EQUITABLE RESOURCES INC /PA/ - 10-K Annual Report

EQUITABLE RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Title of each class		Name of each exchange on which registered
Common Stock, no par value		New York Stock Exchange Philadelphia Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange Philadelphia Stock Exchange
7.35% Capital Securities due April 15, 2038		New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter periods that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III or this Form 10-K or any amendment to this Form 10-K. o

The aggregate market value of voting stock held by non-affiliates of the registrant as of February 14, 2003: $2,136,236,396

The number of shares outstanding of the issuer's classes of common stock as of February 14, 2003: 61,598,512

Part III, a portion of Item 10 and Items 11, 12 and 13 are incorporated by reference from the Proxy Statement for the Company's Annual Meeting of Stockholders to be held on May 15, 2003, which Proxy Statement will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002, except for the Performance Graph, Compensation Committee Report and Audit Committee Report.

Disclosures in the Annual Report on Form 10-K contain statements that express the expectations of future plans, objectives, cost savings, growth and anticipated financial and operational performance of the Company and its subsidiaries, including the approval by FERC of the merger of Equitrans' assets and operations with the Carnegie Pipeline assets and operations, the hedging of projected production and optimization of storage capacity through trading activities, the plan to introduce additional performance-based rate initiatives, the impact of fluctuations in industrial demand on the Company's financial results, the intention to continue to be diluted as an owner of Westport along with the belief that if the Company's interest decreases below 20% its influence is not significant enough to warrant equity accounting, the estimate of $8.1 million and $15 million in operating fees for 2003 from Eastern Seven Partners and the Appalachian Natural Gas Trust respectively, the expectation of making no foreign investments in 2003, the belief that environmental expenditures will not be significantly different in nature or amount in the future and will not have a material effect on the Company's financial position or results of operations, the adequacy of legal reserves and therefore the belief that the ultimate outcome of any matter currently pending will not materially affect the financial position of the Company, the anticipation that dividends will continue to be paid on a regular quarterly basis, the successful implementation and recovery of implementation costs for the Equitable Gas customer information and billing system, the estimated capital expenditures for Equitable Utilities in 2003, Equitable Supply's estimated capital budget for 2003, the effect of a decrease of $0.10 in the market price of natural gas would have on the Company's earnings per diluted share and the fair market value derivative contracts held by the Company for hedging or trading purposes, the expected cost to resolve noise issues and expected cash flow being sufficient to pay debt service on the Company's 50% owned project in Panama, the effect of the application of Financial Accounting Standards Number 143 "Accounting for Asset Retirement Obligations", the potential effect of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51," the likelihood of making payments under certain guarantees, the estimated amount of cash contributions to the pension plan in 2003, the strategic alternatives for the Company's Jamaica power plant project, the total pension expense to be recognized in 2003, the possibility of replacing $125 million of trust preferred securities with straight debt, the deductibility for Federal tax purposes of the capital loss on the Company's previous sale of its midstream operations, the effect of a change in natural gas prices on the Company's earnings per share, the expected repayment of Company debt and other obligations, the anticipated capital expenditures and commitments, the anticipated changes in NORESCO backlog, the anticipated sale of NORESCO contracts, and the expected drilling program, and that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Act of 1995, as amended. Forward looking statements are typically identified by words such as, but not limited to, "estimates", "expects", "anticipates", "intends", "believes", "plan", "forecasts" and similar expressions or future or conditional verbs such as "will", "should", "would", and "could". Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of any possible acquisitions, divestitures, or restructurings. The Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, changes in energy commodity market conditions, increased competition in deregulated energy markets, weather conditions, earnings to be recorded for the Company's investment in Westport, inflation rates, interest rates, changes in hedging positions, changes in Generally Accepted Accounting Principles, successful negotiation of labor contracts, amount of share repurchase by the Company, changing prices, legislative and regulatory changes, timely obtaining necessary regulatory approvals, financial market conditions, availability of financing, curtailments or disruptions in production and gathering, the ability to acquire and apply technology to Company operations, the ability to develop, finance, complete and operate energy infrastructure projects, the impact of asset impairment judgments used on FASB No. 144 and the ability to efficiently operate, gather, and market natural gas and oil, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. In addition, the drilling of development wells can involve significant risks, including those related to timing, success rates and cost overruns and these risks can be affected by lease and rig availability, complex geology and other factors. Although the Company engages in hedging activities to mitigate risks, fluctuations in future crude oil and gas prices could affect the Company's financial position and results of operations. Furthermore, the Company cannot guarantee the absence of errors in input data, calculations, and formulas used in estimates, assumptions and forecasts.

Equitable Resources, Inc. (Equitable or the Company) is an integrated energy company, with an emphasis on Appalachian area natural gas supply activities including production and gathering, natural gas distribution and transmission, and energy infrastructure and efficiency solutions primarily in the northeastern section of the United States and in selected international markets. The Company also has an interest in another public company with oil and gas exploration and production properties in onshore and offshore United States areas. The Company and its subsidiaries offer energy (natural gas, and a limited amount of crude oil and natural gas liquids) products and services to wholesale and retail customers through three business segments: Equitable Utilities, Equitable Supply and NORESCO. The Company and its subsidiaries had approximately 1,500 employees at the end of 2002.

The Company was formed under the laws of Pennsylvania by the consolidation and merger in 1925 of two constituent companies, the older of which was organized in 1888. In 1984, the corporate name was changed to Equitable Resources, Inc.

The Company makes certain filings with the Securities and Exchange Commission (SEC), including its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through its website, www.eqt.com, as soon as reasonably practicable after they are filed with the SEC. The Company's annual report to shareholders, press releases and recent analyst presentations are also available on the website.

Equitable Utilities contains both regulated and non-regulated operations. The regulated group consists of the distribution and interstate pipeline operations, while the nonregulated group is involved in the non-jurisdictional marketing of natural gas, risk management activities and the sale of energy-related products and services. Equitable Utilities generated 42% of the Company's net operating revenues in 2002.

Equitable Utilities' distribution operations are carried out by Equitable Gas Company (Equitable Gas), a division of the Company. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales in eastern Kentucky. The distribution operations provide natural gas services to approximately 275,000 customers, comprising 256,000 residential customers and 19,000 commercial and industrial customers.

Equitable Gas' natural gas supply portfolio includes short-term, medium-term and long-term natural gas supply contracts obtained from various sources including purchases from major and independent producers in the Southwest United States, purchases from local producers in the Appalachian area, purchases from gas marketers, and third party underground storage fields.

Because most of its customers use natural gas for heating purposes, Equitable Gas' revenues are seasonal, with approximately 67% of calendar year 2002 revenues occurring during the winter heating season (January-March, November-December). Significant quantities of purchased natural gas are placed in underground storage inventory during off-peak season to accommodate higher customer demand during the winter heating season.

The interstate pipeline operations of Equitable Utilities include the natural gas transmission and storage activities of Equitrans, L.P. (Equitrans) and Carnegie Interstate Pipeline Company (Carnegie

Pipeline). The interstate pipeline division offers gas transportation, storage and related services to its affiliates and others in the Northeastern United States.

In the second quarter 2002, Equitrans filed with the Federal Energy Regulatory Commission (FERC) to merge its assets and operations with the assets and operations of Carnegie Pipeline in order to create operating efficiencies. The Company anticipates approval of the merger in 2003.

The regulatory environment is designed to increase competition in the natural gas industry. This environment has created a number of opportunities for pipeline companies to expand services and serve new markets. The Company has taken advantage of selected market opportunities by concentrating on Equitrans' underground storage facilities and the location of its pipeline system as a link between the country's major long-line natural gas pipelines.

Equitable Utilities' unregulated marketing division, Equitable Energy LLC (Equitable Energy), purchases, stores and markets natural gas at both the retail and wholesale level, primarily in the Appalachian and mid-Atlantic regions. Services and products offered by the marketing division include commodity procurement and delivery, physical natural gas management operations and control, and customer support services to the Company's energy customers. To manage the price exposure risk of its marketing operations, the Company engages in risk management activities including the purchase and sale of financial energy derivative products. Because of this activity, the energy marketing division is also able to offer energy price risk management services to its larger industrial customers.

The Company also engages in trading activities with the objective of limiting exposure to shifts in market prices. Equitable Energy uses prudent asset management to hedge projected production and to optimize storage capacity assets through trading activities.

Equitable's distribution rates, terms of service, contracts with affiliates and issuance of securities are subject to comprehensive regulation by the Pennsylvania Public Utility Commission (PUC). The distribution rates, terms of service and contracts with affiliates are subject to comprehensive regulation by the Public Service Commission of West Virginia, and to rate regulation by the Kentucky Public Service Commission. Pipeline safety is generally regulated by the rules of the Federal Department of Transportation and/or by the state regulatory commission. The Occupational Safety and Health Administration (OSHA) also imposes certain additional safety regulations.

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas, including transportation rates, storage tariffs and various other matters, is subject to federal regulation, primarily by the FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The FERC's regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. Some of the trading activities of the energy marketing division are subject to various regulations by, but not limited to, the Commodity Futures Trading Commission, FERC and the PUC.

The pipeline operations of Equitrans and Carnegie Pipeline are subject to rate regulation by the FERC. Equitrans' last general rate change application (rate case) was filed in 1997. The rate case was resolved through a FERC approved settlement among all parties. The settlement provided, with certain limited exceptions, that Equitrans not file a general rate increase with an effective date before August 1, 2001 and must file a general rate increase application to take effect no later than August 1, 2003. Equitrans has been in discussions with its customers concerning various options related to the

requirement to file a rate case, including eliminating the requirement through further rate settlement among the parties.

In the second quarter 2002, Equitrans filed with the FERC to merge its assets and operations with the assets and operations of Carnegie Pipeline. The Company anticipates approval of the merger in 2003.

For additional discussion of regulatory matters involving Equitable Utilities, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A) and Note 11 to the Company's consolidated financial statements.

Over the last two years, Equitable Gas has been working with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. In 2001, Equitable Gas received approval from the PUC to implement a performance-based incentive that provides customers a guaranteed purchased gas cost credit, while enabling it to retain any potential cost savings in excess of the credit through more effective management of upstream interstate pipeline capacity. During the third quarter 2002, the PUC approved a one-year extension of this program through September 2004. In that same order, the PUC approved a second performance-based initiative related to balancing services. This initiative runs through 2005.

In the second quarter 2002, the PUC authorized Equitable Gas to offer a sales service that would give residential and small business customers the alternative to fix the unit cost of the commodity portion of their rate for one year. The program was developed in response to customer requests for a method to reduce the fluctuation in gas costs. The Company is currently preparing to offer this sales service to its residential and small business customers.

The Company plans to introduce additional performance-based initiatives, which will require PUC approval, which will advance new incentive mechanisms for managing commodity costs, reducing operating expenses, optimizing cost of capital, and reducing gas line loss.

The large industrial market is extremely competitive resulting in very low realized margins. Despite the continued national economic downturn experienced during 2002, the industrial activity and volumes increased in 2002 compared to 2001. The increased volumes were mainly due to the increase in sales to steel industry customers. Fluctuations in industrial demand do not have a significant impact on the Company's financial results.

Previously, Equitable Supply was referred to as Equitable Production. The Company believes that a better understanding of this business segment can be obtained by expanding the segment's information concerning its two lines of business: production and gathering. The Company has provided additional disclosure on both lines of business. This change does not impact the comparability of the business segment between years.

Equitable Supply operates two lines of business: production and gathering. Equitable's production business develops, produces and sells natural gas and, to a limited extent, crude oil and its associated by-products, with operations in the Appalachian region of the United States. Its natural gas gathering business engages in gathering the Company's and third party gas and in the limited processing and sale of natural gas liquids. Equitable Supply generated approximately 51% of the Company's net operating revenues in 2002.

Equitable's production business, operating through Equitable Production Company and several smaller affiliates (referred to collectively as "Equitable Production") is the largest owner of proved natural gas reserves in the Appalachian Basin, the oldest and geographically one of the largest natural gas producing regions in the United States. Equitable Production currently operates approximately 12,000 wells in Appalachia. As of December 31, 2002, the Company estimated the total proved reserves to be 2,140 billion cubic feet equivalent (Bcfe), including undeveloped reserves of 559 Bcfe.

The areas in which the Company's Appalachian reserves are located are characterized by wells with comparatively low rates of annual decline in production, low production costs and high British thermal unit (Btu) or energy content. For operational and commercial reasons, some of the gas produced is processed to allow heavier hydrocarbon (propane, butane and ethane) streams to be stripped and sold separately. Within certain limits, the Company can vary the amount of the hydrocarbons extracted. This can cause the conversion rate between energy content (measured in Btu) to volumes (measured in MMcfe) to vary. Once drilled and completed, wells in the Appalachian Basin typically have low ongoing operating and maintenance requirements and require minimal capital expenditures. Appalachian Basin producing formations targeted by the majority of wells are characterized by predictable reserves, low rates of production and wells that generally produce for periods longer than 50 years. Many of the Company's wells in these areas have been producing for decades, in some cases since the early 1900's. Reserve estimates for properties with long production histories are generally more reliable than estimates for properties with shorter histories.

Virtually all of the Company's wells are low risk development wells drilled to relatively shallow depths ranging from 1,000 to 7,000 feet below the surface. Many of these wells are completed in more than one producing formation, including coal formations in certain areas, and production from these formations may be mixed or commingled. Commingled production lowers producing costs on a per unit basis compared to isolated zone completions.

In the Appalachian Region during 2002, Equitable Production drilled 363 gross wells at a success rate of greater than 99%. This drilling was concentrated within the core areas of southwest Virginia, southern West Virginia and southeast Kentucky. This activity resulted in an incremental 30.4 MMcf per day of gas sales and developed reserve additions of 116 Bcfe.

Equitable Production currently has an inventory of 3.6 million gross acres of which approximately 70% is considered undeveloped. As of December 31, 2002, the Company estimated the proved undeveloped reserves of the underlying leases and fee interests to be 559 Bcfe from approximately 1,800 proved undeveloped drilling locations. In the last three years, Equitable Production has completed substantially all of the wells it has drilled in Appalachia.

Equitable Gathering operates through Kentucky West Virginia Gas Company, Equitable Field Services and a portion of Equitable Production Company (referred to collectively as "Equitable Gathering") and owns and operates the largest gas gathering and production pipeline system in the Appalachian Basin. The system includes approximately 10,000 miles of pipeline located throughout West Virginia, eastern Kentucky, southwestern Virginia, eastern Ohio and portions of Pennsylvania. Over 80% of the volumes through the pipeline system interconnect with three major interstate pipelines; Columbia Transmission, East Tennessee Natural Gas Company, and Dominion Transmission. Equitable Gathering also maintains interconnects with Equitrans, the Company's interstate transmission affiliate that affords access to the Pittsburgh market area for gathered gas. Maintaining these interconnects affords Equitable Gathering access to multiple markets and flexibility of deliveries when flow interruptions occur. Flow management through these connections also allows Equitable Gathering

to optimize operating conditions for these gathering assets. Total system throughput is approximately 135 Bcf annually, of which approximately 77% of gathering sales are to affiliates.

In July 2001, Equitrans, an affiliate of Equitable Utilities, filed an application with the FERC to transfer all of its natural gas pipeline gathering systems located in West Virginia and Pennsylvania to the Equitable Gathering business of the Equitable Supply business segment. On February 14, 2002, the FERC approved the application resulting in the transfer of gathering systems. The transfer was effective January 1, 2002 for segment reporting purposes. The systems transferred consist of approximately 1,200 miles of low pressure, small diameter pipeline, and related facilities used to gather gas from wells in the region. Total system throughput is approximately 14 Bcf annually, generating annual revenues and expenses of approximately $4 million. The effect of this transfer is not material to the results of operations or financial position of Equitable Utilities or Equitable Supply. Therefore, segment results have not been restated for this transfer.

In February 2000, the Company acquired the Appalachian production assets of Statoil Energy Inc. (Statoil) for $630 million plus working capital adjustments for a total of $677 million. Statoil's assets consisted of approximately 1,200 billion cubic feet of proven natural gas reserves and 6,500 gross natural gas wells in West Virginia, Kentucky, Virginia, Pennsylvania and Ohio.

In April 2000, the Company merged its Gulf of Mexico operations with Westport Oil and Gas Company for $50 million in cash and 15.2 million shares or approximately a 49% interest in the combined company, named Westport Resources Corporation (Westport). In October 2000, Westport completed an initial public offering (IPO) of its shares. Equitable sold 1.3 million shares in this IPO for an after-tax gain of $4.3 million on proceeds of $19.9 million. This IPO reduced the Company's ownership interest in Westport to approximately 36%. On August 21, 2001, Westport completed a merger with Belco Oil & Gas Company. On November 19, 2002, Westport completed a private offering of 3.1 million shares of Westport common stock and on December 16, 2002, Westport closed a public offering of 11.5 million shares of common stock. Equitable continues to own 13.9 million shares, which now represents approximately 20.8% of Westport's total shares outstanding at December 31, 2002. The book value of Equitable's equity in Westport was $139.7 million as of December 31, 2002. The tax basis of the investment was $73.9 million as of December 31, 2002. The Company's intention is to continue to reduce its percentage ownership, whether by dilution as Westport grows, sales of stock, or other means. If the Company's ownership interest in Westport decreases to below 20%, the Company believes its influence will not be significant enough to warrant equity accounting.

In June 2000, the Company sold certain Statoil properties with reserves of 66.0 Bcfe that qualified for the nonconventional fuels tax credit to a partnership, Eastern Seven Partners, L.P, (ESP) for proceeds of $122.2 million in cash, and a retained minority interest in this partnership. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. Prior to this transaction, the Company entered into financial hedges covering the first two years of production. Removal of these hedges upon closing of this transaction resulted in a $7.0 million pretax charge recorded as other loss in June 2000. The Company accounts for its remaining $26.1 million investment under the equity method of accounting. During 2002, 2001 and 2000, the Company received $8.5 million, $8.9 million and $4.9 million, respectively, in fees for operating the wells, gathering the production, and marketing the gas on behalf of the purchaser. Additionally, the Company estimates that it will receive approximately $8.1 million in fees for the performance of the same services in 2003 based on expected production volumes.

In December 2000, the Company sold certain other Statoil gas properties, with reserves of 133.3 Bcfe to a trust, Appalachian Natural Gas Trust (ANGT), for proceeds of $255.8 million and a retained minority interest in this trust. In anticipation of this transaction, the Company had previously

entered into financial hedges. Removal of these hedges upon closing of this transaction resulted in a $57.7 million charge that offset the gain recognized on the sale of these properties. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. The Company accounts for its $36.1 million investment under the equity method of accounting. During 2002 and 2001, the Company received $15.4 million and $16.1 million in fees for operating the wells, gathering the production, and marketing the gas on behalf of the purchaser. No fees were generated in 2000 related to this sale. Additionally, the Company estimates that it will receive approximately $15.0 million in fees for the performance of the same services in 2003 based on expected production volumes.

In December 2000, the Company entered into two prepaid natural gas sales contracts for a total of approximately 52.7 MMcf of reserves. The Company is required to deliver certain fixed quantities of natural gas during the term of the contracts. The first contract is for five years with net proceeds of $104.0 million. The second contract is for three years with net proceeds of $104.8 million and will be completed at the end of 2003. These contracts were recorded as prepaid forward sales and are being recognized in income as deliveries occur. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition.

In December 2001, the Company sold its oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease of 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves for proceeds of approximately $60 million. The field produced approximately 4 Bcfe annually. The proceeds are shown in the December 31, 2001 Consolidated Balance Sheet as restricted cash. The restrictions lapsed and the cash became unrestricted in the second quarter of 2002. Although the Company will no longer operate these properties, it will continue to gather and market the natural gas produced for a fee. These fees were approximately $1.5 million in 2002.

See Notes 4 and 5 to the consolidated financial statements for additional information relating to the Company's acquisitions and divestitures.

The combination of its long-lived production, low drilling costs, high drilling completion rates at shallow depths and proximity to natural gas markets has had a substantial impact on the development of the Appalachian Basin, resulting in a highly fragmented operating environment. In 2002, Kentucky, Virginia and West Virginia had approximately 4,500 independent operators and approximately 100,000 producing natural gas and oil wells. Also, the historical availability of tax incentives has resulted in extensive drilling in the shallow formations with these low technical risk characteristics.

Equitable has historically entered into hedging contracts with respect to forecasted natural gas production and third party purchases and sales at specified prices for a specified period of time. The Company's hedging strategy and information regarding derivative instruments used are outlined below in Item 7A, "Qualitative and Quantitative Disclosures About Market Risk," and in Note 3 to the consolidated financial statements.

NORESCO provides an integrated group of energy-related products and services that are designed to reduce its customers' operating costs and improve their energy efficiency. The segment's activities are comprised of combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation; performance contracting; and energy efficiency programs. NORESCO's customers include governmental, military, institutional, commercial and industrial end-users. NORESCO's energy infrastructure group develops, constructs and operates facilities in the United States and operates private power plants in selected international countries. NORESCO operates in a highly competitive market segment, with a significant number of companies, including affiliates of large energy companies that have entered this market in recent years. NORESCO's focus is on larger contracts in core performance contracting and energy infrastructure markets. NORESCO provided approximately 7% of the Company's net operating revenues in 2002.

The segment's energy infrastructure group develops and operates private power generation, cogeneration and central plant facilities in the United States and operates private power plants in selected international countries. These projects serve a diverse clientele including governmental, institutional, commercial and industrial customers and utilities. NORESCO's capabilities offer a "turnkey" approach to energy infrastructure programs including project development, equipment selection, fuel procurement, environmental permitting, construction, financing and operations and maintenance. Some of these projects are held through equity in nonconsolidated investments. The Company has not made any international investments since April 2001. The Company does not expect to make any international investments in 2003.

The segment's performance contracting group provides solutions for energy efficiency and conservation. Guaranteed energy savings are used to pay for installation of new energy-efficient equipment and systems. Performance contracting provides a "turnkey" solution including engineering analysis, project management, construction, financing, operations and maintenance, and energy savings measurement and verification. This is a growing market, primarily in the public sector, with a considerable opportunity in the Federal Government sector. NORESCO has significant federal contracts and continues to pursue opportunities in this market.

Revenue backlog decreased to $118.2 million at year-end 2002 from $128.3 million at the end of 2001. A substantial portion of the backlog is expected to be constructed within the next 12 months.

Operating revenues as a percentage of total operating revenues for each class of products and services greater than 10% of each of the three business segments during the years 2002 through 2000 are as follows:

See Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 2 and 24 to the consolidated financial statements in Part II, Items 7 and 8, respectively, for financial information by business segment and information regarding commitments and contingencies.

All but an insignificant amount of the Company's assets and operations are located in the continental United States.

In July 2002, the Environmental Protection Agency (EPA) published a final rule that amends the Oil Pollution Prevention Regulation. The effective date of the rule was August 16, 2002. Under the final rule, Owners/Operators of existing facilities were to revise their Spill Prevention Control and Countermeasure Plans (SPCC) on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003. On January 9, 2003, the EPA extended the compliance deadlines for plan amendment and implementation by 60 days with a proposed rule to extend the dates for one year, and possibly longer. Management is currently evaluating the impact of this final rule on the Company.

The Company is also subject to extensive federal, state and local environmental laws and regulations, which are constantly changing. Governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future activities. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future.

Principal facilities are owned by the Company's business segments, with the exception of various office locations and warehouse buildings, which are leased. A limited amount of equipment is also leased. The majority of the Company's properties are located on or under (1) public highways under franchises or permits from various governmental authorities, or (2) private properties owned in fee, or occupied under perpetual easements or other rights acquired for the most part without examination of underlying land titles. The Company's facilities have adequate capacity, are well maintained and, where necessary, are replaced or expanded to meet operating requirements.

Equitable Utilities. This segment owns and operates natural gas distribution properties as well as other general property and equipment in western Pennsylvania, West Virginia and Kentucky. The segment also owns and operates underground storage and transmission facilities in Pennsylvania and West Virginia.

The interstate pipeline operations consist of approximately 1,500 miles of transmission, storage lines, and interconnections with five major interstate pipelines. Equitrans has 15 natural gas storage reservoirs with approximately 500 MMcf per day of peak delivery capability and 59 Bcf of storage capacity of which 27 Bcf is working gas. Equitrans has begun a geologic assessment and volumetric analysis of its storage reservoirs, in an effort to enhance its storage capacity and deliverability capability. The completion of the study is planned for 2003.

Equitable Supply. This business segment owns or controls all of the Company's acreage of proved developed and undeveloped natural gas and oil production properties and owns and operates gathering properties as well as other general property and equipment located in the Appalachian region. Information relating to Company estimates of natural gas and crude oil reserves and future net cash flows is provided in Note 27 (unaudited) to the consolidated financial statements in Part II.

		2002		2001		2000
Natural Gas:
	MMcf produced		67,171		64,706		87,134
	Average sales price per Mcfe sold (net of hedges)	$	3.47	$	3.75	$	2.87
	MMcfe operated(a)		91,793		93,167		89,932
	MMcfe gathered(b)		123,581		106,832		92,440
Crude Oil:
	Thousands of barrels produced		127		451		497
	Average sales price per barrel	$	20.78	$	17.82	$	21.75

Average production cost including severance taxes (lifting cost) of natural gas and crude oil during 2002, 2001, and 2000 was $0.387, $0.482, and $0.509 per Mcf equivalent, respectively.

		Natural Gas	Oil
Total productive wells at December 31, 2002:
	Total gross productive wells	12,333	314
	Total net productive wells	7,344	289
Total acreage at December 31, 2002:
	Total gross productive acres	1,077,552
	Total net productive acres	1,066,499
	Total gross undeveloped acres	2,499,412
	Total net undeveloped acres	2,286,561

No report has been filed with any federal authority or agency reflecting a 5% or more difference from the Company's estimated total reserves.

Substantially all sales are delivered to several large interstate pipelines on which the Company leases capacity. These pipelines are subject to periodic curtailments for maintenance and repairs.

NORESCO. NORESCO is based in Westborough, Massachusetts, and leases offices in 15 locations throughout the United States.

Headquarters. The headquarters is located in leased office space in Pittsburgh, Pennsylvania.

On October 17, 2002, a jury verdict in the civil lawsuit of Fairon Johnson and Sandra Johnson versus Equitable Resources, Inc. and Kentucky West Virginia Gas Company, L.L.C. was rendered against the Company in Knott County Circuit Court, Kentucky. The plaintiff claimed that a well pump house accident that injured him was caused by the Company's natural gas well adjacent to his property. The jury entered a verdict for $50,000 for medical expenses and lost wages and $270 million for pain and suffering and punitive damages. The Company entered into a confidential settlement with the parties dated December 30, 2002. The judge vacated and set aside entirely the judgment as to punitive damages. The expenses related to this litigation and the settlement were substantially insured. The Company did not admit and continues to deny any involvement with causing the plaintiff's accident.

There are various other claims and legal proceedings against the Company arising in the normal course of business. Although counsel is unable to predict with certainty the ultimate outcome, management and counsel believe that the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously. The Company has provided adequate reserves and therefore believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company. The reserves recorded by the Company do not include any amounts for legal costs expected to be incurred. It is the Company's policy to recognize any legal costs associated with any claims and legal proceedings against the Company as they are incurred.

No matters were submitted to a vote of the Company's security holders during the last quarter of its fiscal year ended December 31, 2002.

Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified. Except as indicated above, the officers listed above were elected on May 16, 2002.

On June 11, 2002, Gregory R. Spencer announced his anticipated retirement in the second quarter of 2003 as Senior Vice President and Chief Administrative Officer.

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

The Company's common stock is listed on the New York Stock Exchange and the Philadelphia Stock Exchange. The high and low sales prices reflected in the New York Stock Exchange Composite Transactions, and the dividends declared and paid per share, are summarized as follows (in U.S. dollars per share):

As of February 20, 2003, there were approximately 4,647 shareholders of record of the Company's common stock.

The indentures, under which the Company's long-term debt is outstanding contain provisions which effectively limit the Company's right to declare or pay dividends and make certain other distributions on, and to purchase any shares of, its common stock. Under the most restrictive of such provisions, $462.6 million of the Company's consolidated retained earnings at December 31, 2002 were available for declarations or payments of dividends on, or purchases of, its common stock. The amount and timing of dividends is subject to the discretion of the Board of Directors and depends on business conditions, the Company's results of operations and financial conditions and other factors. Based on currently foreseeable market conditions, the Company anticipates dividends will continue to be paid on a regular quarterly basis.

The following table sets forth information as of December 31, 2002 with respect to compensation plans under which equity securities of the Company are authorized for issuance.

See Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes 4 and 5 to the consolidated financial statements in Part II, Items 7 and 8, respectively, for other matters that affect the comparability of the selected financial data.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The Company's significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of this Form 10-K. The discussion and analysis of the financial statements and results of operations are based upon Equitable's consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. The following critical accounting policies relate to the Company's more significant judgments and estimates used in the preparation of its

consolidated financial statements. There can be no assurance that actual results will not differ from those estimates.

Asset Impairment: The Company is required to test for asset impairment whenever events or changes in circumstances indicate that the carrying value of an asset might not be recoverable. The Company applies Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (Statement No. 144) in order to determine whether or not an asset is impaired. This Statement indicates that if the sum of the future expected cash flows associated with an asset, undiscounted and without interest charges, is less than the carrying value, an asset impairment must be recognized in the financial statements. The amount of the impairment is the difference between the fair value of the asset and the carrying value of the asset.

The Company believes that the accounting estimate related to an asset impairment is a "critical accounting estimate" as it is highly susceptible to change from period to period, because it requires management to make assumptions about cash flows over future years. These assumptions impact the amount of an impairment, which would have an impact on the income statement. Management's assumptions about future cash flows require significant judgment because actual operating levels have fluctuated in the past and are expected to do so in the future.

The Company reviewed its assets relating to a Jamaican power plant project during the second quarter of 2002, as the project had not been operating at expected levels and repeated remediation efforts were unsuccessful. Additionally, the future projections demonstrated that the losses associated with the assets were likely to continue. The Company determined, through its analysis that an impairment existed. As part of the impairment analysis, the Company performed a probability cash flow analysis using the undiscounted future cash flows and compared this amount to the carrying value of the asset. The probability cash flows result in a lower fair value than the carrying value, and an impairment was deemed necessary. An impairment of $5.3 million was recorded and represents the full value of NORESCO's investment in the project. Actual results of the Jamaican power plant project have supported the impairment analysis as performance continues to decline, causing on-going operations to be in doubt. Notwithstanding the write down of the investment to zero, because the Jamaican power plant is part of the Company's consolidated financial statements, it will continue to record any losses from operations despite the nonrecourse nature of the related debt.

Goodwill: Beginning in fiscal year 2002, goodwill is required to be evaluated annually for impairment, in accordance with Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," (Statement No. 142). This statement requires a two-step process be performed to analyze whether or not goodwill has been impaired. Step one is to test for potential impairment, which requires that the fair value of the reporting unit be compared to its book value. If the fair value is higher than the book value, no impairment occurs. If the fair value is lower than the book value, step two must be performed. Step two requires measurement of the amount of impairment loss, if any, and requires that a hypothetical purchase price allocation be done to determine the implied fair value of goodwill. The resulting fair value is then compared to the carrying value of goodwill. If the implied fair value of the goodwill is lower than the carrying value of the goodwill, an impairment must be recorded.

The Company believes that the accounting estimate related to the goodwill impairment is a "critical accounting estimate" because the underlying assumptions used for the discounted cash flow can change from period to period and these changes could cause a material impact to the income statement. Management's assumptions about discount rates, inflation rates and other internal and external economic conditions, such as NORESCO's expected growth rate, require significant judgment based on fluctuating rates and anticipated future revenues. Additionally, Statement No. 142 requires that the goodwill be analyzed for impairment on an annual basis using the assumptions that apply at the time the analysis is updated.

As discussed in the notes to the consolidated financial statements, goodwill recorded at the NORESCO segment was analyzed for impairment with the implementation of Statement No. 142. The fair value of the Company's goodwill was estimated using discounted cash flow methodologies and market comparable information. Based on the analysis, the implied fair value of the goodwill was less than the book value recorded for the goodwill. Therefore, the Company recognized an impairment. During the first quarter of 2002, the implied fair value of the goodwill, using the discounted cash flows methodology, was $51.8 million. The carrying value of the goodwill was $57.3 million, resulting in an after tax impairment charge of $5.5 million In the fourth quarter of 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.

Prior to the adoption of Statement No. 142, the Company assessed the impairment of goodwill whenever events or changes in circumstances indicated that the carrying value might not be recoverable. No such events or indicators occurred, as prescribed by previous accounting guidance, which required the Company to perform such an assessment.

Allowance for Bad Debts: The Company's Utility segment encounters risks associated with the collection of its accounts receivable. As such, Equitable Utilities records a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, Equitable Utilities primarily utilizes a historical rate of accounts receivable "write-offs" as a percentage of total revenue. This historical rate is applied to the current revenues on a monthly basis. Periodically, the reserve is reviewed for reasonableness. The historical rate is updated periodically based on events that may change the rate such as a significant increase or decrease in commodity prices or a significant change in the weather. Both of these items ultimately impact the customers' ability to pay and the rates that are charged to the customers due to the pass through of purchased gas costs to the customers.

The Company believes that the accounting estimate related to the allowance for bad debts is a "critical accounting estimate" because the underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the income statement and working capital. The actual weather, commodity prices, and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from management's assumptions and may impact expected earnings before interest and taxes (EBIT). Additionally, management reviews the adequacy of the allowance on a quarterly basis using the assumptions that apply at that time.

During 2001, $23 million in overdue accounts receivable were reclassified as a regulatory asset. This was due to rate relief allowed Equitable for certain regulated customers severely impacted by the higher rates and colder weather experienced in early 2001. During early 2001, Equitable Gas increased its write off percentage by 1% of revenues, based on the increase in bad debts due to higher bills and colder weather.

Performance Plan: The Company accounts for stock-based compensation awards under Accounting Principles Board Opinion No. 25. The Company treats its performance plan as a variable plan, under which grants were awarded in 2002. The actual cost to be recorded for the plan will not be known until settlement, which is in January 2005, requiring the Company to estimate the total expense to be recognized. The number of shares to be awarded ranges from 0 to 286,000, depending upon attainment of certain performance goals. In the current period, the Company estimated that the performance measures would be met at the full value of 286,000 shares.

The Company believes that the accounting estimate related to the performance plan is a "critical accounting estimate" because it is highly likely to change from period to period based on the market price of the shares and the level of performance by the employees involved. Additionally, the impact on the Statement of Consolidated Income could be material. Management's assumptions about future

stock price and the amount of stock to ultimately be awarded requires significant judgment due to the volatility of the stock market.

Pension Plans: The calculation of the Company's net periodic benefit cost (pension expense) and benefit obligation (pension liability) associated with its defined benefit pension plans (pension plans) requires the use of a number of assumptions that the Company deems to be "critical accounting estimates." Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions. The Company believes that the two most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

The expected long-term rate of return reflects the average rate of earnings expected on funds invested or to be invested in the pension plans to provide for the benefits included in the pension liability. The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon information available to the Company at that time, including the pension plan's investment mix and the forecasted rates of return on these types of securities. The pension plan's investment mix as of January 1, 2002 and January 1, 2003 approximated 60% equities and 40% fixed income securities. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized in accordance with Statement No. 87. Although the long-term rate is intended to be fairly consistent, the Company has reevaluated and reduced the rate in both 2002 and 2003. The expected long-term rates of return determined by the Company as of January 1, 2002 and 2003 totaled 9.75% and 8.75%, respectively. Pension expense increases as the expected long-term rate of return decreases. Therefore, had the Company assumed an expected long-term rate of return of 8.75% as of January 1, 2002, the Company's pension expense for 2002, excluding the effect of any settlements paid during this period, would have been approximately $1.0 million higher than the amount recorded.

The assumed discount rate reflects the current rate at which the pension benefits could effectively be settled. In estimating that rate, Statement No. 87 requires and the Company looks to rates of return on high quality, fixed income investments. The Company discounted its future pension liabilities using rates of 7.00% and 7.50% as of December 31, 2002 and 2001, respectively. The Company's pension liability increases as the discount rate is reduced. Lowering the discount rate by 0.5% (from 7.00% to 6.50%) would increase the Company's projected benefit obligation as of December 31, 2002 by approximately $4.2 million. Additionally, had the Company's discount rate decreased to 6.50% as of December 31, 2002, the Company's pension expense for 2003 would be projected to decrease by approximately $0.1 million as a significant portion of the pension plan's participants are retirees.

Equitable's consolidated net income from continuing operations before cumulative effect of accounting change for 2002 was $150.6 million, or $2.36 per diluted share, compared with $151.8 million, or $2.30 per diluted share, for 2001, and $106.2 million, or $1.60 per diluted share, for 2000.

The 2002 earnings from continuing operations before cumulative effect of accounting change decreased 1% from 2001 due to the decreased equity earnings in nonconsolidated investments primarily related to the Company's investment in Westport, lower realized selling prices, increased benefit costs, and an impairment on the Jamaica power plant project. These factors were mostly offset by reduced expenses from prior year initiatives and process improvements, lower income tax expense, increased drilling, production enhancements, cooler weather and increased commercial and industrial sales.

The 2001 earnings were improved from 2000 due to higher realized selling prices; incremental natural gas production attributable to a full year of production from the acquired Statoil Appalachian oil and gas properties; and lower operating expenses throughout the organization due to continuing

process improvement efforts in all significant business units. The improved 2001 earnings were partially offset by unusually warm weather resulting in reduced throughput volumes.

Business segment operating results are presented in the segment discussions and financial tables on the following pages. Results for the investment in Westport are not attributed to a business segment. Headquarters' operating expenses are billed to operating segments based on a fixed allocation of the annual operating budget. Differences between budget and actual expenses are not allocated to operating segments. Certain performance-related incentive costs and administrative costs totaling $5.4 million and $8.0 million in 2002 and 2001, respectively, were not allocated.

Equitable Utilities' operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities.

The local distribution operation of Equitable Gas, a division of the Company, provides natural gas services in southwestern Pennsylvania and to municipalities and other customers in northern West Virginia. In addition, Equitable Gas provides field line sales (also referred to as "farm tap" service) in eastern Kentucky. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

Over the last two years Equitable Gas has been working with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. In 2001, Equitable Gas received approval from the PUC to implement a performance-based incentive that provides customers a guaranteed purchased gas cost credit for transportation, while enabling Equitable to retain any cost savings in excess of the credit through more effective management of upstream interstate pipeline capacity. During the third quarter 2002, the PUC approved a one-year extension of this program through September 2004. In that same order, the PUC approved a second performance-based initiative related to balancing services. This initiative runs through 2005.

In the second quarter 2002, the PUC authorized Equitable Gas to offer a sales service that would give residential and small business customers the alternative to fix the unit cost of the commodity portion of their rate for one year. The program was developed in response to customer requests for a method to reduce the fluctuation in gas costs. This "first of its kind" program in Pennsylvania is another in a series of service-enhancing initiatives implemented by Equitable Gas. The Company is currently preparing to offer this sales service to its residential and small business customers.

The Company plans to propose additional performance-based initiatives, which will require PUC approval, that will advance new incentive mechanisms for managing commodity costs, reducing operating expense, optimizing cost of capital, and reducing gas line loss.

In the third quarter 2002, the PUC issued an order approving Equitable Gas' request for a Delinquency Reduction Opportunity Program. The program gives incentives to eligible customers to make payments exceeding their current bill amount and receive additional credits from Equitable Gas to reduce the customer's delinquent balance. The program will be fully funded through customer contributions and a surcharge in rates.

Equitable Gas makes quarterly purchased gas cost filings with the PUC that are subject to annual and quarterly reviews and annual audits by the PUC. The PUC completed its last audit in 2001, which approved the Company's purchased gas costs through 1999. The Company's purchased gas costs for

2000, 2001 and 2002 are currently unaudited by the PUC, but have received final prudency review by the PUC through 2001.

Equitable Gas is in the process of implementing a new customer information and billing system for which it has incurred $6.5 million of capital expenditures from project inception through December 31, 2002. Based upon the information currently available to management, the implementation of this system is expected to be successfully completed by the end of 2003. Total capital expenditures for this project are expected to significantly exceed the original estimate. Though the project will exceed the original estimate, no impairment has been recognized, as the Company believes that all costs related to the project are recoverable and will have future benefit to the Company.

The interstate pipeline operations of Equitrans and Carnegie Pipeline are subject to rate regulation by the FERC. Equitrans last rate case was filed in 1997. The rate case was resolved through a FERC approved settlement among all parties. The settlement provided, with certain limited exceptions, that Equitrans must file a general rate increase application to take effect no later than August 1, 2003. Equitrans has been in discussions with its customers concerning various options related to the requirement to file a rate case, including eliminating the requirement through further rate settlement among the parties.

In July 2001, Equitrans, L.P, filed an application with the FERC to transfer all of its natural gas pipeline gathering systems located in West Virginia and Pennsylvania to a subsidiary of the Company within the Equitable Supply segment. In February 2002, the FERC approved the application that resulted in the transfer of the gathering systems. The transfer was effective January 1, 2002 for segment reporting purposes. The systems transferred consist of approximately 1,200 miles of low pressure, small diameter pipeline and related facilities used to gather gas from wells in the region. Total system throughput is approximately 14 Bcf annually, generating annual revenues of approximately $4 million. The effect of this transfer is not material to the results of operations or financial position of Equitable Resources. Additionally, the effect of this transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Supply segments. Therefore, segment results have not been restated for this transfer.

Equitable Utilities' unregulated marketing entity provides commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial and institutional end-users. This division's primary focus is to provide products and services in those areas where the Company has a strategic marketing advantage, usually due to geographic coverage and ownership of physical or contractual assets.

The Company also engages in limited trading activity, with the objective of limiting exposure to shifts in market prices. Equitable Energy uses prudent asset management to optimize the Company's assets through trading activities.

Historically, Equitable Utilities' marketing affiliate purchased and resold a portion of Equitable Supply's production. Beginning January 1, 2003, these marketing activities will be recorded directly in Equitable Supply. The change will not have a significant impact on the Company as a whole; however, there will be a significant reduction in the marketing revenues and purchased natural gas costs for the unregulated marketing activities recorded in Equitable Utilities.

Equitable Utilities forecasts 2003 capital expenditures to be approximately $73 million, a 4% increase over capital expenditures of approximately $70 million for 2002. The 2003 capital expenditures are expected to include 2002 capital commitments totaling $11 million. The total 2003 expenditures include $56 million for Utilities infrastructure improvements, $12 million for technology enhancements and $5 million for new business development. The infrastructure improvements include improvements to existing distribution and transmission lines as well as storage enhancements. The technology expenditures are related to improved measurement, mobilization and automation initiatives and the continued implementation of a customer information and billing system for the distribution operations. The new business capital is planned for distribution extension projects.

The Company classified all gains and losses associated with its energy trading activities to a net presentation for all periods presented in accordance with EITF No. 02-3.

Equitable Utilities had operating income of $101.9 million for 2002, compared with $79.0 million for 2001. The improved results for 2002 are primarily due to higher revenues resulting from cooler weather in the fourth quarter 2002, non-recurring 2001 charges related to pipeline operations workforce reductions and compressor station automation, and an incremental credit related reserve of $7.0 million.

Operating income for Equitable Utilities decreased 15.1% from 2000 to 2001. The decrease in 2001 is primarily due to reduced revenues resulting from warmer weather, charges related to pipeline operations workforce reductions, and a charge related to a decision to add a $7.0 million incremental credit related reserve.

Capital expenditures increased $31.7 million to $70.2 million in 2002 from $38.5 million in 2001 due to increased infrastructure improvement and technological enhancement projects.

Net revenues for 2002 were $156.1 million compared to $154.6 million in 2001. Heating degree days were 5,258 for 2002, which is 4% cooler than the 5,059 degree days recorded in 2001 and 12% warmer than the 30-year normal of 5,968. The colder weather had a positive year-over-year impact on net revenues of approximately $2.2 million, which was partially offset by a decrease in late fee revenue due to improved accounts receivable collections. Commercial and industrial volumes increased 22% from prior year primarily due to the increased sales to steel industry customers. Despite the increase in commercial and industrial volumes, net operating revenues did not proportionately increase due to the relatively low margins on industrial customer volumes.

Total operating expenses decreased $8.1 million, or 10% from $84.3 million in 2001. The decrease is attributable to the non-recurring $7.0 million charge for incremental credit-related reserves recorded in the fourth quarter of 2001. The operating expenses were also favorably impacted by reduced operations and maintenance expenses related to continued process improvement initiatives and reduced collection related costs. The reduced operations and maintenance expenses were partially offset by increases in pension and post retirement benefit costs.

Net revenues for 2001 were $154.6 million compared to $159.8 million in 2000. Heating degree days were 5,059 for 2001, which is 10% warmer than the 5,596 degree days recorded in 2000 and 15% warmer than the 30-year average of 5,968. The warmer weather had a negative year-over-year impact on net revenues of approximately $7.8 million, which was partially offset by increased delivery margins. Commercial and industrial volumes declined 25% from prior year primarily due to the economic decline in the domestic steel industry. The negative net revenue impact from warmer weather was partially mitigated by an increase in industrial demand charge revenues from new customers and reduced gas costs for non-regulated commercial and industrial customers, particularly in the fourth quarter of 2001.

Total operating expenses increased $5.8 million, or 7% from $78.5 million in 2000. The increase is attributable to a $7.0 million charge for incremental credit-related reserves in the fourth quarter of 2001. The increased operating expenses were partially offset by reduced operations and maintenance expenses related to continued process improvement initiatives.

Net operating revenues from pipeline operations decreased to $56.7 million from $62.1 million in 2001. The decrease is related to the previously disclosed transfer of all of its natural gas pipeline gathering systems to the Equitable Supply segment. The transfer resulted in a reduction of $3.6 million in net revenues and $3.1 million in operating costs. Excluding the $3.6 million from the transfer and the first quarter 2001 one-time gain on the sale of extraction facilities of $0.8 million, the net revenues decreased 2% or $1.0 million from the prior year. The decrease is due to reduced extraction revenues from the sale of the facilities and unfavorable transportation margins due to competition.

Operating expenses decreased by $8.5 million from $33.2 million in 2001. The decreased operating expenses are primarily due to the June 2001 and September 2001 charges for workforce reductions and process improvements related to compressor automation totaling $6.0 million. The cost reductions from the prior year non-recurring charges and continued process improvement initiatives favorably impacted the 2002 expenses. These cost savings were offset by the Company's decision to accelerate a pipeline maintenance program. Total operating expenses were also reduced by $3.1 million from the previously mentioned transfer of gathering systems.

Net revenues from pipeline operations in 2001 increased to $62.1 million from $61.1 million in 2000. Pipeline revenues in 2000 include $3.8 million for the recovery of stranded costs in rates from the previously mentioned Equitrans' rate case settlement. Excluding the $3.8 million from the settlement in 2000, the net revenues increased 8% from the prior year. This increase is largely associated with the storage-related service revenues resulting from improved asset utilization. The transportation throughput decline of 13% from 2000 is primarily due to the reduced throughput resulting from warmer weather than prior year.

Operating expenses increased by $4.2 million in 2001 from $29.0 million in 2000. The increased operating expenses are due to the June 2001 and September 2001 charges for workforce reductions and process improvements related to compressor automation totaling $6.0 million. The one-time charges were partially offset by reduced operations and maintenance costs associated with the current year workforce reductions and continued process improvement initiatives.

Depreciation and amortization expenses for 2000 included $2.9 million of amortization expense related to the recovery of stranded costs in rates. Excluding the amortization expense from 2000, total depreciation and amortization expenses increased minimally due to the 2001 capital expenditure program.

Net revenues for energy marketing operations increased $6.6 million, or 47% from $14.0 million in 2001. Excluding the prior year one-time losses of $2.6 million on transactions marked to market, net revenues increased $4.0 million. This increase in net revenues and in unit marketing margins versus prior year is a result of the Company's decision to focus on storage and asset management activities and continued de-emphasis on the low margin trading oriented activities. This decision resulted in the 21% reduction in marketed gas sales volumes in 2002.

Operating expenses decreased 52.7% from 2001 to 2002. The decline in operating expenses is associated with a reduction in workforce due to reduced trading activities in 2002, decreased provisions for bad debts attributable to lower gas prices compared to prior year and reduced costs associated with retail marketing activities.

Comparing 2001 to 2000, net revenues for energy marketing operations decreased $2.5 million, or 15% from $16.5 million in 2000. The decrease was due to lower per unit margins and an 11% reduction in volumes. The decline in volume is in line with the Company's strategic decision to reduce its trading activities that typically generate low margins and, as a result, are not a significant component of operating income.

Operating expenses decreased 11% from 2000 to 2001. The decline in operating expenses is associated with a reduction in workforce due to the strategic decision to limit trading activities in 2001 and from increased investment costs in asset management and retail marketing activities.

Equitable Supply operates two lines of business- production and gathering- with operations in the Appalachian region of the United States. Equitable Production develops, produces and sells natural gas (and minor associated crude oil). Equitable Gathering engages in natural gas gathering and the

processing and sale of natural gas liquids. In April 2000, the Company merged its Equitable Production (Gulf) business with Westport Oil and Gas Company to form Westport Resources in which the Company retains an equity interest. The operations of Equitable Production (Gulf) through the date of the merger are presented after the operations of Equitable Production (Appalachian) and Equitable Gathering.

Equitable Supply completed several transactions, which affect the comparability of the financial data between 2002, 2001 and 2000.

In February 2000, Equitable Supply acquired the Appalachian production assets of Statoil for $630 million plus working capital adjustments for a total of $677 million. Statoil's operations consisted of approximately 1,200 billion cubic feet of proven natural gas reserves and 6,500 natural gas wells in West Virginia, Kentucky, Virginia, Pennsylvania and Ohio.

In December of 2001, the Company sold its oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease in 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves for proceeds of approximately $60 million. The field produced approximately 4 Bcfe annually.

During 2000, the Company utilized two prepaid natural gas sales transactions in order to limit its exposure to commodity volatility, to reduce counter-party risk, and to raise capital. These contracts are based upon energy content or Btu. The Company converts these to their volumetric equivalents or Mcfe using a factor of 1.05 MMBtu per Mcfe.

In December 2000, Equitable sold approximately 26.1 Bcf of future production for proceeds of $104 million. This natural gas advance sales contract is treated as a prepaid forward sale and is recorded as a liability. Under the terms of this sales contract, the Company must deliver approximately 14,300 Mcf per day for five years starting January 1, 2001. The Company recognizes the revenue from this sale as natural gas is gathered and delivered.

In December 2000, Equitable sold approximately 26.6 Bcf of future production for proceeds of $105 million. This natural gas advance sales contract is treated as a prepaid forward sale and is recorded as a liability. Under the terms of this sales contract, the Company must deliver approximately 24,300 Mcf per day for three years starting January 1, 2001. The Company recognizes the revenue from this sale as natural gas is gathered and delivered.

The following table details the specifics of the Company's various prepaid transactions as of December 31, 2002, 2001 and 2000, as the information is the same for all years.

Total Contract Volume (Bcf)		Contract Term		Annual Volume (Bcf)		Gathering Fee ($/Mcf)		Wellhead Price ($/Mcf)		Annual Revenue (Thousands)
26.1		5 years		5.2		$	0.71		$	3.28		$	20,794
26.6		3 years		8.9		$	0.71		$	3.23		$	34,922

Occasionally, the Company enters into a sale of gas properties in order to reduce its exposure to commodity volatility, to reduce counter-party risk, eliminate production risk, and to raise capital, while

providing the Company market-based fees associated with the gathering, marketing, and operation of these producing properties.

In June 2000, Equitable sold properties with 66.0 Bcfe of reserves to a partnership, ESP, for proceeds of approximately $122.2 million and a retained interest in the partnership. This sale of gas properties reduces the natural gas production revenue and reserves reported in subsequent years. The Company retained an interest in the partnership that is recorded as equity in nonconsolidated investments on the Consolidated Balance Sheet under the equity method of accounting. The transaction contains a provision, under certain circumstances, for the Company's equity interest to increase. The Company separately negotiated arms-length, market-based rates for gathering, marketing and operating fees with the partnership in order to deliver their natural gas to the market. The underlying contracts associated with these fees are subject to annual renewal after an initial term. As the operator of the gas properties in the partnership, the Company may from time to time have receivables outstanding from ESP of up to $10 million.

In December 2000, Equitable sold properties with 133.3 Bcfe of reserves to a trust, Appalachian Natural Gas Trust (ANGT), for proceeds of approximately $255.8 million and a retained interest in the trust. This sale of gas properties will reduce the natural gas production revenue and reserves reported in subsequent years. The Company retained an interest in the trust, which is recorded as equity in nonconsolidated investments on the Consolidated Balance Sheet under the equity method of accounting. The transaction contains a provision, under certain circumstances, for the Company's equity interest to increase. The Company separately negotiated arms-length, market-based rates for gathering, marketing and operating fees with the partnership in order to deliver their natural gas to the market. The underlying contracts associated with these fees are subject to annual renewal. As the operator of the gas properties and as a result of a separate agreement, the Company receives a market-based fee for providing a restricted line of credit to the trust that is limited by the fair market value of their remaining reserves.

Below is a table that details the specifics of the Company's various sales of gas properties as of December 31, 2002, 2001 and 2000.

				Volumes Produced (Bcfe)		Revenue Recognized from Fees (Thousands)
Sales of Gas Properties		Reserves Sold (Bcfe)
	2002		2001		2000		2002		2001		2000
ESP		66.0		9.6		10.3		6.6		$	8,522	$	8,876	$	4,913
ANGT		133.3		14.2		15.4		—		$	15,442	$	16,130	$	—

In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target. The performance target was met at the end of 2001. Beginning in 2002, the Company no longer includes ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold decreased by approximately 8.9 Bcf while equity production increased by the same amount. The Company has consolidated the partnership starting in 2002, and the remaining portion not owned by the Company results in a minority interest. The minority interest recognized for the year ended December 31, 2002 was $7.1 million.

As a result of the Company's increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company's effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002 and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future.

Equitable Supply forecasts its 2003 capital budget to be approximately $149 million. This includes $113 million for development of Appalachian holdings by Equitable Production and $36 million for improvements and extensions by Equitable Gathering to gathering system pipelines. The amount related to the ABP transaction was approved separately and in addition to the amounts for the capital budget of approximately $149 million. The forecasted level of development drilling is designed to allow for supply volumes to increase somewhat over 2002 levels. The evaluation of new development locations, market forecasts and price trends for natural gas and oil will continue to be the principal factors for the economic justification of drilling and gathering system investments. Capital expenditures increased from $93.9 million in 2001 to $147.5 million in 2002 and were mainly attributable to an increased level of development drillings in the Appalachian holdings and gathering system enhancements. The capital expenditures in 2001 and 2002 included $81.0 million and $114.4 million, respectively, for development of Appalachian holdings and $12.9 million and $33.1 million, respectively, for gathering system improvements and extensions.

Equitable Supply had earnings before interest and taxes of $164.4 million for 2002, compared with $178.7 million in 2001. The lower results for 2002 are primarily due to a $0.25 reduction in average natural gas prices ($12.5 million) and the minority interest ownership in 2002 of the Appalachian Basin Partnership wells described above ($7.1 million), partially offset by reductions in operating expenses ($6.5 million).

Earnings before interest and taxes increased to $178.7 million in 2001 compared to $113.9 million in 2000. The increase in 2001 was primarily due to higher average effective sales price of $3.72 in 2001, compared to $2.91 in 2000, increased sales volumes due to a full year ownership of the Statoil properties increased gathering fees, and lower operating expenses. These improvements were partially offset by the June and December 2000 sale of gas properties in the monetization transactions described above.

On June 30, 2000, Equitable Supply sold a substantial portion of gas properties, which qualified for nonconventional fuels tax credit to a partnership, ESP, which netted $122.2 million in cash and retained a minority interest in the partnership. In anticipation of this transaction, the Company had previously entered into financial hedges covering the first two years of production. Removal of these hedges upon closing of this transaction resulted in a $7.0 million pretax charge recorded as other loss.

Selling, general, and administrative expenses for the period ended December 31, 2002 increased from the same period in 2001 due to costs associated with legal claims and reserves ($3.5 million). Excluding these charges, selling, general, and administrative expenses decreased in total and per unit due to productivity improvements and a 13.0% increase in handled volumes. From 2000 to 2001 selling, general, and administrative expenses per Mcfe declined 13.0% due to on-going synergies from the Statoil acquisition and an increase in handled volumes.

	Years Ended December 31,
	2002		2001		2000
OPERATIONAL DATA
Net equity sales, natural gas and equivalents (MMcfe)		47,640			38,825		66,356
Average (well-head) sales price ($/Mcfe)	$	3.53		$	3.67	$	3.06
Monetized sales (MMcfe)(a)		14,079			22,845		11,105
Average (well-head) sales price ($/Mcfe)	$	3.27		$	3.81	$	2.04
Weighted average (well-head) sales price ($/Mcfe)	$	3.47		$	3.72	$	2.91
Company usage, line loss (MMcfe)		6,216			5,742		6,568
Lease operating expense (LOE), excluding severance tax ($/Mcfe)	$	0.27		$	0.32	$	0.33
Severance tax ($/Mcfe)	$	0.12		$	0.16	$	0.16
Depletion ($/Mcfe)	$	0.40		$	0.38	$	0.49
Total operated volumes (MMcfe)(b)		91,793			93,167		89,932

Revenues from production, which are derived primarily from the sale of produced natural gas, decreased $15.0 million from 2001 to 2002. The decrease in revenues from production is due primarily to lower effective commodity prices ($15.3 million) and sales of oil properties ($17.0 million), partially offset by increased production from new drilling ($15.5 million) and production enhancements ($1.4 million).

Operating expenses for the period ended December 31, 2002 decreased 6.0% from the same period in 2001. This decrease was primarily due to a 17.0% decrease in lease operating expense resulting from reduced well-tending expenses and productivity improvements and a 23.7% decrease in severance taxes, which is primarily due to declines in the market commodity sales price. Leasehold costs were also lower, as a result of lower delay rental costs due to improved acreage management.

Revenues from production increased slightly from 2000 to 2001. The increase in revenues from production of $3.6 million from 2000 to 2001 was due primarily to the June and December 2000 sale of gas properties ($58.2 million), offset largely due to higher effective commodity prices ($49.6 million) in 2001 versus 2000, and increases in the sales volumes due to a full year ownership of the Statoil assets during 2001 ($13.1 million). Equitable Production's average selling prices for natural gas increased 27.8% over the same period. Other revenues increased by 12.1% due to increased service fees from the 2000 sales of gas properties.

Operating expenses for the period ended December 31, 2001 decreased 24.2% from the same period in 2000. This decrease was primarily due to the reduction in operating costs related to the sale of gas properties to a partnership and a trust discussed above. Depletion expense was reduced both in total and on a per-unit basis as a result of the production asset sales in calendar 2000.

	Years Ended December 31,
	2002		2001		2000
OPERATIONAL DATA
Gathered volumes (MMcfe)		123,581			106,832		92,440
Average gathering fee ($/Mcfe)(a)	$	0.51		$	0.58	$	0.58
Gathering and compression expense ($/Mcfe)	$	0.19		$	0.23	$	0.27
Gathering and compression depreciation ($/Mcfe)	$	0.09		$	0.10	$	0.11

The total operating revenue from gathering fees increased 2.7% from 2001 to 2002, primarily due to a 15.7% increase in gathered volumes offset by a 12% decrease in the average gathering fee per Mcfe. The increase in gathered volumes is primarily due to the transfer of the Equitrans gathering pipeline system from the Equitable Utilities segment. The decrease in average gathering fees per Mcfe is a result of the $0.25/Dth default rate on the Equitrans gathering pipeline system resulting from the FERC approved spin down. This rate remains in effect until March 2004.

Operating expenses for the period ended December 31, 2002 decreased 3.9% from the same period in 2001 despite a 15.7% increase in gathered volumes. This decrease was primarily due to a 6.1% decrease in gathering and compression costs primarily due to a reduction in third party gathering costs. Additional positive items include decreased general and administrative expenses, both in total and on a per unit basis.

Revenues from gathering increased 15.6% from 2000 to 2001, primarily due to the increase in gathered volumes, consistent with the increase in sales volumes noted above from the Statoil assets and absence of a work stoppage in 2001. The gathering revenue increases were not offset by the June and December 2000 asset sales, as the production from these wells is still gathered and compressed by the Company.

Operating expenses for the period ended December 31, 2001 decreased 29.4% from the same period in 2000. This decrease was primarily due to the absence of strike-related expenses incurred in 2000 and operating improvements in the Kentucky West pipeline unit offset by increased operating expenses due to full year ownership of Statoil assets. Gathering and compression expenses per Mcfe decreased 14.8% due to operating improvements in the Kentucky West pipeline unit and lower cost gathering on the acquired assets.

As described above, the Equitable Production—Gulf Operations were merged into Westport effective April 1, 2000. As such, there is no activity for the Production—Gulf Operations in 2002 and 2001. The following description includes results prior to the merger. During 2000, seven gross wells were drilled at a success rate of 86%.


OPERATIONAL DATA
Production:
	Net sales, natural gas and equivalents (MMcfe)		6,087
	Average sales price ($/Mcfe)	$	2.77
	LOE ($/Mcfe)	$	0.24
	SG&A ($/Mcfe)	$	0.27
	Depletion ($/Mcfe)	$	1.11
	Capital expenditures (Thousands)	$	9,034

Results of operations for the Gulf Operations in 2000 include only the first quarter.

NORESCO provides energy-related products and services that are designed to reduce its customers' operating costs and to improve their productivity. The segment's activities are comprised of combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation; performance contracting; and energy efficiency programs. NORESCO's customers include governmental, military, institutional, commercial and industrial end-users. NORESCO's energy infrastructure group develops, designs constructs and operates facilities in the United States and operates private power plants in selected international countries. The Company has not made any international investments since April 2001.

Revenues increased to $190.1 million in 2002 from $157.4 million in 2001, an increase of $32.7 million, or 20.8%. This increase was due primarily to increased construction activity versus the prior year. Gross margins decreased to 21.2% in 2002 from 22.0% in 2001, reflecting a change in the mix of projects constructed during the year. Gross margins have trended downwards over the past three years due to competitive pressures and focus on larger projects with lower gross margins. Gross margin in 2002 included a demand side management program termination of $2.4 million.

Total construction completed during 2002 was $126.9 million versus $103.0 million in 2001, an increase of $23.9 million over 2001. This increase was primarily due to construction activity for a new power plant in California and increased backlog at the beginning of the year, which was subsequently constructed in 2002.

Equity earnings of nonconsolidated investments of $4.7 million in 2002 and $7.6 million in 2001 reflects NORESCO's share of the earnings from its equity investments in power plant assets. The decrease in earnings was primarily due to decreased earnings in a power plant in Panama and another one in Rhode Island.

SG&A expenses increased slightly to $23.5 million in 2002 from $23.1 million in 2002. Included in SG&A expenses in both 2002 and 2001 were $1.0 million related to office consolidations.

Depreciation, depletion and amortization expense decreased from 2001 to 2002 by $4.3 million, primarily due to the elimination of goodwill amortization of $3.7 million.

Revenue backlog decreased to $118.2 million at year-end 2002 from $128.3 million at year-end 2001. The decrease in backlog is primarily attributable to delays in the awarding of government contracts. Substantially all of the backlog is expected to be completed within the next 12 months.

During the second quarter 2002, the Company reviewed the Jamaica power plant project related to the Noresco operating segment for impairment as the project had not been operating to expected levels and repeated remediation efforts were unsuccessful. The Company owns 91.2% of the equity in the project and therefore consolidates the project in its financial statements. As a result of the Company's review, an impairment loss of $5.3 million was recorded to adjust the project assets to their fair value. Actual results of the Jamaican power plant project have supported the impairment analysis as performance continues to decline, causing on-going operations to be in doubt. Notwithstanding the write down of the investment to zero, because the Jamaican power plant is part of the Company's consolidated financial statements, it will continue to record any losses from operations despite the nonrecourse nature of the related debt.

Revenues increased from 2000 to 2001 by $22.8 million, or 16.9%, due primarily to the increase in construction backlog at the beginning of 2001 versus the beginning of 2000. Gross margins decreased to 22.0% in 2001 from 24.8% in 2000, reflecting a change in the mix of projects constructed during the year.

Total construction completed during 2001 was $103.0 million versus $85.1 million in 2000, an increase of $17.9 million over 2000. This increase was primarily due to the increased construction backlog at the beginning of 2001 versus the beginning of 2000.

Equity earnings of nonconsolidated investments of $7.6 million in 2001 and $5.1 million in 2000 reflects NORESCO's share of the earnings from its equity investments in power plant assets. The increase in earnings was primarily due to improved earnings in two power plants in Panama.

SG&A expenses were flat from 2000 to 2001. Included in SG&A expenses in 2001 were $1.4 million related to office consolidations in the third quarter. Included in SG&A expenses in 2000 were $1.0 million related to the decision to discontinue developing international energy infrastructure projects and $0.4 million of additional costs related to the closing of three unprofitable energy services contracting offices.

Depreciation, depletion and amortization expense increased from 2000 to 2001 by $0.6 million, or 12.2%. This increase is primarily due to increased DD&A for power plant projects.

Equity in earnings of nonconsolidated investments decreased in 2002 primarily due to reduced earnings from the Company's ownership interest in Westport and the NORESCO segment's investments in independent power plant projects in Panama and Rhode Island.

Beginning in 2002, the Company consolidated ABP, with the portion not owned by the Company being recorded as minority interest. The minority interest recognized for the year ended December 31, 2002 was $7.1 million.

Equity earnings of nonconsolidated investments in 2000 included a gain on sale of Westport stock. In October 2000, Westport completed an IPO of its shares. Equitable sold 1.325 million shares in this IPO for an after-tax gain of $4.3 million.

On June 30, 2000, Equitable sold a substantial portion of gas properties, which qualified for the nonconventional fuels tax credit to a partnership, ESP, which netted $122.2 million in cash and retained a minority interest in the partnership. In anticipation of this transaction, the Company had previously entered into financial hedges covering the first two years of production. Removal of these hedges upon closing of this transaction resulted in a $7.0 million pretax charge recorded as other loss.

	Years Ended December 31,
	2002		2001		2000
	(Thousands)
Interest expense	$	38,787		$	41,098	$	75,661

In 2002, interest expense decreased primarily due to the decrease in interest rates on short-term debt. This decrease was partially offset by the higher interest expense associated with the new long-term notes issued in November 2002.

Interest expense decreased in 2001 as a result of a $472 million decrease in average short-term debt outstanding, due to the reduction in short term debt originally extended to finance the Statoil acquisition in February of 2000, and subsequently extinguished with the proceeds from the two prepaid natural gas sales and the sale of natural gas properties discussed above.

Average annual interest rates on short-term debt were 1.8%, 4.1%, and 6.4% for 2002, 2001, and 2000, respectively.

In accordance with the requirements of Statement No. 142, the Company tested its goodwill for impairment as of January 1, 2002. The Company's goodwill balance as of January 1, 2002 totaled $57.3 million and is entirely related to the NORESCO segment. The fair value of the Company's goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the impairment test, the Company recognized an impairment of $5.5 million, net of tax, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment are expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in the Company's Statements of Consolidated Income retroactive to the first quarter 2002. In the fourth quarter of 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.

In April 1998, management adopted a formal plan to sell the Company's natural gas midstream operations. A capital loss was treated as a nondeductible item for tax reporting purposes under the then current Treasury regulations embodying the "loss disallowance rule," resulting in additional tax recorded on this sale as a reduction to net income from discontinued operations. In May 2002, the IRS issued new Treasury regulations interpreting the "loss disallowance rule" that now permit this capital loss to be treated as deductible. During June 2002, the Company filed amended tax return filings. Consequently, in the second quarter 2002, the Company recorded a $9.0 million increase in net income from discontinued operations related to this unexpected tax benefit.

Cash flows provided by operating activities totaled $213.0 million in 2002 as compared to $129.9 million in 2001. The $83.1 million increase in operating cash flows from 2002 to 2001 is primarily the result of the Company's increased partnership interest in ABP in 2002, in addition to a $36.9 million increase in income from continuing operations before cumulative effect of accounting change excluding undistributed earnings from nonconsolidated investments, minority interest, and an

impairment of long-lived assets. The combined change in accounts receivable and unbilled revenues, inventory, and accounts payable did not significantly impact the net amount of cash provided by operating activities.

At the end of 2001, the Company's ownership interest in ABP substantially increased to 69% as a result of existing contractual arrangements. Consequently, beginning in 2002, the Company no longer includes ABP production volumes as monetized sales, but instead as equity production sales. Additionally, beginning January 1, 2002, the Company consolidated the partnership with the portion not owned by the Company recorded as a minority interest. The minority interest recognized by the Company for the year ended December 31, 2002 totaled $7.1 million. During 2002, the Company paid approximately $0.4 million to the minority interest owners of ABP. During 2001 the Company paid approximately $40.9 million to the other owners of ABP.

The Company's income from continuing operations before cumulative effect of accounting change totaled $150.6 million in 2002 as compared to $151.8 million in 2001. Income from continuing operations before cumulative effect of accounting change in 2002 included undistributed losses from nonconsolidated investments of $3.5 million while income from continuing operations in 2001 included undistributed earnings from nonconsolidated investments of $22.2 million. The $25.7 million decrease in undistributed earnings from nonconsolidated investments from 2002 to 2001 primarily relates to the Company's equity ownership interest in Westport.

Also included in the $150.6 million of income from continuing operations before cumulative effect of accounting change in 2002 is minority interest expense associated with ABP totaling $7.1 million in addition to a $5.3 million impairment associated with a Jamaican energy infrastructure project that is a consolidated subsidiary of the Company.

Income from continuing operations before cumulative effect of accounting change excluding undistributed earnings from nonconsolidated investments, minority interest expense, and an impairment of long-lived assets totaled $166.5 million and $129.6 million during 2002 and 2001, respectively. The $37.0 million increase is primarily attributable to the overall performance of the Company's operating segments as previously described in addition to an $8.4 million increase in the amount of nonconventional fuels tax credit received by the Company as a result of the Company's increased partnership interest in ABP during 2002.

Net cash flows used in investing activities totaled $167.7 million in 2002 as compared to $125.8 million in 2001 and $363.0 million in 2000.

The Company expended approximately $218.5 million in 2002 for capital expenditures as compared to $132.7 million in 2001 and $123.7 million in 2000. Equitable Supply spent $147.5 million of which $114.4 million was spent on developmental drilling and $33.1 million was spent on infrastructure projects. Equitable Utilities spent $70.2 million, of which $58.3 million was spent on infrastructure projects and $11.9 million was spent on business development.

Cash used in 2002 investing activities included $17.6 million invested in available-for-sale securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures. These securities had net unrealized losses of $1.5 million.

Cash provided by investing activities in 2001 included $63.0 million of proceeds from the oil-dominated field sale within Equitable Supply. These proceeds were held in a restricted cash account at December 31, 2001 for use in a potential like-kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash was made available for operations.

Cash used in investing activities in 2000 also included the acquisition of Statoil properties for $677.2 million and an increase in equity in nonconsolidated investments due to the Westport merger, the combination of which were partially offset by the net proceeds received from the sales of producing properties and from the Gulf asset merger with Westport.

A total of $228 million was authorized for the 2003 capital budget program, as previously described in the business segment results. The Company expects to finance this program with cash generated from operations and with short-term debt.

Net cash flows used in financing activities totaled $57.2 million in 2002 as compared to $26.5 million of cash flows used in financing activities in 2001 and $35.8 million of cash flows provided by financing activities in 2000.

The increase in cash used in financing activities from 2001 to 2002 is primarily the result of an $82.2 million reduction of proceeds received from financial institutions associated with the sale of contract receivables during 2002 offset by the net of the proceeds from issuance of $200 million of long-term debt in the fourth quarter of 2002 to pay down commercial paper and $142.6 million reduction in short-term loans. The additional payments on the proceeds received from financial institutions associated with the transfer of contract receivables is primarily the result of the significant amount of transfers done in 2001 and the fact that certain of the Company's debt covenants limit the amount of contract receivables that can be outstanding at any point in time. The $200 million of long-term debt issued in 2002 has a stated interest rate of 5.15% and is due in 2012.

Net cash used in financing activities during 2002 and 2001 also includes the Company's purchase of shares of its outstanding stock and the payment of dividends through the use of cash provided by operating activities. During 2002 and 2001, the Company repurchased 2.9 million and 1.8 million shares of its outstanding common stock for $97.0 million and $61.2 million, respectively. Of the 18.8 million total shares authorized for repurchase, the Company has repurchased approximately 15.2 million shares through December 31, 2002. Additionally, during 2002, 2001, and 2000, the Company paid dividends on its common shares totaling $41.8 million, $40.4 million, and $38.5 million, respectively.

Cash required for operations is affected primarily by the seasonal nature of the Company's natural gas distribution operations and the volatility of oil and natural gas commodity prices. Short-term loans are used to support working capital requirements during the summer months and are repaid as natural gas is sold during the heating season.

The Company has adequate borrowing capacity to meet its financing requirements. Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements. Interest rates on these short-term loans averaged 1.8% during 2002. The Company maintains a three year revolving credit agreement and a 364-day credit agreement with a group of banks providing a total of $500 million of available credit, which expire in 2003 and 2005, respectively. As of December 31, 2002, the Company had the authority to support a $650 million commercial paper program.

The Company's credit ratings, as determined by either Standards & Poor's or Moody's on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company's credit rating, the higher the level of fees and borrowing rate. As of December 31, 2002, the Company had not borrowed any amounts against these lines of credit. Facility fees, averaging one-eleventh of one percent in 2002 and one-twelfth of one percent in 2001, were paid to maintain credit availability.

The Company's overall objective in its hedging program is to protect earnings from undue exposure to the risk of falling commodity prices. Since it is primarily a natural gas company, this leads to different approaches to hedging natural gas than for crude oil and natural gas liquids.

Equitable has taken advantage of favorable gas prices to significantly hedge production. The approximate volumes and prices of Equitable's hedges and fixed-price contracts for 2003 - 2005 are:

		2003		2004		2005
Volume (Bcf)			45			37			34
Average Price (NYMEX)*		$	4.20		$	4.41		$	4.53

With respect to hedging as of December 31, 2002, the Company's exposure to changes in natural gas commodity prices under current market conditions is $0.05 per diluted share per $0.10 change in the average NYMEX natural gas price for 2003, $0.025 to $0.03 per diluted share for 2004 and 2005, and less than $0.05 per diluted share through 2008. In addition to monetizations, the Company uses derivative instruments to hedge its exposure. The Company has relied almost exclusively on fixed price swaps to accomplish the remainder of this objective during 2001 and 2002 due to the increased market volatility.

Investments classified by the Company as available-for-sale consist of debt and equity securities. In accordance with Statement of Financial Accounting Standards No. 115 "Accounting for Certain Investments in Debt and Equity Securities," (Statement No. 115) available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheet within a separate equity component, accumulated other comprehensive income. The Statement also requires the Company to perform an impairment analysis to assess whether a decline in fair market value below the amortized cost is other-than-temporary. If the decline is deemed to be other-than-temporary, the securities must be written down to fair value, as the new cost basis, and the amount of the impairment must be included in earnings.

At December 31, 2002, the Company's gross unrealized losses relating to these securities were approximately $2.1 million, or 13% of its fair value. The Company performed an impairment analysis in accordance with Statement No. 115 and concluded that the decline below cost is not other-than-temporary. Factors and considerations the Company used to support this conclusion were as follows:

In April 2000, the Company merged its Gulf of Mexico operations with Westport Oil and Gas Company for $50 million in cash and approximately 49% interest in the combined company, named Westport Resources Corporation. In October 2000, Westport completed an IPO of its shares. Equitable sold 1.3 million shares in this IPO for an after-tax gain of $4.3 million, leaving Equitable with a total of 13.9 million shares, or approximately 36% interest in Westport. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. On November 19, 2002, Westport completed a private offering of 3.1 million shares of Westport common stock and on December 16, 2002, Westport closed a public offering of 11.5 million shares. Equitable continues to own 13.9 million shares, which now represent 20.8% of Westport's total shares outstanding at December 31, 2002. The fair market value of Equitable's investment in Westport was $289.3 million as of December 31, 2002. The tax basis of the investment was $73.9 million as of December 31, 2002. The Company's intention is to continue to reduce its percentage ownership, whether by dilution as Westport grows, sales of stock, or other means. If the Company's ownership interest in Westport decreases to below 20%, the Company believes its influence will not be significant enough to warrant equity accounting.

During 2000, as more fully explained in Note 4 to the consolidated financial statements, Equitable Supply sold an interest in oil and gas properties to a partnership, ESP. The Company retained a 1% interest and negotiated arms-length, market-based rates for gathering, marketing and operating fees with the partnership in order to deliver its natural gas to the market. The Company treats oil and gas partnership interests as equity in nonconsolidated investments.

Also in 2000, as more fully explained in Note 4 to the consolidated financial statements, Equitable Supply sold an interest in oil and gas properties to a trust, ANGT. The Company retained a 1% interest and has separately negotiated arms-length, market-based rates with ANGT for gathering, marketing and operating fees to deliver their natural gas to the market. Additionally, the Company has contracted for a market based fee, subject to certain restrictions and limitations, a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT for a market-based fee. The Company treats its interest in ANGT as equity in nonconsolidated investments.

NORESCO has equity ownership interests in independent power plant (IPP) projects located domestically and in selected international locations. Long-term power purchase agreements (PPAs) are signed with the customer whereby they agree to purchase the energy generated by the plant. The length of these contracts ranges from 1 to 30 years. The Company has not made an investment since April 2001 and has a total cumulative investment of $43.8 million. The Company's share of the earnings for 2002 and 2001 related to the total investment was $4.7 million and $7.6 million, respectively. These projects generally are financed on a project basis with nonrecourse financings established at the project level.

In 2001, one of the Company's domestic power plant projects, in which the Company owns a 50% interest, Capital Center Energy in Rhode Island, began experiencing billing disputes. The project has reserved for the amounts in dispute pending resolution of the issues. These disputes adversely affect the cash flows and the financial stability of the project and could trigger project loan covenant violations, particularly if resolution of the disputes is further delayed. In September 2002, the Company filed a complaint against an energy customer, in Providence Superior Court. The complaint requests the court to enter a judgment against the energy customer for the $2.3 million owed for energy services rendered through July 2002. In December, a significant energy customer filed a third-party complaint against the site owner, for the alleged breach of its lease with the owner. In December, the Company issued a notice to the energy customer threatening to shut off services unless its account was brought current through July 2002, and a settlement, featuring a current lump sum payment from the customer and reduced payments for energy supplied going forward (pending final settlement) was entered into on December 31, 2002. The Company also provided the site owner a final settlement offer, which, if

accepted, would result in resolution of all outstanding payment issues. The settlement would also address the future billing structure for energy services, with a goal of minimizing future collection issues. NORESCO's equity interest in this non-recourse financed project is $4.4 million as of December 31, 2002. The Company performed an impairment analysis, in accordance with Statement No. 144, of its equity interest in this project as of December 31, 2002. No impairment was required.

One of the Company's two Panamanian projects, in which the Company owns a 45% interest, Petroelectrica de Panama, is a party to a five-year PPA, which expires in February 2003. The project debt was fully satisfied in December 2002. In November 2002, the project won a bid in which the majority of the project's available capacity is under contract with a local distribution company for the twelve months beginning February 1, 2003.

The Company owns a 50% interest in a second Panamanian electric generation project, IGC/ERI Pan-Am Thermal. The project had previously agreed to retrofit the plant to conform to environmental noise standards by a target date of August 31, 2001. Unforeseen events delayed the final completion date of the required retrofits. The project has obtained an extension from the Panamanian government while it evaluates a land acquisition/rezoning proposal, which, if accepted and executed, would obviate the need for a retrofit requirement. The creditor sponsor continues to evaluate the land acquisition/rezoning proposal while concurrently exploring the feasibility of a final technical resolution to the noise issues. The Company is coordinating with the creditor sponsor to obtain any additional regulatory extensions, which may be required. In September and October, the Panamanian government adopted two resolutions which affect the plant's compliance requirements—by suspending the noise mitigation deadline while the Company achieves the objectives of the land acquisition and rezoning proposal, and by modifying the noise standards applicable to the plant (by making them less stringent). The expected additional cost to the Company of achieving resolution of this issue, whether by a retrofit or implementation of the land acquisition/rezoning proposal, is not expected to exceed $1.5 million.

Additionally, this project experienced poor financial performance during 2002 due to adverse weather (abnormally high rainfall), other adverse market-related conditions, and reduced plant availability related to planned and unplanned outages during the first quarter. These factors depressed revenues, causing a drop below the minimum debt service coverage ratio covenant of the non-recourse loan document. The Company has been actively coordinating with the creditor sponsor on this matter and during the second half of 2002 experienced improvement in operational and financial performance. Despite the debt service coverage ratio issues, cash flows and payment of debt service are expected to be adequate through 2003. The Company performed an impairment analysis, in accordance with Statement No. 144, of its equity interest in this project as of December 31, 2002. No impairment was required.

On April 19, 2001, the Board of Directors of Equitable Resources declared a two-for-one stock split payable on June 11, 2001 to shareholders of record on May 11, 2001.

In December 2001, the Company sold its oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease in 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves for proceeds of approximately $60 million. The field produced approximately 4 Bcfe annually. The proceeds are shown in the December 31, 2001 Consolidated Balance Sheet as restricted cash. The restriction lapsed and the cash became unrestricted in the second quarter of 2002. See Note 8 for additional information related to the restricted cash.

In December 2000, the Company entered into two prepaid natural gas sales contracts for 52.7 MMcf of reserves. The Company is required to sell and deliver certain quantities of natural gas during

the term of the contracts. The first contract is for five years with net proceeds of $104.0 million. The second contract is for three years with net proceeds of $104.8 million and will be completed at the end of 2003. These contracts were recorded as prepaid gas forward sales and are being recognized in income as deliveries occur.

In December 2000, Equitable sold properties, previously acquired from Statoil, with approximately 133.3 Bcfe of reserves to a trust, ANGT, for proceeds of $255.8 million and a retained minority interest in the trust. In anticipation of this transaction, the Company had previously entered into financial hedges. Removal of these hedges upon closing of this transaction resulted in a $57.7 million charge that was offset against the gain recognized on the sale of these properties. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. Equitable accounts for its $36.1 million investment under the equity method of accounting. Equitable estimates that it will receive $15.0 million in fees for operating the wells and gathering and marketing the gas on behalf of the trust in 2003 based on expected production volumes.

In June 2000, Equitable sold properties, which contained approximately 66.0 Bcfe of reserves that qualified for nonconventional fuels tax credits to a partnership, ESP, which netted $122.2 million in cash and a retained minority interest in this partnership. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. Prior to the transaction, the Company entered into financial hedges covering the first two years of production. Removal of these hedges upon closing of this transaction resulted in a $7.0 million pretax charge recorded as other loss. Equitable accounts for its remaining $26.1 million investment under the equity method of accounting. Equitable estimates that it will receive $8.1 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2003 based on expected production volumes.

In April 2000, the Company merged Equitable Production (Gulf) with Westport Oil and Gas Company based in Denver, Colorado, in exchange for $50.0 million and a 49% ownership interest in the combined entity, Westport Resources Corporation.

In February 2000, the Company acquired the Appalachian production assets of Statoil for $630 million plus working capital adjustments for a total of $677 million. The Company initially funded this acquisition through commercial paper, which was replaced by a combination of financings and cash from asset sales.

Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement supercedes or amends existing accounting literature related to the impairment and disposal of long-lived assets.

In accordance with Statement No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets' undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.

discounted at the risk-free rate of interest. Notwithstanding the write down of the Company's investment to zero, because the Jamaican power plant is part of the Company's consolidated financial statements, it will continue to record any losses from operations despite the nonrecourse nature of the related debt.

In June 2002, the FASB's EITF issued EITF No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." EITF No. 02-3 was initially effective for financial statements issued for periods ending after July 15, 2002 and required that gains and losses on energy trading contracts be recorded net (i.e., within operating revenues) on a company's income statement. Prior to this guidance, the Company reported the gains and losses on its energy trading contracts gross (i.e., included the revenues and costs comprising the gains and losses on energy trading derivative contracts within operating revenues and cost of sales, respectively) on its Statements of Consolidated Income in accordance with the guidance contained in EITF No. 98-10. As a result of the guidance contained in EITF No. 02-3, in the third quarter 2002, the Company classified all gains and losses on its energy trading contracts net on its Statements of Consolidated Income for all periods presented.

In the fourth quarter 2002, the FASB revised its consensus contained in EITF No. 02-3. EITF No. 02-3, as revised, rescinds the guidance contained in EITF No. 98-10 and requires that only energy trading contracts that meet the definition of a derivative in Statement No. 133 be carried at fair value. Energy trading contracts that do not meet the definition of a derivative must be accounted for as an executory contract (i.e., on an accrual basis). Additionally, EITF No. 02-3, as revised, states that it will no longer be an acceptable industry practice to account for energy inventory held for trading purposes at fair value when fair value exceeds cost, unless explicitly provided by other authoritative literature. The EITF's revised consensus is effective for all new energy trading contracts entered into and energy inventory held for trading purposes purchased after October 25, 2002. For any energy trading contracts entered into or energy inventory held for trading purposes as of October 25, 2002, companies are required to recognize a cumulative effect of a change in accounting principle beginning the first day of the first fiscal period beginning after December 15, 2002. The implementation of the above provisions of EITF No. 02-3 effective for the year ended December 31, 2002 did not have a material impact on the Company's consolidated financial statements. Additionally, management does not expect the implementation of the above provisions of EITF No. 02-3 that are effective in 2003 to have a material impact on the Company's consolidated financial statements.

EITF No. 02-3, as revised, also requires that all gains and losses on derivative instruments held for trading purposes be presented on a net basis in the income statement for all periods presented, whether or not settled physically. For gains and losses on energy trading activities that are not derivatives pursuant to Statement No. 133, the presentation is determined based upon the guidance contained in EITF No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." This guidance is effective for all periods presented in financial statements issued for periods beginning after December 15, 2002 (earlier adoption is permitted). Prior to the implementation of this guidance, companies are able to present these gains or losses on either a gross or a net basis in accordance with the provisions contained in EITF No. 98-10. In response to the revised guidance on the presentation of gains and losses on energy trading contracts contained in EITF No. 02-3, the Company reevaluated the gross to net reclassifications it had made in its third quarter 2002 statements and has adjusted those reclassifications to be in accordance with EITF No. 02-3, as revised. The reduction from a gross to a net classification has resulted in a reduction in both operating revenues and cost of sales for the Equitable Utilities segment for the years ended December 31, 2002, 2001 and 2000, of $169.4 million, $592.0 million, and $615.7 million, respectively.

In June 2001, the Financial Accounting Standard Board issued Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations," (Statement No. 143) which will be effective in the first quarter of fiscal 2003. Statement No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized by the Company at the time the obligation is incurred. When the liability is initially recorded, the Company must also capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is accreted to its future value through charges to operating expense and the capitalized cost is depreciated over the useful life of the asset. If the obligation is settled for other than the carrying amount, the Company will recognize a gain or loss upon settlement. The Company has not fully completed its analysis, but expects the adoption of Statement No. 143 to result in the recognition of an asset retirement obligation liability of $30.0 million to $40.0 million and a cumulative effect of adoption loss of $5.0 million to $10.0 million. In addition, the Company anticipates recording accretion and depletion expense of $1.5 million to $4.0 million in 2003.

In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," (Statement No. 146) which supercedes EITF No. 94-3, "Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity." Statement No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this standard will not have a material impact on the Company's financial statements.

In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, amending FASB Statement No. 123, Accounting for Stock Based Compensation" (Statement No. 148). This statement amends Statement No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of Statement No. 123 to require prominent disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. Finally, Statement No. 148 amends APB Opinion No. 28 "Interim Financial Reporting" to require disclosure about those effects in interim financial information. The Company will adopt the disclosure provisions and the amendment to APB Opinion No. 28 are effective for interim periods beginning after December 15, 2002.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45). FIN No. 45 clarifies and expands on existing disclosure requirements for guarantees, including loan guarantees. It also would require that, at the inception of a guarantee, the Company must recognize a liability for the fair value of its obligation under that guarantee. The initial fair value recognition and measurement provisions will be applied on a prospective basis to certain guarantees issued or modified after December 31, 2002. The disclosure provisions are effective for financial statements of periods ending after December 15, 2002. The adoption of FIN No. 45 will not have a material impact on its financial position, results of operations or cash flows

In November 2002, the EITF reached a consensus on Issue No. 00-21 "Revenue Arrangements with Multiple Deliverables," (EITF No. 00-21). EITF No. 00-21 provides guidance on how to account for arrangements that involve the delivery or performance of multiple products, services and rights to use assets. The provisions of EITF 00-21 will apply to revenue arrangements entered into in the fiscal periods beginning after June 15, 2003. The Company is currently evaluating the impact EITF No. 00-21 will have on its financial position and results of operations.

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN No. 46), "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51." FIN No. 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN No. 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN No. 46 must be applied for the first interim or annual period beginning after June 15, 2003. Management is currently evaluating the effect that the adoption of FIN No. 46 will have on its results of operations and financial condition. Adequate disclosure has been made for all off balance sheet arrangements that it is reasonably possible to consolidate under FIN No. 46.

The Company entered into transactions with ESP and ANGT by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. Appalachian NPI (ANPI) contributed cash and debt to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI's debt. The Company has given to ANPI, subject to certain restrictions and limitations, a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT for a market based fee. These entities manage the assets and produce, market, and sell the related natural gas from the properties. As of December 31, 2002 Eastern Seven and ANPI had $131.8 million and $289.1 million of total assets, respectively, and $8.5 million and $257.3 million of liabilities (including $213.1 million of long-term debt), respectively. The Company's maximum exposure to loss as a result of its involvement with Eastern Seven and ANPI are $26.1 million and $54.1 million, respectively.

The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position (SOP) "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment (PP&E)." This proposed SOP applies to all nongovernmental entities that acquire, construct or replace tangible property, plant and equipment including lessors and lessees. A significant element of the SOP requires that entities use component accounting retroactively for all PP&E assets to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The Company cannot evaluate the ultimate impact of this exposure draft until it becomes final.

The SEC issued a final rule regarding the use of non-Generally Accepted Accounting Principals (GAAP) financial measures by public companies effective after March 2003. The rule defines a non-GAAP financial measure as a numerical measure of an issuer's historical or future financial performance, financial position or cash flows that:

The Company uses EBIT instead of net income as part of the segment reporting. The Company believes EBIT more accurately depicts the individual financial performance of the segments because both interest and income taxes are controlled on a corporate wide basis and are not fully allocated to the segments. Refer to Note 2 for a reconciliation of the segments' EBIT to net income.

The Company has contracted for a market based fee with ANPI, subject to certain restrictions and limitations, a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT. As of December 31, 2002, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be $18.0 million. As of December 31, 2002, the Company has not recorded a liability for this guarantee, as the Company currently believes that the likelihood of making payment under the guarantee is remote.

The Company has certain minority investments representing ownership interests in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. The Company has entered into agreements with these entities to provide administrative, gathering, marketing, and operating services to deliver their gas to market. In addition, the Company receives a marketing fee for the sale of gas based on the net revenue for gas delivered. The total revenue earned from these fees totaled approximately $23.8 million for the year ended December 31, 2002.

The Company has certain minority investments in certain independent power plant projects located domestically as well as in select other countries. These investments are financed with nonrecourse debt. The Company has entered into agreements with these entities to provide administrative and development services. The total revenue earned from these fees totaled approximately $0.9 million for the year ended December 31, 2002.

In order to accelerate cash collections, Equitable executes transactions to sell certain contract receivables to a financial institution and a variable interest entity. The variable interest entity is a multi-seller conduit that purchases contract receivables from several energy companies. The Company has no ownership interest in or control of the variable interest entity. As further described in Note 1 to the consolidated financial statements, the Company does not retain any interest in the contract receivables once the sale is complete. For the year ended December 31, 2002, approximately $46.7 million of the contract receivables met the criteria for sales treatment.

Poor equity market conditions that have existed since 2000 have contributed to a significant reduction in the fair market value of the Company's pension plan assets. As a result, the Company's benefit obligation relating to its pension plans is significantly under funded. The Company therefore expects to make contributions of approximately $39 million to the Company's pension plans during 2003. The Company was not required to and consequently did not make any contributions to its pension plans during the years ended 2002, 2001, and 2000.

The reduction in the fair market value of the Company's pension plan assets over the last two years, coupled with decreases in the expected rate of return on pension plan assets and increases in the amount of unrecognized actuarial losses, has also contributed to a steady increase in the amount of pension expense recognized by the Company. Total pension expense recognized by the Company in 2002 and 2001, excluding special termination benefits and curtailment losses, totaled $5.3 million and $3.8 million, respectively. Excluding special termination benefits and curtailment losses, the Company recognized a pension benefit of approximately $2.6 million in 2000. Total pension expense expected to be recognized by the Company in 2003, exclusive of any special termination benefits and curtailment losses, is $5.8 million.

The Company's distribution operations are subject to comprehensive regulation by the PUC, the Public Service Commission of West Virginia, and to rate regulation by the Kentucky Public Service

Commission. The Company's interstate pipeline operations are subject to regulation by the FERC. Accounting for the Company's regulated operations is performed in accordance with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." As described in Notes 1 and 11 to the consolidated financial statements, regulatory assets and liabilities are recorded to reflect future collections or payments through the regulatory process. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of the deferred costs.

The following table details the future projected payments associated with the Company's significant contractual obligations as of December 31, 2002.

The Company has the option to call the preferred trust securities on or after April 23, 2003. The Company is currently evaluating this option and may exercise its option, given the proper economic circumstances.

Included in long-term debt is nonrecourse project financing in the amount of $16.1 million. This amount relates to the Jamaican energy infrastructure project in the NORESCO segment discussed previously. The full amount of the financing is classified as current due to the defaults on various debt covenants, for which the bank may attempt to call the loan. The Company is currently working on various alternatives to refinance or restructure the debt or to pursue strategic alternatives for the potential transfer or sale of the Company's project interests.

The indentures and other agreements governing the Company's long-term debt contain certain restrictive financial and operating covenants including covenants that restrict the Company's ability to pay cash dividends, incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, sell assets, and certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Company's debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Company's indebtedness.

Included within the unconditional purchase obligations amount in the table above are annual commitments of approximately $24.1 million relating to the Company's natural gas distribution and production operations for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to six years at December 31, 2002. Approximately $19.1 million of these costs are recoverable in customer rates.

On October 17, 2002, a jury verdict was rendered against the Company in a civil lawsuit in Knott County Circuit Court, Kentucky. The plaintiff claimed that a well pump house accident that injured him was caused by the Company's natural gas well adjacent to his property. The jury entered a verdict for $50,000 for medical expenses and lost wages and $270 million for pain and suffering and punitive damages. The Company entered into a confidential settlement with the parties dated December 30, 2002. The judge vacated and set aside entirely the judgment as to punitive damages. The expenses

related to this litigation and the settlement were substantially insured. The Company did not admit and continues to deny any involvement with causing the plaintiff's accident.

The various regulatory authorities that oversee Equitable's operations will from time to time make inquiries or investigations into the activities of the Company. Equitable is not aware of any wrongdoing or irregularities relating to any such inquiries or investigations.

In July 2002, the EPA published a final rule that amends the Oil Pollution Prevention Regulation. The effective date of the rule was August 16, 2002. Under the final rule Owners/Operators of existing facilities were to revise their SPCC on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003. On January 9, 2003 EPA extended the compliance deadlines for plan amendment and implementation for 60 days with a proposed rule to extend the dates for one year and possibly longer. Management is currently evaluating the impact of this final rule on the Company.

The Company is also subject to extensive federal, state and local environmental laws and regulations, which are constantly changing. Governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future activities. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future.

Any estimated costs associated with identified situations that require remedial action are accrued with certain costs deferred as regulatory assets, as applicable. Management does not know of any environmental liabilities that will have a material effect on Equitable's financial position or results of operations. The Company has identified situations that require remedial action for which approximately $6.1 million is included in other long-term liabilities at December 31, 2002.

At the end of the useful life of a well the Company is required to remediate the site by plugging and abandoning the well. Costs associated with this obligation totaled $0.7 million, $0.8 million and $0.7 million during the years ended 2002, 2001, and 2000, respectively.

The rate of inflation in the United States has been less than moderate over the past several years and has not significantly affected the profitability of the Company. In prior periods of high general inflation, oil and natural gas prices generally increased at comparable rates; however, there is no assurance that this will be the case in the current environment or in possible future periods of high inflation. Regulated utility operations would be required to file a general rate case in order to recover higher costs of operations. Margins in the energy marketing business in the Equitable Utilities segment are highly sensitive to competitive pressures and may not reflect the effects of inflation. The results of

operations in the Company's three business segments will be affected by future changes in oil and natural gas prices and the interrelationship between oil, natural gas and other energy prices. To help mitigate the effect of any future changes in natural gas prices, the Company has entered into hedging contracts with respect to forecasted natural gas production at specified prices for a specified period of time. The Company's hedging strategy and information regarding the derivative instruments used are outlined in Item 7A, "Qualitative and Quantitative Disclosures About Market Risk," and in Note 3 to the consolidated financial statements.

The Audit Committee, composed entirely of outside directors, meets periodically with Equitable's independent auditors and management to review the Company's financial statements and the results of audit activities. The Audit Committee, in turn, reports to the Board of Directors on the results of its review and recommends the selection of independent auditors.

During 2002, Equitable Resources conducted business with PNC Financial Services Group, Inc (PNC), where Mr. James E. Rohr, an Equitable Resources Director, serves as Chairman and Chief Executive Officer. The Company paid PNC a total of $619,637 in fees in 2002 for various services, including commitment fees for a line of credit in which PNC participates with twelve other financial institutions, treasury management fees, and trust fees. The Company also made lease payments to PNC during 2002 totaling $1,472,816, including $872,576 for a lease termination payment, for the financing of communications equipment. Also during 2002, the Company's pension plan for hourly employees paid BlackRock, Inc., a majority-owned subsidiary of PNC, $153,565 in ordinary and customary fees for investment management services. The Company has approximately $16 million invested in BlackRock mutual funds for future satisfaction of plugging and abandonment obligations. All of these transactions were on arms-length terms believed to be fair in the ordinary course of business and Mr. Rohr did not have a direct or indirect material interest in these transactions.

In the course of ordinary business, the Company may have other transactions with companies and organizations for which an Equitable Resources director serves as an officer. Those directors did not have a material interest in any such transactions and none of those transactions exceeded 5% of the gross revenues of either Equitable Resources or the other organization. Moreover, any such transactions were entered into on arms-length terms believed to be fair.

The Company's primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of Equitable through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. The Company's use of derivatives to reduce the effect of this volatility is described in Note 3 to the consolidated financial statements. The Company uses simple, nonleveraged derivative instruments that are placed with major institutions whose creditworthiness is continually monitored. The Company's use of these derivative financial instruments is implemented under a set of policies approved by the Company's Corporate Risk Committee and Board of Directors.

For commodity price derivatives used to hedge forecasted Company production, Equitable sets policy limits relative to the expected production and sales levels, which are exposed to price risk. The level of price exposure is limited by the value at risk limits allowed by this policy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. In general, Equitable's strategy is to become more highly hedged for production over the next several years at prices considered to be at the upper end of historical levels. The

Company believes that prices between $3.00 and $3.50 per MCF are sustainable. Above this range, non-traditional supplies become economically feasible. Furthermore, the Company expects price volatility to result in prices significantly higher and lower than this range. The Company attempts to take advantage of these price fluctuations by hedging more aggressively when prices are much higher than the range and by taking more price risk when prices are significantly below the range. However, the Company has typically not hedged material volumes unless the natural gas prices exceed $4 per MCF. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility.

For commodity price derivatives held for trading positions, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits. These financial instruments include forward contracts, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual agreements.

With respect to the energy derivatives held by the Company for purposes other than trading as of December 31, 2002, the Company continued to execute its hedging strategy by utilizing price swaps of approximately 227.8 Bcf of natural gas. These derivatives have hedged expected equity production through 2008. A decrease of 10% in the market price of natural gas from the December 31, 2002 levels would increase the fair value of the natural gas instruments by approximately $102.8 million. With respect to derivative contracts held by the Company for trading purposes as of December 31, 2002, a decrease of 10% in the market price of natural gas from the December 31, 2002 level would increase the fair market value by approximately $3.9 million.

The above analysis of the energy derivatives held by the Company for purposes other than trading does not include the unfavorable impact that the same hypothetical price movement would have on the Company and its subsidiaries' physical sales of natural gas. The portfolio of energy derivatives held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and as applicable, anticipated transactions occur as expected.

The disclosure with respect to the energy derivatives relies on the assumption that the contracts will exist parallel to the underlying physical transactions. If the underlying transactions or positions are liquidated prior to the maturity of the energy derivatives, a loss on the financial instruments may occur, or the derivative might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.

The Company has variable rate short-term debt. As such, there is some limited exposure to future earnings due to changes in interest rates. A 100 basis point increase or decrease in interest rates would not have a significant impact on future earnings of the Company under its current capital structure.

The Company may enter into interest rate derivative instruments to mitigate exposure to future changes in interest rates, but as of December 31, 2002 the Company had no such instruments outstanding.

		Page Reference
Report of Independent Auditors		53
Statements of Consolidated Income for each of the three years in the period ended December 31, 2002		54
Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2002		55
Consolidated Balance Sheets as of December 31, 2002 and 2001		56
Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 2002		58
Notes to Consolidated Financial Statements		59

We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. 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, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Equitable Resources, Inc. and Subsidiaries at December 31, 2002 and 2001, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Statements of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," effective January 1, 2002.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
YEARS ENDED DECEMBER 31,

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000

Common shares authorized: 160,000,000 shares. Preferred shares authorized: 3,000,000 shares. There are no preferred shares issued or outstanding.

Retained earnings of $462.6 million are available for dividends on, or purchase of, common stock pursuant to restrictions imposed by indentures securing long-term debt.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002

Principles of Consolidation: The consolidated financial statements include the accounts of Equitable Resources, Inc. and all subsidiaries, ventures and partnerships in which a controlling equity interest is held (Equitable or the Company). Equitable, in most instances, utilizes the equity method of accounting for companies where its ownership is less than or equal to 50%. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included in interest charges.

Inventories: The Company's inventory balance consists of natural gas stored underground and materials and supplies. The amount of natural gas stored underground that is not related to the Company's energy trading activities plus the amount of materials and supplies are recorded at the lower of average cost or market. The amount of natural gas stored underground that was purchased on or before October 25, 2002 and that relates to energy trading activities was recorded at fair value in accordance with the Financial Accounting Standards Board's (FASB) Emerging Issues Task Force (EITF) No. 98-10 "Accounting for Contracts Involved in Energy and Risk Management Activities." Subsequent to October 25, 2002, the Company has recorded the purchase of the physical inventory associated with its energy trading activities at the lower of cost or market in accordance with EITF No. 02-3 "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17," which rescinded the guidance contained in EITF No. 98-10.

Properties, Plant and Equipment: Plant, property and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives, ranging from 3 to 70 years except for most natural gas and crude oil production properties as explained below. The cost of minor repairs and replacements is charged to maintenance expense. As of December 31, 2002, accumulated depreciation (in thousands) for Equitable Utility, Equitable Supply and NORESCO were $341,294, $636,608, and $5,421, respectively.

Oil & Gas Properties: The Company uses the successful efforts method of accounting for production activities. Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. The depletion is calculated based on the annual actual production multiplied by the depletion rate per unit. The depletion rate is derived by dividing the total costs capitalized over the number of units expected to be produced over the life of the reserves. Equitable Supply calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia, Ohio and Pennsylvania. Costs of exploratory dry holes, geological and geophysical, delay rentals, and other property carrying costs are charged to expense.

The carrying value of the Company's proved oil and gas properties are reviewed on a field-by-field basis for indications of impairment whenever events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred,

Equitable estimates the expected future cash flows (on an undiscounted basis) from the Company's proved oil and gas properties and compares them to their respective carrying values. The estimated future cash flows used to test those properties for recoverability are based on proved reserves utilizing assumptions about the use of the asset and forward market prices for oil and gas. Proved oil and gas properties that have carrying amounts in excess of undiscounted future cash flows are deemed unrecoverable. Those properties are then written down to fair value, which is estimated using assumptions that marketplace participants would use in their estimates of fair value. In developing estimates of fair value, the Company used forward market prices. For the years ended December 31, 2002 and 2001, the Company did not recognize impairment charges on oil and gas properties.

Additionally, the costs of unproved oil and gas properties are periodically assessed on a field-by-field basis. If unproved properties are determined to be productive, the related costs are transferred to proved oil and gas properties. If unproved properties are determined not to be productive, or if the value has been otherwise impaired, the excess carrying value is charged to expense. For additional information on oil and gas properties, see Note 27.

Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from the depletion pool unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.

Regulatory Accounting: The Company's distribution operations are subject to comprehensive regulation by the Pennsylvania Public Utilities Commission (PUC) and the Public Service Commission of West Virginia. The Company also provides "farm tap" service in Kentucky which is subject only to rate regulation by the Kentucky Public Service Commission. The Company's interstate pipeline operations are subject to regulation by the Federal Energy Regulatory Commission (FERC). Accounting for the Company's regulated operations is performed in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." The application of this accounting policy allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates.

Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between its purchased natural gas cost, less refunds, and the billing of such cost and amortizes the deferral over subsequent periods in which billings either recover or repay such amounts. Such amounts are reflected on the Company's Consolidated Balance Sheets as other current assets or liabilities.

When any portion of the Company's distribution or pipeline operations cease to meet the criteria for application of regulatory accounting treatment for all or part of their operations, the regulatory assets and liabilities related to those portions are eliminated from the Consolidated Balance Sheets and are included in the Statements of Consolidated Income in the period in which the discontinuance of regulatory accounting treatment occurred.

Derivative Commodity Instruments: Derivatives are held as part of a formally documented risk management program. The Company's risk management activities are subject to the management, direction and control of the Company's Corporate Risk Committee (CRC). The CRC reports to the Company's Audit Committee of the Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees.

The Company's risk management program includes the use of exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options (collectively, derivative contracts) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The Company's risk management program also includes the use of interest rate swap agreements to hedge exposures to fluctuations in interest rates. At contract inception, the Company designates its derivative instruments as hedging or trading activities. All derivative instruments are accounted for in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," (Statement No. 133) as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of Financial Accounting Standards Board Statement No. 133" (Statement No. 137) and by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (Statement No. 138). As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. The measurement of fair value is based upon actively quoted market prices when 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, measurement involves judgment and estimates. These estimates are based upon valuation methodologies deemed appropriate by the Company's CRC.

The accounting for the changes in fair value of the Company's derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (net of tax) and is reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of accumulated other comprehensive income recorded up to that date would remain accrued provided that the forecasted transaction remains probable of occurring, and going forward, the change in fair value of the derivative instrument would be recorded in earnings. To the extent that a derivative instrument has been designated and qualifies as a fair value hedge, the change in fair value of the derivative instrument as well as the offsetting change in fair value of the hedged item is recognized in earnings immediately in the same accounting period. The change in fair value of a derivative instrument that is not designated as a hedging instrument is immediately recognized in earnings. The derivative instruments that comprise the amount recorded in accumulated other comprehensive income have been designated and qualify as cash flow hedges.

The revenues and costs comprising any gains and losses on derivative instruments held for trading purposes are recognized within operating revenues (i.e., on a net basis) in the Company's Statement of Consolidated Income in accordance with the guidance contained in EITF No. 02-3.

Capitalized Interest: Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets' estimated useful lives. Interest costs during 2002, 2001 and 2000 of $1.4 million, $2.0 million and $3.3 million, respectively, were capitalized as a portion of the cost of the related long-term assets.

Goodwill: Goodwill is the excess of the acquisition cost of businesses over the fair value of the identifiable net assets (tangible and intangible) acquired. Goodwill was required to be evaluated for impairment at the beginning of 2002 and on an annual basis going forward according to SFAS No. 142 "Goodwill and Other Intangible Assets" (Statement No. 142). The standard requires a two-step process be performed to analyze whether or not goodwill has been impaired. Step one requires that the fair value be compared to book value. If the fair value is higher than the book value, no impairment is indicated and there is no need to perform the second step of the process. If the fair value is lower than the book value, step two must be evaluated. Step two requires that a hypothetical purchase price

allocation analysis be done to reflect a current book value of goodwill. This current value is then compared to the carrying value of goodwill. If the current fair value is lower than the carrying value, an impairment must be recorded. Annually, the goodwill is tested for impairment in the fourth quarter.

Stock-Based Compensation: The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," (APB No. 25) and related interpretations in accounting for stock options and awards. Accordingly, no compensation cost for fixed stock options is included in net income since all awards were made at the fair value on the date of grant. Compensation expense for restricted share awards is ratably recognized over the vesting period, based on the fair value of the stock on the date of grant.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 "Accounting for Stock-Based Compensation," (Statement No. 123) to employee stock-based awards. Refer to Note 21 for more information regarding stock based compensation.

Revenue Recognition: Revenues for regulated natural gas sales to retail customers are recognized as service is rendered, including an accrual for unbilled revenues from the date of each meter reading to the end of the accounting period. Revenue is recognized for production activities when deliveries of natural gas, crude oil and natural gas liquids are made. Revenues from natural gas transportation and storage activities are recognized in the period service is provided. Revenues from energy marketing activities are recognized when deliveries occur. Revenues associated with all activities classified as energy trading were recognized in accordance with mark to market accounting through October 25, 2002. Subsequent to October 25, 2002, in accordance with EITF No. 02-3, only revenues associated with energy trading activities that do not result in physical delivery of an energy commodity (i.e. are settled in cash) are recorded in accordance with mark to market accounting. The revenues associated with the physical delivery of an energy commodity are recognized at contract value when delivered. Revenues associated with the Company's two natural gas advance sales contracts are recognized as natural gas is gathered and delivered.

The NORESCO segment recognizes revenue and profit from long-term contracts, including turnkey energy savings performance contracts, using the percentage of completion method of accounting. The percentage of completion method measures the percentage of contract costs incurred to date to the estimated total contract costs for each contract. Contract costs include all direct material, labor, subcontract costs and those indirect costs related to contract performance. Selling,

general and administrative costs are charged to expense as incurred. Revenue from contract change orders and claims is recognized when settlement is probable and the amount can be reasonably estimated. Costs and estimated profits in excess of billings are classified as a current asset. Amounts billed in excess of costs and estimated profits are classified as a current liability. NORESCO follows this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. However, due to uncertainties inherent in the estimation process, actual results could differ from those estimates. Since the financial reporting of these contracts depends on estimates, which are assessed continually during the term of the contract, recognized revenues and profit are subject to revisions as the contract progresses to completion. The revenue recognized on contracts is not related to progress billings to customers. Revisions in profit estimates are reflected in the period in which the facts that give rise to the revision become known. Accordingly, favorable changes in estimates result in additional profit recognition, and unfavorable changes in estimates result in the reduction of previously recognized revenue and profits. The accuracy of the gross margins the Company reports for contracts is dependent upon various judgments it makes with respect to its contract performance, its cost estimates, and its ability to recover additional contract costs through changes orders or claims. When estimates indicate a loss under a contract, cost of sales is charged with a provision for such loss in the period in which such losses are identified. As work progresses under a loss contract, revenues continue to be recognized, and a portion of the contract costs incurred in each period is charged to the contract loss reserve. The Company had one loss contract as of December 31, 2002.

With certain projects, the Company enters into shared energy savings contracts to provide sustained levels of energy savings to its customers. The terms of the project are defined by an energy services agreement between the Company and the customer. Once completed, these projects will earn revenue from the customer based on the measurement formulas established in the energy services agreement. The Company recognizes revenue from shared energy savings contracts as energy savings are measured and verified, in accordance with the established measurement formulas.

Revenue received from customer contract termination payments is recognized when received. Any maintenance revenues are recognized as related services are performed.

Sales of Receivables: The Company enters into construction contracts with governmental and institutional counterparties whereby those counterparties finance the construction directly with the Company at prevailing market interest rates. In order to accelerate cash collections and manage working requirements, the Company transfers these contract receivables due from customers to financial institutions. The transfer price of the contract receivables is based on the face value of the executed contract with the financial institution. The gain or loss on the sale of contract receivables is the difference between the existing carrying amount of the financial assets involved in the transfer and the transfer price of the contract with the financial institution.

Certain of these transfers do not immediately qualify as "sales" under SFAS No. 140 "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" (Statement No. 140). For the contract receivables that are transferred and still controlled by the Company, a liability is established to offset the cash received from the transfer. This liability is recognized until control has been surrendered in accordance with Statement No. 140, as the cash received by the Company can be called by the financial institution at the time it is determined that control will not be surrendered. The Company de-recognizes the receivables and the liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140. The Company does not retain any interests in the contract receivables, once the sale is complete. As of December 31, 2002, the Company had recorded a current liability of $73.0 million classified as current project financing obligations and a long-term liability of $13.6 million classified as project financing obligations on the Consolidated Balance Sheets. The current project financing obligations represent transfers for which control is expected to be surrendered, and cash could be called, within one year. The related assets are classified

as unbilled revenues as construction progresses and as other assets upon completion of construction. Prior year has been reclassified to conform with current year presentation.

For the year ended December 31, 2002, approximately $46.7 million of the contract receivables met the criteria for sales treatment generating a recognized gain of $1.0 million. The de-recognition of the $46.7 million in receivables and the related liabilities was considered a non-cash transaction and is consequently not reflected in the Statements of Consolidated Cash Flows.

Investments: The Company has evaluated its investment policy in accordance with SFAS No. 115 "Accounting for Certain Investments in Debt and Equity Securities," (Statement No. 115) and has determined that all of its investment securities are appropriately classified as available-for-sale. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the Consolidated Balance Sheet within a separate component of equity, accumulated other comprehensive income. These investments are intended to cover plugging and abandonment and other liabilities for which the Company self-insures and are not expected to be paid in the near future and are therefore considered long term in nature.

The Company owns approximately 20.8% of Westport Resources Corporation (Westport), which it accounts for under the equity method of accounting. The Company's equity investment in Westport totaled $139.7 million as of December 31, 2002 and is included in equity in nonconsolidated investments on the Consolidated Balance Sheets. Because the Company files its consolidated financial statements earlier than Westport, there may be differences between the financial results utilized by the Company to adjust its equity investment and the financial results reported by Westport. The Company records any differences that occur after the filing of the Company's financial statements in the subsequent interim period. There were no significant adjustments recorded by the Company in the fourth quarter 2002 or 2001 related to these differences.

Income Taxes: The Company files a consolidated Federal income tax return. The Company estimates an annual effective income tax rate, based on projected results for the year, and applies this rate to pre-tax income. Any refinements made due to subsequent information, which affects the estimated effective income tax rate, are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations, discontinued operations and cumulative effects of accounting changes. The current provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refundable.

Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities in accordance with SFAS No. 109, "Accounting for Income Taxes," (Statement No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of such temporary differences. The statement also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. Where deferred tax liabilities will be passed through to customers in regulated rates, the Company establishes a corresponding regulatory asset for the increase in future revenues that will result when the temporary differences reverse.

Investment tax credits realized in prior years were deferred and are being amortized over the estimated service lives of the related properties where required by ratemaking rules.

Allowance for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company's accounts receivable, including assessing the probability of collection and the credit-worthiness of certain customers. Reserves for uncollectible accounts are recorded as part of the selling, general and administrative expense on the Statements of Consolidated Income. The reserve is based on historical experience, current and expected economic trends, and specific information about customer

accounts. Accordingly, actual results may differ from these estimates under different assumptions or conditions.

Earnings Per Share (EPS): Basic EPS is computed by dividing income (loss) from continuing operations before extraordinary loss by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS is computed by dividing income (loss) from continuing operations before extraordinary loss, adjusted for the assumed conversion of debt, by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company's common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and awards. See Note 19 for a detailed calculation.

Segment Disclosures: Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company's chief executive officer (chief operating decision maker) in deciding how to allocate resources. Operating segments are evaluated on their contribution to the Company's consolidated results, based on earnings before interest and taxes. Interest charges, income taxes and certain corporate office expenses are managed on a consolidated basis.

Newly Issued Accounting Standards: Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (Statement No. 144). This Statement supercedes or amends existing accounting literature related to the impairment and disposal of long-lived assets.

During the second quarter 2002, the Company reviewed the Jamaica power plant project related to the NORESCO operating segment for impairment as the project had not been operating to expected levels in order to meet anticipated profit goals and remediation efforts were unsuccessful. The Company owns 91.2% of the equity in the project and therefore consolidates the project in its financial statements. As a result of the Company's review, an impairment loss of $5.3 million was recorded to adjust the project assets to their fair value. Fair value was based on the expected future cash flows to be generated by the Jamaican power plant, discounted at the risk-free rate of interest. Actual results of the Jamaican power plant project have supported the impairment analysis as performance continues to decline, causing on-going operations to be in doubt. Notwithstanding the write down of the investment to zero, because the Jamaican power plant is part of the Company's consolidated financial statements, it will continue to record any losses from operations despite the nonrecourse nature of the related debt.

In June 2002, FASB's EITF issued EITF No. 02-3,which was initially effective for financial statements issued for periods ending after July 15, 2002 and required that gains and losses on energy trading contracts be recorded net (i.e., within operating revenues) on a company's income statement. Prior to this guidance, the Company reported the gains and losses on its energy trading contracts gross (i.e., included the revenues and costs comprising the gains and losses on energy trading derivative contracts within operating revenues and cost of sales, respectively) on its Statements of Consolidated Income in accordance with the guidance contained in EITF No. 98-10. As a result of the guidance contained in EITF No. 02-3, in the third quarter 2002, the Company classified all gains and losses on its energy trading contracts net on its Statements of Consolidated Income for all periods presented.

In June 2001, the Financial Accounting Standards Board` issued SFAS No. 143 "Accounting for Asset Retirement Obligations" (Statement No. 143), which will be effective for the first quarter of fiscal 2003. Statement No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized by the Company at the time the obligation is incurred. When the liability is initially recorded, the Company must also capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is accreted to its future value through charges to operating expense and the capitalized cost is depreciated over the useful life of the asset. If the obligation is settled for other than the carrying amount, the Company will recognize a gain or loss upon settlement. The Company has not fully completed its analysis, but expects the adoption of Statement No. 143 to result in the recognition of an asset retirement obligation liability of $30.0 million to $40.0 million and a cumulative effect of adoption loss of $5.0 million to $10.0 million. In addition, the Company anticipates recording accretion and depletion expense of $1.5 million to $4.0 million in 2003.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (Statement No. 146), which supercedes EITF No. 94-3, "Liability Recognition for Certain Employment Termination Benefits and Other Costs to Exit an Activity." Statement No. 146 requires companies to record liabilities for costs associated with exit or disposal activities to be recognized only when the liability is incurred instead of at the date of commitment to an exit or disposal activity. Adoption of this standard is effective for exit or disposal activities that are initiated

after December 31, 2002. The adoption of this standard will not have a material impact on the Company's financial statements.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, amending FASB Statement No. 123, Accounting for Stock Based Compensation" (Statement No. 148). This statement amends Statement No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of Statement No. 123 to require prominent disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. Finally, Statement No. 148 amends APB Opinion No. 28 "Interim Financial Reporting" to require disclosure about those effects in interim financial information. The Company will adopt the disclosure provisions and the amendment to APB No. 28 are effective for interim periods beginning after December 15, 2002.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45). FIN No. 45 clarifies and expands on existing disclosure requirements for guarantees, including loan guarantees. It also would require that, at the inception of a guarantee, the Company must recognize a liability for the fair value, of its obligation under that guarantee. The initial fair value recognition and measurement provisions will be applied on a prospective basis to certain guarantees issued or modified after December 31, 2002. The disclosure provisions are effective for financial statements of periods ending after December 15, 2002. The adoption of FIN No. 45 will not have a material impact on its financial position, results of operations or cash flows.

The Company entered into transactions with Eastern Seven Partners (ESP) and Appalachian Natural Gas Trust (ANGT) by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. Appalachian NPI (ANPI), contributed cash and debt to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI's debt. The Company has given to ANPI, subject to certain restrictions and limitations, a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT for a market based fee. These entities manage the assets and produce, market, and sell the related natural gas from the properties. As of December 31, 2002 ESP and ANPI had $131.8 million and $289.1 million of total assets, respectively, and $8.5 million and $257.3 million of liabilities (including $213.1 million of long-term debt), respectively. The

Company's maximum exposure to loss as a result of its involvement with ESP and ANPI are $26.1 million and $54.1 million, respectively.

The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position (SOP) "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment (PP&E)." This proposed SOP applies to all nongovernmental entities that "acquire, construct or replace tangible property, plant and equipment including lessors and lessees. A significant element of the SOP requires that entities use component accounting retroactively for all PP&E assets to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all PP&E assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of PP&E. The Company cannot evaluate the ultimate impact of this exposure draft until it becomes final.

Stock Split: On April 19, 2001, the Board of Directors of Equitable Resources declared a two-for-one stock split payable on June 11, 2001 to shareholders of record on May 11, 2001.

Reclassification: Certain previously reported amounts have been reclassified to conform to the 2002 presentation.

The Company reports operations in three segments, which reflect its lines of business. The Equitable Utilities segment's activities are comprised of the operations of the Company's state-regulated local distribution company, natural gas transportation, storage, marketing and trading activities involving the Company's interstate natural gas pipelines, and supply and transportation services for the natural gas and electricity markets. The Equitable Supply segment's activities are comprised of the development, production, gathering and sale of natural gas and minor associated oil, and the extraction and sale of natural gas liquids. NORESCO segment's activities are comprised of an integrated group of energy-related products and services that are designed to reduce its customers' operating costs and improve their energy efficiency. NORESCO's activities comprise distributed on-site generation, combined heat and power, and central boiler/chiller plant development, design, construction, and operation; performance contracting; and energy efficiency programs.

Previously, the Equitable Supply segment was referred to as Equitable Production. The Company believes that a better understanding of this business segment can be obtained by expanding the segment's information concerning its two lines of business: production and gathering. The Company has provided additional disclosure on the two lines of business. This change does not impact the comparability of the business segment between years.

Operating segments are evaluated on their contribution to the Company's consolidated results, based on earnings before interest and taxes. Inter-segment activity is recorded at market rates. Interest charges and income taxes are managed on a consolidated basis and allocated pro forma to operating segments. Headquarters costs are billed to operating segments based on a fixed allocation of the annual headquarters' operating budget. Differences between budget and actual headquarters expenses are not allocated to operating segments, but are instead included as a reconciling item to consolidated earnings from continuing operations.

Substantially all of the Company's operating revenues, net income from continuing operations and assets are generated or located in the United States of America.

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company's forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $30.9 million asset and a $25.0 million liability as of December 31, 2002, and a $157.6 million asset as of December 31, 2001. These amounts are classified in the Consolidated Balance Sheets as derivative commodity instruments, at fair value. The decrease in the net amount of derivative commodity instruments, at fair value, from December 31, 2001 to December 31, 2002 is primarily the result of the increase in natural gas prices. The absolute quantities of the Company's derivative commodity instruments that have been designated and qualify as cash flow hedges total 265.1 Bcfe and 196.4 Bcfe as of December 31, 2002 and 2001, respectively, and primarily relate to natural gas swaps. The open swaps at year-end 2002 have maturities extending through December 2008.

The Company deferred a net gain of $2.8 million and a gain of $102.4 million in accumulated other comprehensive income, net of tax, as of December 31, 2002 and 2001, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $21.2 million of unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss as of December 31, 2002 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.

For the year ended December 31, 2002, ineffectiveness associated with the Company's derivative commodity instruments designated as cash flow hedges increased earnings by approximately $1.5 million. These amounts are included in operating revenues in the Statements of Consolidated Income. There was no ineffectiveness for the year ended December 31, 2001.

The Company conducts trading activities through its unregulated marketing group. The function of the Company's trading business is to contribute to the Company's earnings by taking market positions within defined limits subject to the Company's corporate risk management policy.

At December 31, 2002, the absolute notional quantities of the futures, swaps and physical contracts held for trading purposes totaled 19.5 Bcf, 51.9 Bcf, and 112.5 Bcf, respectively.

Below is a summary of the activity of the fair value of the Company's derivative contracts with third parties held for trading purposes during the year ended December 31, 2002 (in thousands).

Fair value of contracts outstanding as of December 31, 2001		$	4,159
	Contracts realized or otherwise settled		(16,638	)
	Other changes in fair value		19,102

Fair value of contracts outstanding as of December 31, 2002		$	6,623

There were no adjustments to the fair value of the Company's derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the years ended December 31, 2002 and 2001.

The following table presents the maturities and the fair valuation source for the Company's derivative commodity instruments that are held for trading purposes as of December 31, 2002.

The overall portfolio of the Company's energy derivatives held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of energy derivatives held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and as applicable, anticipated transactions occur as expected.

In December of 2001, the Company executed a purchase and sale agreement for the sale of the Company's oil-dominated fields. This transaction is in line with management's strategic objectives to focus on core natural gas related activities. The sale resulted in a decrease of 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves for proceeds of approximately $60 million. No gain or loss was recognized on the sale in accordance with the Company's accounting policies.

In April 2000, the Company combined its Gulf of Mexico operations with Westport Oil and Gas Company for $50 million in cash and approximately 49% interest in the combined company, named Westport Resources Corporation. Equitable accounts for the investment in Westport under the equity method of accounting. The effect of this acquisition is not material to the results of operations or financial position of Equitable, and therefore, pro forma financial information is not presented. In October 2000, Westport completed an IPO of its shares. Equitable sold 1.3 million shares in this IPO for an after-tax gain of $4.3 million.

In June 2000, Equitable sold properties with 66.0 Bcfe of reserves, which qualified for the nonconventional fuels tax credits to a partnership, ESP, for proceeds of $122.2 million in cash and a retained minority interest in this partnership. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. Prior to this transaction, the Company entered into financial hedges covering the first two years of production. Removal of these hedges upon closing of this transaction resulted in a $7.0 million pretax charge recorded as other loss. Equitable accounts for its remaining $26.1 million investment under the equity method of accounting. The Company separately negotiated arms-length, market-based rates for gathering, marketing, and operating fees with the

partnership in order to deliver their natural gas to the market. Equitable estimates that it will receive $8.1 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2003 based on expected production volumes.

In December 2000, Equitable sold properties, previously acquired from Statoil, with 133.3 Bcfe of reserves to a trust, ANGT, for proceeds of $255.8 million and a retained minority interest in this trust. In anticipation of this transaction, the Company entered into financial hedges. Removal of these hedges upon closing of this transaction resulted in a $57.7 million charge that was offset against the gain recognized on the sale of these properties. The proceeds received were used to pay down short-term debt associated with the Statoil acquisition. Equitable accounts for its $36.1 million investment under the equity method of accounting. The Company separately negotiated arms-length, market-based rates for gathering, marketing, and operating fees with the trust in order to deliver their natural gas to the market. Equitable estimates that it will receive $15.0 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2003 based on expected production volumes.

On February 15, 2000, the Company, through its subsidiary, ERI Investments, Inc., acquired the Appalachian oil and gas properties of Statoil for $630 million plus working capital adjustments for a total of $677 million. The Company acquired all of the issued and outstanding shares and interests of Eastern States Oil & Gas, Inc. and Eastern States Exploration Co., subsidiaries of Statoil Energy, Inc. The acquisition was initially funded by the Company through short-term debt and was replaced with transactions designed to monetize the oil and gas properties. This acquisition has been accounted for under the purchase method of accounting. Accordingly, the allocation of the cost of the acquired assets and liabilities assumed has been made on the basis of the estimated fair value. The consolidated financial statements include the operating results of these properties from the date of acquisition.

The following table presents certain pro forma financial information for the year ended December 31, 2000 assuming that this acquisition occurred on January 1, 2000. The 2000 results contain pro forma adjustments for depreciation, depletion, and amortization (DD&A) and certain other adjustments together with related income tax effects.

Unaudited Pro Forma		2000
		(Thousands, except per share amounts)
Revenue		$	1,053,802

Net income		$	107,843

Earnings per share:
	Basic	$	1.66

	Diluted	$	1.63

This information is not necessarily indicative of the results the Company would have obtained had these events actually occurred on January 1, 2000, or of the Company's actual or future results of operations of the combined companies.

The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities.

The net deferred tax assets relating to the Company's other comprehensive income balance as of December 31, 2002 were comprised of a $1.5 million deferred tax liability relating to the Company's net unrealized gain from hedging transactions, and a $12.7 million deferred tax asset related to the minimum pension adjustment. The net deferred tax liabilities relating to the Company's other comprehensive income balance as of December 31, 2001 were comprised of a $56.3 million deferred tax liability related to the cumulative effect of adopting Statement No. 133 and the net unrealized gain from the Company's hedging transactions, offset by a $6.0 million deferred tax asset related to the minimum pension adjustment.

Provisions for income taxes differ from amounts computed at the Federal statutory rate of 35% on pretax income from continuing operations. The reasons for the difference are summarized as follows:

Separate effective income tax rates are calculated for net income from continuing operations, discontinued operations and cumulative effects of accounting changes. See Note 7 as to the tax impact of discontinued operations and Note 12 as to the tax impact of cumulative effects of accounting changes.

An income tax benefit of $7.3 million and $2.6 million for the years ended December 31, 2002 and 2001, respectively, triggered by the exercise of nonqualified employee stock options, is reflected as an addition to common stockholders' equity.

As a result of the Company's increased partnership interest in Appalachian Basin Partners (ABP) in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company's effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002 and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future.

The consolidated Federal income tax liability of the Company has been settled with the Internal Revenue Service (IRS) through 1997. The Company anticipates a review of it's Federal income tax liability by the IRS for 1998 and subsequent years, but the Company does not believe that such review, if one occurs, will have a negative impact on future net income.

In April 1998, management adopted a formal plan to sell the Company's natural gas midstream operations. A capital loss was treated as a nondeductible item for tax reporting purposes under the then current Treasury regulations embodying the "loss disallowance rule," resulting in additional tax recorded on this sale as a reduction to net income from discontinued operations. In May 2002, the IRS issued new Treasury regulations interpreting the "loss disallowance rule" that now permit this capital loss to be treated as deductible. During June 2002, the Company filed amended tax return. Consequently, in the second quarter 2002, the Company recorded a $9.0 million increase in net income from discontinued operations related to this unexpected tax benefit.

The net proceeds from the sale of certain properties were placed in an escrow account pursuant to a deferred exchange agreement. This agreement allowed for the use of the funds in a potential like-kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash was made available for operations. As of December 31, 2001, the balance of restricted cash was $63.0 million.

The Company has ownership interests in various nonconsolidated investments that are accounted for under the equity method of accounting. The following table summarizes the equity in nonconsolidated investments.

Equitable Supply's equity in nonconsolidated investments represent ownership interests in transactions by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. Both of these investments follow the equity method of accounting.

The NORESCO segment, through its energy infrastructure division, has investments in unconsolidated partnerships. These investments represent equity ownership interests in independent power plant (IPP) projects located in the United States as well as in selected international countries.

IPP projects which NORESCO and its partners developed, constructed and operate are the result of specific needs of private or governmental entities to secure power that is more cost effective and reliable than the current source of power as well as to meet the growing energy demands of many international countries. Long-term power purchase agreements are signed with the customer whereby they agree to purchase the energy generated by the plant. The length of these contracts ranges from 1 to 30 years.

The Company did not make any additional investments during 2002 and invested approximately $0.1 million in equity in nonconsolidated investments during 2001, with a total cumulative investment of $43.9 million as of December 31, 2002. The Company's ownership share of the earnings for 2002 and 2001 related to the total investments was $4.7 million and $7.6 million, respectively. All projects have been completed within the NORESCO segment using nonrecourse financing at the subsidiary level.

On April 10, 2000, Equitable merged its Gulf of Mexico operations with Westport Oil and Gas Company for approximately $50 million in cash and approximately 49% minority interest in the combined company, named Westport Resources Corporation. Equitable accounted for this investment under the equity method of accounting. In October 2000, Westport completed an IPO of its shares. Equitable sold 1.325 million shares in this IPO for an after-tax gain of $4.3 million, on proceeds of

$19.9 million. Equitable's investment in Westport was $139.7 million as of December 31, 2002 and the aggregate market value of this investment was $289.3 million as of December 31, 2002. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. On November 19, 2002, Westport completed a private offering of 3.1 million shares of Westport common stock and on December 16, 2002, Westport closed a public offering of 11.5 million shares of common stock. Equitable continues to own 13.911 million shares, which represents approximately 20.8% of Westport's total shares outstanding at December 31, 2002. If the Company's ownership interest in Westport decreases to below 20%, the Company believes its influence will not be significant enough to warrant equity accounting.

Investments classified as available-for-sale consist of debt and equity securities that are intended to fund plugging and abandonment and other liabilities for which the Company self-insures. These investments were purchased during the first quarter of 2002. Any unrealized gains or losses are recognized within the Consolidated Balance Sheet as a component of equity, accumulated other comprehensive income. Information regarding the cost and fair value of the Company's available-for-sale investments at December 31, 2002 is as follows:

The following table summarizes the Company's regulatory assets, net of amortization, as of December 31, 2002 and 2001. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of these assets.

		December 31,
Description		December 31,
Description		2002			2001
		(Thousands)
Deferred taxes (Statement No. 109)		$	56,424		$	59,681
Delinquency Reduction Opportunity Program			23,403			23,403
Other postemployment benefits (Statement No. 106)			5,345			4,166
Deferred purchase gas (credits) costs			(2,157	)		7,074
Other			1,439			(25	)
Valuation allowance			(7,000	)		(7,000	)

	Total regulatory assets		77,454			87,299
Amounts classified as other current (liabilities) assets			(2,157	)		7,074

	Total long-term regulatory assets	$	79,611		$	80,225

The regulatory asset associated with deferred taxes primarily represents timing differences associated with the excess of federal tax depreciation over book depreciation on property, plant and equipment associated with Equitable Utilities operations resulting from the adoption of Statement No. 109 in 1993. The Company is recovering the amortization of this asset through rates.

A regulatory asset was recognized as of December 31, 2001 at the distribution company associated with uncollectible accounts receivable resulting in large degree from unusually high natural gas prices and unseasonably cold weather experienced during the winter of 2000-2001. The regulatory asset was

initially established based upon the Company's ability to recover these costs through a surcharge in rates. In the third quarter 2002, the PUC issued an order approving a Delinquency Reduction Opportunity Program that gives incentives to low-income customers to make payments, which exceed their current bill amount in order to receive additional credits from the Company intended to speed the reduction of the customer's delinquent balance. This program will be funded through customer contributions and through the existing surcharge in rates. The Company has established a valuation allowance of $7.0 million as of December 31, 2002 and 2001 against the accounts receivable special arrears regulatory asset relating to the portion of the balance where collection does not appear probable due to the nature of the regulatory asset.

The Company makes quarterly purchased gas cost filings with the PUC that are subject to annual and quarterly reviews and annual audits by the PUC. The PUC completed its last audit in 2001, which approved the Company's purchased gas costs through 1999. The Company's purchased gas costs for 2000, 2001 and 2002 are currently unaudited by the PUC, but have received final prudency review by the PUC through 2001.

The Company has been working with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based ratemaking. In 2002 and 2001, the Company received approval from the PUC to implement, and in some cases extend, performance-based rate incentives. These incentives provide customers with various credits, while enabling the Company to retain any cost savings or productivity enhancements in excess of the credit through more effective management of upstream interstate pipeline assets and balancing services. The PUC has approved these initiatives through, at a minimum, September 2004.

The PUC has also authorized the Company to offer a sales service that would give residential and small business customers the alternative to fix the unit cost of the commodity portion of their rate for a full year.

In accordance with the requirements of Statement No. 142, the Company tested its goodwill for impairment as of January 1, 2002. The Company's goodwill balance as of January 1, 2002 totaled $57.3 million and is entirely related to the NORESCO segment. The fair value of the Company's goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the impairment test, the Company recognized an impairment of $5.5 million, net of tax, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment are expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in the Company's Statements of Consolidated Income retroactive to the first quarter 2002. The tax impact of the impairment was zero since the Company's goodwill has no tax basis. In the fourth quarter of 2002, the Company performed the required annual impairment test of the carrying amount of goodwill and no further impairment was required.

Had the Company been accounting for its goodwill under Statement No. 142 for all prior periods presented, the Company's net income and diluted earnings per share for the years ended December 31, 2002, 2001 and 2000 would have been as follows:

Prior to the adoption of Statement 142 in 2002, amortization of the goodwill was provided on the straight-line method over a life of 20 years. Accumulated amortization at December 31, 2002 and 2001 was $17.5 million. For the years ended December 31, 2001 and 2000 amortization expense, included in depreciation, depletion and amortization, was $3.7 million. There was no amortization expense for the year ended December 31, 2002.

Maximum lines of credit of $500 million and $650 million were available to the Company at December 31, 2002 and 2001, respectively. The Company is not required to maintain compensating bank balances. The Company's credit ratings, as determined by either Standards & Poor's or Moody's on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company's credit rating, the higher the level of fees and borrowing rate. As of December 31, 2002, the Company had not borrowed any amounts against these lines of credit. Commitment fees averaging one-eleventh of one percent in 2002 and one-twelfth of one percent in 2001 were paid to maintain credit availability.

Short-term loans were comprised almost entirely of commercial paper balances of $106.0 million and $275.4 million with weighted average annual interest rates of 1.37% and 2.02% as of December 31, 2002 and 2001, respectively. The maximum amount of outstanding short-term loans at any certain time during the year was $303.6 million in 2002 and $328.8 million in 2001. The average daily balance of short-term loans outstanding over the course of the year was approximately $211.7 million and $234.6 million at weighted average annual interest rates of 1.81% and 4.06% during 2002 and 2001, both respectively.

As of December 31, 2002, the Company has the ability to issue $100 million of additional long-term debt under the provisions of shelf registrations filed with the Securities and Exchange Commission.

The Company issued $200 million of notes on November 15, 2002 with a stated interest rate of 5.15% and a maturity date of November 15, 2012 to pay down commercial paper. In September 2002, the Company entered into interest rate swap agreements with a notional amount of $150 million to hedge the risk of movement in interest rates from the date of the swap agreements to the date of issuance of the long-term debt. On November 15, 2002, shortly after the issuance of the long-term debt, the Company terminated the swap agreements by remitting approximately $1.2 million to the counterparties to the agreements. As these swap agreements were designated at inception as being cash flow hedges and were deemed to be effective, the $1.2 million was included in accumulated other comprehensive income on the Consolidated Balance Sheets and will be reclassified to interest expense in the periods in which the Company's earnings are impacted by the hedged item. The Company estimates that approximately $0.1 million of the net unrealized losses related to the settlement of its interest rate swaps will be recognized in earnings during the next twelve months. The effective annual interest rate on the $200 million of notes is 5.30% after taking into consideration capitalized transaction costs and fees associated with the offering and the effect of the $150 million of interest rate swap agreements that were settled upon issuance of the long-term debt.

Interest expense on long-term debt amounted to $23.8 million in 2002, $23.3 million in 2001, and $23.8 million in 2000. Aggregate maturities of long-term debt are $24.3 million in 2003, $20.5 million in 2004, $10.0 million in 2005, $3.0 million in 2006, and $10.0 million in 2007.

During the first quarter of 2001, a Jamaican energy infrastructure project, a consolidated subsidiary, experienced defaults relating to various loan covenants. Consequently, the Company reclassified the nonrecourse project financing from long-term debt to current liabilities. The Company is currently working on various alternatives to refinance or restructure the debt or to pursue strategic alternatives for the potential transfer or sale of the Company's project interests. As this debt is nonrecourse to the Company, it is not included in the aggregate maturities of long-term debt stated above.

The indentures and other agreements governing the Company's indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company's ability to pay cash dividends, incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, sell assets, and certain other corporate actions. The covenants do not contain a rating trigger. Therefore, in the event that the Company's debt rating changes, this event would not trigger a default under the indentures and other agreements governing the Company's indebtedness.

In 2000, the Company entered into two prepaid natural gas sales contracts for 52.7 MMcf of reserves. The Company is required to sell and deliver certain quantities of natural gas during the term of the contracts. The first contract is for five years with net proceeds of $104.0 million. The second contract is for three years with net proceeds of $104.8 million and will be completed at the end of 2003. As such, these contracts were recorded as prepaid gas forward sales and are being recognized in income as deliveries occur.

As of December 31, 2002 and 2001, the outstanding prepaid gas forward sale was $97.3 million and $153.0 million, respectively, of which $55.7 million was current for both years.

In November 1995, the Company monetized certain Appalachian gas properties to a partnership, ABP, the production from which qualifies for the nonconventional fuels tax credit. The Company treated the proceeds from the deal as monetized production, and consequently recognized all of the activity from the partnership in the Company's Statements of Consolidated Income and reduced the deferred revenue balance established from the receipt of the proceeds by the cash payments made to

the other partners as production occurred. The Company also retained a partnership interest in the properties that increased substantially at the end of 2001 to 69% when a performance target was met. Consequently, beginning in 2002, the Company no longer includes ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold decreased by 8.9 Bcf during the year ended December 31, 2002, while equity production volumes increased by the same amount. Additionally, beginning January 1, 2002, the Company consolidated the partnership with the portion not owned by the Company recorded as a minority interest. The minority interest recognized for the year ended December 31, 2002 was $7.1 million and is included within minority interest other in the Statements of Consolidated Income. The minority interest expense includes additional expense to provide for items in dispute between the parties. The sales volumes attributed to the minority interest owners for the year ended December 31, 2002, was 2.7 Bcf. As of December 31, 2002 and 2001, the deferred revenue associated with ABP was $0 and $1.3 million, respectively, of which $0 and $1.3 million was current, respectively.

The Company's remaining deferred revenue balances relate mainly from billings in excess of costs and advance customer receipts for operating, maintenance, and pipeline contracts associated with the NORESCO and Utilities segments.

In April 1998, $125 million of 7.35% trust preferred capital securities were issued. The capital securities were issued through a subsidiary trust, Equitable Resources Capital Trust I, established for the purpose of issuing the capital securities and investing the proceeds in 7.35% Junior Subordinated Debentures issued by the Company. The capital securities have a mandatory redemption date of April 15, 2038; however, at the Company's option, the securities may be redeemed on or after April 23, 2003. Proceeds were used to reduce short-term debt outstanding. Interest expense for the years ended December 31, 2002 and 2001 includes $9.2 million of preferred dividends related to the trust preferred capital securities. The Company is currently evaluating this option and may exercise their option, given the proper economic circumstances.

The Company has defined benefit pension and other postretirement benefit plans covering union members that generally provide benefits of stated amounts for each year of service. Defined benefit plans covering certain salaried employees use a benefit formula, which is based upon employee compensation and years of service. All other employees are participants in a defined contribution profit sharing and savings plan.

The following table sets forth the defined benefit pension and other postretirement benefit plans' funded status and amounts recognized for those plans in the Company's Consolidated Balance Sheets:

The pension liability of $9.4 million and $4.1 million as of December 31, 2002 and 2001, respectively, is included in other long-term liabilities. The accrued liability for other postretirement benefits of $15.7 million and $15.6 million as of December 31, 2002 and 2001, respectively, is also included in other long-term liabilities.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $112.7 million, $112.4 million, and $57.1 million, respectively, as of December 31, 2002, and were $113.7 million, $112.8 million, and $82.6 million, respectively, as of December 31, 2001.

The Company's costs related to its defined benefit pension and other benefit plans were as follows:

			Pension Benefits									Other Benefits
			2002			2001			2000			2002			2001			2000
			(Thousands)
Components of net periodic benefit cost:
	Service cost		$	2,557		$	2,488		$	2,634		$	380		$	262		$	290
	Interest cost			8,102			8,815			9,335			3,465			3,460			3,297
	Expected return on plan assets			(9,711	)		(11,061	)		(12,893	)		—			(205	)		(545	)
	Amortization of prior service cost			1,281			1,677			1,783			(3	)		(3	)		(145	)
	Amortization of initial net (asset) obligation			—			(122	)		(265	)		674			683			956
	Recognized net actuarial (gain) loss			21			16			(29	)		1,239			954			979
	Special termination benefits			81			2,394			10,629			—			49			1,169
	Settlement (gain) loss			3,036			2,016			(3,143	)		—			—			—
	Curtailment loss			—			209			1,105			—			879			2,425

		Net periodic benefit cost	$	5,367		$	6,432		$	9,156		$	5,755		$	6,079		$	8,426

The following weighted average assumptions were used to determine the benefit obligations and net periodic benefit cost for the Company's defined benefit pension and other post retirement benefit plans.

	Pension Benefits				Other Benefits
	2002		2001		2002		2001
Discount rate	7.00	%	7.50	%	7.00	%	7.50	%
Expected return on plan assets	9.75	%	10.00	%	9.75	%	10.00	%
Rate of compensation increase	4.50	%	4.50	%	4.50	%	4.50	%

The expected rate of return and the rate of compensation increase are established at the beginning of the fiscal year that they relate to based upon information available to the Company at that time, including the Plans' investment mix and the forecasted rates of return on these types of securities. The plans' investment mix as of January 1, 2003, 2002 and 2001 approximated 60% equities and 40% fixed income securities. Any differences between actual experience and assumed experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company's net periodic benefit cost in accordance with SFAS No. 87, "Employers' Accounting for Pensions." The expected rate of return and the rate of compensation increase determined as of January 1, 2003 totaled 8.75% and 4.50%, respectively. These assumptions will be used to derive the Company's 2003 net periodic benefit cost.

For measurement purposes, the annual rates of increase in the per capita cost of covered health care benefits in 2003 for the Pre-65 and Post-65 medical charges are 9.75% and 11.75%, respectively. The rates were assumed to decrease gradually to ultimate rates of 4.50% in 2008 and 2009, respectively.

Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Expense recognized by the Company related to its 401(k) employee savings plans totaled $3.2 million in 2002, $2.9 million in 2001 and $2.8 million in 2000.

At December 31, 2002, shares of Equitable's authorized and unissued common stock were reserved as follows:

The computation of basic and diluted earnings per common share from continuing operations is shown in the table below:

The components of accumulated other comprehensive (loss) income are as follows net of tax:

	2002			2001
	(Thousands)
Cumulative effect of FAS 133 adoption	$	—		$	(37,023	)
Net unrealized gain from hedging transactions		1,617			139,468
Unrealized loss on available-for-sale securities		(1,494	)		—
Minimum pension liability adjustment		(24,663	)		(11,072	)
Foreign currency translation adjustment		7			7

	$	(24,533	)	$	91,380

The Company's 1994 and 1999 Long-Term Incentive Plans (the Plans) provide for the granting of shares of common stock to officers and key employees of the Company. These grants may be made in the form of stock options, restricted stock, stock appreciation rights and other types of stock-based or performance-based awards as determined by the Compensation Committee of the Board of Directors at the time of each grant. Stock awarded under the Plans, or purchased through the exercise of options, and the value of stock appreciation units are restricted and subject to forfeiture should an optionee terminate employment prior to specified vesting dates. In no case may the number of shares granted under the Plans exceed 3,451,000 and 11,000,000 shares, respectively. Options granted under the Plans expire 5 to 10 years from the date of grant and some contain vesting provisions, which are based upon the Company's performance.

Also reflected in the option tables below are options assumed in conjunction with the NORESCO acquisition in July 1997. All outstanding options granted under NORESCO's 1990 Incentive Stock Option Plan were converted by Equitable to nonqualified stock options with the right to receive, upon exercise of the option, the same Equitable stock and cash that shareholders of NORESCO received in the acquisition. As a result of this conversion, 872,000 NORESCO stock options were converted to 512,800 Equitable stock options with the exercise price per share proportionately adjusted. The adjusted exercise prices of these stock options range from $2.55 to $2.98 per share. The acquisition also accelerated the vesting period of these options, the latest of which expire in 2006. During 2002, 2,156 stock options were exercised under this plan, with none outstanding at December 31, 2002.

Pro forma information regarding net income and earnings per share for options granted is required by Statement No. 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of Statement No. 123. The fair value for these option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the following assumptions for 2002, 2001, and 2000, respectively.

Had compensation cost for these options been determined in accordance with Statement No. 123, the Company's net income and diluted earnings per share would have been $146.0 million, or $2.28 per share in 2002, $145.1 million or $2.20 per share in 2001, and $103.4 million or $1.56 per share in 2000.

	Years Ended December 31,
	2002		2001		2000
Options outstanding January 1	6,068,464		5,204,622		3,379,126
Granted	1,547,146		1,694,821		3,122,740
Forfeitures	(205,047	)	(343,851	)	(643,438	)
Exercised	(1,244,559	)	(487,128	)	(653,806	)

Options outstanding December 31	6,166,004		6,068,464		5,204,622

Options outstanding at December 31, 2002 include 2,851,920 exercisable at that date and are summarized in the following table.

On March 12, 2002, the Company granted 143,000 stock awards from the 1999 Long-Term Incentive Plan for the 2002 Executive Performance Incentive Program. The 2002 Plan was established to provide additional incentive benefits to retain senior executive employees of the Company and to further align the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of these awards will occur on March 12, 2005 and is contingent upon the attainment of certain performance measures and will result in a range of zero to 286,000 shares (200% of the award) being awarded. The Company anticipates, based on current estimates, that the performance measures will be met and has expensed a ratable estimate of the award accordingly. The expense for the period ended December 31, 2002 was $6.0 million, and is classified as selling, general and administrative expense.

On September 5, 1997, the Company granted 212,254 stock awards from the 1994 Long-Term Incentive Plan for the Executive Retention Program. This program was established to provide additional incentive benefits to retain senior executive employees of the Company. The vesting of these awards was contingent on attainment of specific stock price targets, which were met on January 1, 2001, and accordingly, the shares were distributed to the participants at that time. In 2002, 2001, and 2000, the Company granted 116,300, 4,000, and 176,000 additional stock awards, respectively, to key executives from the 1999 Long-Term Incentive Plan. The weighted average fair value of these restricted stock grants is $32.92, $36.99, and $20.07, respectively, for 2002, 2001, and 2000. The shares granted under these plans will be fully vested at the end of a three-year period from the date of grant. Compensation expense recorded by the Company related to stock awards was $3.2 million in 2002, $2.3 million in 2001, and $14.1 million in 2000.

The Company's 1994 and 1999 Nonemployee Directors' Stock Incentive Plans provide for the granting of up to 160,000 and 600,000 shares, respectively, of common stock in the form of stock option grants and restricted stock awards to nonemployee directors of the Company. The exercise price for each share is equal to market price of the common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant. At December 31, 2002, 238,600 options were outstanding at prices ranging from $14.19 to $39.13 per share, and 113,200 options had been exercised under these plans since the plan inception.

The carrying value of cash and cash equivalents, as well as short-term loans, approximates fair value due to the short maturity of the instruments. The fair value of the available-for-sale securities are estimated based on quoted market prices for those investments.

The estimated fair value of long-term debt described in Note 14 at December 31, 2002 and 2001 is $521.8 million and $302.5 million, respectively. The fair value was estimated based on discounted values using a current discount rate reflective of the remaining maturity.

The estimated fair value of liabilities for derivative commodity instruments described in Note 3, excluding trading activities which are marked-to-market, was a $30.9 million asset and a $25.0 million liability at December 31, 2002 and a $157.6 million asset at December 31, 2001.

Revenues and related accounts receivable from the Equitable Supply segment's operations are generated primarily from the sale of produced natural gas to certain marketers, Equitable Energy, other Appalachian Basin purchasers, and utility and industrial customers located mainly in the Appalachian area, the sale of produced natural gas liquids to a refinery customer in Kentucky and gathering of natural gas in Kentucky, Virginia, Ohio, Pennsylvania and West Virginia.

The Equitable Utilities Distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to more than 275,000 residential, commercial and industrial customers located in southwest Pennsylvania and parts of West Virginia and Kentucky. The Pipeline operations include FERC-regulated interstate pipeline transportation and storage service for the affiliated utility, Equitable Gas, as well as other utility and end-user customers located in the Appalachian and mid-Atlantic regions. The unregulated Marketing operation provides natural gas operations commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial, institutional and certain marketers primarily in the Appalachian and mid-Atlantic regions. Under state regulations, the Utility is required to provide continuous natural gas service to residential customers during the winter heating season.

Approximately 40% and 32% of the Company's accounts receivable balance as of December 31, 2002 and 2001, respectively, represents amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers who meet the Company's criteria for credit and liquidity strength and by proactively monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company's credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2002, and 2001.

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. NYMEX traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative contracts by limiting dealings to those counterparties who meet the Company's criteria for credit and liquidity strength.

The NORESCO segment's operating revenues and related accounts receivable are generated from performance contracts with federal, state, and local government, institutional customers throughout the United States and cogeneration and power plant facilities in several U.S. and Latin American markets.

The Company is not aware of any significant credit risks that have not been recognized in provisions for doubtful accounts.

The Company has annual commitments of approximately $24.1 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 6 years as of December 31, 2002, which relate to natural gas distribution and production operations. However, approximately $19.1 million of these costs are recoverable in customer rates.

There are various other claims and legal proceedings against the Company arising from the normal course of business. Although counsel is unable to predict with certainty the ultimate outcome, management and counsel believe that the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously. Management has provided adequate reserves and therefore believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company although they could be material to the reported results of operations for the period in which they occur. The reserves recorded by the Company do not include any amounts for legal costs expected to be incurred. It is the Company's policy to recognize any legal costs associated with any claims and legal proceedings against the Company's continuing operations as they are incurred.

In July 2002, the Environmental Protection Agency published a final rule that amends the Oil Pollution Prevention Regulation. The effective date of the rule was August 16, 2002. Under the final rule Owners/Operators of existing facilities were to revise their Spill Prevention Control and Countermeasure Plans on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003. On January 9, 2003, EPA extended the compliance deadlines for plan amendment and implementation for 60 days with a proposed rule to extend the dates for one year and possibly longer. Management is currently evaluating the impact of this final rule on the Company.

operations. The Company has identified situations that require remedial action for which approximately $6.1 million is included in other long-term liabilities at December 31, 2002.

In June 2000, Equitable sold properties with reserves of approximately 66.0 Bcfe, the production from which qualified for nonconventional fuels tax credits. As part of that transaction, Equitable, through its subsidiary, ERI Investments, Inc., guaranteed a tax indemnification to the buyer for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company will guarantee the tax indemnification until the tax statute of limitations closes. As of December 31, 2002, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $23 million. As of December 31, 2002, the Company has not recorded a liability for this guarantee, as the Company currently believes that the likelihood of making any payment under the guarantee is remote. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover any of the amounts paid under the guarantee.

In November 1995, the Company monetized Appalachian gas properties to a partnership, ABP, the production from which qualifies for nonconventional fuels tax credits. As part of that transaction, Equitable, through its subsidiary, ERI Investments, Inc., guaranteed a tax indemnification to the limited partners for any potential tax losses resulting from a disallowance of the nonconventional fuels tax credits, if certain representations and warranties of the Company were not true. The Company will guarantee the tax indemnification until the tax statute of limitation closes. As of December 31, 2002, the maximum potential amount of future payments the Company could be required to make is estimated to be approximately $45 million. As of December 31, 2002, the Company has not recorded a liability for this guarantee, as the Company currently believes that the likelihood of making any payment under the guarantee is remote. The Company does not have any recourse provisions with third parties or any collateral held by third parties associated with this guarantee that could be liquidated to recover any of the amounts paid under the guarantee.

The Company currently has a 1% equity interest in ANGT. ANGT was formed through a $36.2 million cash contribution from the Company and a $261.5 million cash contribution from ANPI. The total proceeds received by ANGT of $297.7 million were used to purchase a net profits interest in certain properties of the Company's Supply segment. ANPI's contribution to ANGT was funded by $10.0 million in cash capital contributions from its owners (institutional investors) and $251.5 million in proceeds from a debt issuance. The assets of ANPI, including its interest in ANGT, collateralize ANPI's debt. The Company has contracted for a market based fee, subject to certain restrictions and limitations, a liquidity reserve guarantee with ANPI secured by the fair market value of the assets purchased by ANGT. As of December 31, 2002, the maximum potential amount of future payments the Company could be required to make under the liquidity reserve guarantee is estimated to be $18.0 million. As of December 31, 2002, the Company has not recorded a liability for this guarantee, as the Company currently believes that the likelihood of making any payment under the guarantee is remote.

The following quarterly summary of operating results reflects variations due primarily to the seasonal nature of the Company's utility business and volatility of natural gas and oil commodity prices:

The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Supply segment in accordance with SFAS No. 69, "Disclosures About Oil and Natural Gas Producing Activities."

The Company information presented for 2000 excludes data associated with reserves that were combined with Westport or sold in 2000 and are now included in the Company's nonconsolidated investments. Information about the natural gas and oil producing activities of these nonconsolidated investments is disclosed separately in this footnote and is calculated based on the Company's proportionate ownership interest percentage.

The following table presents the costs incurred relating to natural gas and oil production activities:

The following table presents the results of operations related to natural gas and oil production.

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers, which was reviewed by the independent consulting firm of Ryder Scott Company LP. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred. All of the Company's proved reserves are in the United States.

In December 2001, the Company sold reserves associated with its Kentucky oil fields totaling 68 billion cubic feet equivalent. The Company sold reserves in the April 2000 Westport merger, and interests in producing properties in the June 2000 and December 2000 sale transactions. In February 2000, the Company purchased reserves in conjunction with the Statoil acquisition. Revisions of previous estimates are mainly due to pricing changes. Increased prices from 2001 to 2002 resulted in

an upward revision of 17 Bcf and decreased prices from 2000 to 2001 resulted in a downward revision of 60 Bcf.

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at

an arbitrary rate of 10%. Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:

Summary of changes in the standardized measure of discounted future net cash flows:

The following tables present information about the natural gas and oil producing activities of the Company's nonconsolidated investments.

Standard Measure of Discounted Future Cash Flow of Nonconsolidated Investments

recognition to future changes in estimated reserves, selling prices or costs and has been discounted at an arbitrary rate of 10%. Estimated future net cash flows from natural gas and oil reserves based on selling prices and costs at year-end price levels are as follows:

In February 2003, the Company purchased the remaining 31% limited partner interest in Appalachian Basin Partners, LP from the minority interest holders for $44.2 million. The limited partner interest represents approximately 60.2 Bcf of reserves in approximately 1,000 wells that have been operated by the Company since their drilling date. In addition, all open disputes with the minority interest holders were resolved. Effective February 1, 2003, ABP will be fully consolidated in the Company's financial statements with no recognition of minority interest, which was $7.1 million in 2002, in the Statement of Consolidated Income. All sales volumes will be attributed to the Company.

In February 2003, the Company issued $200 million of notes with a stated interest rate of 5.15% and a maturity date of March 2018. The proceeds from the issuance will be used for relieving long-term obligations and general corporate purposes.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Information required by Item 10 with respect to directors is incorporated herein by reference from the section captioned "Election of Directors" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 15, 2003, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002.

Information required by Item 10 with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference from the section captioned "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 15, 2003, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002.

Information required by Item 10 with respect to executive officers is included herein after Item 4 at the end of Part I under the heading "Executive Officers of the Registrant," and is incorporated herein by reference.

The information required by Item 405 of Regulation S-K with respect to compliance with Section 16(a) of the Securities Exchange Act of 1984, as amended, is incorporated herein by reference from the section captioned "Compliance with Section 16(a) Reporting," in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 15, 2003, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002.

Except for the sub-sections headed, "Stock Performance Graph", "Compensation Committee Report on Executive Compensation", and "Audit Committee Report", in the Company's definitive proxy statement, information required by Item 11 is incorporated herein by reference from the sections describing "Executive Compensation," "Employment Change-In-Control Arrangements and Non-Competition Agreements" and "Pension Plan" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 15, 2003, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002.

Information required by Item 12 is incorporated herein by reference to the section describing "Voting Securities and Record Date" in the Company's definitive proxy statement relating to the annual meeting of stockholders to be held on May 15, 2003, which will be filed with the Commission within 120 days after the close of the Company's fiscal year ended December 31, 2002.

Within the 90 days prior to the date of this Annual Report on Form 10-K, the Company evaluated the effectiveness of the design and operation of its "disclosure controls and procedures" (Disclosure Controls), and its "internal controls and procedures for financial reporting" (Internal Controls). This evaluation (the Controls Evaluation) was done under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules

adopted by the SEC require that in this section of the Annual Report we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls and Internal Controls based on and as of the date of the Controls Evaluation.

Appearing immediately after the Signatures section of this Annual Report are two separate forms of "Certifications" of the CEO and the CFO. The first form of Certification is required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the Section 302 Certification). This section of the Annual Report contains the information concerning the Controls Evaluation referred to in the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's (SEC) rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Internal Controls are procedures which are designed with the objective of providing reasonable assurance that (1) our transactions are properly authorized; (2) assets are safeguarded against unauthorized or improper use; and (3) our transactions are properly recorded and reported, all to permit the preparation of our financial statements in conformity with accounting principles generally accepted in the United States.

The Company's management, including the CEO and CFO, does not expect that the Disclosure Controls or our Internal Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, control may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

The CEO/CFO evaluation of our Disclosure Controls and Internal Controls included a review of the controls' objectives and design, the implementation by the Company and the effect of the controls on the information generated for use in this Annual Report. In the course of the Controls Evaluation, management sought to identify data errors, controls problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of

evaluation will be done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in Quarterly Reports on Form 10-Q and Annual Report on Form 10-K. The Internal Controls are also evaluated on an ongoing basis by the Company's internal auditors, other personnel in the Finance organization and by the independent auditors in connection with their audit and review activities. The overall goals of these various evaluation activities are to monitor Disclosure Controls and with the Internal Controls and to make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls be maintained as dynamic systems that change (including both improvements and corrections) as conditions warrant.

Among other matters, the Company sought in our evaluation to determine whether there were any "significant deficiencies" or "material weaknesses" in the Company's Internal Controls, or whether the Company had identified any acts of fraud involving personnel who have a significant role in the Company's Internal Controls. This information was important both for the Controls Evaluation generally and because items 5 and 6 in the Section 302 Certifications of the CEO and CFO require that the CEO and CFO disclose that information to the Board's Audit Committee and to the independent auditors and to report on related matters in this section of the Annual Report. In the professional auditing literature, "significant deficiencies" are referred to as "reportable conditions"; these are control issues that could have a significant adverse effect on the ability to record, process, summarize and report financial data in the financial statements. A "material weakness" is defined in the auditing literature as a particularly serious reportable condition where the internal control does not reduce to a relatively low level the risk that misstatements caused by error or fraud may occur in amounts that would be material in relation to the financial statements and not be detected within a timely period by employees in the normal course of performing their assigned functions. Management also sought to deal with other controls issues in the Controls Evaluation, and in each case if a problem was identified, to consider whether to make any revision, improvement and/or correction.

In accordance with SEC requirements, the CEO and CFO note that, since the date of the Controls Evaluation to the date of this Annual Report, there have been no significant changes in Internal Controls or in other factors that could significantly affect Internal Controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Based upon the Controls Evaluation, the CEO and CFO have concluded that, subject to the limitations noted above, the Disclosure Controls are effective to ensure that material information relating to Equitable Resources and its consolidated subsidiaries is made known to management, including the CEO and CFO, particularly during the period when our periodic reports are being prepared, and that our Internal Controls are effective to provide reasonable assurance that the Company's financial statements are fairly presented in conformity with generally accepted accounting principles.

EQUITABLE RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS COVERED
BY REPORT OF INDEPENDENT AUDITORS

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2002

The Company agrees to furnish to the Commission, upon request, copies of instruments with respect to long-term debt, which have not previously been filed.

Each management contract and compensatory arrangement in which any director or any named executive officer participates has been marked with an asterisk (*).

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.

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

In connection with the Annual Report of Equitable Resources, Inc. (the "Company") on Form 10-K for the period ending December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

PENNSYLVANIA (State or other jurisdiction of incorporation or organization)		25-0464690 (IRS Employer Identification No.)
One Oxford Centre, Suite 3300 Pittsburgh, Pennsylvania (Address of principal executive offices)		15219 (Zip Code)

Name and Age	Title	Business Experience
John A. Bergonzi (50)	Vice President and Corporate Controller (Effective January 1, 2003)	Elected to present position October 17, 2002; Corporate Controller and Assistant Treasurer from 1997.
Arthur G. Cantrell (45)	Vice President (Effective January 1, 2003)	Elected to present position October 17, 2002; Elected to President, Equitrans, LP (effective January 1, 2003) October 17, 2002; Executive Vice President, Equitable Utilities from November 16, 2000; Vice President, Equitable Utilities from August 16, 1999; Director of Business Development, Equitable Utilities from August 1, 1998.

Philip P. Conti (43)	Vice President, Finance and Treasurer	Elected to present position August 21, 2000; Director of Planning and Development from June 1, 1998, Assistant Treasurer—Finance from January 19, 1996.
Randall L. Crawford (40)	Vice President (Effective January 1, 2003)	Elected to present position October 17, 2002; Elected to President, Equitable Gas Company, LP (effective January 1, 2003) October 17, 2002; Executive Vice President, Equitable Gas Company from November 16, 2000; Senior Vice President, Equitable Gas Company from December 27, 1999; Vice President, Equitable Gas Company from April 4, 1998.
James M. Funk (53)	Senior Vice President	Elected to present position July 19, 2000; President, Equitable Production Company from June 12, 2000; President, J.M. Funk & Associates, Inc. from January 1999; President, Shell Continental Companies from January 1998; President and Chief Executive Officer, Shell Midstream Enterprises, Inc. from April 1996.
Murry S. Gerber (50)	Chairman, President and Chief Executive Officer	Elected to present position May 30, 2000; President and Chief Executive Officer from June 1, 1998; Chief Executive Officer, Coral Energy, Houston, TX, from November 1995.
Joseph E. O'Brien (50)	Vice President	Elected to present position January 18, 2001; President, Northeast Energy Services, Inc. from January 17, 2000; Senior Vice President, Construction & Engineering from June 14, 1993.

Johanna G. O'Loughlin (56)	Senior Vice President, General Counsel and Secretary	Elected to present position January 17, 2002; Vice President, General Counsel and Secretary from May 26, 1999; Vice President and General Counsel from December 19, 1996.
Charlene Petrelli (41)	Vice President, Human Resources (Effective January 1, 2003)	Elected to present position October 17, 2002; Director of Corporate Human Resources from October 23, 2000; Director of Human Resources, Fisher Scientific International, Inc. from December 1999; Senior Manager Human Resources, Merck & Co, Inc. from March 1998.
David L. Porges (45)	Executive Vice President and Chief Financial Officer	Elected to present position February 1, 2000; Senior Vice President and Chief Financial Officer from July 1, 1998; Managing Director, Bankers Trust Corporation, Houston, TX, and New York, NY, from December 1992.
Gregory R. Spencer (54)	Senior Vice President and Chief Administrative Officer	Elected to present position May 23, 1996.

PART I
Item 1	Business	4
Item 2	Properties	11
Item 3	Legal Proceedings	12
Item 4	Submission of Matters to a Vote of Security Holders	13
	Executive Officers of the Registrant	13
PART II
Item 5	Market for Registrant's Common Equity and Related Stockholder Matters	16
Item 6	Selected Financial Data	17
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A	Qualitative and Quantitative Disclosures About Market Risk	50
Item 8	Financial Statements and Supplementary Data	52
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95
PART III
Item 10	Directors and Executive Officers of the Registrant	96
Item 11	Executive Compensation	96
Item 12	Security Ownership of Certain Beneficial Owners and Management	96
Item 13	Certain Relationships and Related Transactions	96
Item 14	Controls and Procedures	96
PART IV
Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8-K	99
	Index to Financial Statements Covered by Report of Independent Auditors	99
	Index to Exhibits	101
	Signatures	107
	Certifications	108

		2002		2001		2000
Equitable Utilities:
	Residential natural gas sales	21	%	25	%	24	%
	Marketed natural gas	17		25		22
Equitable Supply:
	Produced natural gas equivalents	14		19		22
	Gathering	6		5		5
NORESCO:
	Energy service contracting	18		14		13

		2002	2001	2000
Exploratory wells:
	Productive	—	—	—
	Dry	—	—	1.0
Development wells:
	Productive	338.4	293.5	284.6
	Dry	1.0	—	2.0

	2002						2001
	High		Low		Dividend		High		Low		Dividend
1st Quarter	$	35.67	$	29.32	$	0.160	$	35.25	$	27.69	$	0.148
2nd Quarter		37.55		33.54		0.170		40.50		31.80		0.160
3rd Quarter		36.49		28.67		0.170		36.60		26.00		0.160
4th Quarter		36.89		32.09		0.170		34.69		29.15		0.160

	(I)	(II)		(III)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants, and rights	Weighted- average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under plans (excluding securities listed in column (I))
Equity compensation plans approved by share holders	6,536,805	$	25.0812	4,418,607
Equity compensation plans not approved by share holders	—		—	—

Total	6,536,805	$	25.0812	4,418,607

		2002		2001		2000		1999		1998
		(Thousands except per share amounts)
Operating revenues(a)		$	1,069,068	$	1,109,334	$	1,036,531	$	844,625	$	830,986

Net income (loss) from continuing operations before cumulative effect of accounting change(b)		$	150,626	$	151,808	$	106,173	$	69,130	$	(27,052	)

Net income (loss) from continuing operations before cumulative effect of accounting change per common share:
	Basic	$	2.40	$	2.36	$	1.63	$	1.02	$	(0.37	)

	Diluted	$	2.36	$	2.30	$	1.60	$	1.01	$	(0.37	)

Total assets		$	2,436,891	$	2,518,747	$	2,424,914	$	1,789,574	$	1,860,856
Long-term debt		$	471,250	$	271,250	$	287,789	$	298,350	$	281,350
Preferred trust securities		$	125,000	$	125,000	$	125,000	$	125,000	$	125,000
Cash dividends paid per share of common stock		$	0.67	$	0.63	$	0.59	$	0.59	$	0.59

		2000
FINANCIAL DATA (Thousands)
Revenue from Production		$	16,885
	Other revenues		70

	Total revenues		16,955
Gathering and compression expense			17
Lease operating expense			1,454
Depreciation, depletion and amortization			6,891
Selling, general and administrative expense			1,643
Exploration and dry hole expense			524

	Total operating expenses	$	10,529

	Operating income	$	6,426

	Total		2003		2004-2005		2006-2007		2008+
	(Thousands)
Interest expense	$	778,010	$	40,983	$	77,876	$	75,741	$	583,410
Long-term debt		487,305		40,305		30,500		13,000		403,500
Preferred trust securities		125,000		—		—		—		125,000
Unconditional purchase obligations		222,278		30,931		58,136		55,501		77,710

Total contractual cash obligations	$	1,612,593	$	112,219	$	166,512	$	144,242	$	1,189,620

			2002			2001		2000
			(Thousands except per share amounts)
Operating revenues			$	1,069,068		$	1,109,334	$	1,036,531
Cost of sales				506,363			541,726		459,580

	Net operating revenues			562,705			567,608		576,951

Operating expenses:
	Operation and maintenance			73,430			80,607		103,020
	Production and exploration			27,111			34,500		45,870
	Selling, general and administrative			109,825			124,743		116,050
	Impairment of long-lived assets			5,320			—		—
	Depreciation, depletion and amortization			69,448			73,230		97,777

		Total operating expenses		285,134			313,080		362,717

Operating income				277,571			254,528		214,234
Equity in (losses) earnings of nonconsolidated investments and minority interest				(10,566	)		26,101		25,161
Gain on sale of Westport stock				—			—		6,561
Other loss				—			—		(6,951	)

Earnings before interest & taxes				267,005			280,629		239,005
Interest expense				38,787			41,098		75,661

Income from continuing operations before income taxes and cumulative effect of accounting change				228,218			239,531		163,344
Income taxes				77,592			87,723		57,171

Income from continuing operations before cumulative effect of accounting change				150,626			151,808		106,173

Income from discontinued operations				9,000			—		—
Cumulative effect of accounting change, net of tax				(5,519	)		—		—

Net income			$	154,107		$	151,808	$	106,173

Earnings per share of common stock:
Basic:
	Income from continuing operations before cumulative effect of accounting change		$	2.40		$	2.36	$	1.63
	Income for discontinued operations			0.14			—		—
	Cumulative effect of accounting change, net of tax			(0.09	)		—		—

	Net Income		$	2.45		$	2.36	$	1.63
Diluted:
	Income from continuing operations before cumulative effect of accounting change		$	2.36		$	2.30	$	1.60
	Income from discontinued operations			0.14			—		—
	Cumulative effect of accounting change, net of tax			(0.09	)		—		—

	Net Income		$	2.41		$	2.30	$	1.60

						2002			2001			2000
						(Thousands)
Cash flows from operating activities:
	Net income from continuing operations before cumulative effect of accounting change					$	150,626		$	151,808		$	106,173

	Adjustments to reconcile net income to net cash provided by operating activities:
		Provision for losses on accounts receivable					8,564			14,866			12,129
		Depreciation, depletion and amortization					69,448			73,230			97,777
		Impairment of assets					5,320			—			—
		Amortization of construction contract costs					3,392			1,811			1,229
		Recognition of monetized production revenue					(55,705	)		(84,453	)		(13,715	)
		Deferred income taxes					42,869			62,340			54,519
		Change in undistributed earnings from nonconsolidated investments					3,463			(22,248	)		(23,632	)
		Minority interest					7,103			—			—
		Gain on sale of investment					—			—			(6,561	)
		Changes in other assets and liabilities:
			Accounts receivable and unbilled revenues				(89,860	)		155,860			(183,654	)
			Inventory				21,710			(11,199	)		(35,853	)
			Prepaid expenses and other				12,938			13,824			(27,858	)
			Accounts payable				34,824			(184,069	)		199,843
			Prepaid gas forward sale				—			—			209,294
			Other—net				(1,675	)		(41,901	)		(28,538	)

				Total adjustments			62,391			(21,939	)		254,980

					Net cash provided by operating activities		213,017			129,869			361,153

Cash flows from investing activities:
	Capital expenditures						(218,494	)		(132,679	)		(123,727	)
	Acquisition of Statoil production assets						—			—			(677,235	)
	Proceeds from Gulf asset merger						—			—			158,214
	Proceeds from sale of interest in producing properties						—			—			382,942
	Investment in available-for-sale securities						(17,592	)		—			—
	Unrealized loss on available for sale securities						1,494			—			—
	Change in equity in nonconsolidated investments						3,970			(314	)		(181,757	)
	Proceeds from sale of equity in nonconsolidated investments						—			—			19,875
	Proceeds from sale of receivables						—			1,130			56,553
	Proceeds from sale of property						—			69,058			2,127
	Restricted cash from oil-dominated field sale						62,956			(62,956	)		—

					Net cash used in investing activities		(167,666	)		(125,761	)		(363,008	)

Cash flows from financing activities:
	Dividends paid						(41,809	)		(40,356	)		(38,490	)
	Purchase of treasury stock						(97,028	)		(61,203	)		(29,483	)
	Proceeds from exercises under employee compensation plans						28,485			6,855			9,039
	Loans against construction contracts						23,215			105,420			—
	Proceeds from issuance of long-term debt						200,000			—			—
	Repayments and retirements of long-term debt						(641	)		(10,405	)		—
	(Decrease) increase in short-term loans						(169,447	)		(26,820	)		94,781

					Net cash (used in) provided by financing activities		(57,225	)		(26,509	)		35,847

	Net (decrease) increase in cash and cash equivalents						(11,874	)		(22,401	)		33,992
	Cash and cash equivalents at beginning of year						29,622			52,023			18,031

	Cash and cash equivalents at end of year					$	17,748		$	29,622		$	52,023

	Cash paid during the year for:
		Interest (net of amount capitalized)				$	40,154		$	40,258		$	81,023

		Income taxes				$	18,941		$	15,396		$	11,711

				2002		2001
				(Thousands)
Assets
Current assets:
	Cash and cash equivalents			$	17,748	$	29,622
	Restricted cash				—		62,956
	Accounts receivable (less accumulated provision for doubtful accounts: 2002, $15,294; 2001, $14,807)				160,778		132,750
	Unbilled revenues				130,348		77,080
	Inventory				74,735		96,445
	Derivative commodity instruments, at fair value				38,512		193,623
	Prepaid expenses and other				7,930		20,868

		Total current assets			430,051		613,344

Equity in nonconsolidated investments					245,792		253,214

Property, plant and equipment:
	Equitable Utilities				994,311		979,235
	Equitable Supply				1,529,915		1,333,702
	NORESCO				20,912		24,407

		Total property, plant and equipment			2,545,138		2,337,344
	Less: accumulated depreciation and depletion				983,323		923,067

		Net property, plant and equipment			1,561,815		1,414,277

Investments, available-for-sale					16,098		—

Other assets:
	Regulatory assets				79,611		80,225
	Goodwill				51,656		57,364
	Long term receivables				7,606		49,577
	Other				44,262		50,746

		Total other assets			183,135		237,912

			Total	$	2,436,891	$	2,518,747

				2002			2001
				(Thousands)
Liabilities and Common Stockholders' Equity
Current liabilities:
	Current portion of long-term debt			$	24,250		$	—
	Current portion of nonrecourse project financing				16,055			16,696
	Short-term loans				106,000			275,447
	Accounts payable				136,478			101,654
	Prepaid gas forward sale				55,705			55,705
	Derivative commodity instruments, at fair value				46,768			62,002
	Current portion of project financing obligations				73,032			48,802
	Other current liabilities				93,452			100,686

		Total current liabilities			551,740			660,992

Long-term debt:
	Debentures and medium-term notes				447,000			271,250

		Total long-term debt			447,000			271,250
Deferred and other credits:
	Deferred income taxes				350,690			364,633
	Deferred investment tax credits				13,210			14,336
	Prepaid gas forward sale				41,591			97,296
	Project financing obligations				13,684			60,407
	Other credits				115,337			78,679

		Total deferred and other credits			534,512			615,351
Commitments and contingencies					—			—
Preferred trust securities					125,000			125,000
Common stockholders' equity:
	Common stock, no par value, authorized 160,000 shares; shares issued: 2002 and 2001, 74,504				287,597			282,920
	Treasury stock, shares at cost: 2002, 12,162; 2001, 10,634 (net of shares and cost held in trust for deferred compensation of 642, $12,273 and 362, $6,284)				(271,930	)		(203,353	)
	Retained earnings				787,505			675,207
	Accumulated other comprehensive (loss) income				(24,533	)		91,380

		Total common stockholders' equity			778,639			846,154

			Total	$	2,436,891		$	2,518,747

				Common Stock
				Shares Outstanding		No Par Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Common Stockholders' Equity
				(Thousands)
Balance, December 31, 1999				65,458		$	146,704		$	496,072		$	34		$	642,810
	Comprehensive income:
		Net income								106,173						106,173
		Foreign currency translation											(27	)		(27	)

			Total comprehensive income													106,146
	Dividends ($0.59 per share)									(38,490	)					(38,490	)
	Stock issued:
		Stock-based compensation plans		798			12,712									12,712
	Stock repurchases			(1,178	)		(29,483	)								(29,483	)

Balance, December 31, 2000				65,078			129,933			563,755			7			693,695
	Comprehensive income:
		Net income								151,808						151,808
		Cumulative effect of SFAS No. 133 adoption											(37,023	)		(37,023	)
		Net change in natural gas cash flow hedges											139,468			139,468
		Minimum pension liability adjustment											(11,072	)		(11,072	)

			Total comprehensive income													243,181
	Dividends ($0.63 per share)									(40,356	)					(40,356	)
	Stock issued:
		Stock-based compensation plans		576			10,837									10,837
	Stock repurchases			(1,784	)		(61,203	)								(61,203	)

Balance, December 31, 2001				63,870			79,567			675,207			91,380			846,154

	Comprehensive income:
		Net income								154,107						154,107
		Net change in cash flow hedges:
			Natural gas										(99,678	)		(99,678	)
			Interest rate										(1,150	)		(1,150	)
		Unrealized loss on available-for-sale securities											(1,494	)		(1,494	)
		Minimum pension liability adjustment											(13,591	)		(13,591	)

			Total comprehensive income													38,194
	Dividends ($0.67 per share)									(41,809	)					(41,809	)
	Stock issued:
		Stock-based compensation plans		1,378			33,128									33,128
	Stock repurchases			(2,906	)		(97,028	)								(97,028	)

Balance, December 31, 2002				62,342		$	15,667		$	787,505		$	(24,533	)	$	778,639

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)
Prices actively quoted (NYMEX)(1)	$	4,442		$	(1,055	)	$	71		$	—	$	3,458
Prices provided by other external sources(2)		4,538			1,496			1,067			—		7,101
Prices based on models and other valuation methods(3)		(489	)		(2,100	)		(1,347	)		—		(3,936	)

Net derivative (liabilities) assets	$	8,491		$	(1,659	)	$	(209	)	$	—	$	6,623

					December 31,
Investees					December 31,
Investees		Location	Ownership		2002		2001
					(Thousands)
Eastern Seven Partners, L.P.		USA	1	%	$	26,136	$	26,198
Appalachian Natural Gas Trust(a)		USA	1	%		36,075		36,204

	Total Equitable Supply				$	62,211	$	62,402

IGC/ERI Pan-Am Thermal Generating Limited		Panama	50	%	$	19,976	$	19,736
Petroelectrica de Panama LDC		Panama	45	%		12,213		11,457
Capital Center Energy Company LLC		USA	50	%		4,374		4,571
Compania Hidroeletrico Dona Julia, S.D.R. Ltd.		Costa Rica	24	%		5,108		4,826
Hunterdon Cogeneration LP		USA	50	%		2,066		2,028
Other		USA	Various			138		78

	Total NORESCO					43,875		42,696

Westport Resources Corporation		USA	21	%		139,706		148,116

	Total equity in nonconsolidated investments				$	245,792	$	253,214

		Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
		(Thousands)
Corporate equity securities		$	10,666	$	429	$	(1,947	)	$	9,148
Corporate notes and bonds			6,926		196		(172	)		6,950

	Total investments	$	17,592	$	625	$	(2,119	)	$	16,098

		(Thousands)
Possible future acquisitions		13,192
Stock compensation plans		7,856

	Total	21,048

Options Outstanding						Options Exercisable
Range of Exercise Prices		Number Outstanding at 12/31/02	Weighted Average Remaining Contractual Life	Weighted Average Fair Value		Exercisable as of 12/31/02	Weighted Average Exercise Price
$	11.81 to $15.74	889,691	5.2	$	14.74	889,691	$	14.74
$	15.75 to $19.67	320,667	1.7	$	16.58	304,000	$	16.55
$	19.68 to $23.61	1,161,496	7.2	$	19.86	664,820	$	19.86
$	23.62 to $27.54	193,000	7.1	$	24.47	123,667	$	24.44
$	27.55 to $31.48	528,778	7.9	$	29.05	306,369	$	29.00
$	31.49 to $35.41	2,902,852	8.7	$	32.99	498,248	$	31.64
$	35.42 to $39.35	169,520	7.8	$	37.45	65,125	$	37.67

			2002		2001		2000
			(Thousands)
	At December 31:
	Capitalized costs		$	1,140,129	$	1,022,834	$	954,734
	Accumulated depreciation and depletion			406,399		410,429		332,994

Net capitalized costs			$	733,730	$	612,405	$	621,740

Costs incurred:
	Property acquisition:
		Proved properties	$	—	$	—	$	604,082
		Unproved properties		—		—		9,199
	Land and leasehold maintenance			847		2,005		3,420
	Development			114,341		83,139		93,695

		2002		2001		2000
		(Thousands)
Revenues:
	Affiliated	$	7,145	$	3,938	$	—
	Nonaffiliated		218,568		236,742		252,837
Production costs			26,264		32,495		42,450
Land and leasehold maintenance expenses			847		2,005		3,420
Depreciation and depletion			28,387		28,465		52,077
Impairment of assets			—		—		—
Income tax expense			52,076		62,218		57,232

Results of operations from producing activities (excluding corporate overhead)		$	118,139	$	115,497	$	97,658

		2002		2001		2000
		(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
	Beginning of year	2,072,871		2,164,630		1,146,433
	Revision of previous estimates	44,099		(75,476	)	56,388
	Purchase of natural gas in place	—		—		1,220,509
	Sale of natural gas in place	—		(39,990	)	(311,770	)
	Extensions, discoveries and other additions	82,022		88,413		140,204
	Production	(67,171	)	(64,706	)	(87,134	)

	End of year	2,131,821		2,072,871		2,164,630

Proved developed reserves:
	Beginning of year	1,490,093		1,563,076		965,969
	End of year	1,573,278		1,490,093		1,563,076

		2002		2001		2000
		(Thousands of Barrels)
Oil
Proved developed and undeveloped reserves:
	Beginning of year	1,563		6,867		9,932
	Revision of previous estimates	(4	)	(191	)	134
	Purchase of oil in place	—		—		1,872
	Sale of oil in place	—		(4,662	)	(4,574	)
	Extensions, discoveries and other additions	—		—		—
	Production	(127	)	(451	)	(497	)

	End of year	1,432		1,563		6,867

Proved developed reserves:
	Beginning of year	1,563		6,867		7,996
	End of year	1,432		1,563		6,867

	2002			2001			2000
	(Thousands)
Future cash inflows	$	9,180,390		$	5,966,131		$	24,633,861
Future production costs		(1,529,713	)		(1,242,227	)		(2,864,814	)
Future development costs		(381,667	)		(348,978	)		(327,875	)

Future net cash flow before income taxes		7,269,010			4,374,926			21,441,172
10% annual discount for estimated timing of cash flows		(5,037,625	)		(3,066,798	)		(14,969,946	)

Discounted future net cash flows before income taxes		2,231,385			1,308,128			6,471,226
Future income tax expenses, discounted at 10% annually		(780,985	)		(457,845	)		(2,394,354	)

Standardized measure of discounted future net cash flows	$	1,450,400		$	850,283		$	4,076,872

	2002			2001			2000
	(Thousands)
Sales and transfers of natural gas and oil produced—net	$	(199,449	)	$	(206,675	)	$	(206,393	)
Net changes in prices, production and development costs		720,238			(5,426,615	)		2,557,134
Extensions, discoveries and improved recovery, less related costs		85,508			55,544			408,844
Development costs incurred		69,267			61,667			61,496
Purchase of minerals in place—net		—			(138,274	)		2,627,587
Revisions of previous quantity estimates		103,734			(48,136	)		167,784
Accretion of discount		130,813			632,593			65,230
Net change in income taxes		(323,140	)		1,936,509			(2,142,887	)
Other		13,146			(93,202	)		(42,359	)

Net (decrease) increase		600,117			(3,226,589	)		3,496,436
Beginning of year		850,283			4,076,872			580,436

End of year	$	1,450,400		$	850,283		$	4,076,872

				2002
				(Thousands)
	Capitalized costs			$	474,674
	Accumulated depreciation and depletion				100,130

Net capitalized costs				$	374,544

Costs incurred:
		Property acquisition:
			Proved properties	$	136,828
			Unproved properties		6,251
	Exploration				7,321
	Development				21,433

		Proved properties		$	171,833

	2002
	(Thousands)
Revenues	$	104,103
Production costs		41,670
Exploration expenses		8,421
Depreciation and depletion		52,804
Impairment of assets		5,122
Income tax (benefit) expense		(1,591	)

Results of operations from producing activities	$	(2,323	)

		2002
		(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
	Beginning of year	107,757
	Revision of previous estimates	(3,277	)
	Purchase of natural gas in place	135,248
	Sale of natural gas in place	(1,155	)
	Extensions, discoveries and other additions	8,307
	Production	(17,128	)

	End of year	229,752

Proved developed reserves:
	Beginning of year	83,579
	End of year	140,684

		2002
		(Thousands of Barrels)
Oil
Proved developed and undeveloped reserves:
	Beginning of year	14,280
	Revision of previous estimates	1,250
	Purchase of oil in place	2,514
	Sale of oil in place	(569	)
	Extensions, discoveries and other additions	641
	Production	(1,649	)

	End of year	16,467

Proved developed reserves:
	Beginning of year	5,964
	End of year	12,600

	2002
	(Thousands)
Future cash inflows	$	1,378,592
Future production costs		(401,188	)
Future development costs		(98,685	)

Future net cash flow before income taxes		878,719
Future income taxes		(233,690	)

Future net cash flows after income taxes		645,029
Annual discount at 10% on future net cash flows after income taxes		(277,607	)

Standardized measure of discounted future net cash flows	$	367,422

Discounted future net cash flows before income taxes	$	500,410

(a)	1.	Financial Statements
		The financial statements listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
	2.	Financial Statement Schedule
		The financial statement schedule listed in the accompanying index to financial statements and financial schedule is filed as part of this Annual Report on Form 10-K.
	3.	Exhibits
		The exhibits listed on the accompanying index to exhibits (pages 101 through 106) are filed as part of this Annual Report on Form 10-K.
(b)	Reports on Form 8-K filed during the quarter ended December 31, 2002.
		None.