UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO .

COMMISSION FILE NUMBER 1-3551

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

PENNSYLVANIA		25-0464690
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		Identification No.)

One Oxford Centre, Suite 3300		15219
Pittsburgh, Pennsylvania		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code: (412) 553-5700

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act:

None

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 January 31, 2002: $1,925,952,605

The number of shares outstanding of the issuer’s classes of common stock as of January 31, 2002: 62,652,908

DOCUMENTS INCORPORATED BY REFERENCE

Part III, a portion of Item 10 and Items 11, 12 and 13 are incorporated by reference to the Proxy Statement for the Annual Meeting of Stockholders on May 16, 2002 to be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2001, except for the performance graph, Compensation Committee Report, Audit Committee Report and the Audit Committee Charter.

Index to Exhibits - Page 71

TABLE OF CONTENTS

PART I
Item 1	Business
Item 2	Properties
Item 3	Legal Proceedings
Item 4	Submission of Matters to a Vote of Security Holders Executive Officers of the Registrant

PART II
Item 5	Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6	Selected Financial Data
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A	Qualitative and Quantitative Disclosures About Market Risk
Item 8	Financial Statements and Supplementary Data
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

PART III
Item 10	Directors and Executive Officers of the Registrant
Item 11	Executive Compensation
Item 12	Security Ownership of Certain Beneficial Owners and Management
Item 13	Certain Relationships and Related Transactions

PART IV
Item 14	Exhibits and Reports on Form 8-K
	Index to Financial Statements Covered by Report of Independent Auditors
	Index to Exhibits
	Signatures

Forward-Looking Statements

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 effect of the application of Financial Accounting Standards Number 142, “Goodwill and Other Intangible Assets”, the effect of no longer including Appalachian Basin Partners in monetized sales, the effect of a change in natural gas prices on the Company’s earnings per share, the Company’s forecast for phased implementation of performance based rates, the expected repayment of Company debt and other obligations, the fees for operating, gathering, and marketing gas, anticipated capital expenditures and commitments, 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. We undertake 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, changing prices, legislative and regulatory changes, timely obtaining necessary regulatory approvals, financial market conditions, availability of financing, curtailments or disruptions in production, gathering, or the ability to acquire and apply technology to Company operations, the ability to develop, finance and complete energy infrastructure projects, 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 and exploratory 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 materially 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.

PART I

Item 1. Business

Equitable Resources, Inc. (Equitable or the Company) is an integrated energy company, with emphasis on Appalachian area natural gas 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 the Gulf of Mexico and Rocky Mountain areas. The Company and its subsidiaries offer energy (natural gas, crude oil, and natural gas liquids) products and services to wholesale and retail customers through three business segments: Equitable Utilities, Equitable Production and NORESCO. The Company and its subsidiaries had 1,500 employees at the end of 2001.

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.

Equitable Utilities

Equitable Utilities contains both regulated and non-regulated operations. The regulated group consists of the distribution and interstate pipeline operations, while the unregulated group is involved in non-jurisdictional marketing and trading of natural gas, risk management activities and the sale of energy-related products and services. Equitable Utilities generated 41% of the Company’s net operating revenues in 2001.

Natural Gas Distribution

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 273,000 customers, comprising 255,000 residential customers and 18,000 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 many of its customers use natural gas for heating purposes, Equitable Gas’ revenues are seasonal, with approximately 65% of calendar year 2001 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.

Interstate Pipeline

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, which are regulated by the Federal Energy Regulatory Commission (FERC). The pipeline division offers gas transportation, storage and related services to its affiliates and others in the Northeast United States.

The regulatory environment is designed to increase competition in the natural gas industry which has created a number of opportunities for pipeline companies to expand services and serve new markets. The Company has taken advantage of selected market expansion 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.

The pipeline operations consist of approximately 2,800 miles of transmission, storage and gathering lines, and interconnections with five major interstate pipelines. Equitrans also has 15 natural gas storage reservoirs with approximately 500 million cubic feet (MMcf) per day of peak delivery capability. Equitrans has 59 Bcf of storage capacity of which 27 Bcf is working gas.

Energy Marketing

Equitable Utilities’ unregulated marketing operation, Equitable Energy LLC, 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.

In conjunction with these activities, the Company also engages in limited trading activity. Equitable Energy uses prudent asset management to hedge projected production and optimize storage capacity assets through trading activities. Trading activities are entered into with the objective of limiting exposure to shifts in market prices.

Rates and Regulation

Equitable’s distribution rates, terms of service, contracts with affiliates and issuance of securities are regulated primarily by the Pennsylvania Public Utility Commission (PUC), along with the Kentucky Public Service Commission and the Public Service Commission of West Virginia. 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 is subject to federal regulation, including transportation rates, storage tariffs and various other matters, primarily by the Federal Energy Regulatory Commission (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. 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).

Acquisitions and Divestitures

In December 1999, Equitable acquired the distribution, transmission and production operations of Carnegie Natural Gas Company and subsidiaries (Carnegie) for $40.0 million, including transaction costs. The Carnegie utility operations have been fully integrated into Equitable Gas. The acquisition of Carnegie added approximately 8,000 new distribution customers. See Note D to the consolidated financial statements for additional information related to the Carnegie acquisition.

Competitive Environment

Various regulatory and market trends have combined to promote competition in markets served by Equitable Gas. In addition, Equitable Gas faces price competition with other energy forms. The changes precipitated by the FERC restructuring of natural gas transmission in Order No. 636 have significantly increased competition in the natural gas industry. In the restructured marketplace, competition is increasing to provide natural gas sales to

commercial and residential customers. However, since Equitable Gas has been managing transportation service and gas supply risk for a number of years, the transition to a more competitive environment under Order No. 636 has not had a significant impact on its operations. Equitable Gas has responded to this competitive environment by offering a variety of firm and interruptible services, including natural gas transportation, supply pooling, balancing and brokering to industrial and commercial customers.

The large industrial market is extremely competitive resulting in very low realized margins. The national economic downturn experienced during 2001 has resulted in a significant reduction in industrial activity and volumes, particularly related to the domestic steel industry.

Gas industry competition at the retail level is receiving increased attention from both regulators and legislators. In June 1999, Pennsylvania enacted into law the Natural Gas Choice and Competition Act (the Act) which required local natural gas distribution companies to extend the availability of natural gas transportation service to residential and commercial customers by July 1, 2000, pursuant to a PUC-approved plan. The Company filed a revised tariff after which a negotiated settlement was reached and approved, becoming effective July 1, 2001. In 2001 Equitable Gas made progress on its initiative with the PUC to provide for performance-based rates (PBR). On September 26, 2001, the PUC issued a final order that provides a guaranteed purchased gas cost credit to customers, while enabling Equitable Gas to share in any cost savings from more effective management of capacity release and off-system sales revenues. This order is effective from October 1, 2001 through September 30, 2003.

The Company’s forward plan for PBR, which will require PUC approval, forecasts a phased implementation that will advance new incentive mechanisms for managing commodity costs, reducing operating expense, optimizing cost of capital, and reducing gas line loss.

Equitable Production

Equitable Production develops, produces and sells natural gas and crude oil, with operations in the Appalachian region of the United States. It also engages in natural gas gathering and the processing and sale of natural gas and natural gas liquids. Equitable Production generated approximately 53% of the Company’s net operating revenues in 2001.

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 owns 7,184 net producing wells in Appalachia. As of December 31, 2001, the Company estimates the total proved reserves to be 2,082 billion cubic feet equivalent (Bcfe), including undeveloped reserves of 583 Bcfe.

The areas in which the Company’s Appalachian properties 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 the gas is processed to allow heavier hydrocarbons (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 Mcfe) to vary somewhat. Once drilled and completed, wells in the Appalachian Basin typically have low ongoing operating and maintenance requirements and require minimal capital expenditures. These formations are characterized by slow recovery of the reserves in place, low rates of production and wells that generally produce for longer than 20 years and often more than 50 years. Many of the Company’s wells in these areas have been producing for many years, 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.

Substantially all of the Appalachian wells are relatively shallow, with depths ranging from 1,000 to 7,000 feet below the surface. Many of these wells are completed in more than one producing zone and production from these zones 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 2001, Equitable Production drilled 316 gross wells at a success rate of 100%. This drilling was concentrated within the core areas of southwest Virginia, West Virginia and southeast Kentucky. This activity resulted in an incremental 30 MMcf per day of gas sales and developed reserve additions of 117 Bcfe.

Equitable Production currently has an inventory of 3.6 million gross acres of which approximately 71% has not been developed. As of December 31, 2001, the Company estimated the proved undeveloped reserves of the underlying leases to be 583 Bcfe from 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.

In July 2001, Equitrans filed an order with the FERC to transfer five natural gas pipeline gathering systems located in West Virginia and Pennsylvania to the Equitable Production business segment. On February 13, 2002, the FERC approved the order that resulted in the transfer of gathering systems. The transfer will be effective January 1, 2002 for segment reporting purposes. The systems transferred consist of approximately 1,300 miles of low pressure, small diameter pipeline, and related facilities used to gather gas from wells in the region. The effect of this transfer is not material to the results of operations or financial position of Equitable Utilities or Equitable Production.

In December 1999, the unregulated production properties and well operations of Equitable Utilities’ Equitrans interstate pipeline division were transferred to Equitable Production. These properties included 800 producing natural gas wells and 38.9 Bcfe of proved developed reserves.

Acquisitions and Divestitures

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 operations 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 15.236 million shares or approximately 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 1.325 million shares in this IPO for an after-tax gain of $4.3 million. This IPO reduced the Company’s ownership to approximately 36% interest in Westport. On August 21, 2001, Westport Resources completed a merger with Belco Oil & Gas Company. Equitable continues to own 13.911 million shares, which now represents approximately 27% of Westport’s total shares outstanding at December 31, 2001. The book value of Equitable’s equity in Westport was $148.1 million as of December 31, 2001.

In June 2000, the Company sold properties, previously acquired from Statoil, with reserves of 66.0 Bcfe that qualified for nonconventional fuels tax credit to a partnership, 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 $26.2 million investment under the equity method of accounting. During 2001 and 2000, the Company received $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 $8.5 million in fees for the performance of the same services in 2002 based on expected production volumes.

In December 2000, the Company sold gas properties, previously acquired from Statoil, with reserves of 133.3 Bcfe to a trust 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 completely 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 $36.2 million investment under the equity method of accounting. During 2001, the

Company received $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 $14.6 million in fees for the performance of the same services in 2002 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. 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 3.7 Bcfe annually. The proceeds are shown in the balance sheet as restricted cash. See Note F for additional information related to the restricted cash. 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 are estimated to be approximately $1.3 million in 2002.

See Notes C and D to the consolidated financial statements for additional information relating to the Company’s acquisitions and divestitures.

Competitive Environment

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 2001, Kentucky and West Virginia had approximately 4,500 independent operators and 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.

Hedging Activities

Equitable has historically 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 derivative instruments used are outlined below in Item 7A, “Qualitative and Quantitative Disclosures About Market Risk,” and in Note B to the consolidated financial statements.

NORESCO

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. 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. NORESCO’s customers include commercial, governmental, institutional and industrial end-users. 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 6% of the Company’s net operating revenues in 2001.

The segment’s energy infrastructure group develops and operates private power, 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 hospitals, universities, 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 segment’s performance contracting group provides solutions for energy conservation and efficiency. 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 metering, monitoring 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 increased to $128.3 million at year-end 2001 from $91.0 million at the end of 2000. A substantial portion of the backlog is expected to be built-out within the next 18 months.

Operating Revenues

Operating revenues as a percentage of total operating revenues for each class of products and services greater than 10% of three business segments during the years 2001 through 1999 are as follows:

	2001		2000		1999
Equitable Utilities:
Residential natural gas sales	16	%	15	%	19	%
Marketed natural gas	52		53		33
Equitable Production:
Produced natural gas equivalents	12		13		13
NORESCO:
Energy service contracting	9		8		16

The Company believes that a better understanding of business segments’ revenue contributions can be obtained by analysis of net operating revenues by class of products and services.

	2001		2000		1999
Equitable Utilities:
Residential natural gas sales	14	%	14	%	16	%
Transportation	11		12		18
Marketed natural gas	3		3		2
Equitable Production:
Produced natural gas equivalents	38		40		30
NORESCO:
Energy service contracting	6		6		8

See Management’s Discussion and Analysis of Financial Condition and Results of Operations and Notes U and V to the consolidated financial statements in Part II, Items 7 and 8, respectively, for financial information by business segment and information regarding environmental matters.

Item 2. Properties

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 Pennsylvania, West Virginia and Kentucky. The segment also owns and operates underground storage and transmission facilities in Pennsylvania and West Virginia.

Equitable Production. This business segment owns or controls all of the Company’s acreage of proved developed and undeveloped natural gas and oil production properties located in the Appalachian region. In addition, Kentucky West Virginia Gas Company, LLC, a subsidiary of the Company, owns and operates gathering properties as well as other general property and equipment in Kentucky. Information relating to Company estimates of natural gas and crude oil reserves and future net cash flows is provided in Note X to the consolidated financial statements in Part II.

Natural Gas and Crude Oil Production:

	2001		2000		1999
Natural Gas:
MMcf produced	64,706		87,134		66,328
Average sales price per Mcfe sold	$	3.75	$	2.87	$	2.39
MMcfe operated (a)	93,167		89,932		45,896
MMcfe gathered (b)	106,832		92,440		49,396
Crude Oil:
Thousands of barrels produced	451		497		1,070
Average sales price per barrel	$	17.82	$	21.75	$	15.53

(a) Includes produced volumes and volumes from properties the Company operates for a fee.

(b) Includes operated volumes as well as volumes gathered as a service performed for third parties.

Average production cost (lifting cost) of natural gas and crude oil during 2001, 2000 and 1999 was $0.482, $0.509, and $0.373 per Mcf equivalent, respectively.

	Natural Gas	Oil
Total productive wells at December 31, 2001:
Total gross productive wells	11,797	252
Total net productive wells	6,950	234
Total acreage at December 31, 2001:
Total gross productive acres	1,054,832
Total net productive acres	1,043,799
Total gross undeveloped acres	2,529,871
Total net undeveloped acres	2,317,161

Number of net productive and dry exploratory and development wells drilled:

	2001	2000	1999
Exploratory wells:
Productive	–	–	3.5
Dry		1.0	0.8
Development wells:
Productive	293.5	284.6	118.6
Dry	–	2.0	–

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 16 locations throughout the United States.

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

Item 3. Legal Proceedings

There are no known pending legal proceedings likely to have a material effect on the Company’s financial position or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the Company’s security holders during the last quarter of its fiscal year ended December 31, 2001.

Executive Officers of the Registrant

Name and Age	Title	Business Experience

Philip P. Conti (42)	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.

James M. Funk (52)	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 (49)	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 (49)	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 (55)	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.

David L. Porges (44)	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 (53)	Senior Vice President and Chief Administrative Officer	Elected to present position May 23, 1996.

Officers are elected annually to serve during the ensuing year or until their successors are chosen and qualified. Except as indicated, the officers listed above were elected on May 17, 2001.

PART II

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):

	2001						2000 (a)
	High		Low		Dividend		High		Low		Dividend
1^st Quarter (a)	$	35.25	$	27.69	$	0.148	$	23.00	$	16.13	$	0.148
2^nd Quarter (a)	40.50		31.80		0.160		26.44		20.82		0.148
3^rd Quarter	36.60		26.00		0.160		31.72		23.41		0.148
4^th Quarter	34.69		29.15		0.160		33.38		27.88		0.148

(a) Adjusted to reflect the two-for-one stock split effective June 11, 2001. As a result of this stock split, one-half of a right (adjusted from one right) under the Company’s Preferred Stock Purchase Rights Plan now attaches to each share of common stock outstanding.

As of February 28, 2002, there were approximately 4,811 shareholders of record of the Company’s common stock.

The indentures, under which the Company’s long-term debt is outstanding, contains provisions limiting 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, $436 million of the Company’s consolidated retained earnings at December 31, 2001 were available for declarations or payments of dividends on, or purchases of, its common stock.

The Company anticipates dividends will continue to be paid on a regular quarterly basis.

Item 6. Selected Financial Data

	2001		2000		1999		1998			1997
	(Thousands except per share amounts)
Operating revenues	$	1,764,491	$	1,652,218	$	1,042,013	$	851,811		$	886,525
Net income (loss) from continuing operations (a)	$	151,808	$	106,173	$	69,130	$	(27,052	)	$	74,187
Net income (loss) from continuing operations per common share:
Basic	$	2.36	$	1.63	$	1.02	$	(0.37	)	$	1.03
Diluted	$	2.30	$	1.60	$	1.01	$	(0.37	)	$	1.03
Total assets	$	2,518,747	$	2,424,914	$	1,789,574	$	1,860,856		$	2,328,051
Long-term debt	$	271,250	$	287,789	$	298,350	$	281,350		$	417,564
Preferred trust securities	$	125,000	$	125,000	$	125,000	$	125,000		$
Cash dividends paid per share of common stock	$	0.63	$	0.59	$	0.59	$	0.59		$	0.59

(a) Excludes the (loss) gain from discontinued operations related to the sale of the Company’s natural gas midstream operations of $(8.8) million and $3.9 million in 1998 and 1997, respectively, and an extraordinary loss recognized in 1998 related to the early extinguishments of debt of $(8.3) million, as described in previous filings of the Form 10-K.

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

Critical Accounting Policies Involving Significant Estimates

The Company’s significant accounting policies are described in Note A 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 financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. The following critical accounting policies affect the Company’s more significant judgments and estimates used in the preparation of the consolidated financial statements. There can be no assurance that actual results will not differ from those estimates.

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 exploration and production activities when deliveries of natural gas, crude oil and natural gas liquids occur. Revenues from natural gas transportation and storage activities are recognized in the period the service is provided. Revenues from energy marketing activities are recognized when deliveries occur. Revenues from activities classified as energy trading are recognized immediately.

The Company recognizes revenue from shared energy savings contracts as energy savings are measured and verified. Revenue received from customer contract termination payments is recognized when received. Revenue from other long-term contracts including energy savings performance contracts, such as turnkey contracts, is recognized on a percentage-of-completion basis, determined using the cost-to-cost method (see below for expanded discussion of this method). Any maintenance revenues are recognized as related services are performed.

Oil & Gas Properties - Successful Efforts Method: Equitable uses the successful efforts method of accounting for oil and gas producing activities. The successful efforts method has only the cost of successful drilling capitalized as oil and gas properties. Costs of exploratory dry holes, geological and geophysical, delay rentals, and other property carrying costs are charged to expense. All general and administrative costs are expensed as incurred. Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties are computed using the unit-of-production method by aggregation of properties.

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 purposes of determining whether proved oil and gas properties have been impaired, Equitable utilizes forward market prices (including estimates of forward market prices for periods that extend beyond those with quoted market prices) as of the evaluation date in estimating the future cash flows from the oil and gas properties. This forward market price information is consistent with that generally used in drilling and acquisition planning and decision making. In the impairment calculation, these market prices for future periods are used to value the estimated production from proved reserves for the corresponding periods in arriving at future cash flows. No changes in production from the profile included in the year-end reserve report are assumed.

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 our 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, 2001 and 2000, the Company did not recognize impairment charges on oil and gas properties.

Percentage of Completion Method of Accounting: NORESCO recognizes revenue and profit as work on long-term contracts progresses using the percentage of completion method of accounting. The method relies on estimates of total expected costs. NORESCO follows this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. 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. 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 reversal of previously recognized revenue and profits. When estimates indicate a loss under a contract, cost of sales is charged with a provision for such loss. 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 no loss contracts as of December 31, 2001.

Hedging and Derivatives: Equitable’s primary market risk exposure is the volatility of future prices for natural gas. The Company uses a variety of techniques to minimize this exposure, which includes sales of gas properties, other monetizations, and prepaid natural gas sales. The Company also uses derivative financial instruments to reduce the effect of this volatility. The Company’s strategy is to become more highly hedged at prices considered to be at the upper end of historical levels. The Company uses simple, non-leveraged derivative instruments that are placed with major financial institutions whose credit worthiness is continually monitored. The Corporate Risk Committee and Board of Directors approved a set of policies that guides the use of these derivative financial instruments. Equitable’s use of these derivatives is further explained in Note B to the consolidated financial statements and in Part II Item 7A, “Qualitative and Quantitative Disclosures About Market Risk”.

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, under current market conditions, management’s objective is to reduce its exposure to commodity price changes to $0.01 of earnings per diluted share per $0.10 change in the average NYMEX natural gas price for 2002, $0.03 per diluted share for 2003, and less than $0.04 per diluted share for 2004 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 due to the increased market volatility.

Equitable also conducts trading activities through an unregulated marketing group. The function of the trading business is to contribute to earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy. These derivatives include forward contracts, which may involve physical delivery of an energy commodity, swap agreements, which may require payments to (or receipt of payments from) counterparties based on the difference between a fixed and variable price for the commodity, options and other contractual agreements. The Company’s management made a strategic decision to limit trading activities during 2001.

Newly Issued Accounting Standards: In July 2001, the FASB issued Statement No. 141, Business Combinations, and Statement No. 142, Goodwill and Other Intangible Assets, both of which are effective for fiscal year 2002. Statement No. 141 eliminates the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and further clarifies the criteria to recognize intangible assets separately from goodwill. Under Statement No. 142, goodwill and indefinite intangible assets are no longer amortized but are reviewed annually for impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. The Company has recorded goodwill of $57.4 million at December 31, 2001.

Application of the nonamortization provisions of Statement No. 142 is expected to result in an increase in annual net income of approximately $3.7 million. During 2002, the Company will perform the first of the required impairment tests of goodwill and, therefore, has not yet determined the effect these tests will have on the earnings and financial position of the Company.

In August 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which will be effective for fiscal year 2003. This Statement requires asset retirement obligations to be measured at fair value and to be recognized at the time the obligation is incurred. During 2002, management will assess the impact, if any, of this pronouncement on the earnings and financial position of the Company.

In October 2001, the FASB issued Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which will be effective for fiscal year 2002. Statement 144 provides a single accounting model for long-lived assets to be disposed of and significantly changes the criteria that would have to be met to classify an asset as held-for-sale. Based on current circumstances, the Company believes the application of the new rules will not have a material impact on the earnings and financial position of the Company.

Consolidated Results of Operations

Equitable’s consolidated net income from continuing operations for 2001 was $151.8 million, or $2.30 per diluted share, compared with $106.2 million, or $1.60 per diluted share, for 2000 and $69.1 million, or $1.01 per diluted share, for 1999.

The improved 2001 earnings are 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.

Earnings for 2000 increased over 1999 as a result of increased natural gas production; increased throughput in the regulated distribution operations primarily due to colder weather; lower exploration costs; and lower operating and administrative expenses throughout the organization.

Business Segment Results

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 $8.0 million and $11.2 million in 2001 and 2000, respectively, were not allocated. Prior periods have been reclassified to conform to the current presentation.

Equitable Utilities

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, and the unregulated marketing of natural gas, and limited trading activities.

Natural Gas Distribution

The local distribution operations of Equitable Gas Company (Equitable Gas) a division of the Company, provides natural gas services in southwestern Pennsylvania and to municipalities in northern West Virginia. In addition, Equitable Gas provides field line sales in eastern Kentucky. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

service to residential and commercial customers by July 1, 2000, pursuant to a PUC-approved plan. The Company filed a revised tariff after which a negotiated settlement was reached and approved, becoming effective July 1, 2001. In 2001, Equitable Gas made progress with the PUC to provide for performance-based rates (PBR) in 2001. On September 26, 2001, the PUC issued a final order that provides a guaranteed purchased gas cost credit to customers, while enabling Equitable Gas to share in any cost savings from more effective management of capacity release and off-system sales revenues. This order is effective from October 1, 2001 through September 30, 2003.

Interstate Pipeline

The pipeline operations of Equitrans, L.P. (Equitrans) and Carnegie Interstate Pipeline (Carnegie Pipeline), subsidiaries of the Company, are subject to rate regulation by the FERC. Under present rates, a majority of the annual costs are recovered through fixed charges to customers. Equitrans filed a rate case in April 1997, which addressed the recovery of certain stranded plant costs related to the implementation of FERC Order No. 636. The requested rates were placed into effect in August 1997, subject to refund, pending the issuance of a final order. On April 29, 1999, the FERC approved, without modification, the joint stipulated settlement agreement resolving all issues in the proceeding.

The approved settlement provided for prospective collection of increased gathering charges. In addition, the settlement provided Equitrans the opportunity to retain all revenues associated with interruptible transportation and negotiated rate agreements, as well as moving its gathering charge toward a cost-based rate. In the second quarter of 1999, Equitrans recorded the final settlement of the rate case. The final settlement includes the adjustment of the prior provisions for refund and recognition of the previously deferred revenues and costs related to the stranding of certain gathering facilities.

During 1999, the Company owned a third interstate pipeline, Three Rivers Pipeline Company, which was interconnected with Equitrans. On November 29, 1999, Equitrans filed an application with the FERC to acquire and operate the assets of Three Rivers Pipeline Company that was granted by an order dated April 13, 2000.

In July 2001, Equitrans filed an order with the FERC to transfer five natural gas pipeline gathering systems located in West Virginia and Pennsylvania to the Equitable Production business segment. In February 2002, the FERC approved the order that resulted in the transfer of gathering systems. The transfer will be effective January 1, 2002 for segment reporting purposes. The systems transferred consist of approximately 1,300 miles of low pressure, small diameter pipeline, and related facilities used to gather gas from wells in the region. The effect of this transfer is not material to the results of operations or financial position of Equitable Utilities or Equitable Production, and therefore, the results have not been restated for this transfer.

Energy Marketing

Equitable Utilities’ unregulated marketing entity provides commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial, institutional and residential 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.

In conjunction with these activities, the Company also engages in limited trading activity. Equitable Energy uses prudent asset management to optimize the Company’s assets through trading activities. Trading activities are entered into with the objective of limiting exposure from shifts in market prices.

Capital Expenditures

Equitable Utilities forecasts 2002 capital expenditures to be approximately $80 million, a significant increase over capital expenditures of $38.5 million for 2001. The 2002 capital expenditures include 2001 capital commitments totaling $45 million and planned expenditures from 2002 commitments totaling $35 million. The total 2002 expenditures include $46 million for Utilities infrastructure improvements, $23 million for technology enhancements and $11 million for new business development. The infrastructure improvements include maintenance and improvements to existing distribution and transmission lines as well as storage enhancements. The technology expenditures are related to mobilization and automation initiatives while the new business capital is planned for distribution extension projects.

Equitable Utilities

	Years Ended December 31,
	2001			2000			1999
	(thousands)
OPERATIONAL DATA
Operating expenses/net revenues	65.77		%	60.85		%	64.62		%

Capital expenditures (thousands)	$	38,528		$	28,436		$	43,979
FINANCIAL DATA
Utility revenues	$	408,812		$	377,700		$	324,869
Marketing revenues	1,032,207			1,009,554			487,005
Total revenues	1,441,019			1,387,254			811,874
Purchased natural gas cost	1,210,277			1,149,775			583,974
Net revenues	230,742			237,479			227,900
Operating and maintenance expense	56,013			59,072			57,844
Selling, general and administrative expense	69,344			57,244			53,819
Depreciation, depletion and amortization (DD&A)	26,404			28,185			35,596
Total expenses	151,761			144,501			147,259
Operating income	$	78,981		$	92,978		$	80,641

Equitable Utilities had operating income of $79.0 million for 2001, compared with $93.0 million for 2000. The lower results for 2001 are primarily due to reduced revenues resulting from warm 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.

Operating income for Equitable Utilities increased 15.3% from 1999 to 2000. The increase in 2000 is a result of higher net revenues due principally to the Carnegie acquisition and cooler weather during the heating season. Results for the 2000 period include $0.9 million for the recovery of stranded costs in rates from the previously mentioned Equitrans rate case settlement, which was partially offset by charges of $1.5 million for improvement of utility segment operating processes and consolidation of facilities. Results for 1999 benefited from the recognition of the settlement of Equitrans’ rate case which included stranded cost recovery that had a positive net result of $3.8 million. This benefit was partially offset by charges of $3.0 million for improvement of utility segment operating processes and consolidation of facilities. Excluding the impact of the rate case settlement and process improvement charges in both periods, operating income increased $13.8 million, or 17.3%, over the $79.7 million in 1999.

Distribution Operations

	Years Ended December 31,
	2001		2000		1999
OPERATIONAL DATA
Degree days (30 year average = 5,968)	5,059		5,596		5,485
O&M* per customer	$	296.52	$	271.94	$	254.85
Volumes (MMcf):
Residential	24,753		27,776		25,431
Commercial and industrial	24,500		32,521		22,209
Total natural gas sales and transportation	49,253		60,297		47,640

* O&M is defined for this calculation as the sum of operating and maintenance and selling, general and administrative expenses, excluding other taxes.

FINANCIAL DATA	(thousands)
Net revenues	$	154,624	$	159,818	$	144,969
Operating expenses	84,276		78,454		73,179
Depreciation, depletion and amortization	18,175		17,411		17,086
Operating income	$	52,173	$	63,953	$	54,704

Net revenues for 2001 were $154.6 million compared to $159.9 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 normal 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 warm 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 revenues for the distribution operations increased 10.3% from 1999 to 2000. The increase in net revenues for 2000 is due principally to the total system throughput increase from the Carnegie Gas acquisition and the impact of weather that was 2% colder than the prior year. Weather in the distribution service territory during 2000 was 6% warmer than the 30-year average.

Operating expenses for the distribution operations for 2000 increased 7.2% from 1999. The increase in 2000 is due principally to the acquisition of Carnegie Gas, increased provision for performance-related bonuses and higher administrative costs.

Pipeline Operations

	Years Ended December 31,
	2001		2000		1999
			(thousands)
OPERATIONAL DATA
Transportation throughput (MMBtu)	70,693		81,692		76,727
FINANCIAL DATA
Net revenues	$	62,079	$	61,119	$	73,273
Operating expenses	33,249		29,040		32,607
Depreciation, depletion and amortization	7,872		10,577		18,312
Operating income	$	20,958	$	21,502	$	22,354

Net revenues from pipeline operations 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 2001 transportation throughput decline in 2001 from prior year of 13% is primarily due to the reduced residential throughput resulting from the warmer weather than prior year and 30-year average.

Operating expenses increased by $4.2 million 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 the pipeline operations decreased 16.6% from 1999 to 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. Revenues in 1999 include $17.2 million related to recognition of the rate settlement, pass-through of stranded costs and pass-through of FERC surcharges and products extraction costs. Excluding the impact of the rate settlement, net revenues increased $1.2 million primarily due to the increased throughput from the Carnegie Interstate Pipeline acquisition and increased gathering and storage services.

Operating expenses for the pipeline operations decreased 10.9% from 1999 to 2000. The operating expenses for 2000 include $2.9 million of amortization expense related to the recovery of stranded costs in rates. Operating expenses for 1999 include $11.6 million of amortization expense related to the recovery of stranded costs, $4.0 million for utility segment process improvements and $1.7 million of pass-through products extraction costs. Excluding the impact of these items in both periods, operating expenses of $36.0 million for 2000 increased by $2.4 million. The increase in operating expenses for 2000, excluding these items in both periods, was principally due to the acquisition of Carnegie Interstate Pipeline and increased provisions for performance-related bonuses.

Energy Marketing

	Years Ended December 31,
	2001		2000		1999
	(Thousands)
OPERATIONAL DATA
Marketed gas sales (MMBtu)	215,541		240,922		188,133
Net revenue/MMBtu	$	0.0651	$	0.0687	$	0.0513
FINANCIAL DATA
Net revenues	$	14,039	$	16,542	$	9,658
Operating expenses	7,832		8,822		5,877
Depreciation, depletion and amortization	357		197		198
Operating income	$	5,850	$	7,523	$	3,583

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 which generally 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.

Net revenues for energy marketing operations increased 71.3%, from 1999 to 2000. The increase in net revenues is attributable to greater sales volumes associated with asset management activities and higher unit margins. In addition, the sale of gas in storage during the first quarter of 2000 allowed the Company to benefit from the increasing natural gas prices.

Operating expenses increased 50.1% from 1999 to 2000. The increase in expenses is due principally to the increased investment in the segment’s asset management and retail marketing activities.

Equitable Production

Equitable Production develops, produces and sells natural gas and crude oil, with operations in the Appalachian region of the United States. It also engages in natural gas gathering and the processing and sale of natural gas and natural gas liquids. In April 2000, the Company merged its Equitable Production — Gulf business with Westport Oil and Gas Company to form Westport Resources Corporation (Westport) 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).

Equitable Production (Appalachian)

During calendar 2000, Equitable Production completed several transactions which affects the comparability of the financial data between 2000 and 2001.

In February 2000, Equitable Production 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.

Monetizations

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 3.7 Bcfe annually. The proceeds are shown in the balance sheet as restricted cash. See Note F for additional information related to the restricted cash.

Prepaid Natural Gas Sales

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 Btu 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.

Below is a table that details the specifics of the Company’s various prepaid transactions as of December 31, 2001 and 2000.

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

20,784

26.6

3 years

8.9

0.71

3.23

34,922

Sales of Gas Properties

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 approximately 66.0 Bcfe of reserves to a partnership, Eastern Seven Partners, L.P. (ESP), for proceeds of $122 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 which is recorded as Equity in Nonconsolidated Investments 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 approximately 133.3 Bcfe of reserves to a trust, Appalachian Natural Gas Trust (ANPI), for proceeds of $256 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 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 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, 2001 and 2000.

Sales of Gas
Properties

Reserves
Sold (Bcfe)

Volumes Produced (Bcfe)

Revenue Recognized from Fees
(Thousands)

2001

2000

2001

2000

ESP

66.0

10.3

6.6

8,876

4,913

ANPI

133.3

15.4

–

16,130

–

In November 1995, the Company monetized Appalachian gas properties qualifying for non-conventional fuels tax credit to a partnership, Appalachian Basin Partners (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 increases substantially based on the attainment of a performance target. The performance target was met at the end of 2001. Beginning in 2002, the Company will no longer include ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold will decrease by approximately 8.9 Bcf while equity production will increase by the same amount. The Company will consolidate the partnership starting in 2002, and the remaining portion not owned by the Company will result in a minority interest. The Company will also begin receiving a greater percentage of the non-conventional fuels tax credit based on its increased ownership.

Capital Expenditures

Equitable Production forecasts the 2002 capital budget to be approximately $107 million. This includes $84 million for development of Appalachian holdings, $16 million for improvements to gathering system pipelines, and $7 million for technology initiatives. This forecasted level of development drilling is designed to allow for supply volumes to remain consistent with 2001 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.

Equitable Production (Appalachian)

Operational and Financial Data

	Years Ended December 31,
	2001		2000		1999
OPERATIONAL DATA
Production:
Net equity sales, natural gas and equivalents (MMcfe)	38,825		66,356		30,844
Average (well-head) sales price ($/Mcfe)	$	3.67	$	3.06	$	2.30
Monetized sales (MMcfe) (a)	22,845		11,105		11,819
Average (well-head) sales price ($/Mcfe)	$	3.81	$	2.04	$	1.85
Company usage (MMcfe)	5,742		6,568		3,232
Lease operating expense (LOE), excluding severance tax ($/Mcfe)	$	0.32	$	0.33	$	0.33
Severance tax ($/Mcfe)	$	0.16	$	0.16	$	0.09
Depletion ($/Mcfe)	$	0.38	$	0.49	$	0.42
Production Services:
Gathered volumes (MMcfe)	106,832		92,440		49,396
Average gathering fee ($/Mcfe) (b)	$	0.58	$	0.58	$	0.59
Gathering and compression expense ($/Mcfe)	$	0.23	$	0.27	$	0.33
Gathering and compression depreciation ($/Mcfe)	$	0.10	$	0.11	$	0.15
Total operated volumes (MMcfe) (c)	93,167		89,932		45,896
Volumes handled (MMcfe) (d)	119,874		101,889		58,196
Selling, general, and administrative ($/Mcfe handled)	$	0.20	$	0.23	$	0.33
Capital expenditures (thousands)	$	93,862	$	84,661	$	29,155

(a) Volumes sold associated with the Company’s two prepaid natural gas sales contracts and the ABP partnership discussed above.

(b) Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field where it is produced, to the trunk or main transmission line. Many contracts are for a blended gas commodity and gathering price. In this case the Company utilizes standard measures in order to split the price into its two components.

(c) Includes equity volumes, monetized volumes, and volumes in which interests were sold, but which the Company still operates for a fee.

(d) Includes operated volumes plus volumes gathered for third parties.

	Years Ended December 31,
	2001		2000			1999
			(Thousands)
FINANCIAL DATA
Revenue from Production	$	229,344	$	225,774		$	92,680
Services:
Revenue from gathering fees	61,475		53,268			29,178
Other revenues	11,459		10,120			4,152
Total revenues	302,278		289,162			126,010
Operating expenses:
Gathering and compression expenses	24,594		25,237			16,424
Lease operating expense	21,855		27,893			15,009
Severance tax	10,640		13,103			3,977
Depreciation, depletion and amortization	40,624		57,175			29,141
Selling, general and administrative (SG&A)	24,556		23,470			19,034
Exploration and dry hole expense	2,005		2,896			1,891
Strike-related expenses	–		18,694			–
Total operating expenses	124,274		168,468			85,476
Equity from nonconsolidated investments	726		167			–
Other loss	–		(6,951		)	–
Earnings before interest and taxes (EBIT)	$	178,730	$	113,910		$	40,534

Revenues from production, which are derived primarily from the sale of produced natural gas, increased slightly from 2000 to 2001. The increase in revenues from production of $4 million from 2000 to 2001 is due primarily to higher effective commodity prices offset by the June and December 2000 sale of gas properties (20.3 Bcfe), increases in sales volumes due to a full year ownership of the Statoil assets (4.3 Bcfe), and production from wells shut in or damaged during a fourth quarter 2000 work stoppage (1.4 Bcfe). Equitable Production’s average selling prices for natural gas increased 28% over the same period. The revenue from gathering fees increased 15% 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 fee 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. Other revenues increased by 13% due to increased service fees from the 2000 sales of gas properties.

Operating expenses for the period ended December 31, 2001 decreased 26% 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. Additional positive items included the absence of strike-related expenses incurred in 2000, lower depletion expense 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 15% due to operating improvements in the Kentucky West pipeline unit and lower cost gathering on the acquired assets. General and administrative expenses per Mcfe declined 13% due to on-going synergies from the acquisition and increase in gathering system throughput. Depletion expense was reduced both in total and on a per-unit basis as a result of the production asset sales in calendar 2000.

Revenues from production increased 143.6% from 1999 to 2000. The increase in revenues from production of $133.1 million from 1999 to 2000 is due primarily to increases in sales volumes related to the Statoil acquisition and higher effective commodity prices. The Statoil acquisition added 32.1 Bcfe of sales in 2000. Equitable Production’s average selling prices for natural gas increased 33.0% over the same period. The increase in revenues realized was reduced by the recognition of $77.6 million in hedge losses. The revenue from gathering fees increased 82.6% primarily due to the increase in gathered volumes related to the Statoil acquisition. Other revenues increased by $6.0 million due to the sale of non-conventional fuels tax credits acquired from Statoil and from service fee recoveries.

Operating expenses for the period ended December 31, 2000 totaled $168.5 million, an increase of $83.0 million from the same period in 1999, with the increase due primarily to the Statoil acquisition. Gathering and compression expenses per Mcfe decreased 18.2% due to lower cost gathering on the acquired assets. General and administrative expenses per Mcfe declined 30.3% due to initial synergies from the acquisitions. Severance taxes per Mcfe increased due to increased natural gas sales prices.

On December 10, 2000, a labor situation involving the Kentucky West Virginia unit of the Equitable Production segment and members of the local PACE labor union was settled, after a 56-day strike which had curtailed production in the region. The agreement reached between the Company and the union resulted in a decrease in the represented work force in this unit by 85 people. This reduction from 152 to 67 employees resulted in a fourth quarter charge of $18.7 million, recorded as operations and maintenance expense in the consolidated income statement. Cost savings from the labor settlement were approximately $5.0 million in 2001.

Equitable Production—Gulf

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 Operation in 2001. The following description includes results prior to the merger. During 2000, seven gross wells were drilled at a success rate of 86%.

In the Gulf Region during 1999, 153 gross wells were drilled at a success rate of 82%. This activity resulted in additions of 48.5 Bcfe. The increase was the result of successful development of the West Cameron Block 180 and 198 fields and South Marsh Island 39 field. Equitable Production – Gulf operated both fields.

Equitable Production also participated in exploratory activity during 1999, including a successful well at South Timbalier 196, in which Equitable Production had a 50% working interest. Unsuccessful exploratory activity during 1999 on the West Cameron 575 and the Eugene Island 44 blocks resulted in dry hole expense of approximately $2.5 million in 1999.

Production – Gulf Operation

	Years Ended December 31,
	2000		1999
	(Thousands)
OPERATIONAL DATA
Production:
Net sales, natural gas and equivalents (MMcfe)	6,087		26,853
Average sales price ($/Mcfe)	$	2.77	$	2.34
LOE ($/Mcfe)	$	0.24	$	0.25
SG&A ($/Mcfe)	$	0.27	$	0.26
Depletion ($/Mcfe)	$	1.11	$	1.07
Capital expenditures (thousands)	$	9,034	$	62,944
FINANCIAL DATA
Revenue from Production	$	16,885	$	64,050
Other revenues	70		844
Total revenues	16,955		64,894
Gathering and compression expense	17		155
Lease operating expense	1,454		6,868
Depreciation, depletion and amortization	6,891		29,424
Selling, general and administrative expense	1,643		6,969
Exploration and dry hole expense	524		7,396
Total operating expenses	$	10,529	$	50,812
EBIT	$	6,426	$	14,082

Results of operations for the Gulf in 2000 include only the first quarter. During that period, revenues per Mcfe increased 18% over the full year 1999 average, due to increased commodity prices. Sales volumes decreased due to the faster decline of Gulf production and decreased drilling during 2000. Operating expenses per unit were essentially unchanged from 1999.

NORESCO

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 distributed on-site generation management, 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 U.S. and operates private power plants in selected international countries.

	Years Ended December 31,
	2001			2000			1999
OPERATIONAL DATA
Revenue backlog at December 31 (Thousands)	$	128,264		$	90,978		$	70,999
Gross profit margin	22.0		%	24.8		%	21.5		%
SG&A as a % of revenue	14.7		%	17.0		%	11.7		%
Development expense as a % of revenue	2.6		%	3.3		%	2.6		%
Capital expenditures (Thousands)	$	289		$	1,596		$	6,041

	Years Ended December 31,
	2001		2000		1999
			(Thousands)
FINANCIAL DATA
Energy service contracting revenues	$	157,379	$	134,620	$	169,633
Energy service contract cost	122,790		101,266		133,088
Gross margin	34,589		33,354		36,545
Operating expenses:
Selling, general and administrative	23,112		22,873		19,889
Depreciation, depletion and amortization	5,952		5,304		6,078
Total operating expenses	29,064		28,177		25,967
Operating income	5,525		5,177		10,578
Equity earnings of nonconsolidated investments	7,555		5,109		2,863
Earnings before interest and taxes	$	13,080	$	10,286	$	13,441

Revenue backlog increased to $128.3 million at year-end 2001 from $91.0 million at year-end 2000. The increase in backlog is primarily attributable to an increase in federal government contracts. Substantially all the backlog is expected to be completed within the next 18 months.

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.

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. Gross margins have trended downwards slightly over the past three years due to competitive pressures. The gross margin in 1999 was 21.5%.

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 in the northwest United States.

Depreciation, depletion and amortization (DD&A) 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 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 the power plants in Panama.

Revenue backlog increased to $91.0 million at year-end 2000 from $71.0 million at year-end 1999. The increase in backlog was attributable to an increase in the energy infrastructure project backlog.

Total construction completed during 2000 was $85.1 million versus $151.7 million, a decrease of $66.6 million over 1999. This decrease was primarily due to a $45 million decrease in construction of energy infrastructure projects in 1999.

Revenues decreased from 1999 to 2000 by $35.0 million, or 20.6%, primarily caused by low construction backlog at the beginning of 2000 versus the beginning of 1999. Gross margins increased to 24.8% in 2000 from 21.5% in 1999, reflecting a focus on higher margin products and services and a gross profit increase in a few operational energy services projects.

SG&A expenses increased from 1999 to 2000 by $3.0 million. Increases during 2000 included $1.0 million related to the decision to discontinue developing international energy infrastructure projects and the costs associated with the integrating of this division with the energy services contracting division. Other costs include $0.4 million of additional costs related to the closing of three unprofitable energy services contracting offices in the Northwest United States.

Depreciation, depletion and amortization (DD&A) expense decreased from 1999 to 2000 by $0.8 million, or 12.7%. This decrease was primarily due to a write-down of computer software development in 1999.

Equity income from nonconsolidated investments of $5.1 million in 2000 and $2.9 million in 1999 reflects NORESCO’s share of the earnings from its equity investments in power plant assets, primarily a 50 mega-watt facility in Panama, which is 50% owned by the Company. A 96 mega-watt facility in Panama and a 7 mega-watt facility in Providence, RI were brought on line in late 1999.

Other Income Statement Items

Other Income

	Years Ended December 31,
	2001		2000			1999
			(Thousands)
Other income (loss):
Equity earnings of nonconsolidated investments	$	26,101	$	25,161		$	2,863
Gain on sale of Westport stock	–		6,561			–
Other loss	–		(6,951		)	–
Total other income	$	26,101	$	24,771		$	2,863

Equity earnings of nonconsolidated investments increased in 2001 due to the favorable performance of the NORESCO segment’s investments in several independent power plant projects. Equity earnings of nonconsolidated investments increased in 2000 primarily due to the equity earnings from the Company’s ownership in Westport Resources Corporation (Westport). In October 2000, Westport completed an initial public offering (IPO) of its shares. Equitable sold 1.325 million shares in this IPO for an after-tax gain of $4.3 million. This reduced the Company’s ownership to approximately 36% interest in Westport. On August 21, 2001, Westport Resources completed a merger with Belco Oil & Gas. Equitable continues to own 13.911 million shares, which now represents approximately 27% of Westport’s total shares outstanding at December 31, 2001. Equitable’s equity in Westport was $148.1 million as of December 31, 2001.

On June 30, 2000, Equitable sold a substantial portion of gas properties which qualified for nonconventional fuels tax credit to a partnership 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.

Interest Charges

	Years Ended December 31,
	2001		2000		1999
			(Thousands)
Interest charges	$	41,098	$	75,661	$	37,132

Interest costs 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.

Interest costs increased in 2000 as a result of the Statoil acquisition which increased average debt outstanding by $580 million. The outstanding debt was reduced significantly during the fourth quarter by the proceeds received from the two prepaid gas forward sales, the sale of gas properties. Interest expense also increased as a result of higher interest rates in 2000 compared to 1999.

Average annual interest rates on short-term debt were 4.1%, 6.4%, and 5.2% for 2001, 2000, and 1999, respectively.

Capital Resources and Liquidity

Operating Activities

Cash flows provided by operating activities were $129.9 million in 2001 compared to $361.2 million in 2000 and $154.3 million in 1999. Excluding the $209.3 million cash received in December 2000 from the two prepaid natural gas sales, cash flows from operations decreased $22.0 million. Net income increased $45.6 million over 2000, which was attributed to higher commodity prices throughout the first three quarters of 2001. Depletion expense was lower than prior year primarily due to the two term interest sales of oil and gas properties in 2000 while deferred income tax expense was slightly higher over prior year. In addition, increased monetized production revenue recognition was included in net income that did not affect operating cash flows.

Equitable Utilities Distribution and Energy Marketing operations had decreased accounts receivable and deferred purchased gas costs due to the warmer weather, reduced trading activity, and lower commodity prices late in 2001 compared to the same period in 2000. This positive operating cash flow effect was partially offset by the decrease in accounts payable and the increase in inventory also attributable to the circumstances mentioned above.

As discussed above, the Company entered into two prepaid natural gas sales during 2000 and a monetization in 1995. Revenue is recognized from these transactions as the natural gas is delivered to the purchasing parties. As the actual cash receipts for these transactions took place at the contract inception, any amounts recognized in income are a non-cash item and is included as an adjustment to reconcile net income to net cash provided by operating activities. These amounts were $84.5 million, $13.7 million, and $13.0 million as of December 31, 2001, 2000, and 1999, respectively.

Investing Activities

Cash flows used in investing activities were $125.8 million in 2001 compared to $363.0 million in 2000 and $137.5 million in 1999. Cash provided by investing activities primarily consisted of $63.0 million of proceeds from the oil-dominated fields sale. At year-end, the $63.0 million proceeds remained in a restricted escrow account, which offset the cash inflow. Cash used in investing activities in 2000 primarily includes the acquisition of Statoil properties for $677 million and the increase in equity in nonconsolidated investments due to the Westport merger partially offset by the net proceeds received from the sales of producing properties and from the Gulf asset merger with Westport.

The Company expended approximately $132.7 million in 2001 compared to $123.7 million in 2000 and $102.0 million in 1999 for capital expenditures. These expenditures in all years represented growth projects in the Equitable Production segment, and replacements, improvements and additions to plant assets in the Equitable Utilities and NORESCO units. Equitable Production expended $93.9 million in 2001 primarily for development of the Appalachian region, gathering system pipeline improvements and technology initiatives. NORESCO expended $0.3 million for leasehold improvements and equipment additions and replacements. The Equitable Utilities segment expended $38.5 million primarily for distribution plant additions and replacements and technology improvements.

A total of $166 million has been authorized for the 2002 capital expenditure 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 loans.

In December 1999, the Company acquired the Carnegie Companies for $40 million, including natural gas distribution, pipeline, exploration and production operations.

Financing Activities

Cash flows used in financing activities were $26.5 million in 2001 compared to cash flows provided of $35.8 million in 2000 and cash flows used of $101.2 million in 1999. Throughout 2001, Equitable reduced its short-term debt and bought back shares of its outstanding common stock, as further described below, with cash provided by operating activities. In addition, NORESCO received project-financing loans of $105.4 million against its current construction contracts. It is expected that many of the contracts underlying this financing will be sold in 2002.

During the first quarter of 2001, a Jamaican energy infrastructure project, which is among the consolidated subsidiaries, 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.

The Company continued its stock buyback activities in 2001. Total shares authorized for repurchase under these activities was increased to 18.8 million in 2001. Total purchases under these activities of 12.3 million shares include 1.8 million shares of stock repurchased in 2001 for $61.2 million, and 1.2 million shares of stock repurchased in 2000 for $29.5 million.

Cash generated in all years was partially offset by the payment of the Company’s dividends on common shares, which for 2001, 2000 and 1999 were $40.4 million, $38.5 million and $40.4 million, respectively.

In July 1999, the Company repaid $75.0 million of 7-1/2% debentures, using cash proceeds received in 1998 from the sale of its natural gas midstream operations.

Short-term Borrowings

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 4.1% during 2001. The Company maintains a revolving credit agreement providing $325 million of available credit, and a 364-day credit agreement providing $325 million of available credit, with a group of banks that expire in 2003 and 2002, respectively. As of December 31, 2001, the Company has the authority and credit backing to support a $650 million commercial paper program.

Certain Trading Activities Accounted for at Fair Value

Below is a table that presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of December 31, 2001. For additional information concerning these instruments see Notes A and B in the consolidated financial statements, and the Critical Accounting Policies Involving Significant Estimates discussion presented earlier in Item 7.

Net Fair Value of Contract Assets (Liabilities) at Period-End
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)	$	(21,648	)	$	(1,858	)	$	–		$	–		$	(23,506	)

Prices provided by other external sources(2)	24,836			4,425			1,989			370			31,630

Prices based on models and other valuation methods(3)	(643		)	(1,509		)	(1,544		)	(269		)	(3,965		)
Net derivative assets	$	2,545		$	1,058		$	445		$	101		$	4,159

(1) Contracts include futures and fixed price swaps

(2) Contracts include physical, transport and basis swaps

(3) Contracts include demand charges and other fees

Risk Management

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.

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, under current market conditions management’s objective is to reduce its exposure to commodity price changes to $0.01 per diluted share per $0.10 change in the average NYMEX natural gas price for 2002, $0.03 per diluted share for 2003, and less than $0.04 per diluted share for 2004 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 due to the increased market volatility.

Equity in Nonconsolidated Investments

The Company, within the NORESCO segment, has equity ownership interests in independent power plant (IPP) projects located domestically and in selected international countries. 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 5 to 30 years. The Company invested approximately $0.1 million and $1.6 million in these operations in 2001 and 2000, respectively, with a total cumulative investment of $42.7 million. The Company’s share of the earnings for 2001 and 2000 related to the total investment was $7.6 million and $5.1 million, respectively. These projects generally are financed on a project basis with nonrecourse financings established at the subsidiary level.

During the 2001 second quarter, a domestic energy infrastructure project, included within Equity in Nonconsolidated Investments, experienced a performance default on a creditor’s agreement. The creditors agreed to temporarily delay enforcement of their remedies to provide an opportunity for resolution of the default. The Company fully reserved for this project during the second quarter 2001. A global settlement agreement was executed in October 2001, and in January 2002, as a result of the consummation of an asset transfer transaction the note was satisfied and debt extinguished.

NORESCO owns a 50% interest in a Panamanian thermal electric generation project. The project had previously agreed to retrofit the plant to conform to applicable environmental noise standards by a target date of August 31, 2001. Unforeseen events have continued to extend the final completion date of the required retrofits. The project has obtained an extension from the creditor sponsor until September 2, 2002. The Company has also received an extension from the Panamanian regulators until May 30, 2002. The Company intends to obtain all extensions required in the event the completion of the required retrofits is further delayed.

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 (Westport). 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, leaving Equitable with a total of 13.911 million shares, or approximately 36% interest in Westport. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. Equitable continues to own 13.911 million shares, which now represent 27% of Westport’s total shares outstanding at December 31, 2001. The fair market value of Equitable’s investment in Westport was $241.3 million as of December 31, 2001.

During 2000, Equitable Production sold gas properties with approximately 199 Bcfe in reserves located in the Appalachian Basin region of the United States in two transactions which resulted it retaining a 1% minority interest in each of the resulting partnership and trust. Both of these investments are accounted for under the equity method of accounting.

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. Earnings per share of common stock and weighted average common shares outstanding have been adjusted for the two-for-one stock split.

Acquisitions and Dispositions

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.

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 (Westport). In October 2000, Westport completed an initial public offering in which Equitable sold 1.325 million shares and reduced its ownership percentage to approximately 36%. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. Equitable continues to own 13.911 million shares, which now represent 27% of Westport’s total shares outstanding at December 31, 2001. The fair market value of Equitable’s investment in Westport was $241.3 million as of December 31, 2001 on a pretax basis.

In June 2000, Equitable sold properties which contained approximately 66.0 Bcfe of reserves that qualified for nonconventional fuels tax credits to a partnership 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 $26.2 million investment under the equity method of accounting. Equitable estimates that it will receive $6.0 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2002 based on expected production volumes.

acquisition. Equitable accounts for its $36.2 million investment under the equity method of accounting. Equitable estimates that it will receive $12.0 million in fees for operating the wells and gathering and marketing the gas on behalf of the trust in 2002 based on expected production volumes.

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. These contracts were recorded as prepaid gas forward sales and are being recognized in income as deliveries occur.

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 3.7 Bcfe annually. The proceeds are shown in the balance sheet as restricted cash. See Note F for additional information related to the restricted cash.

Rate Regulation

Accounting for the operations of Equitable’s Utilities segment is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As described in Note A and H 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 deferred costs.

Schedule of Certain Contractual Obligations

Below is a table that details the future projected payments for the Company’s significant contractual obligations as of December 31, 2001.

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
					(Thousands)
Interest expense	$	708,063	$	31,755	$	87,959	$	55,141	$	533,208
Long-term debt	287,946		–		44,800		13,000		230,146
Unconditional purchase obligations	184,738		19,195		56,608		35,404		73,531
Total contractual cash obligations	$	1,180,747	$	50,950	$	189,367	$	103,545	$	836,885

Equitable and its subsidiaries are subject to extensive federal, state and local environmental laws and regulations that affect their operations. 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.

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 $8.0 million is included in other long-term liabilities at December 31, 2001. Environmental matters are described in Note V to the consolidated financial statements.

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 were $0.7 million in both 2001 and 2000.

Inflation and the Effect of Changing Energy Prices

The rate of inflation in the United States has been 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.

Audit Committee

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.

Transactions with Directors’ Companies

During 2001, Equitable Resources conducted business with PNC Financial Services Group, Inc (PNC), where Mr. James E. Rohr, an Equitable Resources Director, serves as Chairman, President and Chief Executive Officer. The Company paid PNC a total of $521,675 in fees in 2001 for various services, including commitment fees for a line of credit in which PNC participates, treasury management fees, and trust fees. Also during 2001, the Company’s pension plan for hourly employees paid BlackRock, Inc., a majority-owned subsidiary of PNC, $117,555 in fees for investment management services. All of these transactions were on arms-length, fair terms 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, fair terms.

Item 7A. Qualitative and Quantitative Disclosures About Market Risk

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 Production 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 B 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 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. Volumes associated with future activities, such as new drilling, recompletions and acquisitions, are not eligible for hedging. 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 at prices considered to be at the upper end of historical levels.

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. In general, this marketing group considers profit opportunities in both physical and financial positions, and Equitable’s policies apply equally thereto. These financial instruments include forward contracts, which may involve physical delivery of an energy commodity, 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, 2001, the Company continued to execute its hedging strategy by utilizing price swaps with volumes of approximately 196.4 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, 2001 levels would increase the fair value of the natural gas instruments by approximately $69.3 million.

With respect to derivative contracts held by the Company for trading purposes as of December 31, 2001, a decrease of 10% in the market price of natural gas from the December 31, 2001 level would increase the fair market value by approximately $4.2 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.

Item 8. Financial Statements and Supplementary Data


Report of Independent Auditors	37

Statements of Consolidated Income for each of the three years in the period ended December 31, 2001	38

Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2001	39

Consolidated Balance Sheets December 31, 2001 and 2000	40 - 41

Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2001	42

Notes to Consolidated Financial Statements	43 - 67

REPORT OF INDEPENDENT AUDITORS

The Board of Directors and Stockholders

Equitable Resources, Inc.

We have audited the accompanying consolidated balance sheets of Equitable Resources, Inc. and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders’ equity and cash flows for each of three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the Index at Item 14(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, 2001 and 2000, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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 A to the consolidated financial statements, the Company adopted the provisions of Statements of Financial Accounting Standards No. 133, “Accounting for Derivatives and Hedging Activities”, effective January 1, 2001.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania
February 5, 2002

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

YEARS ENDED DECEMBER 31,

	2001		2000			1999
	(Thousands except per share amounts)
Operating revenues	$	1,764,491	$	1,652,218		$	1,042,013
Cost of sales	1,196,883		1,075,267			586,663
Net operating revenues	567,608		576,951			455,350
Operating expenses:
Operation and maintenance	80,607		103,020			74,424
Exploration	2,005		3,420			9,288
Production	32,495		42,450			25,854
Selling, general and administrative	124,743		116,050			102,307
Depreciation, depletion and amortization	73,230		97,777			100,722
Total operating expenses	313,080		362,717			312,595
Operating income	254,528		214,234			142,755
Equity in earnings of nonconsolidated investments	26,101		25,161			2,863
Gain on sale of Westport stock	–		6,561			–
Other loss	–		(6,951		)	–
Earnings before interest & taxes	280,629		239,005			145,618
Interest expense	41,098		75,661			37,132
Income before income taxes	239,531		163,344			108,486
Income taxes	87,723		57,171			39,356
Net income	$	151,808	$	106,173		$	69,130
Earnings per share of common stock:
Basic	$	2.36	$	1.63		$	1.02
Diluted	$	2.30	$	1.60		$	1.01

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

YEARS ENDED DECEMBER 31,

	2001			2000			1999
				(Thousands)
Cash flows from operating activities:
Net income	$	151,808		$	106,173		$	69,130
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for losses on accounts receivable	14,866			12,129			11,917
Depreciation, depletion and amortization	73,230			97,777			100,722
Dry hole expense	–			–			2,455
Amortization of construction contract costs	1,811			1,229			23,100
Recognition of monetized production revenue	(84,453		)	(13,715		)	(13,034		)
Deferred income taxes (benefits)	62,340			54,519			14,635
Increase in undistributed earnings from nonconsolidated investments	(22,248		)	(23,632		)	(717		)
Gain on sale of investment	–			(6,561		)	–
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues	155,860			(183,654		)	30,722
Inventory	(11,199		)	(35,853		)	(7,116		)
Prepaid expenses and other	13,824			(27,858		)	(9,090		)
Accounts payable	(184,069		)	199,843			(66,535		)
Prepaid gas forward sale	–			209,294			–
Other – net	(41,901		)	(28,538		)	(1,871		)
Total adjustments	(21,939		)	254,980			85,188
Net cash provided by operating activities	129,869			361,153			154,318
Cash flows from investing activities:
Capital expenditures	(132,679		)	(123,727		)	(101,991		)
Acquisition of Statoil production assets	–			(677,235		)	–
Carnegie acquisition	–			–			(40,128		)
Proceeds from Gulf asset merger	–			158,214			–
Proceeds from sale of interest in producing properties	–			382,942			–
Increase in equity in nonconsolidated investments	(314		)	(181,757		)	(22,719		)
Proceeds from sale of equity in nonconsolidated investments	–			19,875			–
Proceeds from sale of receivables	1,130			56,553			18,360
Proceeds from sale of property	69,058			2,127			8,935
Restricted cash from oil-dominated field sale	(62,956		)	–			–
Net cash used in investing activities	(125,761		)	(363,008		)	(137,543		)
Cash flows from financing activities:
Dividends paid	(40,356		)	(38,490		)	(40,384		)
Purchase of treasury stock	(61,203		)	(29,483		)	(101,574		)
Proceeds from exercises under employee compensation plans	6,855			9,039			6,959
Proceeds from issuance of nonrecourse note for project financing	–			–			17,000
Loans against construction contracts	105,420			–			–
Repayments and retirements of long-term debt	(10,405		)	–			(74,972		)
(Decrease) increase in short-term loans	(26,820		)	94,781			91,783
Net cash (used in) provided by financing activities	(26,509		)	35,847			(101,188		)
Net (decrease) increase in cash and cash equivalents	(22,401		)	33,992			(84,413		)
Cash and cash equivalents at beginning of year	52,023			18,031			102,444
Cash and cash equivalents at end of year	$	29,622		$	52,023		$	18,031
Cash paid during the year for:
Interest (net of amount capitalized)	$	40,258		$	81,023		$	54,516
Income taxes	$	15,396		$	11,711		$	5,759

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2001		2000
	(Thousands)
Assets
Current assets:
Cash and cash equivalents	$	29,622	$	52,023
Restricted cash	62,956		–
Accounts receivable (less accumulated provision for doubtful accounts: 2001, $14,807; 2000, $15,413)	132,750		300,399
Unbilled revenues	77,080		80,157
Inventory	96,445		85,246
Derivative commodity instruments, at fair value	193,623		31,220
Prepaid expenses and other	20,868		34,691
Total current assets	613,344		583,736
Equity in nonconsolidated investments	253,214		230,651
Property, plant and equipment:
Equitable Utilities	979,235		951,612
Equitable Production	1,333,702		1,248,605
NORESCO	24,407		26,204
Total property, plant and equipment	2,337,344		2,226,421
Less accumulated depreciation and depletion	923,067		806,992
Net property, plant and equipment	1,414,277		1,419,429
Other assets:
Regulatory assets	80,225		62,755
Goodwill	57,364		60,635
Contract receivables	49,577		22,843
Other	50,746		44,865
Total other assets	237,912		191,098
Total	$	2,518,747	$	2,424,914

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31,

	2001			2000
	(Thousands)
Liabilities and Common Stockholders’ Equity
Current liabilities:
Current portion of long-term debt	$	–		$	10,100
Current portion of nonrecourse project financing	16,696			461
Short-term loans	275,447			302,267
Accounts payable	101,654			285,723
Prepaid gas forward sale	55,705			55,705
Derivative commodity instruments, at fair value	62,002			58,848
Other current liabilities	100,686			132,477
Total current liabilities	612,190			845,581
Long-term debt:
Debentures and medium-term notes	271,250			271,250
Nonrecourse project financing	–			16,539
Total long-term debt	271,250			287,789
Deferred and other credits:
Deferred income taxes	364,633			247,833
Deferred investment tax credits	14,336			15,411
Prepaid gas forward sale	97,296			153,589
Deferred revenue	6,560			30,232
Project financing obligations	109,209			–
Other credits	72,119			25,784
Total deferred and other credits	664,153			472,849
Commitments and contingencies	–			–
Preferred trust securities	125,000			125,000
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: 2001 and 2000, 74,504	282,920			281,100
Treasury stock, shares at cost: 2001, 10,634; 2000, 9,426	(203,353		)	(151,167		)
Retained earnings	675,207			563,755
Accumulated other comprehensive income	91,380			7
Total common stockholders’ equity	846,154			693,695
Total	$	2,518,747		$	2,424,914

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999


						Retained Earnings			Accumulated Other Comprehensive Income (Loss)				Common Stockholders’ Equity
	Common Stock
	Shares Outstanding		No Par Value
						(Thousands)
Balance, December 31, 1998	71,712		$	241,102		$	467,326		$	(9		)	$	708,419
Comprehensive income:
Net income						69,130							69,130
Foreign currency translation									43				43
Total comprehensive income													69,173
Dividends ($0.59 per share)						(40,384		)					(40,384		)
Stock issued:
Stock-based compensation plans	440		6,959										6,959
Stock repurchases	(6,694	)	(101,357		)								(101,357		)
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 FAS 133adoption									(37,023			)	(37,023		)
Net unrealized gain from derivative instruments									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

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 $436,377 are available for dividends on, or purchase of, common stock pursuant to restrictions imposed by indentures securing long-term debt.

See notes to consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2001

A. Summary of Significant Accounting Policies

Principles of Consolidation: The consolidated financial statements include the accounts of Equitable Resources, Inc. and all subsidiaries, ventures and partnerships in which a controlling 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%.

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: Inventories, which consist of natural gas stored underground and materials and supplies, are stated at the lower of average cost or market.

Properties, Depreciation and Depletion: Plant, property and equipment is carried at cost. Depreciation is provided on 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 Company uses the successful efforts method of accounting for exploration and production activities. Under this method, the cost of productive wells and development dry holes, as well as productive acreage, are capitalized and depleted on the unit-of-production method. Equitable Production currently calculates a single depletion field including all reserves located in Kentucky, West Virginia, Virginia, Ohio and Pennsylvania.

Sales and Retirements Policies: No gain or loss is recognized on the partial sale of oil and gas reserves from a 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.

Deferred Purchased Gas Cost: The Company’s distribution and interstate pipelines are subject to rate regulation by state and federal regulatory commissions. Accounting for these operations is in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Where permitted by regulatory authority under purchased natural gas adjustment clauses or similar tariff provisions, the Company defers the difference between 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.

Derivative Commodity Instruments: The Company uses exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options to hedge exposures to fluctuations in natural gas prices and for trading purposes. At contract inception, the Company designates derivative commodity instruments as hedging or trading activities.

Effective January 1, 2001, the Company adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133) as amended by SFAS 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 and by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133. The cumulative effect of this change is reflected in other comprehensive income (see Note Q). As a result, the Company recognizes all derivatives as either assets or liabilities on the balance sheet 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 each reporting period. 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 Corporate Risk Committee. The intended use of the derivatives and their designation as either a fair value hedge or a cash flow hedge determines when the gains or losses on the derivatives are to be reported in earnings or when they are to be reported as a component of other comprehensive income, until the hedged item is recognized in earnings. The ineffective portion of the derivative’s change in fair value is recognized in earnings immediately, and is included in operating revenues in the Statement of Consolidated Income. Any ineffective portion that was recognized in earnings from a previous period that is “caught up” in a current period and recognized in other comprehensive income will be reversed out of earnings. The Company did not experience any material ineffectiveness with its cash flow hedges in 2001.

Cash Flow Hedges - The derivative financial instruments that comprise the amount recorded in other comprehensive income have been designated and qualify as cash flow hedges. These instruments hedge the Company’s 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. The Company’s derivative financial instruments accounted for as cash flow hedges were recorded as a $157.6 million asset at December 31, 2001, and are reflected on the Consolidated Balance Sheet as a component of derivative commodity instruments at fair value. The difference between these derivatives and the amounts reported on the Consolidated Balance Sheet represent the Company’s derivative contracts held for trading purposes. The effective portion of the derivative’s gain or loss remains until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Consolidated Statement of Income. If a derivative is terminated before settlement date of the hedged item, Other Comprehensive Income recorded up to that date would remain accrued provided that the forecasted sale remains probable to occur, and, going forward, the fair value change of the derivative(s) will be recorded in earnings. At December 31, 2001, the Company estimated that $39.4 million of net unrealized gain on derivative instruments currently reflected in accumulated other comprehensive income will be recognized as earnings during the next twelve months due to physical settlement.

Prior to January 1, 2001, the Company used the deferral accounting method to account for exchange-traded derivative commodity instruments designated and effective as hedges. Under this method, changes in the market value of these hedge positions were deferred and included in other current assets and other current liabilities. These deferred realized and unrealized gains and losses were included in operating revenues when the hedged transactions occur. In the event a hedge contract was terminated early, the deferred gain or loss realized on early termination of the contract was recognized as the hedged production occurs. The Company used the settlement method to account for OTC swap agreements and options designated and effective as hedges. Under this method, gains or losses associated with the contract were recognized at the time the hedged production occurs. Premiums on option contracts were deferred in other current assets and recognized in operating revenues over the option term. Transactions that were not designated and effective as hedges were marked to market. Cash flows from derivative contracts were considered operating activities.

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 2001, 2000 and 1999 of $2.0 million, $3.3 million and $4.6 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 acquired. Goodwill is amortized on a straight-line basis over a period of 20 years. The Company assesses the impairment of goodwill related to consolidated subsidiaries whenever events or changes in circumstances indicate that the carrying value may not be recoverable. A determination of impairment (if any) is made based on estimates of future cash flows. In instances where goodwill has been recorded for assets that are subject to an impairment loss, the carrying amount of the goodwill is eliminated before any reduction is made to the carrying amounts of impaired long-lived assets and identifiable intangibles.

In July 2001, the FASB issued Statement No. 141, Business Combinations, and Statement No. 142, Goodwill and Other Intangible Assets, both of which are effective for fiscal year 2002. Statement No. 141 eliminates the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and further clarifies the criteria to recognize intangible assets separately from goodwill. Under Statement No. 142, goodwill and indefinite intangible assets are no longer amortized but are reviewed annually for impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. The Company has recorded goodwill of $57.4 million at December 31, 2001. Application of the nonamortization provisions of Statement No. 142 is expected to result in an increase in annual net income of approximately $3.7 million. During 2002, the Company will perform the first of the required impairment tests of goodwill and, therefore, has not yet determined the effect these tests will have on the earnings and financial position of the Company.

Stock-Based Compensation: The Company has elected to follow Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock options and awards. Accordingly, compensation cost for stock options and awards is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of grant over the exercise price of the stock option or award.

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 exploration and 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 from activities classified as energy trading are recognized immediately.

The Company recognizes revenue from shared energy savings contracts as energy savings are measured and verified. Revenue received from customer contract termination payments is recognized when received. Revenue from other long-term contracts including energy savings performance contracts, such as turnkey contracts, is recognized on a percentage-of-completion basis, determined using the cost-to-cost method. Any maintenance revenues are recognized as related services are performed.

Sales of Receivables: The Company sells some amounts due from customers to financial institutions. At the time of the transfer, the amounts due from the customer are recognized as revenue, the transfer is accounted for as the sale of a receivable, the receivable is no longer reflected in the financial statements and any related deferred costs are charged to operations.

In September 2000, the Financial Accounting Standards Board issued Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, that replaces in its entirety, FASB Statement No. 125. Although Statement 140 has changed many of the rules regarding securitizations, it continues to require an entity to recognize the financial and servicing assets it controls and the liabilities it has incurred and to derecognize financial assets when control has been surrendered in accordance with the criteria provided in the Statement. As required, the Company has applied the new rules prospectively to transactions beginning in the second quarter 2001.

Income Taxes: The Company files a consolidated federal income tax return. The current provision for income taxes represents amounts paid or estimated to be payable. Deferred income tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities. 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.

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.

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: In August 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, which will be effective for fiscal year 2003. This Statement requires asset retirement obligations to be measured at fair value and to be recognized at the time the obligation is incurred. During 2002, management will assess the impact, if any, of this pronouncement on the earnings and financial position of the Company.

Reclassification: Certain previously reported amounts have been reclassified to conform to the 2001 presentation.

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. All per share information, including earnings per share of common stock, and weighted average common shares outstanding have been adjusted for the two-for-one stock split.

B. Derivative Commodity Instruments

The Company uses exchange-traded natural gas futures contracts, options and OTC natural gas swap agreements and options (collectively, derivative contracts) to hedge exposures to fluctuations in natural gas prices and for trading purposes. 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.

Hedging Activities

In addition to monetizations, the Company uses derivative instruments to hedge its exposure to natural gas price changes.

The following table summarizes the absolute notional quantities of the derivative contracts held for purposes other than trading at December 31, 2001 and 2000. The open swaps at year-end 2001 have maturities extending through December 2008. For 2001, the net gain noted in the table below is based on the commodities marked against the New York Mercantile Exchange (NYMEX) on December 31, 2001 and reported in accumulated other comprehensive income, net of tax. For 2000, prior to adoption of FAS 133, the net loss is based on the commodities marked against the NYMEX on December 29, 2000, which were deferred and reported as other current assets and other current liabilities.

	Absolute Notional Quantity				Deferred Gain (Loss)
	2001		2000		2001		2000
					(Millions)
Natural gas:
Swaps (Bcfe)	$	196.4	$	15.9	$	157.6	$	(17.0	)
Options (Bcfe)	–		61.8		–		(36.8		)
Other swaps:
Oil (MMBle)	$	–	$	0.4	–		$	(1.6	)
Propane (MMBle)	–		0.2		–		(1.5		)
Totals	$	196.4	$	78.3	$	157.6	$	(56.9	)

The Company recognized net losses on its hedging activities of $4.1 million, $77.6 million, and $8.5 million in 2001, 2000 and 1999, respectively. These gains/losses are offset when the underlying products are sold.

Trading Activities

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, 2001, the absolute notional quantities of the futures, swaps and physical contracts held for trading purposes were 30.3 Mcfe, 66.9 Mcfe, and 152.4 Mcfe, respectively.

The table below sets forth the end of period fair value and average fair value during the year for the entire derivative contracts held for trading purposes.

	2001				2000
	Assets		Liabilities		Assets		Liabilities
	(Thousands)				(Thousands )
Fair value at December 31	$	61,553	$	57,394	$	544,485	$	514,809
Average fair value	$	303,019	$	286,102	$	273,590	$	258,862

Excluding any offsetting physical activity, derivative trading activity resulted in net losses of $18.7 million and $8.6 million for 2001 and 2000, respectively.

C. Sale of Property

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 (Westport). 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 1.325 million shares in this IPO for an after-tax gain of $4.3 million. Equitable’s investment in Westport was $148.1 million as of December 31, 2001. On August 21, 2001, Westport completed a merger with Belco Oil & Gas. Equitable currently owns 13.911 million shares, which represents approximately 27% of Westport’s total shares outstanding at December 31, 2001.

In June 2000, Equitable sold properties with approximately 66.0 Bcfe of reserves which qualified for nonconventional fuels tax credits to a partnership, 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 $26.2 million investment under the equity method of accounting. The Company separately negotiated arms-length, market-based rate 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 $8.5 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2002 based on expected production volumes.

In December 2000, Equitable sold properties, previously acquired from Statoil, with approximately 133.3 Bcfe of reserves to a trust 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 completely 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 $36.2 million investment under the equity method of accounting. The Company separately negotiated arms-length, market-based rate 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 $14.6 million in fees for operating the wells and gathering and marketing the gas on behalf of the purchaser in 2002 based on expected production volumes.

D. Acquisitions

On February 15, 2000, Equitable, 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 through commercial paper 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 comparative financial information for the years ended December 31, 2000 and 1999 assuming that this acquisition occurred on January 1, 1999. The 2000 and 1999 results contain pro forma adjustments for DD&A and certain other adjustments together with related income tax effects.

	Years Ended December 31,
	2000		1999
Unaudited Pro Forma
Revenue	$	1,669,490	$	1,166,978
Net income	$	107,843	$	75,430
Earnings per share:
Basic	$	1.66	$	1.11
Diluted	$	1.63	$	1.10

This information is not necessarily indicative of the results the Company would have obtained had these events actually occurred on January 1, 1999, or of the Company’s actual or future results of operations of the combined companies.

In December 1999, the Company acquired Carnegie Natural Gas Company and subsidiaries (Carnegie) for $40 million, including transaction costs. The Carnegie operations include natural gas distribution and pipeline businesses that were integrated into those divisions of the Company’s Utilities segment, as well as exploration and production businesses that were integrated into the Production segment. Carnegie operates more than 1,000 natural gas wells in Pennsylvania and West Virginia and supplies approximately 8,000 industrial, commercial and residential customers. No goodwill was recorded in connection with the acquisition, which was accounted for under the purchase 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.

E. Income Taxes

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

	December 31,
	2001			2000
	(Thousands)
Deferred tax liabilities (assets):
Exploration and development costs expensed for income tax reporting	$	181,219		$	148,347
Other comprehensive income	50,343			–
Tax depreciation in excess of book depreciation	166,547			165,229
Regulatory temporary differences	29,996			24,791
Deferred purchased gas cost	8,023			12,163
Equity earnings in Westport	14,220			6,960
Undistributed earnings of foreign subsidiaries	4,581			–
Deferred revenues/expenses	(14,922		)	(14,774		)
Alternative minimum tax	(33,399		)	(49,540		)
Investment tax credit	(5,361		)	(7,754		)
Uncollectible accounts	(1,119		)	(7,407		)
Postretirement benefits	(4,520		)	(3,905		)
Other	(24,651		)	(13,547		)
Total (including amounts classified as current liabilities of $6,324 for 2001 and $12,730 for 2000)	$	370,957		$	260,563

Income tax expense (benefit) is summarized as follows:

	Years Ended December 31,
	2001		2000		1999
			(Thousands)
Current:
Federal	$	24,686	$	2,042	$	23,758
State	697		610		916
Foreign	–		–		47
Subtotal	25,383		2,652		24,721
Deferred:
Federal	61,844		49,300		14,756
State	496		5,219		(121		)
Subtotal	62,340		54,519		14,635
Total	$	87,723	$	57,171	$	39,356

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

	Years Ended December 31,
	2001			2000			1999
				(Thousands)
Tax at statutory rate	$	83,836		$	57,171		$	37,970
State income taxes	734			3,789			517
Undistributed earnings of foreign subsidiaries	4,581			–			–
Nonconventional fuels tax credit	(1,000		)	(900		)	(817		)
Other	(428		)	(2,889		)	1,686
Income tax expense	$	87,723		$	57,171		$	39,356
Effective tax rate	36.6		%	35.0		%	36.3		%

An income tax benefit of $2.6 million and $1.6 million for the years ended December 31, 2001 and 2000, respectively, triggered by the exercise of nonqualified employee stock options is reflected as an addition to common stockholders’ equity.

The consolidated federal income tax liability of the Company has been settled through 1996.

F. Restricted Cash

The net proceeds from the sale of certain properties were placed in an escrow account pursuant to a deferred exchange agreement. This agreement allows for the use of the funds in a like kind exchange for certain specified assets. As of December 31, 2001, the balance of restricted cash was $63.0 million; no balances were in place as of December 31, 2000.

G. Equity in Nonconsolidated Investments

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.

					December 31,
Investees	Location	Ownership			2001		2000
				(Thousands)
Eastern Seven Partners, L.P.	USA	1	%		$	26,198	$	26,414
Appalachian Natural Gas Trust	USA	1	%		36,204		36,235
Total Equitable Production					62,402		62,649
IGC/ERI Pan-Am Thermal	Panama	50	%		19,736		17,719
Petroelectrica de Panama	Panama	45	%		11,457		9,837
Capital Center Energy	USA	50	%		4,571		4,757
Dona Julia	Costa Rica	24	%		4,826		3,590
Hunterdon Cogeneration LP	USA	50	%		2,028		1,645
Other	USA	Various			78		352
Total NORESCO					42,696		37,900
Westport Resources Corporation	USA	27	%		148,116		130,102
Total equity in nonconsolidated investments					$	253,214	$	230,651

Equitable Production’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 domestically in the United States as well as in selected international countries.

IPP projects which NORESCO and its partners develop, construct 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 5 to 30 years.

The Company has invested approximately $0.1 million and $1.6 million in equity in nonconsolidated investments during 2001 and 2000, respectively, with a total cumulative investment of $42.7 million as of December 31, 2001. The Company’s ownership share of the earnings for 2001 and 2000 related to the total investments was $7.6 million and 5.1 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 (Westport). 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. Equitable’s investment in Westport was $148.1 million as of December 31, 2001 and the aggregate market value of this investment was $241.3 million as of December 31, 2001. On August 21, 2001, Westport Resources completed a merger with Belco Oil & Gas. Equitable continues to own 13.911 million shares, which represents approximately 27% of Westport’s total shares outstanding at December 31, 2001.

H. Regulatory Assets

Certain costs, which will be passed through to customers under ratemaking rules for regulated operations, are deferred by the Company as regulatory assets when recovery through rates is expected. The Company believes that it will continue to be subject to rate regulation that will provide for the recovery of deferred costs. The following table summarizes the regulatory assets.

	December 31,
Description	2001			2000
	(Thousands)
FAS 109 – deferred taxes	$	59,681		$	59,201
Accounts receivable special arrears	23,403			–
FAS 106 – other postemployment benefits	4,166			2,079
Deferred purchase gas costs	7,074			13,567
Valuation allowance and other	(7,025		)	1,475
Total regulatory assets	87,299			76,322
Amounts classified as other current assets	7,074			13,567
Total long-term regulatory assets	$	80,225		$	62,755

I. Intangible Assets

Amortization of the goodwill is provided on the straight-line method over a life of 20 years. Accumulated amortization at December 31, 2001 and 2000 was $17,505 and $13,758, respectively. For the years ended December 31, 2001, 2000 and 1999, amortization expense, included in depreciation, depletion and amortization, was $3,747, $3,747, and $3,746, respectively.

J. Short-Term Loans

Maximum lines of credit of $650 million were available to the Company at December 31, 2001 and 2000. The Company is not required to maintain compensating bank balances. Commitment fees averaging one-twelfth of one percent in 2001 and one-ninth of one percent in 2000 were paid to maintain credit availability.

Short-term loans were comprised almost entirely of commercial paper balances of $275.4 million and $302.3 with weighted average annual interest rates of 2.02% and 6.59% as of December 31, 2001 and 2000, both respectively. The maximum amount of outstanding short-term loans was $328.8 million in 2001 and $900.0 million in 2000. The average daily balance of short-term loans outstanding over the course of the year was approximately $234.6 million and $706.7 million at weighted average annual interest rates of 4.06% and 6.37% during 2001 and 2000, both respectively.

K. Long-Term Debt

	December 31,
	2001		2000
	(Thousands)

7¾ debentures, due July 15, 2026	$	115,000	$	115,000

Medium-term notes:
8.05% to 8.19% Series A, due 2001	–		10,100
8.0% to 9.0% Series A, due 2003 thru 2021	62,750		62,750
6.5% to 7.6% Series B, due 2003 thru 2023	75,500		75,500
6.8% to 7.6% Series C, due 2007 thru 2018	18,000		18,000
	271,250		281,350
Less debt payable within one year	–		10,100
Total debentures and medium-term notes	271,250		271,250
Nonrecourse note for project financing	16,696		17,000
Less current portion of nonrecourse note for project financing	16,696		461
Long-term portion of nonrecourse note for project financing	–		16,539
Total long-term debt	$	271,250	$	287,789

At December 31, 2001, the Company has the ability to issue $150 million of additional long-term debt under the provisions of shelf registrations filed with the Securities and Exchange Commission.

During the first quarter of 2001, a Jamaican energy infrastructure project, which the Company consolidates, 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 below.

Interest expense on long-term debt amounted to $23.3 million in 2001, $23.8 million in 2000, and $26.0 million in 1999. Aggregate maturities of long-term debt are zero in 2002, $24.3 million in 2003, $20.5 million in 2004, $10.0 million in 2005, and $3.0 million in 2006.

L. Prepaid Gas Forward Sale

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. As such, these contracts were recorded as prepaid gas forward sale and are being recognized in income as deliveries occur.

As of December 31, 2001 and 2000, the outstanding prepaid gas forward sale was $153.0 million and $209.3 million, respectively, of which $55.7 million was current for both years.

M. Deferred Revenue

In November 1995, the Company monetized Appalachian gas properties to a partnership, Appalachian Basin Partners (ABP), the production from which qualifies for non-conventional fuels tax credit. The Company recorded the proceeds as deferred revenue which was recognized as production occurred. The Company retained a partnership interest in the properties that increases substantially based on the attainment of a performance target. The performance target was met at the end of 2001. Beginning in 2002, the Company will no longer include ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold will decrease by approximately 8.9 Bcf while equity production will increase by the same amount. The Company will consolidate the partnership starting in 2002, and the remaining portion not owned by the Company will result in a minority interest. In 2002, the remaining portion not owned by the Company will be recorded as a minority interest. The Company will also begin receiving a greater percentage of the non-conventional fuels tax credit based on its increased ownership. As of December 31, 2001 and 2000, the deferred revenue associated with ABP was $1.3 million and $42.2 million, respectively, of which $1.3 million and $14.1 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 Utility segments.

N. Trust Preferred Capital Securities

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, 2001 and 2000 includes $9.2 million of preferred dividends related to the trust preferred capital securities.

O. Pension and Other Postretirement Benefit Plans

The Company has pension and other postretirement benefit plans covering union members that generally provide benefits of stated amounts for each year of service. Plans covering salaried employees use a benefit formula which is based upon employee compensation and years of service.

The following table sets forth the pension and other benefit plans’ funded status and amounts recognized for those plans in the Company’s consolidated balance sheets:

	Pension Benefits						Other Benefits
	2001			2000			2001			2000
	(Thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	113,939		$	123,237		$	46,498		$	41,930
Service cost	2,488			2,634			263			290
Interest cost	8,815			9,335			3,460			3,297
Amendments	(1,699		)	818			–			(2,999		)
Actuarial (gain) loss	8,619			(3,849		)	880			6,427
Benefits paid	(8,888		)	(8,737		)	(5,136		)	(5,112		)
Expenses paid	(647		)	(475		)	–			–
Acquisitions	–			6,905			–			–
Curtailments	1,476			1,844			832			1,496
Settlements	(12,831		)	(28,402		)	–			–
Special termination benefits (a)	2,394			10,629			49			1,169
Benefit obligation at end of year	$	113,666		$	113,939		$	46,846		$	46,498

	Pension Benefits						Other Benefits
	2001			2000			2001			2000
	(Thousands)
Change in plan assets:
Fair value of plan assets at beginning of year	$	110,521		$	158,819		$	2,049		$	5,448
Gain recognized at beginning of year	(174		)	–			–			–
Actual loss on plan assets	(5,449		)	(10,774		)	(233		)	(293		)
Employer contribution	90			90			2			–
Benefits paid	(8,888		)	(8,737		)	(1,745		)	(3,106		)
Expenses paid	(647		)	(475		)	–			–
Settlements	(12,831		)	(28,402		)	–			–
Fair value of plan assets at end of year	$	82,622		$	110,521		$	73		$	2,049
Funded status	$	(31,044	)	$	(3,418	)	$	(46,773	)	$	(44,449	)
Unrecognized net actuarial (gain) loss	17,914			(6,833		)	23,852			21,474
Unrecognized prior service cost (credit)	9,054			12,636			(100		)	(2,452		)
Unrecognized initial net (asset) obligation	–			(119		)	7,417			10,545
Net asset (liability) recognized	$	(4,076	)	$	2,266		$	(15,604	)	$	(14,882	)

Amounts recognized in the statement of financial position consist of:
Accrued benefit liability	$	(30,166	)	$	(2,299	)	$	(15,604	)	$	(14,882	)
Intangible asset	9,056			4,565			–			–
Accumulated other comprehensive loss	(17,034		)	–			–			–
Net asset (liability) recognized	$	(4,076	)	$	2,266		$	(15,604	)	$	(14,882	)
Weighted average assumptions as of December 31:
Discount rate	7.50		%	8.00		%	7.50		%	8.00		%
Expected return on plan assets	10.00		%	10.00		%	9.75		%	10.00		%
Rate of compensation increase	4.50		%	4.50		%	4.50		%	4.50		%

(a) Relates to enhanced benefit costs associated with additional Equitrans retirements in 2001 and the Kentucky West Virginia Gas Company LLC strike related settlements in 2000.

For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2001 for the Pre-65 managed care, Pre-65 non-managed care and all Post-65 medical charges are 4.75%, 5.60% and 5.30%, respectively. The rates were assumed to decrease gradually to ultimate rates of 4.75%, 4.95% and 5.05%. The pension liability of $4,076 at December 31, 2001 is included in other long-term liabilities and the asset of $2,266 at December 31, 2000 is included in prepaid expenses in the Consolidated Balance Sheets. The accrued liability for other postretirement benefits of $15,604 at December 31, 2001 is included in other long-term liabilities and $14,882 at December 31, 2000 is included in other current liabilities.

The Company’s costs related to defined benefit pension and other benefit plans comprised the following:

	Pension Benefits									Other Benefits
	2001			2000			1999			2001			2000			1999
	(Thousands)
Components of net periodic benefit cost:
Service cost	$	2,488		$	2,634		$	2,294		$	262		$	290		$	297
Interest cost	8,815			9,335			9,488			3,460			3,297			3,002
Expected return on plan assets	(11,061		)	(12,893		)	(13,048		)	(205		)	(545		)	(898		)
Amortization of prior service cost	1,677			1,783			1,823			(3		)	(145		)	31
Amortization of initial net (asset) obligation	(122		)	(265		)	(333		)	683			956			955
Recognized net actuarial (gain) loss	16			(29		)	90			954			979			921
Special termination benefits	2,394			10,629			–			49			1,169			–
Settlement (gain) loss	2,016			(3,143		)	(5,781		)	–			–			–
Curtailment loss	209			1,105			1,453			879			2,425			–
Net periodic benefit cost	$	6,432		$	9,156		$	(4,014	)	$	6,079		$	8,426		$	4,308

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 $113,666, $112,787, and $82,622, respectively, as of December 31, 2001 and $113,939, $112,820, and $110,403, respectively, as of December 31, 2000.

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:

	One-Percentage-Point Increase						One-Percentage-Point Decrease
	2001		2000		1999		2001			2000			1999
Effect on total of service and interest cost components	$	210	$	211	$	218	$	(196	)	$	(201	)	$	(207	)
Effect on postretirement benefit obligation	$	2,505	$	2,421	$	2,105	$	(2,381	)	$	(2,337	)	$	(2,815	)

Expense recognized by the Company related to the 401(k) employee savings plans totaled $2.9 million in 2001, $2.8 million in 2000 and $2.3 million in 1999.

P. Common Stock and Earnings Per Share

At December 31, 2001, shares of Equitable’s authorized and unissued common stock were reserved as follows:

		(Thousands)
Possible future acquisitions		13,190
Stock compensation plans		8,934
Total		22,124

Earnings Per Share

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

	Years Ended December 31,
	2001		2000		1999
	(Thousands except per share amounts)
Basic earnings per common share:
Net income applicable to common stock	$	151,808	$	106,173	$	69,130
Average common shares outstanding	64,347		65,100		68,088
Basic earnings per common share	$	2.36	$	1.63	$	1.02
Diluted earnings per common share:
Net income applicable to common stock	$	151,808	$	106,173	$	69,130
Average common shares outstanding	64,347		65,100		68,088
Potentially dilutive securities:
Stock options and awards (a)	1,728		1,232		586
Total	66,075		66,332		68,674
Diluted earnings per common share	$	2.30	$	1.60	$	1.01

(a) Options to purchase 80,665 shares, 42,000 shares, and 24,000 shares of common stock were not included in the computation of diluted earnings per common share because the options’ exercise prices were greater than the average market prices of the common shares for 2001, 2000, and 1999, respectively.

Q. Accumulated Other Comprehensive Income

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

	2001			2000
	(Thousands)
Cumulative effect of FAS 133 adoption	$	(37,023	)	$	–
Net unrealized gain from hedging transactions	139,468			–
Minimum pension liability adjustment	(11,072		)	–
Foreign currency translation adjustment	7			7
	$	91,380		$	7

Contained within the Company’s deferred tax assets and liabilities, detailed in Note E, are items related to other comprehensive income. As of December 31, 2001, these items were comprised of a $56.3 million deferred tax liability related to the cumulative effect of FAS 133 adoption and the net unrealized gain from hedging transactions, and a $6.0 million deferred tax asset related to the minimum pension adjustment. As of December 31, 2000, there were no items contained within deferred income taxes related to other comprehensive income.

R. Stock-Based Compensation Plans

Long-Term Incentive Plans

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 6,000,000 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 2001, 1,960 stock options were exercised under this plan, with 2,156 outstanding at December 31, 2001.

Pro forma information regarding net income and earnings per share for options granted is required by SFAS No. 123, “Accounting for Stock-Based Compensation,” and has been determined as if the Company had accounted for its employee stock options under the fair value method of SFAS 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 2001, 2000, and 1999, respectively.

	Years Ended December 31,
	2001			2000			1999

Risk-free interest rate (range)	2.2% to 5.0		%	5.42% to 6.80		%	4.75% to 6.41		%
Dividend yield	1.93		%	2.36		%	3.35		%
Volatility factor	.201			.231			.216
Weighted average expected life of options	8 years			8 years			7 years
Options granted	1,694,821			3,122,740			2,100,400
Weighted average fair market value of options granted during the year	$	9.80		$	7.19		$	3.58

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company’s employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. Had compensation cost for these options been determined in accordance with SFAS No. 123, the Company’s net income and diluted earnings per share would have been $145.1 million, or $2.20 per share in 2001 and $103.4 million or $1.56 per share in 2000. The amounts of estimated expenses that would have been recognized in 1999 were not considered material to the financial statements.

	Years Ended December 31,
	2001		2000		1999
Options outstanding January 1	5,204,622		3,379,126		2,516,370
Granted	1,694,821		3,122,740		2,100,400
Forfeitures	(343,851	)	(643,438	)	(905,800	)
Exercised	(487,128	)	(653,806	)	(331,844	)
Options outstanding December 31	6,068,464		5,204,622		3,379,126

Options outstanding at December 31, 2001 include 2,287,935 exercisable at that date and are summarized in the following table.

Options Outstanding									Options Exercisable
Range of Exercise Prices					Number Outstanding at 12/31/01	Weighted Average Remaining Contractual Life	Weighted Average Remaining Contractual Life		Exercisable as of 12/31/01	Weighted Average Exercise Price
$	0	To	$	3.94	2,156	4.9	$	2.98	2,156	$	2.98
$	11.81	To	$	15.74	1,601,508	6.0	$	14.77	1,220,397	$	14.68
$	15.75	To	$	19.67	371,332	3.4	$	16.73	320,667	$	16.58
$	19.68	To	$	23.61	1,469,316	8.2	$	19.86	398,679	$	19.87
$	23.62	To	$	27.54	230,000	8.1	$	24.50	79,335	$	24.44
$	27.55	To	$	31.48	714,631	8.9	$	29.03	213,125	$	29.02
$	31.49	To	$	35.41	1,574,562	9.2	$	31.58	22,017	$	32.70
$	35.42	To	$	39.35	104,959	7.4	$	38.38	31,559	$	36.76

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 and the continued employment of the participants until January 1, 2001. In 2000 and 1999, the Company granted 176,000 and 256,000 additional stock awards, respectively, to key executives. The weighted average fair value of these restricted stock grants is $20.07 and $11.50, respectively, for 2000 and 1999. The shares granted under these plans vest at the end of a three-year period. Upon vesting, shares are released to participants. Compensation expense recorded by the Company related to stock awards was $14.1 million in 2000 and $4.6 million in 1999.

Effective January 1, 2001, the performance conditions of the Long-Term Incentive Plan were met and the shares became fully vested and were distributed to the participants.

Nonemployee Directors’ Stock Incentive Plans

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, 2001, 217,400 options were outstanding at prices ranging from $14.19 to $39.13 per share, and 81,200 options had been exercised under these plans since the plan inception.

S. Fair Value of Financial Instruments

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 estimated fair value of long-term debt described in Note K at December 31, 2001 and 2000 is $302.5 million and $311.2 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 B, excluding trading activities which are marked-to-market, was $157.6 million and $56.9 million at December 31, 2001 and 2000, respectively.

T. Concentrations of Credit Risk

Revenues and related accounts receivable from the Equitable Production segment’s operations are generated primarily from the sale of produced natural gas to 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 278,000 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 residential end-users 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.

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. 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 cogeneration and power plant development facilities in several U.S. and Latin American markets, and performance contracting for commercial, industrial and institutional customers and various government facilities including military facilities throughout the United States.

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

U. Financial Information by Business Segment

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 Production segment’s activities are comprised of the exploration, development, production, gathering and sale of natural gas and oil, and the extraction and sale of natural gas liquids. NORESCO segment’s activities are comprised of cogeneration and power plant development, the development and implementation of energy and water efficiency programs, performance contracting and central facility plant operations.

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 as 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 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.

	Years Ended December 31,
	2001			2000			1999
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	1,315,553		$	1,235,756		$	703,969
Equitable Production	291,559			281,842			168,411
NORESCO	157,379			134,620			169,633
Total	$	1,764,491		$	1,652,218		$	1,042,013
Intersegment revenues:
Equitable Utilities	$	125,466		$	151,498		$	107,905
Equitable Production	10,719			24,275			22,493
Total	$	136,185		$	175,773		$	130,398
Depreciation, depletion and amortization:
Equitable Utilities	$	26,404		$	28,185		$	35,596
Equitable Production	40,624			64,065			58,565
NORESCO	5,952			5,304			6,078
Headquarters	250			223			483
Total	$	73,230		$	97,777		$	100,722
Segment profit:
Equitable Utilities	$	78,981		$	92,978		$	80,641
Equitable Production	178,730			120,336			54,616
NORESCO	13,080			10,286			13,441
Total segment profit	$	270,791		$	223,600		$	148,698
Reconciling items:
Headquarters earnings (loss) before interest and taxes not allocated to operating segments:
Westport equity earnings	$	17,820		$	19,885		$	–
Other	(7,982		)	(4,480		)	(3,080		)
Earnings before interest and taxes	280,629			239,005			145,618
Interest expense	41,098			75,661			37,132
Income tax expenses	87,723			57,171			39,356
Net income	$	151,808		$	106,173		$	69,130
Other significant noncash expense items:
Equitable Utilities:
(Decrease) increase in deferred purchased natural gas cost	$	(6,493	)	$	15,429		$	(10,370	)
Regulatory asset valuation allowance	7,000			–			–
Equitable Production:
Lease and gathering system impairments	2,410			1,960			3,518
NORESCO:
Revenues in excess of billings	18,759			7,677			2,771
Total	$	21,676		$	25,066		$	(4,081	)

	Years Ended December 31,
	2001		2000		1999
			(Thousands)
Segment assets:
Equitable Utilities	$	937,147	$	1,115,960	$	886,894
Equitable Production	1,138,550		975,523		670,828
NORESCO	264,960		143,030		145,925
Total operating segments	2,340,657		2,234,513		1,703,647
Headquarters assets, including cash and short-term investments	178,090		190,401		85,927
Total	$	2,518,747	$	2,424,914	$	1,789,574
Expenditures for segment assets (a):
Equitable Utilities	$	38,528	$	28,436	$	43,979
Equitable Production	93,862		770,930		92,099
NORESCO	289		1,596		6,041
Total	$	132,679	$	800,962	$	142,119

(a) 2000 expenditures include $677 million for the acquisition of Statoil Energy, Inc. See Note D; 1999 expenditures include $40 million for the acquisition of Carnegie Natural Gas Company, including $17.7 million in Equitable Utilities and $22.3 million in Equitable Production. See Note D.

V. Commitments and Contingencies

There are various 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 the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously.

Management 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 Company has annual commitments of approximately $20.2 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 12 years at December 31, 2001, which relate to natural gas distribution and production operations. However, approximately $19.1 million of these costs are recoverable in customer rates.

The Company is subject to federal, state and local environmental laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. 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 and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations.

W. Interim Financial Information (Unaudited)

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

	March 31		June 30		September 30		December 31
	(Thousands except per share amounts)
2001
Operating revenues	$	851,157	$	345,544	$	243,768	$	324,022
Operating income	108,273		50,773		41,897		53,585
Net income	71,266		31,437		24,800		24,305
Earnings per share:
Basic	$	1.10	$	0.49	$	0.39	$	0.38
Diluted	$	1.08	$	0.47	$	0.38	$	0.37
2000
Operating revenues	$	374,877	$	332,497	$	335,284	$	609,560
Operating income	75,748		50,671		42,626		45,189
Net income	39,103		16,225		19,141		31,704
Earnings per share:
Basic	$	0.59	$	0.25	$	0.30	$	0.49
Diluted	$	0.58	$	0.25	$	0.29	$	0.48

X. Natural Gas And Oil Producing Activities (Unaudited)

The supplementary information summarized below presents the results of natural gas and oil activities for the Equitable Production 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 information presented for 1999 excludes data associated with natural gas reserves related to rate-regulated and other utility operations. In 1999, the exploration and production operations conducted by Equitrans were transferred from Equitable Utilities to Equitable Production. Accordingly, the 1999 oil and natural gas information presented below reflects this transfer. These reserves (proved developed) are less than 5% of total Company proved reserves for the years presented.

Production Costs

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

	2001		2000		1999
	(Thousands)
At December 31:
Capitalized costs	$	1,022,834	$	954,734	$	947,803
Accumulated depreciation and depletion	410,429		332,994		410,921
Net capitalized costs	$	612,405	$	621,740	$	536,882
Costs incurred:
Property acquisition:
Proved properties	$	–	$	604,082	$	23,165
Unproved properties	–		9,199		722
Exploration	2,005		3,420		7,143
Development	83,139		93,695		59,647

Results of Operations for Producing Activities

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

	2001		2000		1999
	(Thousands)
Revenues:
Affiliated	$	–	$	–	$	14,067
Nonaffiliated	239,170		247,390		158,369
Production costs	32,495		42,450		26,206
Exploration expenses	2,005		3,420		4,001
Depreciation and depletion	25,785		48,121		52,009
Impairment of assets	–		–		5,018
Income tax expense	62,699		56,740		32,911
Results of operations from producing activities (excluding corporate overhead)	$	116,186	$	96,659	$	52,291

Reserve Information

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. In December 2001, the Company sold reserves associated with the Kentucky oil fields totaling 68 billion cubic feet equivalent. A decrease in pricing from 2000 to 2001 resulted in a downward revision of 60 billion cubic feet equivalent. In February 2000, the Company purchased reserves in conjunction with the Statoil acquisition. 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 1999, the Company decreased its estimate of the annual production decline from 4% to 3%, to be more representative of the region. This revision increased 1999 proved developed natural gas and crude oil reserves by 85,574 million cubic feet equivalent. Also during 1999, the exploration and production operations conducted by Equitrans were transferred to Equitable Production and reflected in the reserve information for 1999 as other additions to proved reserves of 43,829 million cubic feet equivalent. 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.

	2001		2000		1999
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	2,164,630		1,146,433		899,881
Revision of previous estimates	(75,476	)	56,388		134,576
Purchase of natural gas in place	–		1,220,509		46,124
Sale of natural gas in place	(39,990	)	(311,770	)	–
Extensions, discoveries and other additions	88,413		140,204		132,180
Production	(64,706	)	(87,134	)	(66,328	)
End of year	2,072,871		2,164,630		1,146,433
Proved developed reserves:
Beginning of year	1,563,076		965,969		780,817
End of year	1,490,093		1,563,076		965,969

	2001		2000		1999
	(Thousands of Barrels)
Oil
Proved developed and undeveloped reserves:
Beginning of year	6,867		9,932		9,826
Revision of previous estimates	(191	)	134		(23	)
Purchase of oil in place	–		1,872		44
Sale of oil in place	(4,662	)	(4,574	)	–
Extensions, discoveries and other additions	–		–		1,155
Production	(451	)	(497	)	(1,070	)
End of year	1,563		6,867		9,932
Proved developed reserves:
Beginning of year	6,867		7,996		8,331
End of year	1,563		6,867		7,996

Standard Measure of Discounted Future Cash Flow

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:

	2001			2000			1999
	(Thousands)
Future cash inflows	$	5,966,131		$	24,633,861		$	2,877,829
Future production costs	(1,242,227		)	(2,864,814		)	(808,115		)
Future development costs	(348,978		)	(327,875		)	(139,626		)
Future net cash flow before income taxes	4,374,926			21,441,172			1,930,088
10% annual discount for estimated timing of cash flows	(3,066,798		)	(14,969,946		)	(1,098,185		)
Discounted future net cash flows before income taxes	1,308,128			6,471,226			831,903
Future income tax expenses, discounted at 10% annually	(457,845		)	(2,394,354		)	(251,467		)
Standardized measure of discounted future net cash flows	$	850,283		$	4,076,872		$	580,436

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

	2001			2000			1999
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(206,675	)	$	(206,393	)	$	(146,230	)
Net changes in prices, production and development costs	(5,426,615		)	2,557,134			156,020
Extensions, discoveries and improved recovery, less related costs	55,544			408,844			140,402
Development costs incurred	61,667			61,496			30,479
Purchase of minerals in place – net	(138,274		)	2,627,587			26,152
Revisions of previous quantity estimates	(48,136		)	167,784			101,778
Accretion of discount	632,593			65,230			42,487
Net change in income taxes	1,936,509			(2,142,887		)	(128,301		)
Other	(93,202		)	(42,359		)	(67,224		)
Net (decrease) increase	(3,226,589		)	3,496,436			155,563
Beginning of year	4,076,872			580,436			424,873
End of year	$	850,283		$	4,076,872		$	580,436

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

Production Costs of Nonconsolidated Investments

	2001
	(Thousands)
At December 31:
Capitalized costs	414,653
Accumulated depreciation and depletion	75,012
Net capitalized costs	$	339,641
Costs incurred:
Property acquisition:	188,857
Proved properties	20,414
Unproved properties	16,220
Exploration	30,878
Development	$	256,369

Results of Operations for Producing Activities of Nonconsolidated Investments

	2001
	(Thousands)
Revenues	$	93,214
Production costs	26,519
Exploration expenses	8,367
Depreciation and depletion	33,148
Impairment of assets	2,518
Income tax expense	8,243
Results of operations from producing activities	$	14,419

Reserve Information of Nonconsolidated Investments

	2001
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	65,587
Revision of previous estimates	(1,707	)
Purchase of natural gas in place	75,826
Sale of natural gas in place	(427	)
Extensions, discoveries and other additions	14,794
Production	(15,647	)
End of year	138,426
Proved developed reserves:
Beginning of year	49,526
End of year	107,365

	2001
	(Thousands of Barrels)
Oil
Proved developed and undeveloped reserves:
Beginning of year	9,298
Revision of previous estimates	(1,165	)
Purchase of oil in place	10,040
Sale of oil in place	(130	)
Extensions, discoveries and other additions	1,618
Production	(1,317	)
End of year	18,344
Proved developed reserves:
Beginning of year	7,661
End of year	13,645

Standard Measure of Discounted Future Cash Flow of Nonconsolidated Investments

	2001
	(Thousands)
Future cash inflows	$	679,664
Future production costs	(224,903		)
Future development costs	(57,963		)
Future net cash flow before income taxes	396,798
Future income taxes	(81,832		)
Future net cash flows after income taxes	314,966
Future income tax expenses, discounted at 10% annually	(115,364		)
Standardized measure of discounted future net cash flows	$	199,602
Discounted future net cash flows before income taxes	$	246,980

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

Not Applicable.

PART III

Item 10. Directors and Executive Officers of the Registrant

Information required by Item 10 with respect to directors is incorporated herein by reference to the section describing “Election of Directors” in the Company’s definitive proxy statement relating to the annual meeting of stockholders to be held on May 16, 2002, which will be filed with the Commission within 120 days after the close of the Company’s fiscal year ended December 31, 2001.

Information required by Item 10 with respect to compliance with Section 16(a) of the Exchange Act is incorporated by reference to the section describing “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 16, 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.”

The information required by Item 405 of Regulation S-K contained under the caption “Compliance with Section 16(a) Reporting” on page 5 of the Proxy Statement is incorporated herein by reference.

Item 11. Executive Compensation

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 to 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 16, 2002.

Item 12. Security Ownership of Certain Beneficial Owners and Management

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 16, 2002.

Item 13. Certain Relationships and Related Transactions

None.

PART IV

Item 14. Exhibits and Reports on Form 8-K

(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 71 through 75) 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, 2001.

1. Form 8-K dated October 31, 2001 reclassifying certain amounts in the third quarter press release dated October 19, 2001.

EQUITABLE RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS COVERED

BY REPORT OF INDEPENDENT AUDITORS

(Item 14 (a))

1. The following consolidated financial statements of Equitable Resources, Inc. and Subsidiaries are included in Item 8:	Page Reference

Statements of Consolidated Income for each of the three years in the period ended December 31, 2001	38

Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 2001	39

Consolidated Balance Sheets December 31, 2001 and 2000	40 - 41

Statements of Common Stockholders’ Equity for each of the three years in the period ended December 31, 2001	42

Notes to Consolidated Financial Statements	43 - 67

2. Schedule for the Years Ended December 31, 2001, 2000 and 1999 included in Part IV:

II — Valuation and Qualifying Accounts and Reserves	70

All other schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE THREE YEARS ENDED DECEMBER 31, 2001

Column A	Column B		Column C						Column D			Column E
Description	Balance at Beginning of Period		Additions Charged to Costs and Expenses			Acquisitions			Deductions (b)			Balance at End of Period
						(Thousands)
2001
Accumulated provisions for doubtful accounts	$	15,413	$	14,866	(a)	–			$	(15,472	)(a)	$	14,807
2000
Accumulated provisions for doubtful accounts	$	13,024	$	12,129		$	400	(c)	$	(10,140	)	$	15,413
1999
Accumulated provisions for doubtful accounts	$	9,818	$	11,917		$	108	(d)	$	(8,819	)	$	13,024

Note:

(a) Excludes the $23.4 million accounts receivable special arrears receivables that were written-off directly and a regulatory asset was created for its recovery in rates. See Note H within Item 8 for further discussion of the Company’s regulatory assets.

(b) Customer accounts written off, less recoveries.

(d) Addition to the Provision for Doubtful Accounts relates to the acquisition of Carnegie Distribution.

INDEX TO EXHIBITS

Exhibits	Description	Method of Filing

3.01	Restated Articles of Incorporation of the Company dated May 18, 1999	Filed as Exhibit 3.01 to Form 10-K for the year ended December 31, 1999

3.02	Bylaws of the Company (amended through May 17, 2000)	Filed as Exhibit 3.02 to Form 10-Q for the quarter ended June 30, 2000

4.01 (a)	Indenture dated as of April 1, 1983 between the Company and Pittsburgh National Bank relating to Debt Securities	Filed as Exhibit 4.01 (Revised) to Post-Effective Amendment No. 1 to Registration Statement (Registration No. 2-80575)

4.01 (b)	Instrument appointing Bankers Trust Company as successor trustee to Pittsburgh National Bank	Filed as Exhibit 4.01 (b) to Form 10-K for the year ended December 31, 1998

4.01 (c)	Resolutions adopted June 22, 1987 by the Finance Committee of the Board of Directors of the Company establishing the terms of the 75,000 units (debentures with warrants) issued July 1, 1987	Filed as Exhibit 4.01 (c) to Form 10-K for the year ended December 31, 1998

4.01 (d)	Supplemental indenture dated March 15, 1991 with Bankers Trust Company eliminating limitations on liens and additional funded debt	Filed as Exhibit 4.01 (f) to Form 10-K for the year ended December 31, 1996

4.01 (e)	Resolution adopted August 19, 1991 by the Ad Hoc Finance Committee of the Board of Directors of the Company Addenda Nos. 1 through 27, establishing the terms and provisions of the Series A Medium-Term Notes	Filed as Exhibit 4.01 (g) to Form 10-K for the year ended December 31, 1996

4.01 (f)	Resolutions adopted July 6, 1992 and February 19, 1993 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 through 8, establishing the terms and provisions of the Series B Medium-Term Notes	Refiled as Exhibit 4.01 (h) to Form 10-K for the year ended December 31, 1997

4.01 (g)	Resolution adopted July 14, 1994 by the Ad Hoc Finance Committee of the Board of Directors of the Company and Addenda Nos. 1 and 2, establishing the terms and provisions of the Series C Medium-Term Notes	Filed as Exhibit 4.01 (i) to Form 10-K for the year ended December 31, 1995

4.01 (h)	Resolution adopted January 18 and July 18, 1996 by the Board of Directors of the Company and Resolutions adopted July 18, 1996 by the Executive Committee of the Board of Directors of the Company, establishing the terms and provisions of the 7.75% Debentures issued July 29, 1996	Filed as Exhibit 4.01 (j) to Form 10-K for the year ended December 31, 1996

4.01 (i)	Junior Subordinated Indenture Between Equitable Resources, Inc. and Bankers Trust Company	Filed as Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 1998

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

Exhibits	Description	Method of Filing

4.01 (j)	Amended and Restated Trust Agreement Between Equitable Resources, Inc. and Bankers Trust Company	Filed as Exhibit 4.2 to Form 10-Q for the quarter ended June 30, 1998

4.01 (k)	Equitable Resources, Inc. 7.35% Junior Subordinated Deferrable Interest Debentures Certificate	Filed as Exhibit 4.3 to Form 10-Q for the quarter ended June 30, 1998

4.01 (l)	Rights Agreement dated as of April 1, 1996 between the Company and Chemical Mellon Shareholder Services, L.L.C., setting forth the terms of the Company’s Preferred Stock Purchase Rights Plan	Filed as Exhibit 1 to Registration Statement on Form 8-A filed April 16, 1996

10.01	Trust Agreement with Pittsburgh National Bank to act as Trustee for Supplemental Pension Plan, Supplemental Deferred Compensation Benefits, Retirement Program for Board of Directors and Supplemental Executive Retirement Plan	Refiled as Exhibit 10.01 to Form 10-K for the year ended December 31, 1999

* 10.02	Equitable Resources, Inc. Directors’ Deferred Compensation Plan (Amended and Restated Effective May 16, 2000)	Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 2000

* 10.03	1999 Equitable Resources, Inc. Long-Term Incentive Plan (as amended May 26, 1999)	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 1999

* 10.04	1999 Equitable Resources, Inc. Short-Term Incentive Plan	Filed as Exhibit 10.04 to Form 10-K for the year ended December 31, 1999

* 10.05	1999 Equitable Resources, Inc. Non-Employee Directors’ Stock Incentive Plan (as amended May 26, 1999)	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 1999

* 10.06	Equitable Resources, Inc. 1994 Long-Term Incentive Plan	Refiled as Exhibit 10.06 to Form 10-K for the year ended December 31, 1999

* 10.07	Equitable Resources, Inc. and Subsidiaries Deferred Compensation Plan (Amended and Restated Effective May 16, 2000)	Filed as Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2000

* 10.08	Equitable Resources, Inc. Breakthrough Long-Term Incentive Plan with certain executives of the Company (as amended through November 30, 1999)	Filed as Exhibit 10.01 to Form 10-Q for the quarter ended September 30, 2000

* 10.09 (a)	Employment Agreement dated as of May 4, 1998 with Murry S. Gerber	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 1998

* 10.09 (b)	Amendment No. 1 to Employment Agreement with Murry S. Gerber	Filed as Exhibit 10.09 (b) to Form 10-K for the year ended December 31, 1999

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

Exhibits	Description	Method of Filing

* 10.10	Change in Control Agreement dated December 1, 1999 with Murry S. Gerber (corrected)	Filed herein as Exhibit 10.10

* 10.11	Supplemental Executive Retirement Agreement dated as of May 4, 1998 with Murry S. Gerber	Filed as Exhibit 10.4 to Form 10-Q for the quarter ended June 30, 1998

* 10.12	Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with Murry S. Gerber	Filed as Exhibit 10.12 to Form 10-K for the year ended December 31, 1999

* 10.13 (a)	Employment Agreement dated as of July 1, 1998 with David L. Porges	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 1998

* 10.13 (b)	Amendment No. 1 to Employment Agreement with David L. Porges	Filed as Exhibit 10.13 (b) to Form 10-K for the year ended December 31, 1999

* 10.14	Change of Control Agreement dated November 30, 1999 with David L. Porges (corrected)	Filed herein as Exhibit 10.14

* 10.15	Amended and Restated Post-Termination Confidentiality and Non-Competition Agreement dated December 1, 1999 with David L. Porges	Filed as Exhibit 10.15 to Form 10-K for the year ended December 31, 1999

* 10.16	Change of Control Agreement dated December 1, 1999 with Gregory R. Spencer	Filed as Exhibit 10.16 to Form 10-K for the year ended December 31, 1999

* 10.17	Noncompete Agreement dated December 1, 1999 with Gregory R. Spencer	Filed as Exhibit 10.17 to Form 10-K for the year ended December 31, 1999

* 10.18	Change of Control Agreement dated December 1, 1999 with Johanna G. O’Loughlin	Filed as Exhibit 10.18 to Form 10-K for the year ended December 31, 1999

* 10.19	Noncompete Agreement dated December 1, 1999 with Johanna G. O’Loughlin	Filed as Exhibit 10.19 to Form 10-K for the year ended December 31, 1999

* 10.20 (a)	Agreement dated May 29, 1996 with Paul Christiano for deferred payment of 1996 director fees beginning May 29, 1996	Filed as Exhibit 10.04 (a) to Form 10-K for the year ended December 31, 1996

* 10.20 (b)	Agreement dated November 26, 1996 with Paul Christiano for deferred payment of 1997 director fees	Filed as Exhibit 10.04 (b) to Form 10-K for the year ended December 31, 1996

* 10.20 (c)	Agreement dated December 1, 1997 with Paul Christiano for deferred payment of 1998 director fees	Filed as Exhibit 10.04 (c) to Form 10-K for the year ended December 31, 1997

* 10.20 (d)	Agreement dated December 15, 1998 with Paul Christiano for deferred payment of 1999 director fees	Filed as Exhibit 10.19 (d) to Form 10-K for the year ended December 31, 1998

* 10.20 (e)	Agreement dated November 29, 1999 with Paul Christiano for deferred payment of 2000 director fees	Filed as Exhibit 10.20 (e) to Form 10-K for the year ended December 31, 1999

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

Exhibits	Description	Method of Filing

* 10.21 (a)	Agreement dated May 24, 1996 with Phyllis A. Domm for deferred payment of 1996 director fees beginning May 24, 1996	Filed as Exhibit 10.14 (a) to Form 10-K for the year ended December 31, 1996

* 10.21 (b)	Agreement dated November 27, 1996 with Phyllis A. Domm for deferred payment of 1997 director fees	Filed as Exhibit 10.14 (b) to Form 10-K for the year ended December 31, 1996

* 10.21 (c)	Agreement dated November 30, 1997 with Phyllis A. Domm for deferred payment of 1998 director fees	Filed as Exhibit 10.14 (c) to Form 10-K for the year ended December 31, 1997

* 10.21 (d)	Agreement dated December 5, 1998 with Phyllis A. Domm for deferred payment of 1999 director fees	Filed as Exhibit 10.20 (d) to Form 10-K for the year ended December 31, 1998

* 10.21 (e)	Agreement dated November 30, 1999 with Phyllis A. Domm for deferred payment of 2000 director fees	Filed as Exhibit 10.21 (e) to Form 10-K for the year ended December 31, 1999

* 10.22 (a)	Agreement dated December 31, 1987 with Malcolm M. Prine for deferred payment of 1988 director fees	Filed as Exhibit 10.21 (a) to Form 10-K for the year ended December 31, 1998

* 10.22 (b)	Agreement dated December 30, 1988 with Malcolm M. Prine for deferred payment of 1989 director fees	Filed as Exhibit 10.21 (b) to Form 10-K for the year ended December 31, 1998

* 10.23	Release Agreement dated December 8, 1999 with John C. Gongas, Jr.	Filed as Exhibit 10.23 to Form 10-K for the year ended December 31, 1999

* 10.24	Change in Control Agreement dated June 12, 2000 by and between Equitable Resources, Inc. and James M. Funk	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2000

* 10.25	Noncompete Agreement dated June 12, 2000 by and between Equitable Resources, Inc. and James M. Funk	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2000

* 10.26	Change of Control Agreement dated October 30, 2000 by and between Equitable Resources, Inc. and Philip P. Conti	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2000

* 10.27	Purchase Agreement by and among Equitable Resources Energy Company, ET Bluegrass Company, EREC Nevada, Inc. and ERI Services. Inc. and AEP Resources, Inc. dated September 12, 1998 for the purchase of midstream assets	Filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 1998

*10.28	Indemnification Agreement effective July 19, 2000 by and between Equitable Resources, Inc. and James M. Funk	Files as Exhibit 10.28 to Form 10-K for the year ended December 31, 2000

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

Exhibits	Description	Method of Filing

*10.29	Indemnification Agreement effective August 11, 2000 by and between Equitable Resources, Inc. and Philip P. Conti	Filed as Exhibit 10.29 to Form 10-K for the year ended December 31, 2000

*10.30	Indemnification Agreement dated January 18, 2001 by and between Equitable Resources, Inc. and Joseph E. O’Brien	Filed as Exhibit 10.30 to Form 10-K for the year ended December 31, 2000

*10.31	Change of Control Agreement dated January 30, 2001 by and between Equitable Resources, Inc. and Joseph E. O’Brien	Filed as Exhibit 10.31 to Form 10-K for the year ended December 31, 2000

*10.32	Noncompete Agreement dated January 30, 2001 by and between Equitable Resources, Inc. and Joseph E. O’Brien	Filed as Exhibit 10.32 to Form 10-K for the year ended December 31, 2000

*10.33	Equitable Resources, Inc. Directors’ Deferred Compensation Plan (amended and Restated Effective December 6, 2000)	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2001

*10.34	Equitable Resources, Inc. 2001 Short-Term Incentive Plan	Filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2001

*10.35	Equitable Resources, Inc. Deferred Compensation Plan (Amended and Restated March 1, 2001)	Filed as Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 2001

*10.36	Equitable Resources, Inc. Production Long-Term Performance Incentive Plan	Filed as Exhibit 10.4 to Form 10-Q for the quarter ended March 31, 2001

*10.37	Equitable Resources, Inc. Executive Short-Term Incentive Plan	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2001

*10.38	1999 Equitable Resources, Inc. Long-Term Incentive Plan As Amended and Restated May 17, 2001	Filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2001

21	Schedule of Subsidiaries	Filed herewith as Exhibit 21

23.01	Consent of Independent Auditors	Filed herewith as Exhibit 23.01

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 (*).

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		EQUITABLE RESOURCES, INC.

	By:	/s/ Murry S. Gerber
		Murry S. Gerber
		Chairman, President and Chief Executive Officer

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.

	/s/	MURRY S. GERBER		Chairman, President and	March 13, 2002
			Murry S. Gerber	Chief Executive Officer
(Principal Executive Officer)

	/s/	DAVID L. PORGES		Executive Vice President and	March 13, 2002
			David L. Porges	Chief Financial Officer
(Principal Financial Officer)

	/s/	JOHN A. BERGONZI		Corporate Controller and	March 13, 2002
			John A. Bergonzi	Assistant Treasurer
(Principal Accounting Officer)

	/s/	PHYLLIS A. DOMM		Director	March 13, 2002
			Phyllis A. Domm

	/s/	E. LAWRENCE KEYES, JR.		Director	March 13, 2002
			E. Lawrence Keyes, Jr.

	/s/	THOMAS A. MCCONOMY		Director	March 13, 2002
			Thomas A. McConomy

	/s/	GEORGE L. MILES, JR.		Director	March 13, 2002
			George L. Miles, Jr.

	/s/	DONALD I. MORITZ		Director	March 13, 2002
			Donald I. Moritz

	/s/	MALCOLM M. PRINE		Director	March 13, 2002
			Malcolm M. Prine

	/s/	JAMES E. ROHR		Director	March 13, 2002
			James E. Rohr

	/s/	DAVID S. SHAPIRA		Director	March 13, 2002
			David S. Shapira

	/s/	J. MICHAEL TALBERT		Director	March 13, 2002
			J. Michael Talbert