2003 outage were approximately $20.6 million, of which SCE&G was responsible for approximately $13.9 million.
E. Allowance for Funds Used During Construction (AFC)
AFC is a noncash item that reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.1%, 8.3% and 8.8% for 2003, 2002 and 2001, 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. Unbilled revenues totaled approximately $133.9 million and $107.7 million as of December 31, 2003 and 2002, 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 $26.7 million and $25.3 million at December 31, 2003 and 2002, respectively, which amounts are included in other regulatory assets.
Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the state commission 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, 2003 and 2002 SCE&G had undercollected through the gas cost recovery procedure approximately $11.9 million and $24.6 million, respectively, which amounts are also included in other regulatory assets. At December 31, 2003 PSNC Energy had overcollected through the gas cost recovery procedure approximately $1.0 million, which is included in other regulatory liabilities. At December 31, 2002 PSNC Energy had undercollected $10.6 million which is included in other regulatory assets.
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:
2003 2002 2001 - -------------------------------------- -------------- --------------- SCE&G 3.02% 2.93% 2.98% GENCO 2.66% 2.66% 2.71% SCPC 2.13% 2.14% 2.60% PSNC Energy 4.05% 4.29% 4.06% Aggregate of Above 3.10% 3.06% 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. See Note 1H.
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 or $2.17 per share. The resulting impairment charge is reflected on the statement of operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed its annual evaluation as of January 1, 2003 and no further impairment was indicated.
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 records its liability for decommissioning cost in deferred credits.
Under SCE&G's method of funding decommissioning costs, funds collected through rates ($3.2 million in each of 2003, 2002 and 2001) 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.
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 $1.5 million and $2.0 million at December 31, 2003 and 2002, 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 is included in other regulatory assets.
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 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 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 are amortized with recovery provided through rates. Deferred amounts for SCE&G, net of amounts previously recovered through rates and insurance settlements, totaled $10.9 million and $17.9 million at December 31, 2003 and 2002, respectively. Deferred amounts for PSNC Energy totaled approximately $7.0 million and $7.8 million at December 31, 2003 and 2002, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 10C.
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, repurchase agreements, treasury bills and notes.
M. Commodity Derivatives
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. Substantially all of the Company's derivatives contracts do not extend beyond two years. (See Note 9). 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 current asset or liability. PSNC Energy's tariffs include a provision for the recovery of actual gas costs incurred. PSNC Energy records transactions fees and any realized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs.
N. New Accounting Standards
The Company adopted SFAS 143 effective January 1, 2003. SFAS 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. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits (each totaling approximately $87 million) related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the initial measurement of the ARO, the amounts reflected within these regulatory assets and liabilities were recharacterized.
The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the Consolidated Balance Sheet as of December 31, 2003, and the proforma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001.
Proforma net income (loss) and earnings (loss) per share for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods.
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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146.
The Company adopted the disclosure provisions of SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," effective January 1, 2003. SFAS 148 requires 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 148.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 149.
SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150.
The Company adopted SFAS 132 (Revised 2003), Employers' Disclosure about Pension and Other Postretirement Benefits," which is effective for financial statements issued for fiscal years ending December 15, 2003. This statement increased existing disclosure requirements by requiring more details about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of this statement.
O. Equity Compensation Plan
Under the SCANA Corporation Long-Term Equity Compensation Plan (the 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 SFAS 148 "Accounting for Stock-Based Compensation - Transition and Disclosure."
All options have been granted with exercise prices equal to the fair market value of the Company's stock on the respective grant dates since the Plan's inception; therefore, 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, pro forma net income (loss) and earnings (loss) per share would have been as presented below:
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. Affiliated Transactions
SCE&G holds two equity-method investments in partnerships involved in converting coal to non-conventional fuel. SCE&G had recorded as receivables from these affiliated companies approximately $13.4 million and $8.5 million at December 31, 2003 and 2002, respectively. SCE&G had recorded as payables to these affiliated companies approximately $12.2 million and $8.0 million at December 31, 2003 and 2002, respectively.
R. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
S. 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. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company (SCE&G)
Electric
In January 2003 the SCPSC granted SCE&G a composite increase in retail electric rates of approximately 5.8% 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 its order, the SCPSC extended through 2005 its approval of the accelerated capital recovery plan for SCE&G's Cope Generating Station. Under the plan, based on the level of revenues and operating expenses, 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 additional 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 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 was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving SCE&G's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of SCE&G's purchasing practices and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order discussed below.
In December 2002 the SCPSC approved 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 approved 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 reflected 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. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending.
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, 2003 and 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002 $.928 March-October 2003 $.728 November-December 2002 $.877 November-December 2003
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 2003, as a result of the annual review, the SCPSC approved SCE&G's request to reduce the billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at December 31, 2003 of $10.9 million.
Public Service Company of North Carolina, Incorporated (PSNC Energy)
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 2003 and 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002 $.595 March 2003 $.215 February-June 2002 $.725 April-November 2003 $.350 July-October 2002 $.600 December 2003 $.410 November-December 2002
On October 13, 2003 in connection with PSNC Energy's 2003 Annual Prudence Review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2003. The NCUC also authorized new rate decrements to refund overcollections of certain gas costs included in PSNC Energy's deferred accounts, effective November 1, 2003.
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 in 2002, and the Swain County portion is expected to be completed in the spring of 2004. Through December 31, 2003 approximately $27.4 million had been spent on this project.
In December 1999 the NCUC issued an order approving the Company'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 order dated August 5, 2003, the SCPSC found that for the period April 2002 through December 2002 SCPC's gas purchasing policies and practices were prudent and SCPC properly adhered to the gas cost recovery provisions of its gas tariff.
3. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Pension and Other Postretirement 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 credited 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.
In addition to pension benefits, the Company provides certain unfunded postretirement 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.
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Information regarding the benefit obligations and the funding thereof is presented below.
Changes in Benefit Obligation
Data related to the changes in the projected benefit obligation for retirement benefits and the accumulated benefit obligation for other postretirement benefits are presented below.
The accumulated benefit obligation for retirement benefits at the end of 2003 and 2002 was $589.8 million and $570.0 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.
Significant assumptions used to determine the above benefit obligations are as follows:
A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to decrease gradually to 5.0% for 2011 and remain at that level thereafter. The effects of a one percentage point increase or decrease on accumulated other postretirement benefit obligation for health care benefits are as follows:
1% 1% Millions of dollars Increase Decrease ------------------------------
Effect on postretirement benefit obligation $0.9 $(1.1)
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed December 8, 2003 to make additional voluntary prescription drug benefits available through Medicare. SCANA has elected not to recognize the effects of the Act in these financial statements. The Company will be evaluating the implications of the Act during 2004 and will recognize expected financial effects as prescribed by accounting standards in effect for subsequent reporting periods.
Changes in Plan Assets
Retirement Benefits ----------------------------------- Millions of dollars 2003 2002 ---- ----
Fair value of plan assets, January 1 $666.9 $831.6 Actual return on plan assets 150.3 (130.0) Benefits paid (29.5) (34.7) ------ ----- Fair value of plan assets, December 31 $787.7 $666.9 ====== ======
At the end of 2003 and 2002, the fair value of plan assets for the pension plan exceeded both the benefit obligation and the accumulated benefit obligation discussed above. Since the accumulated benefit obligation is less than the fair value of plan assets, there is no adjustment to other comprehensive income.
In connection with the joint ownership of Summer Station, as of December 31, 2003 and 2002 the Company recorded within deferred credits a $9.3 million and $9.1 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, 2003 and 2002, the Company also recorded a $6.5 million and $6.4 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.
Expected Cash Flows
The total benefits expected to be paid from the pension plan or from the Company's assets for the pension and other postretirement benefits plans, respectively, are as follows:
Expected Benefit Payments Millions of dol Pension Benefits Other Postretirement Benefits* - --------------------------------------- --------------------------------- - --------------------------------------- --------------------------------- 2004 $39.2 $13.4 2005 41.0 13.7 2006 42.8 14.0 2007 43.3 14.3 2008 48.0 14.5 2009 - 2013 266.0 75.2 * Net of participant contributions
Net Periodic Cost
As allowed by SFAS 87 and SFAS 106, 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:
The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $100,000.
Pension Plan Contributions
While the investment performance over the 2000-2002 period and the recent decline in discount rates have significantly reduced the level of pension income, the pension trust has been and remains adequately funded. No contributions have been required since 1997, and the Company does not anticipate making contributions to the funded pension plan in 2004. As such, these declines in pension income have had no impact on the Company's cash flows.
Pension Plan Asset Allocations
The Company's pension plan asset allocation at December 31, 2003 and 2002 and the target allocation for 2004 are as follows:
Target Percentage of Plan Assets Asset Category Allocation At December 31 ---------- -------------- 2004 2003 2002 ---- ---- ---- Equity Securities 70% 71% 73% Debt Securities 30% 29% 27%
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability for the pension plan, (2) maximizing return within reasonable and prudent levels of risk in order to minimize contributions, and (3) maintaining sufficient liquidity to meet benefit payment obligations on a timely basis. These objectives have been based on a ten-year investment horizon, so that interim fluctuations should be viewed with appropriate perspective. The pension plan operates with several risk and control procedures, including ongoing reviews of liabilities, investment objectives, investment managers and performance expectations. Transactions involving certain types of investments are prohibited. Equity securities held by the pension plan during the above periods did not include SCANA Corporation common stock.
In developing the expected long-term rate of return assumptions, management continually evaluates the pension plan's historical cumulative actual returns over several periods, all of which returns have been in excess of related broad indices, and management anticipates that the pension 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 a target asset allocation of 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.
Long-Term Equity Compensation Plan
The Long-Term Equity Compensation 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, 2000 160,429 25.53 Granted 716,368 27.43 Exercised - n/a Forfeited (74,516) 26.93 ----------------------------------------- ----------------- ----------------------------------------- ----------------- Outstanding - December 31, 2001 802,281 27.11 ----------------------------------------- ----------------- ----------------------------------------- ----------------- Granted 1,116,638 27.56 Exercised (103,677) 27.12 Forfeited (97,332) 27.38 ----------------------------------------- ----------------- Outstanding - December 31, 2002 1,717,910 27.39 ----------------------------------------- ----------------- Granted - n/a Exercised (203,052) 27.41 Forfeited (21,173) 27.50 ----------------------------------------- ----------------- ----------------------------------------- ----------------- Outstanding - December 31, 2003 1,493,685 27.39 ----------------------------------------- -----------------
At December 31, 2002 and 2001exercisable options totaled 274,306 at a weighted average exercise price of $26.91 and 47,275 at a weighted average exercise price of $25.53, respectively.
For purposes of the pro forma information presented in Note 1O, 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 and 2001 was $4.67 and $5.13, respectively, and was estimated using the Black-Scholes Option pricing model with the following weighted average assumptions. No options were granted in 2003.
2002 2001 ---- ---- Expected life of options (years) 7 7 Risk free interest rate 4.64% 5.08% Volatility of underlying stock 21% 22% Dividend yield of underlying stock 4.4% 4.2%
4. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund requirements for the years 2004 through 2008 are summarized as follows:
Year Amount Year Amount - -------------- ----------------- ------------------ ----------------- (Millions of dollars)
2004 $202 2007 $71 2005 197 2008 161 2006 381 - -------------- ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt maturing in 2004 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, 2003 SCE&G had not yet borrowed under the agreement.
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.
SCE&G has a three-year revolving line of credit totaling $75.0 million, expiring in 2005, that provides a source of liquidity in addition to other lines of credit..
Substantially all of SCE&G's and GENCO's utility plant is pledged as collateral in connection with long-term debt.
On February 11, 2004 GENCO issued $100 million of senior secured promissory notes maturing February 1, 2024 and bearing a fixed interest rate of 5.49%. Proceeds from this issuance will be used to support GENCO's construction program and to repay intercompany advances borrowed for that purpose.
5. SHORT-TERM BORROWINGS
Details of lines of credit (including uncommitted lines of credit) and short-term borrowings at December 31, 2003 and 2002, are as follows:
Millions of dollars 2003 2002 - --------------------------------------------------------------- ---------------
Lines of credit (total and unused) Committed $625 $475 Uncommitted 113 (1) 113
Commercial paper outstanding (270 or fewer days):
SCE&G $94.4 $127.6 Weighted average interest rate 1.15% 1.40%
Fuel Company $45.7 $50.1 Weighted average interest rate 1.15% 1.38%
PSNC Energy $55.2 $31.1 Weighted average interest rate 1.17% 1.42%
Total $195.3 $208.8 Weighted average interest rate 1.16% 1.40%
(1) Includes a $78 million line that either the Company or SCE&G may use.
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 14, 2004. The credit agreement provides for a maximum of $125 million to be outstanding at any time. Since the credit agreement expires within one year, commercial paper outstanding is classified as short-term debt.
6. 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, 2003 approximately $44 million of retained earnings were restricted by this requirement as to payment of cash dividends on SCE&G's common stock.
Cash dividends on common stock were declared during 2003, 2002 and 2001 at an annual rate per share of $1.38, $1.30 and $1.20, 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, 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 Other comprehensive income 2 3 5 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Balance, December 31, 2003 $2 $4 $6 ===============================================================================
During 2003, no unrealized gains (losses) on securities were reclassified into net income (loss). The Company recognized a gain of $3.9 million , net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the year ended December 31, 2003.
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 (DTAG) 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 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.
7. PREFERRED STOCK
Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase or sinking fund requirements for preferred stock for the years 2004 through 2008 is $2.7 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend.
Changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2003, 2002 and 2001 are summarized as follows:
Number of Shares Millions of Dollars - ------------------------------------------------------------------------------- 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 Shares Redeemed - $50 par value (6,378) (0.3) - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Balance at December 31, 2003 193,595 $9.7 ===============================================================================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of SCE&G, issued $50 million of 7.55% Trust Preferred Securities, Series A. On May 21, 2003 SCE&G effected the redemption of the Trust Preferred Securities.
8. INCOME TAXES
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $790.9 million at December 31, 2003 and $751.1 million at December 31, 2002 (see Note 1I), are as follows:
Millions of dollars 2003 2002 - ---------------------------------------------------------- ------------------ Deferred tax assets: Nondeductible reserves $70.6 $66.9 Unamortized investment tax credits 59.9 61.0 Investments in equity securities 43.3 25.0 Deferred compensation 22.3 21.2 Other 40.5 26.3 - ---------------------------------------------------------- ------------------ Total deferred tax assets 236.6 200.4 - ---------------------------------------------------------- ------------------
Deferred tax liabilities: Property, plant and equipment 889.2 814.4 Pension plan benefit income 94.5 93.0 Deferred fuel costs 13.6 17.9 Other 30.2 26.2 - ---------------------------------------------------------- ------------------ Total deferred tax liabilities 1,027.5 951.5 - ---------------------------------------------------------- ------------------ Net deferred tax liability $790.9 $751.1 ========================================================== ==================
The Internal Revenue Service has completed and closed examinations of the Company's consolidated federal income tax returns through the tax year ended in 2000, with the exception of the Company's interest in the synthetic fuel partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it is in the process of closing this partnership examination with no changes being proposed, and that a formal closing letter is forthcoming. The IRS makes no challenge to the declaration that the synthetic fuel facility was properly placed in service, and takes no issue with the evidence submitted demonstrating that the facility produces a qualifying fuel. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.
9. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2003 and 2002 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, certificates of deposit, 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 considered.
Investments
Certain of the Company's 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, the Company performs periodic assessments of whether any decline in the value of these securities to amounts below the Company'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. The Company also holds investments in several partnerships and joint ventures, some of which are accounted for using the equity method.
Telecommunications Investments
At December 31, 2003 SCANA Communications Holdings, Inc. (SCH), a wholly owned, indirect subsidiary of the Company, held the equity and debt securities of the following companies.
In May 2003 the Company's investment in ITC Holding Company, Inc. was sold. The transaction resulted in the receipt of net after-tax cash proceeds of approximately $48 million and the receipt of an investment interest in a newly formed entity, Magnolia Holding Company LLC (Magnolia Holding). A book gain, net of tax, of approximately $39 million was realized upon this transaction. Magnolia Holding holds ownership interests in several Southeastern communications companies.
ITC^DeltaCom, Inc. (ITC^DeltaCom) is a regional provider of telecommunications services. The common shares of ITC^DeltaCom owned by SCH have a market value of $3.4 million. The ITC^DeltaCom preferred shares owned by SCH are classified as held to maturity due to their debt features, and the market value is not readily determinable.
Knology, Inc. (Knology) is a broadband service provider of cable television, telephone and internet services. In August 2003, Magnolia Holding distributed its holdings in Knology preferred stock to Magnolia Holding's members. As a result, SCH's basis in Magnolia Holding was reduced by, and SCH's basis in Knology was increased by, approximately $6.2 million. During 2003, SCH recorded impairment losses associated with its Knology investment totaling $34.6 million, net of taxes. These impairments were based upon valuation information obtained in connection with the Magnolia Holding transaction and the subsequent completion of Knology's initial public offering. SCH's investment in Knology's common stock reflects the $9.03 trading price of such stock at December 31, 2003.
Derivatives
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, 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, apprises 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.
Commodities
The Company uses derivative instruments to hedge forward 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 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 (NYMEX) 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 gains (losses) of approximately $3.9 million, $(20.6) million and $(16.9) million, net of tax, as a result of qualifying cash flow hedges whose hedged transactions occurred during the years ended December 31, 2003, 2002 and 2001, respectively. These amounts were recorded in cost of gas. The Company estimates that most of the December 31, 2003 unrealized gain balance of $4.9 million, net of tax, will be reclassified from accumulated other comprehensive income (loss) to earnings in 2004 and 2005 as a decrease to gas cost if market prices remain stable. As of December 31, 2003, all of the Company's cash flow hedges settle by their terms before the end of 2006.
The Company recorded option premiums of $0.7 million and gains of $0.3 million, net of tax, as a result of qualifying fair value hedges during the year ended December 31, 2003. The premiums and gains were recorded in cost of gas. As of December 31, 2003 all of the Company's fair value hedges had settled.
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 provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as a regulatory asset or liability for the over or under recovery of gas costs.
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 current asset or liability.
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 rate 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 upon termination of a swap are recorded as basis adjustments 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 recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred.
The Company received a payment to terminate a swap totaling $29.3 million in 2002. This amount is being amortized over the ten-year term of the underlying debt it formerly hedged. At December 31, 2003 the estimated fair value of the Company's swaps totaled $6.3 million related to combined notional amounts of $333.1 million.
In anticipation of the issuance of debt, the Company uses interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, the Company paid approximately $3.5 million upon the termination of a forward starting interest rate swap.
10. COMMITMENTS AND CONTINGENCIES
A. Lake Murray Dam Reinforcement
In October 1999 FERC mandated that SCE&G reinforce its Lake Murray Dam in order to comply with new federal safety standards. 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, 2003 totaled approximately $169 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 $10.9 billion. Each reactor licensee is currently liable for up to $100.6 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 $67.1 million per incident, but not more than $6.7 million per year.
Congress failed to renew the Price-Anderson Indemnification Act when it expired in 2003. The Act is expected to be renewed with only modest changes in 2004. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired 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 retrospective assessments under certain conditions to cover insurer's losses. Based on the current annual premium, SCE&G's portion of the retrospective premium assessment would not exceed $15.8 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 deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $10.9 million at December 31, 2003. 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 by the end of 2004, with certain monitoring and other activities continuing until 2007. As of December 31, 2003, SCE&G has spent approximately $19.7 million to remediate the Calhoun Park site, and expects to spend an additional $2.2 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. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from the Columbia MGP. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of December 31, 2003, SCE&G has spent approximately $3.0 million related to these three sites, and expects to spend an additional $5.0 million.
Public Service Company of North Carolina, Incorporated
PSNC Energy is responsible for environmental cleanup at five sites in North Carolina on which MGP residuals are present or suspected. 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. PSNC Energy has recorded a liability and associated regulatory asset of approximately $7.0 million, which reflects the estimated remaining liability at December 31, 2003. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.2 million. Management believes that all MGP cleanup costs incurred will be recoverable through gas rates.
D. Franchise Agreements
See Notes 1B and 4 for a discussion of the electric and gas franchise agreements between SCE&G and the city 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 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 a subsidiary of the Company entered into, in the ordinary course of business, a fifteen-year take-and-pay contract with an unaffiliated natural gas supplier to purchase natural gas beginning in the spring of 2004. In December 2002, as a result of the failure of the supplier and its guarantor to meet contractual obligations related to credit support provisions, the subsidiary terminated the contract and the supplier initiated arbitration. In December 2003, an unrelated, creditworthy third party agreed to serve as supplier for the Company for the fifteen-year term with similar terms and conditions and a lower daily volume, and as a result the arbitration was dismissed and both parties executed releases of claims.
On August 21, 2003, SCE&G was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. 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.
A complaint was filed on October 22, 2003 against SCE&G by the State of South Carolina alleging that SCE&G violates the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that SCE&G failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. SCE&G is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are the subject of a similar lawsuit that was filed and served on SCE&G, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and SCE&G. SCE&G further believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, SCE&G filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to SCE&G's electric and gas service, to approve SCE&G's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.
The Company, SCE&G and PSNC Energy are also engaged in various other claims and litigation incidental to their 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 $12.4 million, $11.5 million and $12.1 million in 2003, 2002 and 2001, respectively. Future minimum rental payments under such leases are as follows:
Millions of dollars 2004 $16.6 2005 13.1 2006 12.2 2007 10.4 2008 9.7 Thereafter 9.2 ------- $71.2
At December 31, 2003 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $10 million.
G. Purchase Commitments
Purchase commitments under forward contracts for natural gas purchases, gas transportation capacity agreements, coal supply contracts, construction projects and other commitments are as follows:
Millions of dollars 2004 $1,348.6 2005 725.6 2006 529.9 2007 387.4 2008 366.8 Thereafter 3,638.4 --------- $6,996.7
Forward contracts for natural gas purchases include customary "make-whole" or default provisions, but are not considered to be "take-or-pay" contracts.
In addition, included in purchase commitments are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such commitments without penalty.
11. 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 operations 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 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. SCE&G and PSNC Energy are regulated by the SCPSC and the NCUC, respectively. 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 the Georgia 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. Due to the sale of ITC Holding and DTAG, Telecommunications Investments no longer meets SFAS 131 criteria as a reportable segment and is reclassified into All Other for 2003 and 2002.
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 eight 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 the quantitative thresholds for determining reportable segments in 2003 or 2002, and none met the quantitative thresholds in 2001 except Telecommunications Investments.
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, net 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 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 adjustments to net income and income tax expense include the cumulative effect of the accounting change described in Note 1G.
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, net for SCE&G's Electric Operations and Gas Distribution, and all assets for PSNC Energy and the remaining segments. As a result, adjustments to assets include non-utility plant and non-fixed assets for SCE&G.
Adjustments to Interest Expense, Income Tax Expense (Benefit) 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. Expenditures for Assets are adjusted for AFC. Deferred Tax Assets are adjusted to net them against deferred tax liabilities on a consolidated basis.
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 88
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 102
Item 8.
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 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, including competition from alternate fuels in industrial interruptible markets, (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.
OVERVIEW
SCE&G is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas. SCE&G's business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to heating requirements. SCE&G's electric service area extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 34 of the 46 counties in South Carolina and covers more than 22,000 square miles.
Electric Operations
The electric operations segment is comprised of the electric operations of SCE&G and Fuel Company, and is primarily engaged in the generation, transmission and distribution of electricity in South Carolina. At December 31, 2003 SCE&G provided electricity to over 570,000 customers. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements and is consolidated with SCE&G for financial reporting purposes.
Operating results for electric operations are primarily driven by customer demand for electricity, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which is currently 12.45%. Demand for electricity is primarily affected by weather, customer growth and the economy. In addition, significant legislative and regulatory matters could significantly impact the results of operations and cash flows for the electric operations segment.
In South Carolina the state legislature is not actively pursuing electric restructuring. However, both houses of the U.S. Congress passed energy legislation in 2003, with the House of Representatives passing an energy conference report. The Senate failed to pass the conference report due to its inability to reach a compromise on certain key issues unrelated to utilities. If a compromise is reached in 2004, such legislation is expected to contain provisions that would repeal PUHCA and transfer additional regulatory authority to FERC. This legislation may also impose stringent requirements on retail electric suppliers to generate electricity from renewable energy resources, which sources may or may not include hydroelectric generation. In addition, largely in response to the August 2003 blackout in eight northern states and parts of Canada, the energy legislation would likely include provisions to develop and enforce reliability standards for high-voltage transmission systems and to expedite construction of transmission lines. SCE&G cannot predict whether such legislation will be enacted, and if it is, the conditions it would impose on utilities.
If the energy legislation stalls in 2004, or if it fails to address certain issues, FERC is expected to proceed with regulatory initiatives that would significantly change the country's existing regulatory framework governing transmission, open access and energy markets and would attempt, in large measure, to standardize the national energy market. In July 2002 FERC issued a Notice of Proposed Rulemaking on Standard Market Design (SMD) which FERC supplemented with the issuance of a "white paper" in April 2003. If implemented, the proposed rule could 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 FERC's action to determine potential effects on SCE&G's operations. Additional directives from FERC are expected, and would likely be significantly influenced by the energy legislation discussed in the preceding paragraph.
The North American Electric Reliability Council (NERC) is comprised of utilities and other market participants who voluntarily develop and comply with NERC policies and standards which govern the planning and operation of the nation's interconnected bulk power system (the Grid). Currently these policies and standards are enforceable only through voluntary compliance by NERC members. Since the August 2003 blackout, and in response to issues identified during investigation of the blackout, NERC has been developing additional reliability standards, policies, and procedures. NERC is working with the regions and utilities in North America to strengthen existing enforcement and compliance programs, and is seeking to develop contracts between the regions and utility members to require compliance with these standards. NERC is also actively pursuing federal legislation to provide it with the authority to enforce reliability standards on all market participants, not just utilities. SCE&G continues to work with NERC and directly with other utilities to develop additional reliability policies and standards and continues to comply with NERC's existing policies and standards.
Gas Distribution
The gas distribution segment is comprised of the local distribution operations of SCE&G and is primarily engaged in the purchase and sale, primarily at retail, of natural gas in portions of South Carolina. At December 31, 2003 this segment provided natural gas to more than 276,000 customers.
Operating results for gas distribution are primarily influenced by customer demand for natural gas, the ability to control costs and allowed rates to be charged to customers. Embedded in these rates is an allowed regulatory return on equity, which is currently 12.25%. Demand for natural gas is primarily affected by weather, customer growth, the economy and, for commercial and industrial customers, the availability and price of alternate fuels. Natural gas competes with electricity, propane and heating oil to serve the heating and, to a lesser extent, other household energy needs of residential and small commercial customers. This competition is generally based on price and convenience. Large commercial and industrial customers often have the ability to switch from natural gas to an alternate fuel, such as propane or fuel oil. Natural gas competes with these alternate fuels based on price. As a result, any significant disparity between supply and demand, either of natural gas or of alternate fuels, and due either to production or delivery disruptions or other factors, will affect price and impact SCE&G's ability to retain large commercial and industrial customers.
RESULTS OF OPERATIONS
Net Income
Net income and the percent change from the previous year for the years 2003, 2002 and 2001 were as follows:
Millions of dollars 2003 2002 2001 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- Net income $220.5 $219.6 $221.9 Percent increase (decrease) in net income 0.41% (12.50%) (1.04%)
o 2003 vs 2002 Net income increased slightly primarily due to higher electric margins of $36.8 million, higher gas margins of $2.6 million, reduction of preferred dividend requirements of $0.9 million and other of $1.3 million, partially offset by higher operations and maintenance expenses of $15.9 million (including $7.1 due to lower pension income), higher depreciation and amortization expense of $10.9 million, higher property taxes of $7.2 million and higher interest expense of $6.7 million.
o 2002 vs 2001 Net income decreased primarily due to higher operations and maintenance expenses of $30.4 million (including $6.3 million due to lower pension income), higher property taxes of $6.5 million, and higher interest expense of $4.7 million, partially offset by higher electric margins of $37.3 million.
Pension Income
Pension income was recorded on SCE&G's financial statements as follows:
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 2003 decreased significantly compared to 2002 and 2001, primarily as a result of a less favorable investment market. See also the discussion of pension accounting in Critical Accounting Policies.
Allowance for Funds Used During Construction (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 7.8% of income before income taxes in 2003, 9.3% in 2002 and 6.5% in 2001.
The decrease in AFC for 2003 vs 2002 is primarily the result of the completion of the Urquhart Station repowering project in June 2002. In addition, in January 2003 the SCPSC issued an order allowing SCE&G to include all Jasper County generating project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in its electric rate base. At the time the expenditures were included in the rate base, AFC was no longer calculated on those amounts. These decreases were partially offset by increased AFC from subsequent construction expenditures related to the Jasper County generating and Lake Murray Dam projects (see discussion at CAPITAL PROJECTS).
The increase in AFC for 2002 vs 2001 was primarily the result of increased construction expenditures for the Urquhart Station repowering, Jasper County generating and Lake Murray Dam projects.
Dividends Declared
SCE&G's Board of Directors has declared the following dividends on common stock held by SCANA during 2003:
------------------ ------------------ --------------------- ------------------ Declaration Date Dividend Amount Quarter Ended Payment Date ------------------ ------------------ --------------------- ------------------
February 20, 2003 $35.3 million March 31, 2003 April 1, 2003 May 1, 2003 $36.5 million June 30, 2003 July 1, 2003 July 31, 2003 $37.0 million September 30, 2003 October 1, 2003 November 7, 2003 $36.0 million December 31, 2003 January 1, 2004 ------------------ ------------------ --------------------- ------------------
Electric Operations
Electric Operations is comprised of the electric operations of SCE&G and Fuel Company. Electric operations sales margins for 2003, 2002 and 2001, were as follows:
Interest Expense
Components of interest expense, excluding the debt component of AFC, were as follows:
o 2003 vs 2002 Interest expense increased by $10.9 million, primarily due to a $22.0 million increase from additional borrowings, which was partially offset by $10.2 million as a result of lower interest rates.
o 2002 vs 2001 Interest expense increased by $11.9 million as a result of increased borrowings which was partially offset by $2.8 million as a result of lower interest rates.
Income Taxes
Income taxes decreased approximately $5.2 million for the year 2003 compared to 2002 and decreased approximately $10.1 million for the year ended 2002 compared to 2001. Changes in income taxes are primarily due to changes in operating income. SCE&G's effective tax rate has also been favorably impacted in recent years by the flow-through of federal investment tax credits and the recovery of the equity portion of AFC.
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.
SCE&G's current estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 2004-2006 are as follows:
- ------------------------------------- -------------- -------------- Type of Facilities 2004 2005 2006 - ------------------ ---- ---- ---- (Millions of dollars) SCE&G: Electric Plant: Generation $197 $52 $135 Transmission 45 51 42 Distribution 105 113 119 Other 14 13 12 Nuclear Fuel 22 5 31 Gas 23 21 23 Common 58 16 16 Other 2 2 - - ------------------------------------- -------------- -------------- - ------------------------------------- -------------- -------------- Total SCE&G $466 $273 $378 - ------------------------------------- -------------- --------------
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. Also included in other commercial commitments are obligations for the Lake Murray Dam reinforcement project. See Note 10 to SCE&G's consolidated financial statements.
Included in purchase obligations are customary purchase orders under which SCE&G has the option to utilize certain vendors without the obligation to do so. SCE&G may terminate such purchase obligations without penalty.
SCE&G also has nuclear fuel obligations that are not listed in the contractual cash obligations above. While no specific monetary amount is specified for nuclear fuel contracts, SCE&G's two-thirds share of expected cost is $22.2 million for the year 2004, a total of $54.6 million for the years 2005-2007, a total of $11.9 million for the years 2008-2009 and a total of $20.0 million for the years 2010-2011.
The Company also has a legal obligation associated with the decommissioning and dismantling of Summer Station that is not listed in the contractual cash obligations above. See Note 1 to the Company's consolidated financial statements.
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.
Included in cash outlays are the following specific projects:
o FERC mandated that SCE&G's Lake Murray Dam be reinforced to comply with new federal safety standards. Construction for the project and related activities is expected to be complete in 2005 at a cost of approximately $275 million, of which approximately $169 million had been incurred through December 31, 2003.
o Construction continues on SCE&G's 875 MW generation plant in Jasper County, South Carolina. The plant is expected to begin commercial operation in mid-2004 and cost approximately $450 million, of which approximately $425 million had been incurred through December 31, 2003.
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 the SCPSC and the SEC. The following describes the financing programs currently utilized by SCE&G.
(1) Comprised of a $78 million uncommitted line that either SCE&G or the Company may use.
In addition, SCE&G has a three-year revolving line of credit totaling $75 million, expiring in 2005, that provides backup liquidity.
SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage) and covering substantially all of its properties, prohibits the issuance of additional bonds (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, 2003 the Bond Ratio was 5.08. 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 $1,279 million at December 31, 2003), (ii) retirements of Class A Bonds (which retirement credits totaled $156.9 million at December 31, 2003), 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, 2003 approximately $924.6 million 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, 2003 the New Bond Ratio was 4.87.
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, 2003 the Preferred Stock Ratio was 1.55.
The Articles also require the consent of 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, 2003 the ten percent test would have limited issuances of unsecured indebtedness to approximately $413.5 million. Unsecured indebtedness at December 31, 2003 totaled approximately $94.4 million, and was comprised of short-term borrowings.
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, 2003 SCE&G had not borrowed under the agreement, but expects to fully draw these amounts in 2004. Any such amounts would be included in the ten percent test.
Financing Cash Flows
During 2003 SCE&G experienced net cash inflows related to financing activities of approximately $106 million primarily arising from borrowings in support of SCE&G's construction program and for other general corporate purposes.
In anticipation of the issuance of debt, SCE&G may use interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within other deferred debits or credits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, SCE&G paid approximately $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds in December 2003, SCE&G paid approximately $3.5 million upon the termination of a forward starting interest rate swap.
For additional information on significant financing transactions see the Consolidated Statements of Capitalization and Note 4 to the consolidated financial statements.
ENVIRONMENTAL MATTERS
In the years 2001 through 2003, SCE&G's capital expenditures for environmental control totaled approximately $168.5 million. These expenditures were in addition to expenditures included in "Other operation and maintenance" expenses, which were approximately $23.5 million, $23.7 million, and $17.0 million during 2003, 2002 and 2001, respectively. It is not possible to estimate all future costs related to environmental matters, but forecasts for capitalized environmental expenditures for SCE&G are $23.2 million for 2004 and $106.7 million for the four-year period 2005 through 2008. These expenditures are included in SCE&G's construction program discussed in Liquidity and Capital Resources and include the matters discussed below.
Electric Operations
The Clean Air Act Amendments of 1990 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 indicated that it would finalize regulations by December 2004 for stricter limits on mercury and other pollutants generated by coal-fired plants.
The EPA has undertaken an aggressive enforcement initiative against the utilities industry, and the DOJ has brought suit against a number of utilities in federal court alleging violations of the CAA. At least two of these suits have either been tried or have had substantive motions decided - one favorable to the industry and one not. Neither is binding as precedent on SCE&G. 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). SCE&G has received and responded to Section 114 requests for information related to Canadys and Wateree Stations. The regulations under the CAA provide certain exemptions to the definition of "major modifications," including an exemption for routine repair, replacement or maintenance. On October 27, 2003 EPA published a final revised NSR rule in the Federal Register with an effective date of December 26, 2003. The new rule represents an industry - favorable departure from certain positions advanced by the federal government in the NSR enforcement initiative. However, on motion of several Northeastern states, the United States Circuit Court of Appeals for the District of Columbia stayed the effect of the final rule. The ultimate application of the final rule to SCE&G is uncertain. 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 under what it believes is a fair reading of both the prior regulation and the contested revised regulation. The regulations also provide an exemption for an increase in emissions resulting from increased hours of operation or production rate and from demand growth. The current state of continued DOJ enforcement actions is the subject of speculation industry-wide, but 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 two plants. SCE&G believes that any enforcement actions relative to SCE&G's compliance with the CAA would be without merit. However, if successful, such actions could have a material adverse effect on SCE&G's financial condition, cash flows and results of operations. To comply with current and anticipated state and federal regulations, SCE&G expects to incur capital expenditures totaling approximately $129.9 million over the 2004-2008 period to retrofit existing facilities, with increased operation and maintenance costs of approximately $1.2 million per year. To meet compliance requirements for the years 2009 through 2013, SCE&G anticipates additional capital expenditures of approximately $52.6 million.
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 2004. 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 financial condition and results of operations and cash flows of SCE&G.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 required that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mil per KWh of net nuclear generation after April 7, 1983. Payments, which began in 1983, are subject to change and will extend through the operating life of SCE&G's Summer Station. SCE&G entered into a contract with the DOE in 1983 providing for permanent disposal of its spent nuclear fuel by the DOE. The DOE presently estimates that the permanent storage facility will not be available until 2010. SCE&G has on-site spent nuclear fuel storage capability until at least 2018 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through spent fuel pool reracking, dry cask storage or other technology as it becomes available. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available.
On January 28, 2004 SCE&G and Santee Cooper (one-third owner of Summer Station) filed suit in the Court of Federal Claims against the DOE for breach of the above contract. The contract known as the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (Standard Contract), required the federal government to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning not later than January 31, 1998, in exchange for agreed payments fixed in the Standard Contract at particular amounts. As of the date of filing, the federal government has accepted no spent fuel from Summer Station or any other utility for transport and disposal, and has indicated that it does not anticipate doing so until 2010, at the earliest. As a consequence of the federal government's breach of contract, the plaintiffs have incurred and will continue to incur substantial costs There are two additional causes of action alleged as well - damages for breach of the implied covenant of good faith and fair dealing and a takings claim demanding just compensation for the taking of the plaintiffs' real property (necessitated by the storage). This lawsuit is one of 48 similar lawsuits brought by nuclear utilities as of January 29, 2004.
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 $10.9 million and $17.9 million at December 31, 2003 and 2002, 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 by the end of 2004, with certain monitoring and other activities continuing until 2007. As of December 31, 2003, SCE&G has spent approximately $19.7 million to remediate the Calhoun Park site, and expects to spend an additional $2.2 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. In addition, in March 2003 SCE&G signed a consent agreement with DHEC related to a site formerly owned by SCE&G. The site contained residue material that was moved from an MGP. The removal action for this site has been completed. SCE&G anticipates that major remediation activities for the three owned sites will be completed before 2006. As of December 31, 2003, SCE&G has spent approximately $3.0 million related to these three sites, and expects to incur an additional $5.0 million.
REGULATORY MATTERS
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. Material retail rate proceedings are described in more detail in Note 2 to the consolidated financial statements.
In conjunction with a January 2003 order, the SCPSC allowed SCE&G to include all Jasper County generating station project expenditures as of December 31, 2002 and other construction work in progress expenditures as of June 30, 2002 in electric rate base. Once this generating station is complete, SCE&G may seek to include the remaining project expenditures in electric rate base. Construction expenditures for the Lake Murray Dam construction project, which totaled approximately $169 million as of December 31, 2003, have not been included in its electric rate base. When the Lake Murray project is completed in 2005, SCE&G will determine whether to seek inclusion of such expenditures in electric rate base.
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, 2003 is approximately $2.5 million, and through December 31, 2003, they have generated and passed through to SCE&G approximately $97.4 million in such tax credits. At December 31, 2003 SCE&G has recorded on its balance sheet $66.6 million deferred fuel tax benefits, which include partnership losses, net of tax.
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, net of partnership losses and other expenses, 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 to the consolidated financial statements.
The IRS has completed and closed examinations of the Company's consolidated federal income tax returns through the tax year ended in 2000, with the exception of the Company's interest in the synthetic fuel partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it has begun the process of closing this partnership examination with no changes being proposed, and that a formal closing letter is forthcoming. The IRS audit report makes no challenge to the declaration that the synthetic fuel facility was properly placed in service, and takes no issue with evidence submitted demonstrating that the facility produces a qualifying fuel.
On October 29, 2003, the IRS issued Announcement 2003-70 stating that it had completed a review of chemical change issues associated with tax credits claimed under IRC Section 29 relating to the production and sale of synthetic fuel. It further stated that it would resume the issuance of private letter rulings (PLRs) concerning synthetic fuel credits consistent with the guidelines regarding chemical change previously set forth in Revenue Procedures 2001-30 and 2001-34 and certain additional requirements related to sampling, testing and recordkeeping procedures, even though the IRS has indicated that the level of chemical change required under that guidance is not sufficient for IRC Section 29 purposes. The IRS also stated in the announcement that it would continue to issue PLRs because it recognized that many taxpayers and their investors have relied on its long standing ruling practice to make investments. In Announcement 2003-46 issued on June 27, 2003, the IRS had questioned the validity of certain test procedures and results that had been presented to it by taxpayers with interests in synfuel operations as evidence that the required significant chemical change had occurred, and had initiated a review of these test procedures and results which was completed as noted in Announcement 2003-70.
Separately, the Permanent Subcommittee on Investigations of the Government Affairs Committee of the United States Senate (Subcommittee) is conducting an investigation of potential abuses of tax credits by producers of synthetic fuel under IRC Section 29. The Subcommittee Chairman, in a memorandum commencing the investigation, has stated that he anticipates the investigation will focus on whether certain synthetic fuel producers are claiming tax credits even though their product is not a qualified synthetic fuel under Section 29 and IRS regulations. The memorandum also states that the investigation will address whether certain corporations are engaging in transactions solely to take advantage of unused Section 29 credits with no other business purpose, and the IRS' efforts to curb abuses related to these credits.
While the effect of these two developments is not clear, SCE&G is aware that PLRs have been issued since October 29, 2003. SCE&G has not had any communication with the Subcommittee staff, and with the imminent conclusion of the IRS audit, SCE&G continues to believe that all of its synthetic fuel tax credits have been properly claimed.
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. At December 31, 2003 SCE&G had capitalized approximately $8.0 million related to the application process and expects to capitalize an additional $1.0 million in 2004. SCE&G expects the extension to be granted in mid-2004.
CRITICAL ACCOUNTING POLICIES
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.
Utility Regulation
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. 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 condition would be materially affected. See Note 1 to the consolidated financial statements for a description of SCE&G's regulatory assets and liabilities, including those associated with SCE&G's environmental assessment program.
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, 2003 SCE&G's net investments in fossil/hydro and nuclear generation assets were approximately $2,113 million and $563 million, respectively.
Revenue Recognition and Unbilled Revenues
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, SCE&G records 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. At December 31, 2003 and 2002, accounts receivable included unbilled revenues of $50.0 million and $43.9 million, respectively, compared to total revenues for 2003 and 2002 of $1.83 billion and $1.68 billion, respectively.
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 expected write-offs. These estimates are based on, among other things, comparisons of the relative age of accounts, assigned credit ratings for commercial and industrial accounts, and consideration of actual write-off history. SCE&G's Electric Distribution and Gas Distribution segments have an established write-off histories and the regulated service areas that enable them to reliably estimate their provisions 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. SCE&G expects to receive a 20-year license extension for Summer Station that will significantly impact the eventual cost of and funding for decommissioning. 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.
Under SCE&G's method of funding decommissioning costs, 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.
Accounting for Pensions and Other Postretirement Benefits
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 $6.8 million recorded in 2003 reflects the use of a 6.5% discount rate and an assumed 9.25% long-term return on plan assets. SCE&G believes that these assumptions were, and that the resulting pension income amount was, reasonable. For purposes of comparison, using a discount rate of 6.0% in 2003 would have lowered SCE&G's pension income approximately $1.7 million. Had the assumed long-term return on assets been reduced to 9.0% in 2003, SCE&G's pension income would have been reduced by approximately $1.5 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 beginning of year discount rate of 6.5% as being within a reasonable range of interest rates for obligations rated Aa by Moodys as of January 1, 2003. This same discount rate was also selected for determination of OPEB costs discussed below.
The following information with respect to pension assets (and returns thereon) 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 25 year cumulative actual returns of 10.8%, 12.0% and 12.7%, respectively, all of 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 a target asset allocation of 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 investment performance in 2000-2002 and the recent 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 after 2008.
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 6.5% and recorded a net SFAS 106 cost of $13.1 million for 2003. Had the selected discount rate been 6.0%, the expense would have been approximately $0.4 million higher.
Asset Retirement Obligations
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 operation. Because such obligation relates solely to SCE&G's regulated electric operations, adoption of SFAS 143 had no impact on results of operations; however, as of January 2003, SCE&G recorded an ARO of approximately $111 million, which exceeded the previously recorded reserve for nuclear plant decommissioning of approximately $87 million. At December 31, 2003 such ARO totaled approximately $118 million.
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.
OTHER MATTERS
Claims and Litigation
For a description of claims and litigation see Item 3. LEGAL PROCEEDINGS and Note 10 to the consolidated financial statements.
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.
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, 2003 and 2002 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, 2003. 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, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 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.
s/Deloitte & Touche LLP Columbia, South Carolina February 26, 2004
(a) $4.50 par value, authorized 50 million shares
See Notes to Consolidated Financial Statements.
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 predominantly in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
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, 2003 and 2002, the Company had approximately $39.5 million and $29.6 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, 2003 and 2002 the Company had approximately $10.7 million and $9.0 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $100.0 million, $109.5 million and $95.8 million in 2003, 2002 and 2001, respectively.
Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $1.8 million, $0.4 million and $0.7 million in 2003, 2002 and 2001, respectively.
The Company holds two equity-method investments in partnerships involved in converting coal to synthetic fuel. The Company's receivables from these affiliated companies totaled approximately $13.4 million and $8.5 million at December 31, 2003 and 2002, respectively. The Company's payables to these affiliated companies totaled approximately $12.2 million and $8.0 million at December 31, 2003 and 2002, 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 certain 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, 2003, approximately $337 million and $398 million of regulatory assets (including environmental) and liabilities, respectively, as shown below.
Accumulated deferred income tax liabilities arising from utility operations that have not been included in customer rates are recorded as a regulatory asset. Accumulated deferred income tax assets arising from deferred investment tax credits are recorded as a regulatory liability.
Under-collections - fuel adjustment clauses, net represent amounts 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 manufactured gas plant (MGP) sites currently or formerly owned by the Company. Costs incurred at sites owned by the Company are being recovered through rates. Such costs, totaling approximately $10.9 million, are expected to be fully recovered by the end of 2009.
Asset retirement obligation - nuclear decommissioning represents the regulatory asset associated with the legal obligation to decommission and dismantle V. C. Summer Nuclear Station (Summer Station) as required in SFAS 143, "Accounting for Asset Retirement Obligations." (See Note 1N).
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 the Company's two partnerships involved in converting coal to synthetic fuel. Under a plan approved by the SCPSC, any tax credits generated from non-conventional fuel produced by the partnerships and consumed by the Company and ultimately passed through to the Company, net of partnership losses and other expenses, 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 period of approximately ten years. The accumulated storm damage reserve can be applied to offset actual incremental 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. These amounts are not earning a return, but are being amortized through cost of service over approximately 15 years.
Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists. 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 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, liquidity or financial position in the period the write-off would be recorded.
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 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 $1,002.8 million and $962.4 million as of December 31, 2003 and 2002, respectively (including amounts related to ARO). Accumulated depreciation associated with the Company's share of Summer Station was approximately $449.5 million and $417.9 million as of December 31, 2003 and 2002, respectively (including amounts related to ARO). The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation and maintenance" expenses and totaled approximately $74.7 million for the year ended December 31, 2003.
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 the Company begins accruing for each successive outage immediately upon completion of the preceding outage. The Company accrued approximately $0.5 million per month from January 2001 through June 2002 for the outage period ended June 2002, and approximately $0.6 million per month from July 2002 through December 2003 for the outage period ended December 2003. Total outage costs for the fall 2003 outage was approximately $20.6 million, of which the Company was responsible for approximately $13.9 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%, 7.8% and 8.8% for 2003, 2002 and 2001, 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. Unbilled revenues totaled approximately $50 million and $43.9 million as of December 31, 2003 and 2002, 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 $26.7 million and $25.3 million at December 31, 2003 and 2002, respectively, which amounts are included in 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, 2003 and 2002 the Company had undercollected through the gas cost recovery procedure approximately $11.9 million and $24.6 million, respectively, which amounts are also included in 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 3.02%, 2.93% and 2.98% for 2003, 2002 and 2001, 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 records its liability for decommissioning cost in deferred credits.
Under the Company's method of funding decommissioning costs, funds collected through rates ($3.2 million in each of 2003, 2002 and 2001) 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.
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 $1.5 million and $2.0 million at December 31, 2003 and 2002, 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 other regulatory assets.
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 the Company, in the form of capital contributions. In 2003 and 2002, capital contributions of approximately $8.5 million and $7 million, respectively, were received by the Company 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 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.
At the Company, site assessment and cleanup costs are deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $10.9 million and $17.9 million at December 31, 2003 and 2002, respectively. The deferral includes the estimated costs associated with the matters discussed in Note 10C.
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 5.)
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
The Company adopted SFAS 143, effective January 1, 2003. SFAS 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. As of December 31, 2002, prior to the adoption of SFAS 143, the Company carried deferred debits and deferred credits (each totaling approximately $87 million) related to the decommissioning and dismantling of Summer Station and the funding thereof. Effective January 1, 2003, in connection with the measurement of the ARO, the amounts reflected within these regulatory assets and liabilities were recharacterized.
The following table presents such recharacterized amounts related to the decommissioning obligation and the funding thereof as recorded in the Consolidated Balance Sheet as of December 31, 2003, and the proforma amounts that would have been recorded as of December 31, 2002 and 2001 had SFAS 143 been adopted at the beginning of 2001.
Proforma net income for periods prior to the adoption of SFAS 143 would not differ from amounts actually recorded during these periods.
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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, " Accounting for Derivative Instruments and Hedging Activities". SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 149.
SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150.
The Company adopted SFAS 132 (Revised 2003), Employers' Disclosure about Pension and Other Postretirement Benefits," which is effective for financial statements issued for fiscal years ending December 15, 2003. This statement increased existing disclosure requirements by requiring more details about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of this statement.
O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
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. RATE AND OTHER REGULATORY MATTERS
Electric
In January 2003 the SCPSC granted the Company a composite increase in retail electric rates of approximately 5.8% 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, based on the level of revenues and operating expenses, 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 additional 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 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 was effective for service rendered on and after February 1, 2003. In April 2003 the SCPSC issued an order approving the Company's request to maintain the fuel cost component of rates at 1.678 cents per KWh, effective May 1, 2003. The SCPSC also reaffirmed the prudence of the Company's purchasing practice and recognized the efficiency of SCE&G's electric generating plants; however, it deferred action on the recovery of certain purchased power costs pending the resolution of the appeal of the SCPSC's May 2002 order discussed below.
In December 2002 the SCPSC approved the Company's request to capitalize the cost of fuel consumed in the production of test power for the gas turbines installed at Urquhart 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 approved 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 reflected 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. The Consumer Advocate of South Carolina appealed to the South Carolina Circuit Court (Circuit Court) the portion of the SCPSC's order related to the recovery of certain purchased power costs. The appeal is still pending.
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, 2003 and 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.728 January-February 2003 $.596 January-October 2002 $.928 March-October 2003 $.728 November-December 2002 $.877 November-December 2003
The SCPSC allows the Company 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 2003, as a result of the annual review, the SCPSC approved the Company's request to reduce the billing surcharge from 3.0 cents per therm to 0.8 cents per therm, which is intended to provide for the recovery, prior to the end of the year 2009, of the balance remaining at December 31, 2003 of $10.9 million.
3. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefit Plans
The Company participates in SCANA's 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 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 credited 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.
In addition to pension benefits, the Company provides certain unfunded postretirement 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.
The measurement date used to determine pension and other postretirement benefit obligations is December 31. Information regarding the benefit obligations and the funding thereof is presented below.
Changes in Benefit Obligations
Data related to the changes in the projected benefit obligation for retirement benefits and the accumulated benefit obligation for other postretirement benefits are presented below.
Retirement Benefits Other Postretirement Benefits ---------------------- -----------------------
Millions of dollars 2003 2002 2003 2002 ---- ---- ---- ----
Benefit obligation, January 1 $595.6 $530.8 $183.4 $166.7 Service cost 9.5 9.1 2.7 3.1 Interest cost 36.7 39.8 11.4 12.4 Plan participants' contributions - 0.8 0.9 - Actuarial loss 7.6 50.6 4.3 10.8 Benefits paid (29.5) (34.7) (14.2) (10.5) ------ ----- -- ------ - ----- Benefit obligation, December 31 $619.9 $595.6 $188.4 $183.4 ====== ====== ====== ======
The accumulated benefit obligation for retirement benefits at the end of 2003 and 2002 was $589.8 million and $570.0 million, respectively. These accumulated retirement benefit obligations differ from the projected retirement benefit obligations above in that they reflect no assumptions about future compensation levels.
A 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate was assumed to decrease gradually to 5.0% for 2011 and remain at that level thereafter. The effects of a one-percentage-point increase or decrease on accumulated other postretirement benefit obligation for health care benefits are as follows:
1% 1% Millions of dollars Increase Decrease --------------- -----------------
Effect on postretirement benefit obligation $0.9 $(1.1)
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed December 8, 2003 to make additional voluntary prescription drug benefits available through Medicare. The Company has elected not to recognize the effects of the Act in these financial statements. The Company will be evaluating the implications of the Act during 2004 and recognize expected financial effects as prescribed by accounting standards in effect for subsequent reporting periods.
Changes in Plan Assets
Retirement Benefits ----------------------------------- Millions of dollars 2003 2002 ---- ----
Fair value of plan assets, January 1 $666.9 $831.6 Actual return on plan assets 150.3 (130.0) Benefits paid (29.5) (34.7) ------ -- ----- Fair value of plan assets, December 31 $787.7 $666.9 ====== ======
At the end of 2003 and 2002, the fair value of plan assets for the pension plan exceeded both the projected benefit obligation and the accumulated benefit obligation discussed above. Since the accumulated benefit obligation is less than the fair value of plan assets, there is no adjustment to other comprehensive income.
In connection with the joint ownership of Summer Station, as of December 31, 2003 and 2002 the Company recorded within deferred credits a $9.3 million and $9.1 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, 2003 and 2002, the Company also recorded a $6.5 million and $6.4 million receivable, respectively, from Santee Cooper, representing an estimate of its portion of the unfunded net postretirement benefit obligation.
Expected Cash Flows
The total benefits expected to be paid from the pension plan or from the Company's assets for the pension and other postretirement benefits plans, respectively, are as follows:
Expected Benefit Payments Millions of dollars Pension Benefits Other Postretirement Benefits* - ------------------- ---------------- ------------------------------ 2004 $39.2 $13.4 2005 41.0 13.7 2006 42.8 14.0 2007 43.3 14.3 2008 48.0 14.5 2009 - 2013 266.0 75.2 * Net of participant contributions
Net Periodic Cost
As allowed by SFAS 87 and SFAS 106, 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:
The effect of a one-percentage-point increase or decrease in the assumed health care cost trend rate on total service and interest cost is less than $100,000.
Pension Plan Contributions
While the investment performance over the 2000-2002 period and the recent decline in discount rates have significantly reduced the level of pension income, the pension trust has been and remains adequately funded. No contributions have been required since 1997, and the Company does not anticipate making contributions to the funded pension plan in 2004. As such, these declines in pension income have had no impact on the Company's cash flows.
Pension Plan Asset Allocations
The Company's pension plan asset allocation at December 31, 2003 and 2002 and the target allocations for 2004 are as follows:
Target Percentage of Plan Assets Asset Category Allocation At December 31 ---------- -------------- 2003 2002 ---- ---- Equity Securities 70% 71% 73% Debt Securities 30% 29% 27%
The assets of the pension plan are invested in accordance with the objectives of (1) fully funding the actuarial accrued liability for the pension plan (Plan), (2) maximizing return within reasonable and prudent levels of risk in order to minimize contributions, and (3) maintaining sufficient liquidity to meet benefits payment obligations on a timely basis. These objectives have been based on a ten-year investment horizon, so that interim fluctuations should be viewed with appropriate perspective. The pension plan operates with several risk and control procedures including a review of liabilities, investment objectives, investment managers and performance expectations. Transactions involving certain types of investments are prohibited. Equity securities held by the pension plan during the above periods did not include SCANA Corporation common stock.
In developing the expected long-term rate of return assumptions, management evaluates the pension plan's historical cumulative actual returns over several periods, which have all been in excess of related broad indices, and management anticipates that the pension 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 a target asset allocation of 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.
4. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund requirements for the years 2004 through 2008 are summarized as follows:
- ------------------ ----------------- ------------------ ----------------- Year Amount Year Amount - ------------------ ----------------- ------------------ ----------------- (Millions of dollars)
2004 $138 2007 $38 2005 188 2008 38 2006 172 - ------------------ ----------------- ------------------ -----------------
Approximately $35.5 million of the long-term debt maturing in 2004 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, 2003 the Company had not yet borrowed under the agreement.
On October 15, 2002 the Company 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.
The Company has a three-year revolving line of credit totaling $75.0 million, expiring in 2005, that provides a source of liquidity in addition to other lines of credit.
Substantially all utility plant is pledged as collateral in connection with long-term debt.
5. SHORT-TERM BORROWINGS
Details of lines of credit and short-term borrowings at December 31, 2003 and 2002, are as follows:
Millions of dollars 2003 2002 - --------------------------------------------------------- ---------------
Lines of credit (total and unused) Committed $400 $300 Uncommitted (1) 78 - Short-term borrowings outstanding Commercial paper (270 or fewer days) $140.1 $177.7 Weighted average interest rate 1.15% 1.40%
(1) Comprised of a $78 million line that either the Company or SCANA may use.
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 14, 2004. 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 $45.7 million and $50.1 million at December 31, 2003 and 2002, respectively, at weighted average interest rates of 1.15% and 1.38%, respectively.
The Company's commercial paper outstanding totaled $94.4 million and $127.6 million at December 31, 2003 and 2002, respectively, at weighted average interest rates of 1.15% and 1.40%, respectively.
6. 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, 2003 approximately $44 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
7. PREFERRED STOCK
Retirements under sinking fund requirements are at par values. The aggregate of the annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 2004 through 2008 is $2.7 million. The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend.
Changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 2003, 2002 and 2001 are summarized as follows:
Number of Shares Millions of Dollars - -------------------------------------------------------- ----------------------- 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 Shares Redeemed - $50 par value (6,378) (0.3) - -------------------------------------------------------- ----------------------- Balance at December 31, 2003 193,595 $9.7 ======================================================== =======================
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly owned subsidiary of SCE&G, issued $50 million of 7.55% Trust Preferred Securities, Series A. On May 21, 2003 SCE&G effected the redemption of the Trust Preferred Securities.
8. INCOME TAXES
The Internal Revenue Service has completed and closed examinations of the Company's consolidated federal income tax returns through the tax year ended in 2000, with the exception of the Company's interest in the synthetic fuel partnership, S. C. Coaltech No. 1 L.P. The IRS has notified the Company that it is in the process of closing this partnership examination with no changes being proposed, and that a formal closing letter is forthcoming. The IRS makes no challenge to the declaration that the synthetic fuel facility was properly placed in service, and takes no issue with the evidence submitted demonstrating that the facility produces a qualifying fuel. The Company continues to believe that all of its synthetic fuel tax credits have been properly claimed.
9. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2003 and 2002 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, certificates of deposits, 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 considered.
o In anticipation of the issuance of debt, the Company also uses interest rate lock or similar agreements to manage interest rate risk. Payments received or made upon termination of such agreements are recorded within other deferred debits on the balance sheet and are amortized to interest expense over the term of the underlying debt. In connection with the issuance of First Mortgage Bonds in May 2003, the Company paid approximately $11.9 million upon the termination of a treasury lock agreement. In connection with the issuance of First Mortgage Bonds on December 2003, the Company paid approximately $3.5 million upon the termination of a forward starting interest rate swap.
10. COMMITMENTS AND CONTINGENCIES:
A. Lake Murray Dam Reinforcement
In October 1999 FERC mandated that the Company reinforce its Lake Murray Dam in order to comply with new federal safety standards. 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, 2003 totaled approximately $169 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 $10.9 billion. Each reactor licensee is currently liable for up to $100.6 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 $67.1 million per incident, but not more than $6.7 million per year.
Congress failed to renew the Price-Anderson Indemnification Act when the Act expired in 2003. The Act is expected to renew with only modest changes in 2004. The delayed renewal has no impact on the Company due to the "grandfathered" status of existing licensees that are covered under the expired 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 retrospective 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 $15.8 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 deferred and amortized with recovery provided through rates. Deferred amounts, net of amounts previously recovered through rates and insurance settlements, totaled $10.9 million at December 31, 2003. 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 by the end of 2004, with certain monitoring and other activities continuing until 2007. As of December 31, 2003, the Company has spent approximately $19.7 million to remediate the Calhoun Park site, and expects to spend an additional $2.2 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. In addition, in March 2003 the Company signed a consent agreement with DHEC related to a site formerly owned by the Company. The site contained residue material that was moved from a MGP site. The removal action for this site has been completed. The Company anticipates that major remediation activities for the three owned sites will be completed before 2006. As of December 31, 2003, the Company has spent approximately $3.0 million related to these three sites, and expects to spend an additional $5.0 million.
D. Franchise Agreements
See Notes 1B and 4 for a discussion of the electric and gas franchise agreements between the Company and the cities of Columbia and Charleston.
E. Claims and Litigation
On August 21, 2003, the Company was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation, Progress Energy Services Company, and South Carolina Electric & Gas Company, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. The plaintiffs are seeking damages for the alleged improper use of electric transmission easements but have not asserted a dollar amount for their claims. Specifically, the plaintiffs contend that the licensing of attachments on electric utility poles, towers and other facilities to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric transmission line right-of-way constitutes a trespass. The Company is confident of the propriety of its actions and intends to mount a vigorous defense. 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.
A complaint was filed on October 22, 2003 against the Company by the State of South Carolina alleging that the Company violates the Unfair Trade Practices Act by charging municipal franchise fees to some customers residing outside a municipality's limits. The complaint also alleges that the Company failed to obey, observe, or comply with the lawful order of the SCPSC by charging franchise fees to those not residing in a municipality. The complaint seeks restitution to all affected customers and penalties up to $5,000 for each separate violation. The Company is confident of the reasonableness of its actions and intends to mount a vigorous defense. The allegations contained in the complaint are the subject of a similar lawsuit that was filed and served on the Company, for which a Motion to Dismiss is pending. The allegations are also the subject of a purported class action lawsuit filed on or about December 12, 2003 against Duke Energy Corporation, Progress Energy Services Company and the Company. The Company further believes that the resolution of these actions will not have a material adverse impact on its results of operations, cash flows or financial condition. In addition, the Company filed a petition with the SCPSC on October 23, 2003 pursuant to S. C. Code Ann. R.103-836. The petition requests that the SCPSC exercise its jurisdiction to investigate the operation of the municipal franchise fee collection requirements applicable to the Company's electric and gas service, to approve the Company's efforts to correct any past franchise fee billing errors, to adopt improvements in the system which will reduce such errors in the future, and to adopt any regulation which the SCPSC deems just and proper to regulate the franchise fee collection process.
The Company is also engaged in various other claims and litigation incidental to their 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 $9.9 million, $9.3 million and $9.0 million in 2003, 2002 and 2001, respectively. Future minimum rental payments under such leases are as follows:
Millions of dollars 2004 $13.0 2005 11.5 2006 10.9 2007 9.4 2008 8.8 Thereafter 8.2 --------- $61.8
At December 31, 2003 minimum rentals to be received under noncancelable subleases with remaining lease terms in excess of one year totaled approximately $10 million.
G. Purchase Commitments
Purchase commitments for coal supply, construction projects and other commitments are as follows:
Millions of dollars ------------------- 2004 $297.8 2005 250.6 2006 110.9 2007 5.3 2008 2.8 Thereafter 12.6 ----------- $680.0
In addition, included in purchase commitments are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such commitments without penalty.
11. 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 Operations' 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, net for its segments. Therefore, the Company does not allocate 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's deferred tax assets are netted with deferred tax liabilities for reporting purposes.
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, net for all reportable segments. As a result, adjustments to assets include 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.
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of dollars - ----------------------------------------------------------------------------- First Second Third Fourth 2003 Quarter Quarter Quarter Quarter Annual - -----------------------------------------------------------------------------
Total operating revenues $478 $422 $484 $448 $1,832 Operating income 99 88 150 88 425 Net income 47 40 88 45 220 - -----------------------------------------------------------------------------
Millions of dollars - ----------------------------------------------------------------------------- First Second Third Fourth 2002 Quarter Quarter Quarter Quarter Annual - -----------------------------------------------------------------------------
Total operating revenues $411 $403 $472 $397 $1,683 Operating income 99 79 155 84 417 Net income 52 40 86 41 219 - -----------------------------------------------------------------------------
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
Item 7. Management's Narrative Analysis of Results of Operations...... 132
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 136
Item 8. Financial Statements and Supplementary Data.................... 137
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 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, including competition from alternate fuels in industrial interruptible markets, (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 assets and the 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, 2003 and 2002 was as follows:
Millions of dollars 2003 2002 - ------------------------------------------------------------------ -------------
Net income (loss) $30.9 $(207.0) Less: Cumulative effect of accounting change - (229.6) - ------------------------------------------------------------------ ------------- Income before cumulative effect of accounting change $30.9 $22.6 ================================================================== =============
Income before the cumulative effect of accounting change increased approximately $8.3 million, primarily due to increased margin of $12.7 million, and other income of $4.6 million, and reduced interest expense of $0.7 million, which was partially offset by higher operating expenses of $4.1 million and higher income taxes of $5.6 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 effective January 1, 2002. The charge is presented on the Consolidated Statements of Operations as the Cumulative Effect of Accounting Change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. PSNC Energy performed an annual evaluation as of January 1, 2003 and no further impairment was indicated.
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 has authorized the following distributions/dividends on common stock held by SCANA during 2003:
Declaration Date Distribution Amount Quarter Ended Payment Date
February 20, 2003 $4.5 million March 31, 2003 April 1, 2003 May 1, 2003 $4.5 million June 30, 2003 July 1, 2003 July 31, 2003 $4.0 million September 30, 2003 October 1, 2003 November 7, 2003 $4.0 million December 31, 2003 January 1, 2004
Gas Distribution
Gas distribution sales margins for 2003 and 2002 were as follows:
Millions of dollars 2003 2002 Change % Change - ----------------------------------- -------------- ----------------- -----------
Operating revenues $508.9 $355.7 $153.2 43.1% Less: Cost of gas (330.4) (189.9) (140.5) (74.0%) - ----------------------------------- -------------- ----------------- Gross margin $178.5 $165.8 $12.7 7.7% =================================== ============== ================= ===========
Gas distribution sales margin for the year ended December 31, 2003 increased $6.8 million due to higher natural gas usage attributable to colder weather, $4.2 million due to customer growth and $0.7 million due to higher other operating revenues. The margin increase was partially offset by $1.2 million due to lower industrial natural gas usage arising from competition with alternate fuels. In addition to these changes affecting margins, revenues and costs also increased in 2003 because of higher commodity natural gas prices.
Operation and Maintenance Expenses
The $4.8 million increase in operation and maintenance expenses from 2002 is primarily due to increased bad debt expense of $2.4 million related to higher write-offs and increased gas costs. Also contributing to the increase are higher outside labor and general business expenses of $1 million and the impact of reduced pension income of $0.9 million.
Other Income
Other income increased $4.6 million for the year ended December 31, 2003 as compared to the same period in 2002 primarily due to increased income of $1.6 million from secondary market activities, such as off-system gas sales and pipeline capacity release, and increased interest income of $0.9 million primarily from amounts under-collected from customers through the operation of the Rider D mechanism. This mechanism allows PSNC Energy to recover all prudently incurred gas costs. In addition, merchandising and jobbing income increased $2.4 million primarily due to increased interest income of $0.8 million, a reduced provision for bad debt of $0.7 million, and increased appliance sales of $0.5 million.
Interest Expense
Interest expense decreased $0.7 million over 2002 due to reduced long-term debt and lower 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 2004 construction budget is approximately $51 million, compared to actual construction expenditures for 2003 of $48.5 million.
PSNC Energy's contractual cash obligations as of December 31, 2003 are summarized as follows:
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. Because these contracts relate to regulated gas businesses, their effects on gas costs are reflected in gas rates.
Included in purchase obligations are customary purchase orders under which PSNC Energy has the option to utilize certain vendors without the obligation to do so. PSNC Energy may terminate such purchase obligations without penalty.
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.
At December 31, 2003 PSNC Energy had available the following securities to meet its liquidity needs:
(Millions) Lines of credit: 364-day $125 Short-term borrowings outstanding: Commercial paper (270 or fewer days) $55 Weighted average interest rate 1.17%
PSNC Energy is party to two interest rate swap agreements which allow it to pay variable rates and receive fixed rates on a combined notional amount of $33.1 million at December 31, 2003. (See Note 7 to the 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
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, 2003 PSNC Energy had recorded approximately $16.5 million and $86.0 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities. 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 other deferred 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 other deferred 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, 2003 and 2002, accounts receivable included unbilled revenues of $38.3 million and $27.7 million, respectively, compared to total revenues for 2003 and 2002 of $508.9 million and $355.7 million, respectively.
SFAS 142 - In connection with the adoption of SFAS 142, "Goodwill and Other Intangible Assets," SCANA Corporation performed an initial valuation analysis of its investment in PSNC Energy using an independent appraisal. 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. PSNC Energy performed an annual evaluation as of January 1, 2003 and no further impairment was indicated.
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 provision for the recovery of actual gas costs incurred. PSNC Energy records transaction fees and any realized gains or losses from derivatives acquired as part of its hedging program in deferred accounts as regulatory assets and liabilities for the over or under recovery of gas costs. In an October 2003 order, in connection with PSNC Energy's 2003 annual prudency review, the NCUC determined that PSNC Energy's gas costs, including all hedging transactions, were reasonably and prudently incurred during the 12-month review period ended March 31, 2003.
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, 2003 and 2002, 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, 2003. 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, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 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 1 to the consolidated financial statements, the Company adopted Statement of Financial Standards No. 142, "Goodwill and Other Intangibles," effective January 1, 2002.
s/Deloitte & Touche LLP Columbia, South Carolina February 26, 2004
See Notes to Consolidated Financial Statements.
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. 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 certain 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, 2003, approximately $17 million and $86 million of regulatory assets and liabilities, respectively, as shown below.
December 31, Millions of dollars 2003 2002 - ----------------------------------------------------------------------- -------- - ----------------------------------------------------------------------- --------
Excess deferred income taxes - $(1) Under-(over-) collections - gas cost adjustment clause, net $(1) 10 Deferred environmental remediation costs 9 9 Non-legal asset retirement obligations (77) (70) - ----------------------------------------------------------------------- -------- Total $(69) $(52) ======================================================================= ========
Excess deferred income taxes represent deferred income taxes recorded in prior years at a rate higher than the current statutory rate. Pursuant to a North Carolina Utilities Commission (NCUC) order, the Company was required to refund these amounts to customers through a rate decrement.
Under-(over-) collections - gas cost adjustment clause, net represents amounts under- or over-collected from customers pursuant to the Company's Rider D mechanism approved by the NCUC. This mechanism allows the Company to recover all prudently incurred gas costs. (See Note 1F.)
Deferred environmental remediation costs represents costs associated with the assessment and cleanup of manufactured gas plant (MGP) sites currently or formerly owned by the Company. A portion of the costs incurred are being recovered through rates. Approximately $2.2 million in costs have been incurred and deferred that are not currently being recovered through gas rates (see Note 8). Management believes these costs and the remaining costs of approximately $7.0 million will be recoverable.
Non-legal asset retirement obligations represent net collections through depreciation rates of estimated costs to be incurred for the future retirement of assets for which no legal retirement obligation exists.
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, liquidity or financial position in the period the write-off would be recorded.
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 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 12.7%, 12.1% and 7.0% for the years ended December 31, 2003, 2002 and 2001, 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 $38.3 million and $27.7 million as of December 31, 2003 and 2002, 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 a manner authorized by the NCUC. Pursuant to the operation of Rider D, at December 31, 2003 the Company had overcollected from customers approximately $1.0 million, net. The Company had undercollected from customers approximately $10.2 million, net at December 31, 2002.
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 4.1%, 4.3% and 4.1% for 2003, 2002 and 2001, respectively.
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. The Company has no other significant intangible assets subject to amortization as provided in SFAS 142.
If the Company had ceased amortization of the $466 million acquisition adjustment during all periods presented in the consolidated statements of operations, net income (loss) would have been as follows:
(Millions of dollars) 2003 2002 2001 ---- ---- ----
Net Income (Loss) as Reported $31 $(207) $15 Amortization of Acquisition Adjustment - - 13 -- - ------ - -- -- Net Income (Loss) as Adjusted $31 $(207) $28 === ====== ===
In connection with 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 approximately $230 million. The resulting impairment charge is reflected on the statement of operations as the cumulative effect of an accounting change. SFAS 142 requires that an impairment evaluation be performed annually and at the same time each year. The Company performed an annual evaluation as of January 1, 2003 and no further impairment was indicated.
H. Income 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 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, certain 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 2003 and 2002 net capital contributions of $1.2 million and $0.6 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 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.
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.
The Company receives refunds from its pipeline transporters. Pursuant to an order of the NCUC, these funds are segregated from the Company's general funds and may only 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.
L. New Accounting Standards
The Company adopted SFAS 143, "Accounting for Asset Retirement Obligations," 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 adopted SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 145.
The Company adopted SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," effective January 1, 2003. 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. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 146.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" was issued in April 2003. SFAS 149 amends and clarifies accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, " Accounting for Derivative Instruments and Hedging Activities". SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 149.
SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" was issued in May 2003. SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. There was no impact on the Company's results of operations, cash flows or financial position from the initial adoption of SFAS 150.
M. Related Party Transactions
The Company has related party transactions with its equity method investees. The Company records as cost of gas the storage and transportation costs charged by these investees. These costs totaled approximately $16.5 million, $17.0 million and $17.2 million in 2003, 2002 and 2001, respectively. The Company owed these investees approximately $1.3 million at December 31, 2003 and $1.4 million at December 31, 2002 and 2001.
At December 31, 2003 an affiliate owed the Company $0.9 million for natural gas and transportation services. Additionally, the Company owed an affiliate $0.2 million related to billing and collection services for the sale of energy-related products and service contracts.
Effective January 1, 2001 PSNC Production Corporation (PSNC Production) and SCANA Public Service Company LLC were sold to SCANA Energy Marketing, Inc. (SEMI), a subsidiary of SCANA, for $4.4 million, which approximated their net book value. During the fourth quarter 2003, SEMI paid the Company $9.4 million for an outstanding receivable due from PSNC Production. The receivable was for cash advanced by the Company to PSNC Production prior to the sale.
N. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the presentation adopted for 2003.
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. 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 delivered 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 2003 and 2002 was as follows:
Rate Per Therm Effective Date Rate Per Therm Effective Date
$.460 January-February 2003 $.300 January 2002 $.595 March 2003 $.215 February-June 2002 $.725 April-November 2003 $.350 July-October 2002 $.600 December 2003 $.410 November-December 2002
In October 2003, in connection with the Company's 2003 Annual Prudence Review, the NCUC determined that the Company's gas costs, including all hedging transactions, were reasonable and prudently incurred during the 12-month review period ended March 31, 2003. The NCUC also authorized new rate decrements to refund over-collections of certain gas costs included in the Company's deferred accounts, effective November 1, 2003.
A state expansion fund, established by the North Carolina General Assembly 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 million. The Madison County and Jackson County portions of the project were completed in 2002, and the Swain County portion is expected to be completed in the spring of 2004. Through December 31, 2003 approximately $27.4 million had been spent on this project.
In December 1999 the NCUC issued an order approving SCANA's acquisition of the Company. As specified in the order, the Company 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.
3. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS
Employee Benefit Plans
The Company participates 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 applicable federal income tax regulations as determined by an independent actuary. The Company also participates 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.
For the years ended December 31, 2003 and 2002, the Company's net periodic benefit income (loss) was approximately $(1.2) million and $0.2 million, respectively, for the pension plan, and net periodic benefit cost was approximately $2.9 million and $2.3 million, respectively, for the postretirement plan.
4. LONG-TERM DEBT
Long-term debt maturities are $7.5 million for 2004 and $3.2 million for each of 2005 through 2008.
5. SHORT-TERM BORROWINGS
Millions of dollars 2003 2002 ---------------------------------------------------------- ---------------
Lines of credit (total and unused) $125.0 $125.0 Short-term borrowings outstanding: Commercial paper (270 or fewer days) $55.2 $31.1 Weighted average interest rate 1.17% 1.42%
The Company pays fees to banks as compensation for committed lines of credit.
6. INCOME TAXES
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $92.9 million at December 31, 2003 and $87.7 million at December 31, 2002 (see Note 1H) are as follows:
7. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2003 and 2002 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 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. The carrying values reflect the fair values of derivatives designated as hedges under SFAS 133 criteria (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.
In January 2003 the Company filed a summary of its hedging program for natural gas purchases with the NCUC for informational purposes. The primary goal of the program is to reduce price volatility to firm customers. In an October 2003 order, the NCUC declared the program was reasonable. Transaction fees and any gains or losses are recorded in deferred accounts for subsequent rate consideration. As of December 31, 2003 the Company had deferred net costs of approximately $2.2 million.
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 fair value of interest rate swaps is recorded within other deferred debits on the balance sheet. The resulting credits serve to reflect the hedged long-term debt at its fair value. Periodic receipts or payments related to the interest rate swaps are credited or charged to interest expense as incurred. ..
At December 31, 2003 the estimated fair value of the Company's swaps totaled $1.9 million related to combined notional amounts of $33.1 million.
8. COMMITMENTS AND CONTINGENCIES
A. Environmental
The Company is responsible for environmental cleanup at five sites in North Carolina on which manufactured gas plant (MGP) residuals are present or suspected. 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. The Company has recorded a liability and associated regulatory asset of approximately $7.0 million, which reflects its estimated remaining liability at December 31, 2003. Amounts incurred and deferred to date that are not currently being recovered through gas rates are approximately $2.2 million. Management believes that all MGP cleanup costs will be recoverable through gas rates.
B. 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.
C. Purchase Commitments
As of December 31, 2003 purchase commitments under forward contracts for natural gas purchases are $266 million and $108 million for 2004 and 2005, respectively.
In addition, included in purchase commitments are customary purchase orders under which the Company has the option to utilize certain vendors without the obligation to do so. The Company may terminate such commitments without penalty.
PART II, ITEM 9
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:
SCANA: None
SCE&G: None
PSNC Energy: None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
SCANA:
As of December 31, 2003, an evaluation was performed under the supervision and with the participation of SCANA'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, SCANA's management, including the CEO and CFO, concluded that SCANA's disclosure controls and procedures were effective as of December 31, 2003. There has been no change in SCANA's internal controls over financial reporting during the quarter ended December 31, 2003 that has materially affected or is reasonably likely to materially affect SCANA's internal control over financial reporting.
SCE&G:
As of December 31, 2003, 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, 2003. There has been no change in SCE&G's internal controls over financial reporting during the quarter ended December 31, 2003 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.
PSNC Energy:
As of December 31, 2003, 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, 2003. There has been no change in PSNC Energy's internal controls over financial reporting during the quarter ended December 31, 2003 that has materially affected or is reasonably likely to materially affect the Company's internal control over financial reporting.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
SCANA: A list of SCANA's executive officers is in Part I of this annual report at page 24. 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 2004 annual meeting of shareholders which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934 within 120 days after the end of SCANA's fiscal year.
CODE OF ETHICS
SCANA has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer or controller. SCANA has posted the text of the code on its Internet website at www.scana.com.
*Mr. Stowe is a member of the Audit Committee of SCE&G's board of directors and has been determined by SCE&G's board of directors to be an audit committee financial expert within the meaning of Item 401(h) of Regulation S-K. SCE&G's board of directors has also determined that Mr. Stowe is independent, as that term is used in Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.
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 2003 all Section 16(a) filing requirements applicable to its officers, directors and greater than 10% beneficial owners were complied with.
CODE OF ETHICS
SCE&G has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer or controller. SCE&G has posted the text of the code on its Internet website at www.scana.com.
ITEM 11.
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 2004 annual meeting of shareholders.
(1) Payments under the Annual Incentive Plan. (2) For 2003, other annual compensation consists of life insurance premiums on policies owned by named executive officers. (3) Payouts of performance share awards under the Company's Long-Term Equity Compensation Plan. (4) All other compensation for all named executive officers consists solely of Company matching contributions to defined contribution plans. (5) Reflects actual salary paid in 2003. Base salary of $870,900 became effective on February 20, 2003.
Long-Term Incentive Plans Awards
The following table lists the performance share awards and the performance unit awards made in 2003 (for potential payment in 2006) under the Long-Term Equity Compensation Plan and estimated future payouts under that plan at threshold, target and maximum levels for each of the executive officers included in the Summary Compensation Table.
Payouts on performance share awards occur when SCANA's total shareholder return is in the top two-thirds of the Long-Term Equity Compensation Plan peer group for that period, and will vary based on SCANA's ranking against that peer group. Executives earn threshold payouts (40% of award) at the 33rd percentile of three-year performance. Target payouts (100% of award) will be made at the 50th percentile of three-year performance. Maximum payouts (150% of award) will be made when performance is at or above the 75th percentile of the peer group. Payments will be made on a sliding scale for performance between threshold and target and target and maximum. No payouts will be earned if performance is at less than the 33rd percentile. Awards are designated as target shares of SCANA common stock and may be paid in stock or cash or a combination of stock and cash. Payouts on performance unit awards occur when SCANA's three-year average growth in earnings per share from ongoing operations equals or exceeds 4%. Executives earn threshold payments (50% of award) at 4% average growth, target payments (100% of award) at 6% average growth and maximum payouts (150% of award) at 8% average growth. No payouts will occur if average growth in earnings per share from ongoing operations over the period is less than 4%. Awards are designated as target units of SCANA common stock and may be paid in stock or cash or a combination of stock and cash.
Defined Benefit Plans
SCANA has 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 has 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 - $456,312; Mr. Lorick - $290,436; Mr. Marsh - $349,416; Mr. Arthur - $114,180 and Mr. Byrne - $271,452.
Termination, Severance and Change in Control Arrangements
SCANA maintains an Executive Benefit Plan Trust. The purpose of the trust is to help retain and attract 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 covered 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 and performance unit 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 2003, 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 Committee 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, 2003, compensation for non-employee directors of SCANA and its subsidiaries has included the following:
o an annual retainer of $36,000 (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 day a regular meeting of the Board is held; o $300 for participation in a telephone conference meeting of 30 minutes or less, and $600 for participating in a longer conference; o $3,000 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 and 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 2003, the only director participating in the Voluntary Deferral Plan was Mr. Bennett, whose account was credited with interest of $2,366 for the year.
Under the Director Compensation and Deferral 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 2003, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan, Stowe and York and Ms. Miller 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER INFORMATION
SCANA: The information called for by this Item is incorporated herein by reference to the caption "Share Ownership of Directors, Nominees and Executive Officers" and "Five Percent Ownership of SCANA Common Stock" and "Equity Compensation Plan Information" within Item 2 - approval of Amended Director Compensation and Deferral Plan" in SCANA's definitive proxy statement for the 2004 annual meeting of shareholders.
SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The following table lists shares of SCANA common stock beneficially owned on February 23, 2004 by each director and each person named in the Summary Compensation table in Item 11, Executive Compensation.
*Each of the above owns less than 1% of the shares outstanding.
All directors and executive officers as a group (17 persons) total 837,860 shares, including 625,832 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 Mr. Bookhart-6,601 shares owned by close relatives, the beneficial ownership of which he disclaims. (2) Includes shares purchased through February 11, 2004, 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 23, 2004, each of the following directors had acquired under the plan, the number of hypothetical shares following his or her name: Messrs. Amick-7,591, Bennett-7,060, Burkhardt-8,705, Hagood-2,755, Hipp-7,491, Sloan-7,815, Stowe-7,992, York-8,284 and Ms. Miller-8,323. (4) Includes shares subject to currently exercisable options and options that will become exercisable within 60 days in the following amounts: Messrs. Timmerman-311,535; Lorick-90,921; Marsh-100,215; Byrne-56,600; Arthur-56,600. (5) Hypothetical shares acquired under the SCANA Executive Deferred Compensation Plan are not included in the above table. As of February 23, 2004, each of the following officers had acquired under the plan, the number of hypothetical shares following his or her name: Messrs. Timmerman-25,022; Lorick-4,703; Marsh-4,579; Byrne-2,711; Arthur-4,232. (6) Human Resources Committee. (7) Long-Term Equity Compensation Plan Committee.
ITEM 13.
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 caption "Related Party Transactions" in SCANA's definitive proxy statement for the 2004 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 2004 annual meeting of shareholders shall not be incorporated by reference into any such filings.
SCE&G: During 2003, SCANA incurred advertising expenses of $66,163 (including the value of non-utility in-kind services provided by SCANA and its subsidiaries) on account of advertising services provided by subsidiaries of The Liberty Corporation. 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
SCANA: The information required by Item 14 is incorporated herein by reference to Proposal 3 in SCANA's definitive proxy statement for the 2004 annual meeting of shareholders.
SCE&G and PSNC Energy:
SCANA's Audit Committee Charter requires the Audit Committee to pre-approve all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed by the external auditors. Pursuant to a policy adopted by the Audit committee, the Committee Chairman may pre-approve the rendering of services on behalf of the Audit Committee.
Independent Auditors Fees
The following table set forth the aggregate fees billed to SCE&G and PSNC Energy for the fiscal years ended December 31, 2002 and 2003 by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates.
2003 2002 ---- ---- SCE&G PSNC Energy SCE&G PSNC Energy ----- ----------- ----- ----------- Audit Fees (1) $747,716 $143,661 $1,003,258 $232,068 Audit Related Fees (2) 348,301 72,200 53,418 5,440 Tax Fees (3) 32,053 2,813 36,998 2,960 All Other Fees (4) 78,958 40,000 ------------- -------------------------- ---- ------ - - Total Fees $1,128,070 $218,674 $1,172,632 $280,468
(1) Fees for audit services billed in 2003 and 2002 consisted of audits of the companies' annual financial statements, reviews of the companies quarterly financial statements, comfort letters, statutory and regulatory audits, consents and other services related to the Securities and Exchange Commission ("SEC"), and accounting research. (2) Includes Sarbanes-Oxley section 404 readiness assistance and employee benefit plan audits for 2003, and employee benefit plan and subsidiary audits for 2002. (3) Includes tax compliance and tax services. (4) Includes depreciation studies in 2002.
In 2003 and 2002 all of the Audit Related Fees, Tax Fees and All Other Fees were approved by the Audit Committee.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed or furnished as a part of 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 or furnished with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the 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 2003 for SCANA, SCE&G and PSNC Energy:
SCANA Corporation: Date of report: October 27, 2003 Items reported: 7 and 12
South Carolina Electric & Gas Company: Date of report: October 27, 2003 Items reported: 7 and 12
Date of report: October 30, 2003 Item reported: 5
Date of report: October 31, 2003 Items reported: 5 and 7
Public Service Company of North Carolina Incorporated: Date of report: October 27, 2003 Items reported: 7 and 12
(a)Includes $309,645 uncollectible reserve balance for SCANA Public Service Company LLC which was sold to SCANA Energy Marketing effective January 1, 2001.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SCANA CORPORATION
s/W. B. Timmerman BY: W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director
DATE: February 27, 2004
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.
s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer)
s/K. B. Marsh K. B. Marsh, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
s/ J. E. Swan J. E. Swan, Controller (Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp J. A. Bennett L. M. Miller W. B. Bookhart, Jr. M. K. Sloan W. C. Burkhardt H. C. Stowe E. T. Freeman G. S. York D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: February 27, 2004
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY: s/N. O. Lorick N. O. Lorick President and Chief Operating Officer
DATE: February 27, 2004
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.
s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
s/K. B. Marsh K. B. Marsh, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
s/ J. E. Swan J. E. Swan, Controller (Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp J. A. Bennett L. M. Miller W. B. Bookhart, Jr. M. K. Sloan W. C. Burkhardt H. C. Stowe E. T. Freeman G. S. York D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: February 27, 2004
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
BY: s/Jerry W. Richardson Jerry W. Richardson President and Chief Operating Officer
DATE: February 27, 2004
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to the registrant and any subsidiaries thereof.
s/W. B. Timmerman W. B. Timmerman, Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
s/K. B. Marsh K. B. Marsh, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
s/ J. E. Swan J. E. Swan, Controller (Principal Accounting Officer)
Other Directors*:
B. L. Amick W. M. Hipp J. A. Bennett L. M. Miller W. B. Bookhart, Jr. M. K. Sloan W. C. Burkhardt H. C. Stowe E. T. Freeman G. S. York D. M. Hagood
*Signed on behalf of each of these persons by Kevin B. Marsh, Attorney-in-Fact
DATE: February 27, 2004