Item 1. Business
The Company
Consolidated Natural Gas Company (CNG or the Company) operates in all phases of the natural gas business, explores for and produces oil, and provides a variety of retail energy marketing services. The Company is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a fully integrated gas and electric holding company headquartered in Richmond, Virginia. The Company is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act).
On January 28, 2000, Dominion completed the acquisition of CNG and merged CNG into a subsidiary (New Company) of Dominion. The New Company was incorporated in Delaware in 1999 and at the time of the merger changed its name to Consolidated Natural Gas Company. The “Company” is used throughout this report and, depending on the context of its use, refer to CNG, one of CNG’s consolidated subsidiaries, or the entirety of CNG and its consolidated subsidiaries, both before and after the merger with Dominion.
As of December 31, 2003, the Company had approximately 4,600 full-time employees. Approximately 2,600 employees are subject to collective bargaining agreements.
The Company’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and its telephone number is (804) 819-2000.
Operating Segments
The Company manages its operations through three primary operating segments. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.
Delivery manages the Company’s gas distribution systems, customer service operations and the Company’s nonregulated retail energy marketing activities.
Energy manages the Company’s gas transmission pipeline and storage system, certain gas production operations, the Cove Point liquefied natural gas facility and field services and gas marketing operations.
Exploration & Production manages the Company’s gas and oil exploration, development and production operations.
While the Company manages its daily operations as described above, its assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Notes 1 and 24 to the Consolidated Financial Statements.
Business Developments
Since reactivating its Cove Point liquefied natural gas (LNG) facility in August 2003, the Company started construction on a fifth storage tank. The new tank is expected to be completed in the first quarter of 2005 and increases the current storage capacity from 5.0 billion cubic feet (bcf) to 7.8 bcf. In February 2004, the Company announced plans to increase the Cove Point storage tank capacity to 14.6 bcf and the plant’s deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. Associated with the Cove Point expansion, the Company also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed into service in 2008.
The Company is a participant in two deepwater Gulf of Mexico projects, Devils Tower and Front Runner, that are expected to start production in 2004. The Devils Tower deepwater production platform, which is known as a spar, has been installed with production scheduled to commence in the second quarter of 2004. Front Runner spar installation is expected to begin in the second quarter of 2004, with production anticipated to start in the fourth quarter of 2004.
Seasonality
Gas sales in the Delivery segment typically vary seasonally based on increased demand by residential and commercial customers for heating use due to changes in temperature. The Energy segment is also impacted by seasonal changes in the prices of commodities that it actively markets and trades. For Exploration & Production, natural gas and oil prices can vary seasonally as well. See Risk Factors and Cautionary Statements That May Affect Future Results in Item 7. Management’s Discussion and Analysis of Results of Operations for additional information on how weather may affect the Company’s results of operations.
Regulation
The Company is subject to regulation by the Securities and Exchange Commission (SEC), Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency (EPA), Department of Energy (DOE), the Army Corps of Engineers, and other federal, state and local authorities.
State Regulatory Matters
The Company’s gas distribution service is regulated by the Public Utilities Commission of Ohio (Ohio Commission),
Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission).
Status of Gas Deregulation
Each of the three states in which the Company has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.
Ohio-Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, the Company on its own initiative offers retail choice to customers. At December 31, 2003, approximately 670,000 of the Company’s 1.2 million Ohio customers were participating in this open-access program. Large industrial customers in Ohio also source their own natural gas supplies.
Pennsylvania-In Pennsylvania, supplier choice is available for all residential and small commercial customers. At December 31, 2003, approximately 95,000 residential and small commercial customers had opted for Energy Choice in the Company’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.
West Virginia-At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers be licensed in West Virginia.
Rate Matters-Gas Distribution
The Company’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate-Pennsylvania, Ohio and West Virginia. When necessary, the Company’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, certain of the Company’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are generally subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective three-month or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchase gas cost expenses.
Ohio-In December 2003, the Ohio Commission approved a joint application filed by the Company and several other Ohio natural gas companies for recovery of bad debt expense via a rider known as a bad debt tracker. The tracker insulates the Company from the effect of changes in bad debt expense, which is affected by the volatility of natural gas prices, weather, and prices charged by competitive retail natural gas suppliers. The tracker is an adjustable rate that recovers the cost of bad debt in a manner similar to a gas cost recovery rate. Instead of recovering bad debt costs through its base rate, the Company now will recover all bad debt expenses in Ohio through the bad debt tracker and will remove bad debt from base rates. Annually, the Company will assess the need to adjust the tracker based on the preceding year’s actual bad debt expense.
West Virginia-In August 2003, the Company filed an application with the West Virginia Commission to increase its purchased gas cost rate by approximately $31 million on an annualized basis, effective for the period January 1, 2004 through October 31, 2004. The increase is in anticipation of higher purchased gas costs expected for that period. The Company’s rate moratorium expired at the end of 2003. The application reflected the traditional purchase gas adjustment treatment for the Company’s purchased gas costs. The West Virginia Commission issued an order setting an interim rate in the fourth quarter of 2003, with a final rate order to be issued in the second quarter of 2004.
Rate Matters-Gas Transmission
The Company implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2003. In all material respects, these filings were approved by FERC in the form requested by the Company and were subject to only minor modifications. The Company has no significant rate matters pending before FERC at this time.
Public Utility Holding Company Act of 1935
The Company is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of the Company and its subsidiaries with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters.
Federal Energy Regulatory Commission
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. FERC also has jurisdiction over the construction of pipeline and related facilities used in transportation and storage of natural gas in interstate commerce.
Competition in the natural gas industry was increased by FERC Order 636, which was issued in 1992. FERC Order 636 requires transmission pipelines to operate as open-access transporters and provide transportation and storage services on an equal basis for all gas suppliers, whether purchased from the Company or from another gas supplier.
The Company’s interstate gas transportation and storage activities are conducted in accordance with certificates, tariffs and service agreements on file with FERC. The Company is also subject to the Natural Gas Pipeline Safety Act of 1968, which authorizes the establishment and enforcement of federal pipeline safety standards and places jurisdiction of these standards with the Department of Transportation.
In November 2003, FERC issued new Standards of Conduct governing conduct between interstate transmission gas and electricity providers and their marketing function or their energy related affiliates. The new rule redefines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences. All transmission providers must be in compliance by June 2004. The Company has adopted an implementation plan and will train the appropriate personnel to ensure compliance with the new rules.
In December 2002, Congress enacted the Pipeline Safety Act of 2002, which included new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission and storage pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. The Company is currently evaluating its natural gas transmission and storage properties under the final regulations issued in December 2003 and is assessing the nature and costs of inspection and potential remediation activities at this time.
Environmental Regulations
Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, see Item 3. Legal Proceedings and Note 20 to the Consolidated Financial Statements.
From time to time the Company may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, the Company may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. The Company does not believe that any currently identified sites will result in significant liabilities.
The Company has applied for or obtained the necessary environmental permits for the operation of its regulated facilities. Many of these permits are subject to re-issuance and continuing review.
Competition
Deregulation and restructuring in the gas industry continue to create issues that affect or will likely affect the markets where the Energy and Delivery segments do business, and govern the way these business units and their competitors operate. The natural gas industry continues to evolve into a competitive marketplace where energy companies will compete to provide energy and energy services to a broad range of customers.
Delivery
Deregulation is at varying stages in the three states in which the Company’s gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small commercial customers. In Ohio, legislation has not been enacted to require supplier choice for residential and commercial natural gas consumers. However, the Company offers an Energy Choice program to customers on its own initiative, in cooperation with the Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. See Status of Gas Deregulation for additional information.
Energy
The Company’s large underground natural gas storage network and the location of its pipeline system provide a significant link between the country’s major gas pipelines and large markets in the Northeast and Mid-Atlantic regions and on the East Coast. The Company’s pipelines are part of an interconnected gas transmission system which continues to provide local distribution companies, marketers, power generators and commercial and industrial customers the accessibility of supplies nationwide.
The Company competes with domestic and Canadian pipeline companies and gas marketers to provide or arrange transportation, storage and other services for customers. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enables the Company to tailor its services to meet the needs of individual customers.
Exploration & Production
The Company conducts exploration and production operations in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico. Competitors range from major international oil companies to smaller independent producers.
The Company faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since the Company is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development.
In terms of its production activities, the Company sells most of its deliverable natural gas and oil into short and intermediate-term markets. The Company faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, the Company owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions which strengthens its knowledge of the marketplace and delivery options.
Availability of Natural Gas for Retail Distribution
The Company is engaged in the sale and storage of natural gas through its operating subsidiaries. The Company’s natural gas supply is obtained from various sources including: purchases from major and independent producers in the Southwest and Midwest regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from the Company’s and third party underground storage fields.
The Company continues to purchase volumes from the array of accessible producing basins using its firm capacity resources. These purchased supplies include Appalachian resources in Ohio, Pennsylvania and West Virginia and production from the Gulf Coast, Mid-Continent and offshore areas. Upon FERC’s restructuring of the interstate pipeline business in 1992 and 1993, pipelines no longer sell the delivered natural gas commodity; rather, customers provide their own gas supply for wholesale storage and/or delivery by the pipelines. Much of the supply is purchased by local distributors, energy marketing companies or end-users under seasonal or spot purchase agreements.
The Company’s underground storage facilities play an important part in balancing gas supply with sales demand and are essential to servicing the Mid-Atlantic and Northeast’s large volume of space-heating business. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.
Item 2.
Item 2. Properties
The Company shares its principal office in Richmond, Virginia, with its parent company, Dominion. Such office space is leased. The Company leases offices in other cities in which its subsidiaries operate.
Delivery’s investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network includes approximately 27,000 miles of pipe, exclusive of service pipe.
Energy has approximately 7,900 miles of gas transmission, gathering and storage pipeline and operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. The Company owns 20 of these storage fields and has joint-ownership with other companies in six of the fields. The total designed capacity of the underground storage fields is approximately 960 billion cubic feet (bcf). The Company’s share of the total capacity is about 717 bcf. Energy also has 5 bcf of above ground storage capacity at its Cove Point liquefied natural gas facility. Energy’s storage operation also includes approximately 372,000 acres of operated leaseholds and more than 2,000 storage wells. Energy also has more than 100 compressor stations with approximately 597,000 installed compressor horsepower located in Ohio, Virginia, West Virginia, Pennsylvania and New York. Some of the stations are used interchangeably for several functions.
The map below illustrates the Company’s gas transmission pipelines and storage facilities.
Exploration & Production owns 4.9 trillion cubic feet of proved equivalent natural gas reserves and produces approximately .9 billion cubic feet of equivalent natural gas per day from its leasehold acreage and facility investments. The Company, either alone or with partners, holds interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. The Company also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. The Company’s share of developed leasehold totals 2.2 million acres, with another 1.6 million acres held for future exploration and development drilling opportunities.
Information detailing the Company’s gas and oil operations presented on the following pages includes the activities of the Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included in the Energy segment:
Company-Owned Proved Gas and Oil Reserves
Estimated net quantities of proved gas and oil reserves at December 31 of each of the last three years were as follows:
Certain subsidiaries of the Company file Form EIA-23 with the DOE, which reports gross proved reserves, including the working interests share of other owners, for properties operated by such Company subsidiaries. The proved reserves reported in the table above represent the Company’s share of proved reserves for all properties, based on the Company’s ownership interest in each property. For properties operated by the Company, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2003 are based upon a study for each of the Company’s properties prepared by the Company’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.
Quantities of Gas and Oil Produced
Quantities of gas and oil produced* during each of the last three years ending December 31 follow:
*
Gas and oil production quantities include the production from the Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included in the Energy segment.
The average sales price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Company operations at market prices) realized during the years 2003, 2002 and 2001 was $4.15, $3.60 and $4.03, respectively. The respective average prices without hedging results per mcf of gas produced were $5.26, $3.25 and $4.14, respectively. The respective average sales prices realized for oil with hedging results were $24.80, $23.73 and $24.58 per barrel and the respective average prices without hedging results were $30.74, $25.03 and $24.71 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2003, 2002 and 2001 was $0.75, $0.51 and $0.49 respectively.
Acreage
Gross and net developed and undeveloped acreage at December 31, 2003 was:
Net Wells Drilled in the Calendar Year
The number of net wells completed during each of the last three years ending December 31 follows:
As of December 31, 2003, 60 gross (42 net) wells were in process of drilling, including wells temporarily suspended.
Productive Wells
The number of productive gas and oil wells in which the Company had an interest at December 31, 2003, follow:
The number of productive wells includes 311 gross (123 net) multiple completion gas wells and 22 gross (10 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes.
Item 3.
Item 3. Legal Proceedings
From time to time, the Company and its subsidiaries are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Company and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on the Company’s financial position, liquidity or results of operations.
See Regulation in Item 1. Business and Note 20 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which the Company is a party.
Before being acquired by the Company, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hildalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.
In July 1997, Jack Grynberg, an oil and gas entrepreneur, brought suit against CNG and several of its subsidiaries. The suit seeks damages for alleged fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg’s claims were dismissed on the basis that they overlapped with Mr. Wright’s claims which are noted below. Mr. Grynberg has filed an appeal. The defendants plan to file a motion to dismiss in the spring of 2004.
In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against Dominion Exploration & Production, Inc. (formerly known as CNG Producing Company), a subsidiary of CNG, alleging various fraudulent valuation practices in the payment of royalties on federal leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against CNG Producing Company was resolved by settlement in late 2002, and the case was remanded back to the U.S. District Court for the Eastern District of Texas.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Omitted pursuant to General Instruction I.(2)(c).
Part II
Item 5.
Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters
Dominion Resources, Inc. (Dominion) owns all of the Company’s common stock.
The Company paid quarterly cash dividends on its common stock to Dominion during 2003 and 2002 as follows:
Restrictions on the payment of dividends by the Company are discussed in Note 18 to the Consolidated Financial Statements.
Item 6.
Item 6. Selected Financial Data
Omitted pursuant to General Instruction I.(2)(a).
Item 7.
Item 7. Management’s Discussion And Analysis Of Results Of Operations
Management’s Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The “Company” or “CNG” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company; one of Consolidated Natural Gas Company’s consolidated subsidiaries; or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. The Company is a wholly-owned subsidiary of Dominion.
Contents of MD&A
The reader will find the following information in this MD&A:
n Forward-Looking Statements
n Introduction
n Accounting Matters
n Results of Operations
n Segment Results of Operations
n Credit Risk
n Risk Factors and Cautionary Statements That May Affect Future Results
Forward-Looking Statements
This report contains statements concerning the Company’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by words such as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.
The Company makes forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to be materially different from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.
The Company bases its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements are made. The Company cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, materially differ from actual results. The Company undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
Introduction
CNG is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services.
The Company is organized primarily on the basis of products and services sold in the United States. The Company manages its operations based on three primary operating segments: Delivery, Energy and Exploration & Production. These segments, and their composition, reflect changes made to the Company’s management structure during the fourth quarter of 2003.
The contributions to net income by the Company’s primary operating segments are determined based upon a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing segment performance or allocating resources among the segments.
Those specific items are reported in the Corporate and Other segment.
Energy includes the following operations:
n A regulated interstate gas transmission pipeline and storage system, serving the Company’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;
n A liquefied natural gas (LNG) unloading and storage facility in Maryland;
n Certain natural gas production operations located in the Appalachian basin and
n Field services operations, representing aggregation of gas supply and related wholesale activities related to the Appalachian area.
Energy’s revenue and cash flows are derived from both regulated and nonregulated operations. Revenue and cash flow provided by gas transmission operations and the Company’s LNG facility are based primarily on cost-of-service rates established by Federal Energy Regulatory Commission (FERC). The operating results of the Energy segment also reflect the impact of weather on demand for natural gas, customer growth as influenced by overall economic conditions and changes in prices of commodities. Variability in revenue and cash flow provided by these regulated businesses results primarily from changes in rates while sales volumes and prices charged to customers affect the variability in revenue and cash flow provided by the nonregulated businesses. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding the use of resources for operations and maintenance or capital-related activities.
Revenue and cash flow for the Energy segment’s nonregulated businesses are subject to variability associated with changes in commodity prices. Energy’s nonregulated businesses use physical and financial contracts to hedge this price risk. Certain hedging activities may require cash deposits to satisfy margin requirements. In addition, reported earnings for this segment reflect changes in the fair value of certain derivatives and these values may change significantly from period to period. Variability in expenses for these nonregulated businesses relates largely to the costs of purchased commodities for resale and payments under financially-settled contracts.
Delivery includes the Company’s regulated gas distribution utilities and customer service operations. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. The segment also includes nonregulated retail marketing businesses that supply gas, electricity and related products and services to residential and small commercial customers in the Northeast and Midwest.
Revenue and cash flow provided by the Company’s gas distribution utility operations are based primarily on cost-of-service rates established by state regulatory authorities. Variability in Delivery’s revenue and cash flow relates largely to changes in volumes, which are primarily weather sensitive. In addition, for distribution utility operations, revenue may vary based on changes in levels of rate recovery for the costs of gas purchased and sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail marketing of gas and electricity may also be affected by changes in weather and commodity prices as well as acquisition and potential loss of customers.
Sales growth in the regulated residential service areas of Ohio, Pennsylvania and West Virginia has generally been limited since these areas have experienced minimal population growth, and the vast majority of households in these areas already use natural gas for space heating. Sales are also being affected by regulatory and legislative initiatives to deregulate natural gas at the retail level. Under open access programs in Ohio and Pennsylvania, customers may choose a gas supplier other than their local gas utility and have the local utility provide transportation of the commodity through its existing delivery system. Delivery’s retail energy marketing businesses currently have gas customers in Ohio, Pennsylvania and Illinois.
Large industrial customers in Ohio source their own natural gas supplies. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.
Variability in expenses results from changes in the cost of purchased gas and routine maintenance and repairs (including labor and benefits as well as decisions regarding the use of resources for operations and maintenance or capital-related activities). For gas distribution utility operations, the Company is permitted to seek recovery of the cost of gas purchased and sold to customers.
Exploration & Production includes the Company’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.
The Company operates a drilling program focused on low risk development drilling in several proven onshore regions of the United States, while also maintaining some exposure to higher risk exploration opportunities. Significant development drilling programs are currently underway in West Texas, the Appalachians and the Rocky Mountains where the Company holds sizeable acreage positions and operational experience. While each region provides the Company with exploration opportunities, most exploratory drilling takes place in the Gulf Coast region, including the deepwater Gulf of Mexico. The Company maintains an active and ongoing drilling program, participating in 763 net wells during 2003, and replacing approximately 230 percent of its 2003 production.
Revenue and cash flow provided by exploration and production operations are based primarily on the production and
sale of company-owned natural gas and oil reserves. Variability in the segment’s revenue and cash flow relates primarily to changes in commodity prices, which are market based, and volumes, which are impacted by numerous factors including drilling success, timing of development projects, as well as external factors such as severe weather. The Company manages commodity price volatility by hedging a substantial portion of its near term expected production.
Variability in the segment’s expenses relates primarily to changes in operating costs and production taxes, which tend to increase and decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related E&P service industry costs, while severance and property taxes move with changes in revenue. A changing price environment impacts both operating costs and the cost of acquiring, finding and developing natural gas and oil reserves.
Corporate and Other includes the activities of CNG International and other minor subsidiaries, as well as costs of the Company’s corporate functions. It also includes specific items attributable to the Company’s operating segments that are reported in Corporate and Other. CNG International is engaged in energy-related activities primarily outside of the United States. However, the Company has decided to focus on the United States gas and oil markets and, accordingly, is pursuing the sale of CNG International (see Note 7 to the Consolidated Financial Statements).
Accounting Matters
Critical Accounting Policies and Estimates
The Company has identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to its financial condition or results of operations under different conditions or using different assumptions.
Accounting for derivative contracts at fair value
The Company uses derivative instruments to manage its commodity and financial market risks. Accounting requirements for derivatives and hedging activities are complex; interpretation of these requirements by standard-setting bodies is ongoing.
Generally, derivatives are reported on the Consolidated Balance Sheets at fair value. Changes in the fair value of derivatives that are not designated as accounting hedges are recorded in earnings.
The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Company’s management.
For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value. In addition, for hedges of forecasted transactions, the Company must estimate the expected future cash flows of the forecasted transactions, as well as evaluate the probability of the occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could affect the timing of recognition in earnings for changes in fair value of certain hedging derivatives.
Use of estimates in goodwill impairment testing
The Company is required to test its goodwill for potential impairment on an annual basis, or more frequently if impairment indicators are present. In performing the test, the Company estimates the fair value of its reporting units by using discounted cash flow analyses and other valuation techniques based on multiples of earnings for peer group companies, as well as analyses of recent business combinations involving peer group companies. These calculations are dependent on many subjective factors, including management’s estimate of future cash flows, the selection of appropriate discount and growth rates and the selection of peer group companies and recent transactions. The cash flow estimates used by the Company are based on relevant information available at the time the estimates are made. However, estimates of future cash flows are highly uncertain by nature and may vary significantly from actual results.
The underlying assumptions and estimates involved in preparing these fair value calculations could change significantly from period to period. Modifications to any of these assumptions, particularly changes in discount rates and changes in growth rates inherent in management’s estimate of future cash flows, could result in a future impairment of goodwill.
Use of estimates in long-lived asset impairment testing
Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Company would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset’s carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. Although cash flow estimates used by the Company are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.
Employee benefit plans
The Company sponsors and also participates in certain Dominion noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected rate of return on plan assets, discount rates applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs, also have a significant impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants rather than immediately.
The selection of discount rates and expected long-term rates of return on plan assets are critical assumptions. The Company determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:
n Historical return analysis to determine expected future risk premiums;
n Forward looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;
n Expected inflation and risk-free interest rate assumptions and
n The types of investments expected to be held by the plans.
Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under the Company’s plans.
Accounting for regulated operations
Methods of allocating costs to accounting periods for operations subject to federal or state cost-of-service rate regulation may differ from accounting methods generally applied by nonregulated companies. When the timing of cost recovery prescribed by regulatory authorities differs from the timing of expense recognition used for accounting purposes, the Company’s Consolidated Financial Statements may recognize a regulatory asset for expenditures that otherwise would be expensed. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through rates. Regulatory liabilities represent probable future reductions in revenue associated with expected customer credits through rates or amounts collected from customers for expenditures not yet incurred. Management makes assumptions regarding the probability of regulatory asset recovery through future rates approved by applicable regulatory authorities. The expectations of future recovery are generally based upon orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, they would be expensed in the period such assessment is made. See Notes 2 and 12 to the Consolidated Financial Statements.
Accounting for gas and oil operations
The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using a unit-of-production method. The depreciable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The calculations under this accounting method are dependent on engineering estimates of proved reserve quantities and estimates of the amount and timing of future expenditures to develop the proved reserves. Proved reserves, and the cash flows related to these reserves, are estimated based on a combination of historical data and expected future activity. Actual reserve quantities and development expenditures may differ from the forecasted amounts.
In addition, the Company has significant investments in unproved properties, which are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base, determined on a property-by-property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base.
Capitalized costs in the depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling-the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves assuming period-end hedge-adjusted prices. The Company performs the ceiling test quarterly, on a country-by-country basis, and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. Any impairment of excess gas and oil property costs over the ceiling is charged to operations. Given the volatility of natural gas and oil prices, it is possible that the Company’s estimate of discounted future net cash flows from proved natural gas and oil reserves could change in the near term. If natural gas or oil prices have declined as of the date of the ceiling test, or if the Company revises its estimates of the quantities or timing of future production from its proved reserves, recognition of natural gas and oil property impairments could occur. See Notes 2 and 25 to the Consolidated Financial Statements.
Newly Adopted Accounting Standards in 2003
During 2003, the Company was required to adopt several new accounting standards which affect the comparability of its Consolidated Financial Statements. The requirements of those standards are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The following discussion is presented to provide an understanding of the financial statement impacts of those standards when comparing the 2003 Consolidated Financial Statements to prior years.
SFAS No. 143
Adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003 affected the comparability of the Company’s 2003 Consolidated Financial Statements to those of prior years as follows:
n Recognition of asset retirement obligations of $198 million and reversal of $84 million that had been previously recorded in the accumulated provision for depreciation, depletion and amortization and
n Recognition of $109 million of capitalized asset retirement costs in property, plant and equipment and a $3 million increase in accumulated depreciation, depletion and amortization, representing the depreciation of such costs through December 31, 2002.
FIN 46R
Upon adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R), on December 31, 2003 with respect to special purpose entities, the Company was required to consolidate a variable interest lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet at December 31, 2003 reflects an additional $223 million in net property, plant and equipment and deferred charges and an additional $234 million of related debt.
In addition, under FIN 46R, the Company reports its junior subordinated notes held by an affiliated trust as long-term debt, rather than the trust preferred securities issued by the trust. At December 31, 2002, the Company consolidated the trust and reported the trust preferred securities on its Consolidated Balance Sheet.
Results of Operations
Following is a summary of contributions by its operating segments to net income for the year ended December 31, 2003 and 2002:
Overview
2003 vs. 2002
Net income in 2003 was $638 million, reflecting no change from 2002. The Company’s primary operating segments contributed an additional $81 million to net income. This increase largely reflects the benefits of higher natural gas prices during 2003 on sales of the Company’s gas and oil production. See Note 24 to the Consolidated Financial Statements for information about the Company’s operating segments. The increased contribution by the operating segments was offset by several specific charges to income recognized by the Company during 2003 and reported in the Corporate and Other segment, including:
n $65 million of after-tax charges for asset impairments related to its international business that is held for sale;
n $11 million after-tax loss from adopting new accounting standards and
n $4 million of after-tax severance costs for workforce reductions.
Analysis of Consolidated Operations
Presented below are selected amounts related to the Company’s results of operations:
An analysis of the Company’s results of operations for 2003 compared to 2002 follows:
Operating Revenue
Regulated gas sales revenue increased 44% to $1.3 billion, primarily due to:
n Recovery of higher gas prices in rates ($289 million) and
n Comparably colder weather in the first and fourth quarters of 2003 ($79 million), reflecting 7% more heating degree-days in 2003.
The increase in regulated gas sales revenue was largely offset by a comparable increase in purchased gas expense.
Nonregulated gas sales revenue increased 73% to $1.5 billion primarily reflecting a $642 million increase in revenue from field services and retail energy marketing operations, reflecting higher prices ($473 million) and higher volumes ($169 million). The increase includes $533 million of higher gas sales to another Dominion affiliate, as part of Dominion’s enterprise-wide price risk management strategy. See Note 23 to the Consolidated Financial Statements.
Gas transportation and storage increased 4% to $767 million primarily reflecting higher storage revenues related to the reactivation of the Cove Point LNG facility in August 2003.
Gas and oil production revenue increased 19% to $1.2 billion due primarily to higher average realized prices for gas and oil. It also includes $43 million related to deliveries under a volumetric production payment (VPP) transaction.
Other revenue increased 40% to $579 million, primarily reflecting:
n A $107 million increase in nonregulated electric revenue primarily resulting from customer growth in retail energy sales ($76 million) and increased revenue from the Company’s power generation facilities ($31 million);
n A $22 million increase in sales of extracted products;
n An $18 million increase in brokered oil sales primarily due to higher realized prices and
n A $13 million increase in gathering service revenue associated with the distribution operations.
Operating Expenses and Other Items
Purchased gas expense increased 77% to $2.2 billion, primarily reflecting:
n A $591 million increase associated with field services and retail energy marketing, reflecting higher prices ($442 million) and higher volumes ($149 million);
n A $335 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue and
n A $30 million increase associated with brokered gas sales, reflecting higher commodity prices.
The increase includes $343 million of higher gas purchases from another Dominion subsidiary. See Note 23 to the Consolidated Financial Statements.
Electric fuel and energy purchases expense increased 90% to $196 million, associated with nonregulated electric energy marketing operations, related primarily to higher volumes, including $44 million of additional energy purchases from another Dominion subsidiary. See Note 23 to the Consolidated Financial Statements.
Liquids, pipeline capacity and other purchases expense increased 20% to $187 million reflecting primarily $16 million of higher Exploration & Production segment oil purchases and $15 million of gas transmission and storage costs that were recovered through rates and reflected in gas transportation and storage revenue.
Other operations and maintenance expense increased 25% to $712 million, primarily reflecting the following increases:
n Costs related to current year gas and oil production activities ($61 million);
n Decrease in net pension credits and an increase in other postretirement benefit (OPEB) costs ($56 million);
n Accretion expense for asset retirement obligations ($12 million);
n Asset impairment loss related to the Company’s generation facility in Kauai, Hawaii that was sold in December 2003 ($16 million) and
n Provision for workforce reductions ($6 million).
These increases were partially offset by lower bad debt expense ($7 million).
Depreciation, depletion and amortization (DD&A) expense increased 5% to $581 million, primarily reflecting higher finding and development costs.
Other taxes increased 11% to $225 million, primarily due to higher gross receipts taxes and severance taxes, partially offset by lower sales and use taxes.
Other income (loss) decreased $67 million, primarily reflecting an impairment loss related to CNG International’s equity investment in Australian natural gas pipelines that are held for sale.
Income taxes-The Company’s effective tax rate increased to 36.5% for 2003, primarily as a result of the expiration of nonconventional fuel credits as of January 1, 2003, benefits related to including certain subsidiaries in consolidated state income tax returns in 2002 and the establishment of a valuation allowance in 2003.
Cumulative effect of changes in accounting principles-During 2003, the Company was required to adopt several new accounting standards, resulting in a net after-tax loss of $11 million which included the following:
n A $5 million after-tax loss related to SFAS No. 143, and
n A $6 million after-tax loss related to FIN 46R.
Segment Results of Operations
Energy Segment
The Energy segment includes the Company’s natural gas transmission pipeline and storage businesses, including the
Cove Point LNG facility, certain natural gas production and field services (aggregation of gas supply and related wholesale activities) operations.
bcf = billion cubic feet
Presented below are the key factors that impacted the Energy segment’s operating results:
The increase in net income primarily reflects the following:
n Field services operations benefited from higher commodity sales prices and higher volumes;
n Reactivation of the Cove Point LNG unloading facility in August 2003 and
n Higher realized prices received on Appalachian natural gas production.
Delivery Segment
The Delivery segment includes the Company’s regulated gas distribution and customer service business and nonregulated energy marketing operations and related products and services.
Presented below are the key factors that impacted the Delivery segment’s operating results:
The increase in net income primarily reflects the following:
n Weather often has a significant impact on Delivery’s distribution operations. Higher gas sales and transport volumes were attributed to comparably colder weather in the first quarter and fourth quarter of 2003. Heating degree-days were 7% higher in the franchise service areas in 2003;
n Decrease in net pension credits and an increase in OPEB costs and
n Bad debt expenses were lower in 2003. In December 2003, the Public Utility Commission of Ohio approved a bad debt rider, effective January 1, 2003, that permits the Company to recover all qualifying actual incremental bad debt expense for customers in that gas utility service territory. The 2003 benefit relates to the deferral of 2003 bad debt expenses as a regulatory asset, pending future recovery.
Exploration & Production Segment
The Exploration & Production segment includes the Company’s gas and oil exploration, development and production business.
bbl = barrel
mcf = thousand cubic feet
mcfe = thousand cubic feet equivalent
(1)
Excludes $43 million of revenue recognized in 2003 under the volumetric production payment agreement described in Note 10 to the Consolidated Financial Statements.
Presented below are the key factors that impacted the segment’s operating results:
The increase in net income primarily reflects the following:
n Higher average realized prices for gas and oil;
n Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production. A reduction in production associated with the sale of mineral rights under a volumetric production payment agreement (VPP) was more than offset by increased Gulf of Mexico gas production;
n Higher DD&A rate applied to current year production, reflecting increased acquisition, finding and development costs;
n Higher operations and maintenance expenses which increased in connection with overall higher commodity prices in 2003, that caused an increase in the demand for equipment, labor and services;
n Higher severance taxes, resulting from higher gas and oil revenue associated with higher commodity prices in a higher commodity price environment and
n Higher income taxes primarily reflecting the expiration of Section 29 production credits beginning in 2003.
Corporate and Other
Corporate and other includes the operations of CNG International and other minor subsidiaries.
The net loss for Corporate and Other was $69 million for 2003, compared to net income of $12 million in 2002. The 2003 net loss primarily reflected:
n A $78 million ($65 million after-tax) charge for impairment losses related to certain CNG International investments classified as assets held for sale (see Note 7 to the Consolidated Financial Statements);
n A $6 million ($4 million after-tax) charge for severance costs related to workforce reductions, including $3 million, $2 million and $1 million attributable to the Energy, Delivery and Exploration & Production segments, respectively;
n A $6 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of FIN 46R on December 31, 2003 (see Note 3 to the Consolidated Financial Statements); and
n A $5 million after-tax loss associated with the cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143 on January 1, 2003 (see Note 3 to the Consolidated Financial Statements) attributable to the Energy segment.
Credit Risk
The Company’s exposure to potential credit risk results primarily from its marketing of natural gas and sales of gas and oil production. Presented below is a summary of the Company’s net credit exposure as of December 31, 2003. The Company calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. At December 31, 2003, the Company held no collateral made available by its counterparties.
(1)
Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 29% of the total gross credit exposure.
(2)
The five largest counterparty exposures, combined, for this category represented approximately 10% of the total gross credit exposure.
(3)
The five largest counterparty exposures, combined, for this category represented approximately 8% of the total gross credit exposure.
(4)
The five largest counterparty exposures, combined, for this category represented approximately 2% of the total gross credit exposure.
Risk Factors and Cautionary Statements That May Affect Future Results
Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; fluctuations in energy-related commodities prices and the effect these could have on the Company’s earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements and ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are becoming deregulated; political and economic conditions (including inflation and deflation) and completing the divestiture of investments held by CNG International Corporation. Other more specific risk factors are as follows:
The Company’s operations are weather sensitive. The Company’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes, can be destructive, disrupting operations, causing production delays and unusual maintenance and repair that require the Company to incur additional expenses.
The Company is subject to complex governmental regulation that could adversely affect its operations. The Company’s operations are subject to extensive regulation and require numerous permits, approvals and certificates from federal, state and local governmental agencies. The Company must also comply with environmental legislation and associated regulations. Management believes the necessary approvals have been obtained for the Company’s existing operations and that its business is conducted in accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, may require the Company to incur additional expenses.
Costs of environmental compliance, liabilities and litigation could exceed the Company’s estimates. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, the Company may be a responsible party for environmental clean-up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
The use of derivative instruments could result in financial losses. The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management in Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part II, Item 7. MD&A of this Form 10-K. The reader’s attention is directed to those paragraphs and Risk Factors and Cautionary Statements That May Affect Future Results in MD&A, for discussion of various risks and uncertainties that may affect the future of the Company.
Market Rate Sensitive Instruments and Risk Management
The Company’s financial instruments, commodity contracts and related derivative instruments are exposed to potential losses due to adverse changes in interest rates and commodity prices as described below. Interest rate risk generally is related to the Company’s outstanding debt. Commodity price risk is present in the Company’s gas production and procurement operations and energy marketing operations due to the exposure to market shifts in prices received and paid for natural gas and oil. The Company uses derivative instruments to manage price risk exposures for these operations.
The following sensitivity analysis estimates the potential loss of future earnings or fair value from market rate sensitive instruments over a selected time period due to a 10% unfavorable change in interest rates and commodity prices.
Commodity Price Risk
The Company manages the price risk associated with purchases and sales of natural gas and oil by using derivative commodity instruments, including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of the Company’s derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange.
A hypothetical 10% unfavorable change in market prices of the Company’s derivative commodity instruments would have resulted in a decrease in fair value of approximately $370 million and $352 million as of December 31, 2003 and 2002, respectively.
The impact of a change in energy commodity prices on the Company’s derivative commodity instruments at a point in time is not necessarily representative of the results that will be real- ized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, are substantially offset by recognition of the hedged transaction, such as revenue from sales.
Interest Rate Risk
The Company manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. The Company also enters into interest rate sensitive derivatives, including interest rate swap agreements. For financial instruments outstanding at December 31, 2003, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $3 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2002, would have resulted in a decrease in annual earnings of approximately $2 million.
Investment Price Risk
The Company sponsors employee pension and other postretirement benefit plans and participates in plans sponsored by Dominion that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in the Company’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed by the Company to the employee benefit plans.
Risk Management Policies
The Company has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements which facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on Dominion’s credit policies and the Company’s December 31, 2003 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8.
Item 8. Financial Statements and Supplementary Data
Index
Report of Management’s Responsibilities
The Company’s management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections of the Company’s annual report on Form 10-K. The Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of America. Other financial information in the Form 10-K is consistent with that in the Consolidated Financial Statements.
Management maintains a system of internal controls designed to provide reasonable assurance, at a reasonable cost, that the Company’s assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel, and internal audits. Management believes that during 2003 the system of internal control was adequate to accomplish the intended objectives.
The Consolidated Financial Statements have been audited by Deloitte & Touche LLP, independent auditors, who have been engaged by Dominion’s Audit Committee which is composed entirely of independent directors. Deloitte & Touche LLP’s audits were conducted in accordance with auditing standards generally accepted in the United States of America and included a review of the Company’s accounting systems, procedures and internal controls to the extent necessary for the purpose of its report.
The Board of Directors also serves as the Company’s Audit Committee and meets periodically with the independent auditors, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.
Management recognizes its responsibility for fostering a strong ethical climate so that the Company’s affairs are conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in the Company’s code of ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the confidentiality of proprietary information and full disclosure of public information.
Consolidated Natural Gas Company
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors of
Consolidated Natural Gas Company
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Consolidated Natural Gas Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with 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 Consolidated Natural Gas Company and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their 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.
As discussed in Note 3 to the consolidated financial statements, the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, derivative contracts not held for trading purposes, the consolidation of variable interest entities, and guarantees in 2003; goodwill and intangible assets in 2002; and derivative contracts and hedging activities in 2001.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia
February 26, 2004
Consolidated Natural Gas Company
Consolidated Statements of Income
The accompanying notes are an integral part of the Consolidated Financial Statements.
Consolidated Natural Gas Company
Consolidated Balance Sheets
Consolidated Natural Gas Company
Consolidated Balance Sheets (Continued)
(1) Debt securities issued by Consolidated Natural Gas Company constitute 100% of the trust’s assets; the trust is no longer subject to consolidation effective December 31, 2003.
The accompanying notes are an integral part of the Consolidated Financial Statements.
Consolidated Natural Gas Company
Consolidated Statements of Common Shareholder’s Equity and Comprehensive Income
(1)
As described in Note 10 to the Consolidated Financial Statements, $53 million was reclassified to offset an impairment of gas and oil producing properties in 2001.
The accompanying notes are an integral part of the Consolidated Financial Statements.
Consolidated Natural Gas Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of the Consolidated Financial Statements.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements
Note 1. Nature of Operations
Consolidated Natural Gas Company (CNG or the Company), a public utility holding company registered under the Public Utility Holding Company Act of 1935 (1935 Act), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). The Company, through its subsidiaries, operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. Its regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and its energy marketing businesses serve 1.4 million residential and commercial customer accounts in the Northeast and Midwest. Its interstate gas transmission pipeline system services each of its distribution subsidiaries, non-affiliated utilities and end-users in the Midwest, Mid-Atlantic states and the Northeast. The Company’s exploration and production operations are located in several major gas and oil producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.
The Company’s regulated gas distribution subsidiaries include The East Ohio Gas Company (Dominion East Ohio), The Peoples Natural Gas Company (Dominion Peoples) and Hope Gas, Inc. (Dominion Hope). These subsidiaries are subject to price regulation by their respective state utility commissions.
Dominion Retail, Inc. (Dominion Retail) pursues opportunities arising from the deregulation of the energy industry at the retail level. Dominion Products and Services, Inc. (Dominion Products and Services) provides certain energy-related services to customers of the Company’s gas distribution subsidiaries and others.
Dominion Transmission, Inc. (Dominion Transmission) operates a regional interstate pipeline and storage system regulated by the Federal Energy Regulatory Commission. Dominion Transmission also holds a 24.72% partnership interest in the Iroquois Gas Transmission System, L.P., a limited partnership that owns and operates an interstate natural gas pipeline that transports Canadian gas to utility and power generation customers in New York and New England.
Dominion Field Services, Inc. (Dominion Field Services) is engaged in the aggregation of metered gas supplies and other related wholesale activities.
Dominion Exploration & Production, Inc. (Dominion E&P) explores for and produces gas and oil. CNG Main Pass Gas Gathering Corporation (CNG Main Pass Gas Gathering) and CNG Oil Gathering Corporation (CNG Oil Gathering) hold 13.6% and 33.3%, respectively, partnership interests in gas and oil gathering systems located in the Gulf of Mexico.
CNG International Corporation (CNGI) holds investments in energy-related activities outside the United States. The Company is pursuing the sale of CNGI’s investments. See Note 7 for more information.
On September 5, 2002, the Company acquired 100% ownership of Cove Point LNG Limited Partnership (Dominion Cove Point), a cost-based rate-regulated entity. Dominion Cove Point’s assets include a liquefied natural gas import facility located near Baltimore, Maryland, a liquefied natural gas storage facility and an approximately 85-mile natural gas pipeline. Dominion Cove Point became fully operational in August 2003 and is included in the Energy operating segment.
On November 1, 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus Natural Gas Corp. (Louis Dreyfus), a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. Dominion acquired Louis Dreyfus and then merged it into a newly formed, wholly-owned subsidiary of Dominion, Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). Immediately after the merger, Dominion contributed DOTEPI to the Company. The acquisition of DOTEPI doubled the Company’s proved gas and oil reserves. DOTEPI is included in the Company’s Exploration & Production operating segment.
The Company manages its daily operations through three primary operating segments: Delivery, Energy and Exploration & Production. In addition, the Company also reports its corporate functions as a segment. Assets remain wholly-owned by the Company’s legal subsidiaries.
The Delivery segment includes the Company’s regulated gas distribution subsidiaries, Dominion East Ohio, Dominion Peoples and Dominion Hope as well as the nonregulated energy marketing subsidiaries, Dominion Retail and Dominion Products and Services.
The Energy segment includes the Company’s gas transmission pipeline and storage operations, the gas production operations of Dominion Transmission and the activities of Dominion Field Services and Dominion Cove Point.
The Exploration & Production segment includes the Company’s gas and oil exploration and production operations of Dominion E&P and DOTEPI and its investments in CNG Main Pass Gas Gathering and CNG Oil Gathering.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
The Corporate and Other segment includes the activities of CNGI and other minor subsidiaries, costs of the Company’s corporate functions and certain expenses which are not allocated to the operating segments.
The “Company” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries.
Note 2. Significant Accounting Policies
General
The Company makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles). These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.
The Consolidated Financial Statements represent the Company’s accounts after the elimination of intercompany transactions. The Company follows the equity method of accounting for investments with a 50% or less interest in partnerships and corporate joint ventures when the Company is able to significantly influence the financial and operating policies of the investee. The Company reports its equity earnings from these investments in other income.
Certain amounts in the 2002 and 2001 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation.
Operating Revenue
Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Company’s customer accounts receivable at December 31, 2003 and 2002 included $108 million and $103 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its utility customers. The Company estimates unbilled utility revenue based on weather factors, historical usage and applicable customer rates.
The primary types of sales and service activities reported as operating revenue include:
Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;
Nonregulated gas sales consist primarily of sales of natural gas at market-based rates, brokered gas sales and other gas marketing activities;
Gas transportation and storage consist primarily of regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers;
Gas and oil production consists primarily of sales of natural gas, oil and condensate produced by the Company. Gas and oil production revenue is reported net of royalties and
Other revenue consists primarily of miscellaneous service revenue from gas distribution operations; brokered oil and other extracted products; gas and oil processing; gas transmission pipeline capacity release and nonregulated sales of electricity.
Purchased Gas-Deferred Costs
Where permitted by regulatory authorities, the differences between actual purchased gas expenses and the levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods.
Income Taxes
The Company files a consolidated federal income tax return and participates in an intercompany tax allocation agreement with Dominion and its subsidiaries. The Company’s current income taxes are based on its taxable income, determined on a separate company basis. However, under the 1935 Act and the intercompany tax allocation agreement, the Company’s cash payments to Dominion are reduced for a portion of income tax benefits realized by Dominion as a result of filing consolidated returns. Where permitted by regulatory authorities, the treatment of temporary differences can differ from the requirements of Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. Accordingly, a regulatory asset has been recognized if it is probable that future revenue will be provided for the payment of deferred tax liabilities. Deferred investment tax credits are being amortized over the service lives of the property giving rise to such credits. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized.
Stock-based Compensation
Employees of the Company may receive stock-based awards, such as stock options and restricted stock, granted under Dominion-sponsored stock plans. The Company measures
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
compensation cost for stock-based awards issued to its employees in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation expense is measured based on the intrinsic value, the difference between fair market value of Dominion common stock and the exercise price of the underlying award, on the date when both the price and number of shares the recipient is entitled to receive are known, generally the grant date. Compensation expense, if any, is recognized on a straight-line basis over the stated vesting period of the award. Compensation expense associated with these awards was not material in 2003, 2002 and 2001. The pro forma impact on net income, had the Company measured compensation expense based on the fair value of the options on the date of grant, would not have been material for 2003, 2002 and 2001.
Cash and Cash Equivalents
Current banking arrangements generally do not require checks to be funded until actually presented for payment. At December 31, 2003 and 2002, accounts payable included the net effect of checks outstanding but not yet presented for payment of $45 million and $34 million, respectively. For purposes of the Consolidated Statements of Cash Flows, the Company considers cash and cash equivalents to include cash on hand, cash in banks and temporary investments purchased with a remaining maturity of three months or less.
Inventories
Materials and supplies inventories are valued using primarily the weighted-average cost method. Stored gas inventory used in local gas distribution operations is valued using the last-in-first-out (LIFO) method. Under the LIFO method, those inventories were valued at $59 million and $52 million at December 31, 2003 and December 31, 2002, respectively. Based on the average price of gas purchased during 2003, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $265 million. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.
Derivative Instruments
The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity and financial market risks of its business operations.
All derivatives not qualifying for the normal purchase and normal sales exception are reported on the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. For derivatives that are not designated as hedging instruments, any changes in fair value are recorded in earnings.
Valuation Methods
Fair value is based on actively quoted market prices, if available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, the Company must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis.
For options and contracts with option-like characteristics where pricing information is not available from external sources, the Company generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Other option models are used by the Company under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Company estimates fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different assumptions could have a material effect on the contract’s estimated fair value.
Derivative Instruments Designated as Hedging Instruments
The Company designates a substantial portion of derivative instruments as fair value or cash flow hedges for accounting purposes. For all derivatives designated as hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument. The Company assesses whether the hedge relationship between the derivative and the hedged item is highly effective in offsetting changes in fair value or cash flows, both at the inception of the hedge and on an ongoing basis. Any change in fair value of the derivative that is not effective in offsetting changes in the fair value of the hedged item is recognized currently in earnings. Also, in the case of options that are designated as hedging instruments, management may elect to exclude changes in time value from the measurement of hedge effectiveness, thus requiring that such changes be recorded currently in earnings. The Company discontinues hedge accounting prospectively for derivatives that have ceased to be highly effective hedges.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Cash Flow Hedges-A significant portion of the Company’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of natural gas, oil and other commodities. The Company also uses interest rate swaps to hedge variable interest rates on long-term debt. For cash flow hedge transactions in which the Company is hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (AOCI) until earnings are affected by the hedged item.
Fair Value Hedges-The Company also engages in fair value hedges by using derivative instruments to mitigate the fixed price exposure inherent in firm commodity commitments. In addition, the Company has designated interest rate swaps as fair value hedges to manage its exposure to fixed interest rates on certain long-term debt. For fair value hedge transactions, changes in the fair value of the derivative will generally be offset currently in earnings by changes in the hedged item’s fair value.
Statement of Income Presentation-Gains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in the Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and any gains or losses attributable to the changes in the time value of options, excluded from the measurement of effectiveness, are included in other operations and maintenance expense.
Derivative Instruments Held for Other Purposes
Certain derivative instruments are not designated as hedges for accounting purposes. However, to the extent the Company does not hold offsetting positions for such derivatives, management believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.
Statement of Income Presentation:
n Financially-Settled Derivatives-Not Held for Trading Purposes or Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in other operations and maintenance expense on a net basis.
n Physically-Settled Derivatives-Not Held for Trading Purposes or Designated as Hedging Instruments: Effective October 1, 2003, all statement of income related amounts for physically settled derivative sales contracts are presented in revenue, while all statement of income related amounts for physically settled derivative purchase contracts are reported in expenses. For the nine months ended September 30, 2003, unrealized changes in fair value for physically settled derivative contracts are presented in other operations and maintenance expense on a net basis.
Non-derivative energy-related contracts are no longer subject to fair value accounting, effective January 1, 2003. The Company recognizes revenue or expense on a gross basis at the time of contract performance, settlement or termination.
Property, Plant and Equipment
Property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, other direct costs and capitalized interest. The costs of repairs and maintenance, including minor additions and replacements, are charged to expense as incurred. In 2003, 2002 and 2001, the Company capitalized interest costs of $67 million, $70 million and $22 million, respectively.
The depreciable cost of gas utility and transmission property retired, less salvage, is charged to accumulated depreciation at retirement. Amounts related to cost of removal collections and expenditures are recorded as regulatory liabilities or regulatory assets. The Company records gains and losses upon retirement of nonregulated property based on the difference between proceeds received, if any, and the property’s undepreciated basis at the retirement date.
Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives or in the case of gas and oil producing properties, the unit-of-production method.
The Company’s annual depreciation rates on property, plant and equipment are as follows:
The Company follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end hedge-adjusted market prices. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established on a country-by-
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
country basis. Approximately 15% of the Company’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2003.
Depreciation of gas and oil producing properties is computed using the units-of-production method. Under the full cost method the depreciable base of costs subject to amortization also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties are initially excluded from the depreciable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depreciable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depreciable base. See Asset Retirement Obligations for a discussion of gas and oil abandonment and dismantlement costs.
Goodwill and Intangible Assets
Goodwill is subject to review for impairment rather than periodic amortization. The Company evaluates goodwill for impairment on at least an annual basis or when an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. Prior to the adoption of SFAS No. 142, Goodwill and Other Intangible Assets, on January 1, 2002, goodwill arising from acquisitions completed before July 1, 2001 was amortized on a straight-line basis over periods up to 40 years.
Impairment of Long-Lived and Intangible Assets
The Company performs an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. These assets are written down to fair value if the sum of the expected future undiscounted cash flows is less than the carrying amounts.
Regulatory Assets and Liabilities
For utility operations subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. The economic effects of practices prescribed by regulatory authorities for rate- making purposes must be considered in the application of generally accepted accounting principles.
Asset Retirement Obligations
Beginning in 2003, the Company recognizes its asset retirement obligations at fair value as incurred, capitalizing these amounts as costs of the related tangible long-lived assets. Due to the absence of relevant market information, fair value is estimated using discounted cash flow analyses. The Company reports the accretion of the liabilities due to the passage of time as an operating expense. Through 2002, the Company’s accounting and reporting practices for future dismantlement and restoration activities for its gas and oil wells and platforms recognized such costs as a component of depletion expense, with recognized amounts included in accumulated depreciation, depletion and amortization.
Amortization of Debt Issuance Costs
The Company defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and amortized over the lives of the new issues.
Note 3. Newly Adopted Accounting Standards
SFAS No. 143
Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The adoption of SFAS No. 143 resulted in an after-tax loss of $5 million, representing the cumulative effect of a change in accounting principle. The impact of adopting SFAS No. 143 for 2003, other than the cumulative effect of a change in accounting principle, was not material.
EITF 03-11
The Company adopted Emerging Issue Task Force (EITF) Issue No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, on October 1, 2003. EITF 03-11 addresses classification of income statement related amounts for derivative contracts. Income statement amounts related to periods prior to October 1, 2003 are presented as originally reported. See Note 2.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
SFAS No. 149
The Company adopted SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 reflects decisions made by FASB and its Derivatives Implementation Group in connection with issues raised about the application of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Generally, changes resulting from SFAS No. 149 apply to contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The initial adoption of SFAS No. 149 did not have a material impact on the Company’s results of operations and financial position.
FIN 46R
On December 31, 2003, the Company adopted FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) for its interests in special purpose entities. FIN 46R addresses the consolidation of variable interest entities (VIEs), which are entities that are not controllable through voting interests or in which the VIEs’ equity investors do not bear the residual economic risks and rewards.
Under FIN 46R, the Company consolidated a special purpose lessor entity through which the Company had financed and leased a new power generation project. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $223 million in net property, plant and equipment and deferred charges and an additional $234 million of related debt. The cumulative effect of adopting FIN 46R for its interest in special purpose entities was an after-tax charge of $6 million, representing depreciation expense associated with the consolidated assets. Annual depreciation expense for these assets is expected to be approximately $7 million.
In 2001, the Company established CNG Capital Trust I that sold trust preferred securities to third party investors. The Company received the proceeds from the sale of the trust preferred securities in exchange for junior subordinated debt notes issued by the Company to be held by the trust. Upon adoption of FIN 46R, the Company’s Consolidated Balance Sheet at December 31, 2003 reports the junior subordinated notes held by the trusts as long-term debt, rather than the trust preferred securities.
The Company is required to adopt FIN 46R for its interests in VIEs that are not considered special purpose entities no later than March 31, 2004. The Company is still evaluating the impact that adopting FIN 46R for these interests may have on its future results of operations or financial condition.
FIN 45
In November 2002, FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others-An Interpretation of FASB Statements No. 5, 57 and 107 (FIN 45). Under FIN 45, issuers of certain types of guarantees must recognize a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. In addition, FIN 45 requires increased disclosures for specific types of guarantees.
FIN 45’s initial recognition requirements apply only to guarantees issued or modified after December 31, 2002. The Company does not anticipate any material impact on its future results of operations or financial condition as a result of recording newly issued or modified guarantees at fair value.
2002 and 2001
SFAS No. 142
The Company adopted SFAS No. 142 on January 1, 2002. There was no impact to the Company’s financial statements upon adoption.
SFAS No. 133
The Company adopted SFAS No. 133 on January 1, 2001 and recorded an after-tax loss of $14 million, representing the cumulative effect of this change in accounting principle. The Company also recorded a net after-tax charge to AOCI of $105 million.
Pro Forma Information Reflecting Adoption of New Standards
Disclosure requirements associated with the adoption of FIN 46R and SFAS No. 143 require a presentation of pro forma net income and earnings per share for 2002 and 2001 as if the Company had applied the provisions of those standards as of January 1, 2001. Other standards adopted during 2003 do not require pro forma information and are excluded from the amounts presented below.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
SFAS No. 143 also requires a pro forma presentation of asset retirement obligations as if the Company had applied the provisions of SFAS No. 143 as of January 1, 2001. Those amounts are as follows:
Note 4. Acquisitions
Cove Point
In September 2002, the Company acquired 100% ownership of Dominion Cove Point, a cost-based rate-regulated entity for $225 million in cash. The Company recorded $75 million of goodwill, representing the excess of the purchase price over the regulatory basis of Dominion Cove Point’s assets acquired and liabilities assumed. Dominion Cove Point’s assets include a liquefied natural gas import facility located near Baltimore, Maryland, a liquefied natural gas storage facility and an approximately 85-mile natural gas pipeline. Dominion Cove Point became fully operational in August 2003. The goodwill arising from the acquisition was allocated to the Energy segment for purposes of impairment testing under SFAS No. 142.
Louis Dreyfus
In November 2001, Dominion acquired all of the outstanding shares of common stock of Louis Dreyfus, a natural gas and oil exploration and production company headquartered in Oklahoma City, Oklahoma. Dominion acquired Louis Dreyfus by merging it into a newly formed, wholly-owned subsidiary of Dominion, DOTEPI. Immediately after the merger, Dominion contributed DOTEPI to the Company.
The aggregate purchase price was $1.8 billion, which consisted of approximately 14 million shares of Dominion common stock valued at $881 million, $902 million in cash and employee stock options with a fair value on the date of grant of approximately $13 million. The Company recorded $543 million of goodwill, representing the excess of purchase price over the fair value of the Louis Dreyfus assets acquired and liabilities assumed.
The operations of Louis Dreyfus are included in the Exploration & Production segment and the goodwill arising from the acquisition has been allocated to that segment for purposes of impairment testing under SFAS No. 142.
Note 5. Operating Revenue
The Company’s operating revenue consists of the following:
Note 6. Restructuring and Other Merger-Related Activities
In 2001, after fully integrating the Company into Dominion’s existing organization and operations, management initiated a focused review of Dominion’s combined operations and developed a plan of reorganization. As a result, the Company recognized the following restructuring costs and related liabilities during 2001:
(1)
Dominion Resources Services (Dominion Services), a Dominion subsidiary service company under the 1935 Act, provides certain services to Dominion’s operating subsidiaries. Accordingly, charges are allocated and billed among the operating subsidiaries in accordance with predefined service agreements.
(2)
Includes charges for abandonment of leased office space and related costs by the Company and Dominion Services.
The change in the liabilities for severance and related costs and lease termination costs during 2003 and 2002 are presented below:
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 7. International Investments
CNGI was engaged in energy-related activities outside of the continental United States, primarily through equity investments in Australia and Argentina. After completing the CNG acquisition, the Company’s management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on its core business. These assets are classified as part of assets held for sale in other current assets in the Consolidated Balance Sheets. As of December 31, 2002, the CNGI assets included investments in property, plant and equipment totaling $55 million and equity method investments totaling $83 million.
During 2003, the Company recognized impairment losses totaling $78 million ($65 million after-tax) related primarily to investments in a pipeline business located in Australia and a small generation facility in Kauai, Hawaii that was sold in December 2003 for cash proceeds of $42 million. These impairment losses were reported in other income ($62 million) and other operations and maintenance expense ($16 million) in the Consolidated Statement of Income. The impairment losses represented adjustments to the assets’ carrying amounts to reflect the Company’s current evaluation of fair market value less estimated costs to sell, which were derived from a combination of actual 2003 transactions, management estimates, and other fair market value indicators. The Company expects to complete the sale of the remaining assets by December 31, 2004.
Note 8. Income Taxes
Details of income tax expense were as follows:
Total statutory U.S. federal income rate reconciles to the effective income tax rates as follows:
(1)
The Company’s effective tax rate increased in 2003, reflecting the effects of the expiration of nonconventional fuel tax credits and the establishment of a valuation allowance on CNGI and expiring federal and state loss carryforwards.
(2)
The Company’s effective income tax rate decreased in 2002, reflecting the benefit of including certain subsidiaries in consolidated state income tax returns.
Deferred income taxes reflect the net effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
The Company’s net deferred income taxes consist of the following:
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
For 2003 and 2002, amounts include $20 million and $10 million, respectively, of current deferred tax liabilities reported in other current liabilities.
At December 31, 2003, the Company had the following loss and credit carryforwards:
n Federal loss carryforwards of $237 million that expire if unutilized during 2004 through 2007. A valuation allowance on $45 million has been established due to the uncertainty of realizing the future deductions;
n State loss carryforwards of $550 million that expire if unutilized during 2008 through 2022. A valuation allowance on $88 million has been established due to the uncertainty of realizing the future deductions; and
n Federal minimum tax credits of $44 million that do not expire.
Note 9. Hedge Accounting Activities
The Company is exposed to the impact of market fluctuations in the price of natural gas and oil and financial market risks of its business operations. The Company uses derivative instruments to mitigate its exposure to these risks and designates derivative instruments as fair value or cash flow hedges for accounting purposes. Selected information about the Company’s hedge accounting activities follows:
The following table presents selected information related to cash flow hedges included in AOCI in the Consolidated Balance Sheet at December 31, 2003:
The actual amounts that will be reclassified to earnings in 2004 will vary from the expected amounts presented above as a result of changes in market prices and interest rates. The effect of amounts being reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies.
In addition, $83 million of unrealized gains related to certain contracts designated as hedging instruments were reclassified from AOCI to earnings in December 2001. This reclassification was required in relation to the Company’s recognition of an impairment of its gas and oil producing properties at December 31, 2001, due primarily to the decline in gas wellhead prices as of that date.
Concurrent with the December 2, 2001 Enron Corp. and certain of its subsidiaries (Enron) bankruptcy filing, the Company’s Enron derivatives designated as cash flow hedges of anticipated sales of natural gas no longer qualified for hedge accounting and, accordingly, were de-designated from their hedging relationships for accounting purposes.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 10. Property, Plant and Equipment
Major classes of property, plant and equipment and their respective balances are:
Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2003, and the years in which the excluded costs were incurred, follow:
Amortization rates for capitalized costs under the full cost method of accounting for the Company’s United States cost centers in thousand cubic feet (mcf) equivalent were $1.26, $1.24 and $1.24 for 2003, 2002 and 2001, respectively.
At December 31, 2001, the Company recognized an impairment of its gas and oil producing properties, due primarily to the decline in gas wellhead prices. The non-cash charge amounted to $83 million and reduced 2001 net income by $53 million. The effect of the impairment adjustment was offset in its entirety by the reclassification of certain deferred gains from AOCI to earnings. These deferred gains related to hedging contracts that were not considered in the calculation of the impairment charge. Since the deferred gains related to hedges of forecasted sales from the Company’s producing properties, such amounts were reclassified from AOCI to earnings when impairment of the producing properties was recognized. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of December 31, 2003.
There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2003. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.
Volumetric Production Payment Transaction
In 2003, the Company received $266 million in cash for the sale of a fixed-term overriding royalty interest in certain of its natural gas reserves for the period August 2003 through August 2007. The sale reduced the Company’s natural gas reserves by approximately 66 billion cubic feet (bcf). While the Company is obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, it retains control of the properties and the rights to future development drilling. If production from the properties is inadequate to deliver approximately 66 bcf of natural gas scheduled for delivery to the purchaser, the Company has no obligation to make up the shortfall. Cash proceeds received from this volumetric production payment transaction were recorded as deferred revenue. The Company will recognize revenue from the transaction as natural gas is produced and delivered to the purchaser.
Classification of Mineral Rights
Companies with gas and oil exploration and production operations have become aware that a question has arisen about whether contractual mineral rights should be classified as intangible assets rather than tangible assets on the balance sheet as a result of SFAS Nos. 141, Business Combinations, and 142. If, as a result of the resolution of this issue, reclassification of the costs associated with its mineral rights is required, the Company’s net intangible assets would increase and its net property, plant and equipment would decrease. As of December 31, 2003, the amount subject to reclassification was approximately $3.6 billion. While resolution of this issue may affect the balance sheet classification of these assets, there would be no impact on the Company’s results of operations or cash flows.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 11. Goodwill and Intangible Assets
There were no material changes in the carrying amount of goodwill during the year ended December 31, 2003.
All of the Company’s intangible assets, other than goodwill, are subject to amortization. Amortization expense for intangible assets was $18 million, $19 million and $19 million for 2003, 2002 and 2001, respectively. There were no material acquisitions of intangible assets during 2003 and 2002. Intangible assets are included in other assets on the Consolidated Balance Sheets. The components of intangible assets at December 31, 2003 and 2002 were as follows:
Annual amortization expense for intangible assets is estimated to be $18 million for 2004, $17 million for 2005, $15 million for 2006, $13 million for 2007 and $10 million for 2008.
Note 12. Regulatory Assets and Liabilities
Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process or amounts that have been collected from customers and not yet expended. The Company’s regulatory assets and liabilities included the following:
(1)
In other current assets
(2)
In other current liabilities
Pending the expected recovery of costs recognized under SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, the Company’s rate-regulated subsidiaries have deferred the differences between SFAS No. 106 costs and amounts included in rates.
Income taxes recoverable through future rates represent amounts to be collected from customers related to the recognition of additional deferred income taxes not previously recorded under past ratemaking practices.
In December 2003, the Public Utilities Commission of Ohio (Ohio Commission) authorized the collection of previously deferred costs associated with certain uncollectible customer accounts from 2001. The Ohio Commission order approves amortization of this regulatory asset of $51 million over five years through the tracker rider effective in 2004. Also in December 2003, the Ohio Commission approved the deferral and recovery of excess bad debt costs incurred in 2003 and thereafter for certain uncollectible customer accounts not contemplated in current base rate recoveries. The total deferral of 2003 excess uncollectible amounts was $13 million. Collection of this deferral through the tracker rider is also effective in 2004.
Estimated rate contingencies and refunds are associated with certain increases in prices by the Company’s rate regulated utilities and other rate-making issues that are subject to final modification in regulatory proceedings.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Rates charged to customers by the Company’s regulated businesses include a provision for the cost of future activities to remove assets expected to be incurred at the time of retirement.
The incurred costs underlying regulatory assets may represent past expenditures by the Company’s rate regulated gas operations or may represent the recognition of liabilities that ultimately will be settled at some time in the future. At December 31, 2003, approximately $69 million of the Company’s regulatory assets represented past expenditures on which it does not earn a return. These expenditures consist primarily of customer bad debts. Customer bad debts in the amount of $50 million will be recovered over five years.
Note 13. Asset Retirement Obligations
The Company’s asset retirement obligations are primarily associated with the abandonment of certain natural gas pipelines and the dismantlement and restoration activities for its gas and oil wells and platforms.
In addition, the Company has asset retirement obligations related to its natural gas gathering, storage, transmission and distribution systems, including approximately 2,300 gas storage wells in the Company’s underground natural gas storage network. These obligations result from certain safety requirements to be performed at the time any pipeline or storage well is abandoned. However, the Company expects to operate its natural gas gathering, storage, transmission and distribution systems in perpetuity. Thus, asset retirement obligations for those assets will not be reflected in the Company’s Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur when expected retirement or abandonment dates for individual pipelines or storage wells are determined by the Company’s operational planning.
Changes to the Company’s asset retirement obligations during 2003 follow:
Note 14. Short-Term Debt and Credit Agreements
Joint Credit Facilities
In May 2002 and May 2003, Dominion, Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion, and the Company entered into two joint credit facilities that allowed aggregate borrowings of up to $2 billion. The facilities include a $1.25 billion 364-day revolving credit facility that terminates in May 2004 and a $750 million three-year revolving credit facility that terminates in May 2005. The 364-day facility includes an option to extend any borrowings for an additional period of one year to May 2005. These joint credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and the Company and other general corporate purposes. The three-year facility can also be used to support up to $200 million of letters of credit. The Company expects to renew the 364-day revolving credit facility prior to its maturity in May 2004.
At December 31, 2003, total outstanding commercial paper supported by the joint credit facilities was $1.44 billion, of which the Company’s borrowings were $151 million, with a weighted-average interest rate of 1.24%. At December 31, 2002, total outstanding commercial paper supported by previous credit agreements was $1.2 billion, of which the Company’s borrowings were $397 million, with a weighted-average interest rate of 1.76%.
At December 31, 2003, total outstanding letters of credit supported by the three-year facility were $85 million issued on the behalf of other Dominion subsidiaries. At December 31, 2002, total outstanding letters of credit supported by the three- year facility were $106 million, of which $35 million was issued for the Company on behalf of its subsidiaries.
Credit Facility
In August 2003, the Company entered into a $1.0 billion 364-day revolving credit facility that terminates in August 2004. This credit facility is being used to support the issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial contracts used by the Company in its risk management strategies for its gas and oil production. At December 31, 2003, outstanding letters of credit under this facility totaled $820 million. At December 31, 2002, outstanding letters of credit under the previous credit facility totaled $500 million.
In January 2004, the Company entered into a $200 million letter of credit agreement to support the issuance of a letter of credit to provide collateral required by a counterparty on derivative financial contracts used by the Company in its risk management strategies for its gas and oil production. The
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
agreement terminates in May 2004 and is not expected to be renewed.
Note 15. Long-Term Debt
The Company’s long-term debt consists of the following:
(1)
Represents weighted-average coupon rate for debt outstanding as of December 31, 2003.
(2)
At the option of holders in October 2006, these notes are subject to redemption at 100% of the principal amount plus accrued interest.
(3)
New debt reflected on the Company’s Consolidated Balance Sheet as a result of FIN 46R.
(4)
Represents changes in fair value of certain fixed-rate long-term debt associated with fair value hedging relationships.
Based on stated maturity dates rather than early redemption dates that could be elected by the instrument holders, the scheduled principal payments of long-term debt at December 31, 2003 were as follows (in millions):
The Company’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2003, there were no events of default under the Company’s covenants.
Note 16. Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust
In 2001, Dominion CNG Capital Trust I (Trust), a finance subsidiary of the Company, which holds 100% of the voting interests, sold 8 million 7.8% trust preferred securities for $200 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by the Trust. In exchange for the $200 million realized from the sale of the trust preferred securities and $6 million of common securities that represent the remaining 3% beneficial ownership interest in the assets held by the Trust, the Company issued $206 million of its 2001 7.8% junior subordinated notes due October 31, 2041. The junior subordinated notes constitute 100% of the Trust’s assets. The Trust must redeem the trust preferred securities when the junior subordinated notes are repaid or if redeemed prior to maturity.
Under previous accounting guidance, the Company consolidated the Trust in the preparation of its Consolidated Financial Statements. In accordance with FIN 46R, the Company does not consolidate the Trust as of December 31, 2003 and instead reports on its Consolidated Balance Sheets the junior subordinated notes issued by the Company and held by the Trust as long-term debt.
Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the Company when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the trust preferred securities to the extent that the Trust has funds legally and immediately available to make distributions. The Trust’s ability to pay amounts when they are due on the trust preferred securities is dependent solely upon the payment of amounts when they are due on the junior subordinated notes. If the payment on the junior subordinated notes is deferred, the Company may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, the Company may not make any payments or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 17. Accumulated Other Comprehensive Income
Presented in the table below is a summary of accumulated other comprehensive income by component:
Note 18. Dividend Restrictions
The 1935 Act and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts.
The Company received dividends from its subsidiaries of $405 million, $345 million and $336 million in 2003, 2002 and 2001, respectively. At December 31, 2003, the Company’s consolidated subsidiaries had approximately $2.5 billion in capital accounts other than retained earnings, representing capital stock, additional paid-in capital and accumulated other comprehensive income. The Company had approximately $3.8 billion in capital accounts other than retained earnings at December 31, 2003. Generally, such amounts are not available for the payment of dividends by affected subsidiaries, or by the Company itself, without specific authorization by the SEC. In 2000, in response to a Dominion request, the SEC granted relief, authorizing payment of dividends by the Company from other capital accounts to Dominion in amounts up to $1.6 billion, representing the Company’s retained earnings prior to Dominion’s acquisition of the Company. Furthermore, the Company submitted a similar request to the SEC in 2002, seeking relief from this restriction in regard to DOTEPI, the subsidiary into which Louis Dreyfus was merged. The application requests relief up to approximately $303 million, representing Louis Dreyfus’ retained earnings prior to the acquisition by Dominion.
Certain agreements associated with the Company’s joint credit facilities with Dominion and Virginia Power contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Company’s ability to pay dividends to Dominion or receive dividends from its subsidiaries at December 31, 2003.
See Note 16 for a description of potential restrictions on dividend payments by the Company in connection with the deferral of distribution payments on trust preferred securities.
Note 19. Employee Benefit Plans
The Company provides certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, the Company reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.
In 2001, the Company maintained qualified noncontributory defined benefit pension plans covering substantially all employees. In 2002, the Company’s pension plan for employees not represented by recognized bargaining units was merged with the Dominion pension plan, which provides these benefits to multiple Dominion subsidiaries. The Company recognized $63 million and $80 million of net periodic pension credits in 2003 and 2002, respectively, related to the merged plan. The Company made no contributions to the merged plan in either 2003 or 2002.
The Company still maintains qualified pension plans that cover employee groups represented by collective bargaining units. Retirement benefits payable under all plans are based primarily on years-of-service, age and compensation. The Company’s contributions to the plans are determined in accordance with the provisions of the Employment Retirement Income Security Act of 1974. Prior to 2002, the Company’s pension program also included nonqualified pension plans that provided payment of supplemental pension benefits to certain retirees. Beginning in 2001, participants of certain of the nonqualified pension plans became employees of Dominion Services. As a result of this change, all associated plan liabilities were transferred to Dominion, and the Company reported no net periodic benefit costs related to affected participants under these plans after 2000. However, to the extent such employees provided services to the Company after 2000, the Company recognized such costs as part of the support services provided by Dominion Services.
Effective January 1, 2001, the Consolidated Natural Gas Service Company, Inc. (CNG Services) was merged into Dominion Services. Employees of CNG Services became employees of Dominion Services but continued to participate in the Company’s pension and other postretirement benefit plans during 2001. In 2002, such employees became participants in plans sponsored by Dominion.
The Company’s measurement date for the majority of its employee benefit plans is December 31. The Company uses a
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
market-related value of pension plan assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses.
The Company participates in plans providing retiree health care and life insurance benefits with annual premiums based on several factors such as age, retirement date and years-of-service.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Under the provisions of SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, presently enacted changes in relevant laws are required to be considered in current period measurements of postretirement benefit costs and the accumulated postretirement benefit obligation (APBO).
In January 2004, the FASB issued Staff Position No. FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which allowed plan sponsors to elect to defer recognizing the effects of the Act. The Company elected not to defer recognition of the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending. When issued, that guidance could require the Company to change previously reported information.
Based on an analysis performed by a third party actuary, the Company has determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D and therefore expects to receive the federal subsidy offered under the Act. The Company considered the passage of the Act a significant event requiring remeasurement of its APBO on December 8, 2003. The impact of remeasurement on the 2003 postretirement net periodic benefits cost was not material. The Company will amortize the unrecognized actuarial gains associated with the benefits of the subsidy over the average remaining service period of plan participants in accordance with SFAS No. 106. This amortization will lower future annual net postretirement benefits costs by approximately $6 million beginning in 2004.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
The following tables summarize information for the Company’s pension and other postretirement benefit plans for employees represented by collective bargaining units, including the changes in the pension and other postretirement benefit plan obligations and plan assets and a statement of the plans’ funded status:
(1)
Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion subsidiaries.
The accumulated benefit obligation for the Company-sponsored defined benefit pension plans was $451 million and $417 million at December 31, 2003 and 2002, respectively. Under its funding policies, the Company evaluates plan funding requirements annually, usually in the third quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, the amount of contributions, if any, is determined at that time.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
The Company’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocation for the Company’s pension funds is 45% U.S. equity securities; 8% non-U.S. equity securities; 22% debt securities; and 25% other, such as real estate and private equity investments. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. The Company’s asset allocations for pension plans and other postretirement plans for employees represented by collective bargaining units at December 31, 2003 and 2002 were as follows:
The components of the provision for net periodic benefit cost were as follows:
(1)
Amounts represent all benefit plans in which the Company participates, including benefit plans covering multiple Dominion subsidiaries.
Significant assumptions used in determining the net periodic cost recognized in the Consolidated Statements of Income were as follows, on a weighted-average basis:
(1)
The medical cost trend rate for 2003 is assumed to gradually decrease to 4.75% by 2007 and continues at that rate for years thereafter.
Significant assumptions used in determining the projected pension and postretirement benefit obligations recognized in the Consolidated Balance Sheets were as follows, on a weighted-average basis:
The Company determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:
• Historical return analysis to determine expected future risk premiums;
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
• Forward looking return expectations derived from the yield on long term bonds and the price earnings ratios of major stock market indices;
• Expected inflation and risk-free interest rate assumptions, and
• The types of investments expected to be held by the plans.
Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under the Company’s plans.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:
The Company also participates in employee savings plans that cover substantially all employees. Employer matching contributions of $8 million, $7 million and $9 million were incurred in 2003, 2002 and 2001, respectively.
Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain subsidiaries fund postretirement benefit costs through Voluntary Employees’ Beneficiary Associations. The remaining subsidiaries do not prefund postretirement benefit costs but instead pay claims as presented.
Note 20. Commitments and Contingencies
As the result of issues generated in the ordinary course of business, the Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. Management believes that the final disposition of these proceedings will not have a material effect on the Company’s financial position, liquidity or results of operations.
Long-term Contracts
Presented below is a summary of the Company’s commitments as of December 31, 2003 under long-term fixed quantity, fixed price purchase contracts:
Lease Commitments
The Company leases various facilities, vehicles and equipment under both operating and capital leases. Future minimum lease payments under noncancellable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2003 are as follows:
Rental expense included in other operations and maintenance expense totaled $39 million, $32 million and $34 million for 2003, 2002 and 2001, respectively. Beginning in 2004, approximately $8 million will be recognized annually as interest expense associated with the debt obligations of a newly consolidated VIE resulting from the adoption of FIN 46R.
Environmental Matters
The Company is subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations of the Company. The Company may sometimes seek recovery of environmental-related expenditures through regulatory proceedings or through joint-interest operating agreements.
The Company has determined that it is associated with 16 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with which the Company is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time, it is not known to what degree these sites may contain environmental contamination. Therefore, the Company is not able to estimate the cost, if any, that may be required for the possible remediation of these sites.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Before being acquired by Dominion, Louis Dreyfus was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hildalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus and facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits as a result of the alleged plume. Although the results of litigation are inherently unpredictable, the Company does not expect the ultimate outcome of the case to have a material adverse impact on its financial position or results of operations, cash flows or financial position.
Guarantees, Letters of Credit and Surety Bonds
Beginning in 2003, the issuance of certain types of guarantees requires the recognition of a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. Furthermore, any performance required by the Company under such guarantees would result in the recognition of additional liabilities in the Company’s Consolidated Financial Statements.
As of December 31, 2003, the Company had issued $1.4 billion of guarantees, including: $972 million to support commodity transactions of subsidiaries; $288 million for subsidiary debt and $133 million for guarantees supporting other agreements of subsidiaries. The Company had also purchased $48 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $821 million. The Company enters into these arrangements to facilitate commercial transactions by its subsidiaries with third parties. While the majority of these guarantees do not have a termination date, the Company may choose at any time to limit the applicability of such guarantees to future transactions. To the extent a liability subject to a guarantee has been incurred by a consolidated subsidiary, that liability is included in the Company’s Consolidated Financial Statements. The Company is not required to recognize liabilities for guarantees on behalf of its subsidiaries in the Consolidated Financial Statements, unless performance is considered probable. No such liabilities have been recognized as of December 31, 2003. The Company believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.
Indemnifications
In addition, as part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2003, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.
Enron Bankruptcy
Based on management’s evaluation of the estimated collectibility of amounts due from Enron and the valuation of Enron-related commodity contracts, the Company recorded a pre-tax charge to earnings of approximately $108 million in the fourth quarter of 2001. This charge primarily represented the impaired fair value of natural gas forward and swap contracts with Enron. Management continues to believe that this charge substantially eliminates any further Enron-related earnings exposure.
During 2002, the Company terminated all outstanding and open positions with Enron. The Company has submitted a claim in the Enron bankruptcy case for the value of such contracts, measured at the effective dates of contract termination. Various contingencies, including developments in the Enron bankruptcy proceedings, may affect the Company’s ultimate exposure to Enron.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 21. Fair Value of Financial Instruments
Substantially all of the Company’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported based on historical cost. Fair values have been determined using available market information and valuation methodologies considered appropriate in the opinion of management. The financial instruments’ carrying amounts and fair values as of December 31, 2003 and 2002 were as follows:
(1)
Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.
(2)
Fair value is based on market quotations.
Note 22. Credit Risk
Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion and its subsidiaries, including the Company, maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. Amounts reported as margin deposit liabilities represent funds held by the Company that resulted from various trading counterparties exceeding agreed-upon credit limits established by the Company. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from the Company exceeding agreed-upon credit limits established by the counterparties. As of December 31, 2003 and 2002, the Company had margin deposit assets of $59 million and $52 million, respectively. The Company had no margin deposit liabilities as of December 31, 2003 or 2002.
The Company maintains a provision for credit losses based on factors surrounding the credit risk of its customers, historical trends and other information. Management believes, based on the Company’s credit policies and its December 31, 2003 provision for credit losses, that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
The Company sells natural gas and provides distribution services to residential, commercial and industrial customers and provides transmission services to utilities and other energy companies. In addition, the Company enters into contracts with various companies in the energy industry for purchases and sales of energy-related commodities, including natural gas and oil, in its hedging activities. Except for gas and oil exploration and production business activities, these transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. Management does not believe that this geographic concentration contributes significantly to the Company’s overall exposure to credit risk. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.
The Company’s exposure to credit risk is concentrated primarily within its sales of gas and oil production and energy marketing activities, as the Company transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At December 31, 2003, gross credit exposure related to these transactions totaled $227 million, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist). The Company held no collateral at December 31, 2003. Of this amount, investment grade counterparties represent 66% and no single counterparty exceeded 8%.
Note 23. Related Parties
The Company engages in related party transactions primarily with other Dominion subsidiaries. The Company’s accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. The Company is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. The significant related party transactions are disclosed below.
Transactions with Other Dominion Subsidiaries
The Company transacts with other Dominion affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. The Company enters into certain derivative commodity contracts with Dominion affiliates. These contracts, which are principally comprised of commodity swaps, are used by the Company to manage commodity price risks associated with the purchases
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Notes to Consolidated Financial Statements, Continued
and sales of natural gas. The Company designates the majority of these contracts as cash flow hedges for accounting purposes. The affiliated commodity transactions are presented separately from the derivative gains and losses below:
At December 31, 2003 and 2002, the Company’s Consolidated Balance Sheets included derivative assets with Dominion affiliates of $50 million and $55 million, respectively, and derivative liabilities with Dominion affiliates of $48 million for both periods. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that had been designated as hedges, are included in the balance of AOCI in the Consolidated Balance Sheets.
Dominion Services and other Dominion subsidiaries provide certain administrative and technical services to the Company. The Company provides certain services to affiliates, including technical services to affiliates. The cost of these services follow:
In 2003, the Company made $4 million of lease payments to another Dominion subsidiary for a power generation facility. As a result of adopting FIN 46R, the Company was required to consolidate a special purpose lessor entity through which the Company had financed and leased this power generation facility. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects in an additional $223 million in net property, plant and equipment and deferred charges and an additional $234 million of related debt, reflected as affiliated notes payable.
Transactions with Dominion
During 2003 and 2002, Dominion advanced $1.1 billion and $1.5 billion, respectively, net of repayments, to the Company pursuant to a short-term demand note. Dominion subsequently converted $900 million of the amounts borrowed by the Company into an equity contribution. Effective March 1, 2003, a consolidated Dominion money pool was formed and the existing CNG money pool was terminated pursuant to a SEC order. Outstanding balances under the CNG money pool and certain borrowings from Dominion pursuant to the short-term demand note were converted to Dominion money pool borrowings in March 2003. In September 2003, Dominion made a $600 million equity contribution to the Company that was accomplished by reducing the money pool borrowings of the Company’s subsidiaries. At December 31, 2003, net outstanding borrowings under the Dominion money pool totaled $901 million of regulated subsidiary borrowings. At December 31, 2003 and December 31, 2002, net outstanding borrowings under the demand note totaled $126 million and $563 million, respectively. During 2003 and 2002, the Company incurred $13 million and $3 million, respectively, in interest charges related to these borrowings.
In exchange for a reduction in amounts payable to Dominion, the Company recognized $6 million and $32 million of additional paid-in capital in 2003 and 2002, respectively.
Transactions with Related Parties-Other Than Dominion Subsidiaries
Upon adoption of FIN 46R, the Company ceased consolidating CNG Capital Trust I beginning on December 31, 2003. See Note 16 for more information.
Equity Method Investments
At December 31, 2003 and 2002, the Company’s equity method investments totaled $243 million and $258 million, respectively. The Company’s equity method investments are reported in investments and, as discussed in Note 7, in assets held for sale on the Consolidated Balance Sheets. Equity earnings on these investments totaled $21 million in 2003, $23 million in 2002 and $18 million in 2001. The equity earnings are reported in other income in the Consolidated Statements of Income.
Note 24. Operating Segments
The Company is organized primarily on the basis of products and services sold in the United States.
As a result of changes in the Company’s management reporting structure during the fourth quarter of 2003, the nature and composition of the Company’s primary operating segments have changed. Retail energy marketing operations, formerly in the Energy segment, are now included in the Delivery segment. All segment information has been recast to conform to the new segment structure.
The Company manages its operations based on three primary operating segments:
The Energy segment includes the Company’s gas transmission pipeline and storage system, certain gas production operations, the liquefied natural gas storage facility and the
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
activities of the Company’s field services and gas marketing operations.
The Delivery segment includes the Company’s regulated gas distribution systems and customer service operations and the Company’s nonregulated retail energy marketing activities.
The Exploration & Production segment includes the Company’s gas and oil exploration, development and production operations. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.
In addition, the Company also reports its corporate functions as a segment. The Corporate and Other segment includes the activities of CNGI and other minor subsidiaries and costs of the Company’s corporate functions. In addition, the contribution to net income by the Company’s primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment and include:
n 2003 cumulative effect of changes in accounting principles;
n 2003 impairment loss related to certain CNGI investments classified as held for sale;
n 2003 severance costs for workforce reductions;
n 2001 restructuring activities;
n 2001 cumulative effect of adopting SFAS No. 133 and
n 2001 estimated impairment of Enron natural gas contracts.
Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.
The following table presents segment information pertaining to the Company’s operations:
As of December 31, 2003, 2002 and 2001, and for the years then ended, less than 1% of the Company’s total long-lived assets and revenue were associated with international operations.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 25. Gas and Oil Producing Activities (Unaudited)
Capitalized Costs
The aggregate amounts of costs capitalized for gas and oil producing activities and related aggregate amounts of accumulated depreciation, depletion and amortization follow:
Total Costs Incurred
The following costs were incurred in gas and oil producing activities during the years ended December 31, 2003, 2002 and 2001:
(1)
Development costs incurred for proved undeveloped reserves were $177 million, $205 million and $130 million for 2003, 2002 and 2001, respectively.
Results of Operations
The Company cautions that the following standardized disclosures required by the FASB do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.
(1)
Depreciation, depletion and amortization for 2001 includes a full cost impairment of $83 million, which was offset completely by the reclassification of certain deferred gains from AOCI. See Notes 9 and 10.
(2)
Income tax for 2001 includes $30 million related to the full cost impairment.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Company-Owned Reserves
Estimated net quantities of proved gas and oil (including condensate) reserves in the United States at December 31, 2001 through 2003 and changes in the reserves during those years are shown in the two tables which follow.
*
Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion. Proved reserves associated with the Canadian properties approximated 1 bcf of gas and 6.6 million barrels of oil at December 31, 2000. The property was transferred at market value of $4.5 million.
*
Effective January 1, 2001, the Company transferred its 21% interest in heavy oil producing properties in Alberta, Canada, to another subsidiary of Dominion. Proved reserves associated with the Canadian properties approximated 1 bcf of gas and 6.6 million barrels of oil at December 31, 2000. The property was transferred at market value of $4.5 million.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities owned by the Company.
(1)
Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end.
(2)
Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $331 million, $238 million and $148 million for 2004, 2005 and 2006, respectively.
In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pre-tax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.
Consolidated Natural Gas Company
Notes to Consolidated Financial Statements, Continued
Note 26. Quarterly Financial Data (Unaudited)
A summary of the quarterly results of operations for the years ended December 31, 2003 and 2002 follows. Amounts shown reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods.
Because a major portion of the gas sold or transported by the Company’s distribution and transmission operations is ultimately used for space heating, both revenue and earnings are subject to seasonal fluctuations. Seasonal fluctuations may be further influenced by the timing of rate relief granted under regulation to compensate for the increased cost of providing service to customers.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Senior management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the Company’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are 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
Omitted pursuant to General Instruction I.(2)(c).
Item 11.
Item 11. Executive Compensation
Omitted pursuant to General Instruction I.(2)(c).
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Omitted pursuant to General Instruction I.(2)(c).
Item 13.
Item 13. Certain Relationships and Related Transactions
Omitted pursuant to General Instruction I.(2)(c).
Item 14.
Item 14. Principal Accountant Fees and Services
The following table presents fees paid to Deloitte & Touche for the fiscal year ended December 31, 2003 and 2002.
Audit Fees are for the audit and review of the Company’s financial statements in accordance with generally accepted auditing standards, including comfort letters, statutory and regulatory audits, consents and services related to Securities and Exchange Commission matters.
Audit-Related Fees are for assurance and related services that are related to the audit or review of the Company’s financial statements, including employee benefit plan audits, due diligence services and financial accounting and reporting consultation.
During 2003, the Board adopted a pre-approval policy for Deloitte & Touche services and fees. Attached to the policy is a schedule that details the services to be provided and an estimated range of fees to be charged for such services. In December 2003, Dominion’s Audit Committee approved the services and fees for 2004.
Part IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.
3. Exhibits
(b) Reports on Form 8-K
The Company filed a report on Form 8-K on November 25, 2003, relating to the sale of $200,000,000 aggregate principal amount of the Company’s 2003 Series A 5.0% Senior Notes Due 2014.
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors of
Consolidated Natural Gas Company
Richmond, Virginia
We have audited the consolidated financial statements of Consolidated Natural Gas Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries as of December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, and have issued our report thereon dated February 26, 2004 (which report expresses an unqualified opinion and includes an explanatory paragraph as to changes in accounting principles for: asset retirement obligations, derivative contracts not held for trading purposes, the consolidation of variable interest entities, and guarantees in 2003; goodwill and intangible assets in 2002; and derivative contracts and hedging activities in 2001); such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedules of the Company, listed in Item 15. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Richmond, Virginia
February 26, 2004
Consolidated Natural Gas Company (Parent Company)
Schedule I-Condensed Financial Information of Registrant
Condensed Statements of Income
The accompanying notes are an integral part of the Condensed Financial Statements.
Consolidated Natural Gas Company (Parent Company)
Schedule I-Condensed Financial Information of Registrant
Condensed Balance Sheets
The accompanying notes are an integral part of the Condensed Financial Statements.
Consolidated Natural Gas Company (Parent Company)
Schedule I-Condensed Financial Information of Registrant
Condensed Statements of Cash Flows
The accompanying notes are an integral part of the Condensed Financial Statements.
Consolidated Natural Gas Company (Parent Company)
Schedule I-Condensed Financial Information of Registrant
Notes to Condensed Financial Statements
Note 1. Basis of Presentation
Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Consolidated Natural Gas Company (the Company) do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the Consolidated Financial Statements and related notes included in the 2003 Form 10-K, Part II, Item 8.
Accounting for Subsidiaries-The Company has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.
Income Taxes-The unconsolidated income tax expense or benefit computed for the Company in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, reflects the tax assets and liabilities of the Company on a stand-alone basis and the effect of filing a consolidated U.S. tax return with its subsidiaries.
Note 2. Long-Term Debt
The Company’s long-term debt consists of the following:
(1)
Represents weighted-average coupon rate for debt outstanding as of December 31, 2003.
(2)
At the option of holders in October 2006, these notes are subject to redemption at 100% of the principal amount plus accrued interest.
(3)
Represents changes in fair value of certain fixed-rate long-term debt associated with fair value hedges.
Based on stated maturity dates rather than early redemption dates that could be elected by the instrument holders, the scheduled principal payments of long-term debt at December 31, 2003 were are follows (in millions):
The Company’s long-term debt agreements contain customary covenants and default provisions. As of December 31, 2003, there were no events of default under the Company’s covenants.
Note 3. Guarantees, Letters of Credit and Surety Bonds
Beginning in 2003, the issuance of certain types of guarantees requires the recognition of a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. Furthermore, any performance required by the Company under such guarantees would result in the recognition of additional liabilities in the Company’s Consolidated Financial Statements.
As of December 31, 2003, the Company had issued the following types of guarantees on behalf of its subsidiaries:
(1)
Guarantees of debt of Dominion Oklahoma Texas Exploration and Production Inc. (DOTEPI). In the event of default by the subsidiaries, the Company would be obligated to repay such amounts.
(2)
Guarantees of contract payments, primarily for certain of its subsidiaries involved in natural gas and oil production, natural gas delivery and energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. If any one of these subsidiaries fails to perform or pay under the contracts and the counterparties seek performance or payment, the Company would be obligated to satisfy such obligation. The Company receives similar guarantees from counterparties as collateral for credit extended by the Company.
Standby Letters of Credit
At December 31, 2003, the Company had authorized the issuance of standby letters of credit by financial institutions totaling $821 million, for the benefit of counterparties that had extended credit primarily to Dominion & Exploration and Production, Inc. In the unlikely event that the Company does not pay amounts when due under the covered contracts, the
Consolidated Natural Gas Company (Parent Company)
Schedule I-Condensed Financial Information of Registrant
Notes to Condensed Financial Statements, Continued
counterparties may present their claims for payment to the financial institutions, which would then request payments from the Company. The $820 million of letters of credit were provided under the 364-day revolving credit facility that matures in August 2004. As of December 31, 2003, no amounts had been presented for payment under these letters of credit.
Surety Bonds
At December 31, 2003, the Company had issued $48 million of surety bonds primarily in connection with licenses, permits, leases and well drilling. Under the terms of the surety bonds, the Company and then Dominion Resources, Inc. are obligated to indemnify the respective surety bond company for any amounts paid on behalf of the Company’s subsidiaries.
Indemnifications
In addition, as part of commercial contract negotiations in the normal course of business, the Company may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Company is unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate the Company have not yet occurred or, if any such event has occurred, the Company has not been notified of its occurrence. However, at December 31, 2003, management believes future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on its results of operations, cash flows or financial position.
Note 4. Dividend Restrictions
The Company received dividends from its consolidated subsidiaries in the amounts of $405 million, $345 million and $336 million for 2003, 2002 and 2001, respectively.
The Public Utility Holding Company Act of 1935 (1935 Act) and related regulations issued by the SEC impose restrictions on the transfer and receipt of funds by a registered holding company from its subsidiaries, including a general prohibition against loans or advances being made by the subsidiaries to benefit the registered holding company. Under the 1935 Act, registered holding companies and their subsidiaries may pay dividends only from retained earnings, unless the SEC specifically authorizes payments from other capital accounts. At December 31, 2003, the Company’s consolidated subsidiaries had approximately $2.5 billion in capital accounts other than retained earnings, representing capital stock, additional paid-in capital and accumulated other comprehensive income. The Company had approximately $3.8 billion in capital accounts other than retained earnings at December 31, 2003. In 2000, in response to a Dominion request, the SEC granted relief, authorizing payment of dividends by the Company from other capital accounts to Dominion in amounts up to $1.6 billion, representing the Company’s retained earnings prior to Dominion’s acquisition of the Company. Furthermore, the Company submitted a similar request to the SEC in 2002, seeking relief from this restriction in regard to DOTEPI, the subsidiary into which Louis Dreyfus was merged. The application requests relief of up to approximately $303 million, representing Louis Dreyfus’ retained earnings prior to the acquisition by Dominion.
Consolidated Natural Gas Company
Schedule II-Valuation and Qualifying Accounts
(a)
Represents net amounts charged-off as uncollectible.
(b)
Represents payments of liabilities.
(c)
Represents adjustments reflecting changes in estimates.
(d)
Represents transfer due to merger of the Company’s service company into Dominion’s service company.
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.
CONSOLIDATED NATURAL GAS COMPANY
By:
/s/ THOS. E. CAPPS
(Thos. E. Capps, Chairman of the Board of Directors and Chief Executive Officer)
Date: March 1, 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 indicated on the 1st day of March, 2004.
Signature
Title
/s/ THOS. E. CAPPS
Thos. E. Capps
Chairman of the Board of Directors and Chief Executive Officer
/s/ THOMAS F. FARRELL, II
Thomas F. Farrell, II
President, Chief Operating Officer and Director
/s/ THOMAS N. CHEWNING
Thomas N. Chewning
Executive Vice President, Chief Financial Officer and Director
/s/ DUANE C. RADTKE
Duane C. Radtke
Executive Vice President and Director
/s/ STEVEN A. ROGERS
Steven A. Rogers
Vice President and Controller (Principal Accounting Officer)